ELECTRIC POWER RESEARCH INSTITUTE 

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

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

Estimating Total Sulfuric Acid Emissions 

from Stationary Power Plants 

1016384 

Effective February 7, 2008, this report has been made publicly available in accordance with Section 

734.3(b)(3) and published in accordance with Section 734.7 of the U.S. Export Administration 

Regulations. As a result of this publication, this report is subject to only copyright protection and does not 

require any license agreement from EPRI. This notice supersedes the export control restrictions and any 

proprietary licensed material notices embedded in the document prior to publication

 

ELECTRIC POWER RESEARCH INSTITUTE 

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

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

Estimating Total Sulfuric Acid Emissions 

from Stationary Power Plants 

1016384 

Technical Update, March 2008 

EPRI Project Manager 

Naomi Goodman 
 

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES 

THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF 

WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). 

NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY 

PERSON ACTING ON BEHALF OF ANY OF THEM: 

(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH 

RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM 

DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR 

PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED 

RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS 

SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR 

(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING 

ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED 

OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS 

DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN 

THIS DOCUMENT. 

ORGANIZATION(S) THAT PREPARED THIS DOCUMENT 

J. E. Cichanowicz, Inc. 

This is an EPRI Technical Update report. A Technical Update report is intended as an informal report of 

continuing research, a meeting, or a topical study. It is not a final EPRI technical report. 

NOTE 

For further information about EPRI, call the EPRI Customer Assistance Center at 800.313.3774 or 

e-mail askepri@epri.com. 

Electric Power Research Institute, EPRI, and TOGETHER...SHAPING THE FUTURE OF ELECTRICITY 

are registered service marks of the Electric Power Research Institute, Inc. 

Copyright © 2008 Electric Power Research Institute, Inc. All rights reserved. 
 

iii 

CITATIONS 

This document was prepared by 

J.E Cichanowicz, Inc. 

P.O. Box 905 

Saratoga, CA 95071 

Principal Investigator 

E. Cichanowicz 

This document describes research sponsored by the Electric Power Research Institute (EPRI). 

This publication is a corporate document that should be cited in the literature in the following 

manner: 

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

2008. 1016384. 

 

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 

ACKNOWLEDGEMENTS 

The methodology described in this document was developed by Southern Company Services and 

modified, with permission, by EPRI. Individuals responsible for the development of the original 

Southern Company sulfuric acid model are Keith E. Harrison and Larry S. Monroe, Ph.D. of the 

Southern Company. April Freeman of Southern Company also provided review and input into 

this version of the model. 

 

ix 

EXECUTIVE SUMMARY 

The U. S. Environmental Protection Agency’s (EPA’s) Toxic Release Inventory (TRI) reporting 

system requires that, beginning in 1998, electric utilities estimate their emissions of over 600 

chemicals. Sulfuric acid (H2SO4) is one of the chemicals included in the TRI reporting 

requirement, when it is present in an aerosol form. The EPA defines sulfuric acid aerosols as 

“includ[ing] mists, vapors, gas, fog, and other airborne forms of any particle size.” Sulfuric acid 

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

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

droplets of the acid. 

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

electrical power production facilities. The methodology described in this report was developed 

by Southern Company Services (SCS). Between 2000 and 2005, SCS developed several versions 

of the estimation methodology and released draft reports on request. The SCS model is widely 

used in the electrical power generation industry for TRI reporting and other emissions estimation 

purposes. In 2007, EPRI received permission from Southern Company Services to modify the 

SCS estimation method to include additional data and improvements, and to publish this method 

under EPRI sponsorship. The 2008 version of this report contains several updates from EPRI’s 

2007 version. 

The basic method for estimating sulfuric acid emissions remains unchanged from that described 

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

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

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

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

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

include a byproduct reaction of SCR, as well as the NOx control process of selective noncatalytic reduction (SNCR), and other types of FGC. This paper does not currently consider other 

developing SO3/H2SO4 removal technologies such as the various types of sorbent-based 

approaches that employ calcium-based, sodium-based, or other reagents, as described by 

Dombrowski (2004) and Weilert (2004). 

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

emissions from combustion systems, primarily coal-fired boilers. The 2008 version of the model 

is based on data from over 40 coal-fired units, representing various boiler types and coal sources. 

The estimates of SO3 production from combustion of coal are consistent with theoretical 

predictions that approximately 1% of the sulfur in coal is converted to SO3, although a wide 

range of conversions from 0.2% to 1.6% is reported, depending on coal source and boiler type. 

Data are obtained from field tests, reporting the removal of SO3 or H2SO4 by air heaters, 

particulate control equipment such as electrostatic precipitators (ESPs) and fabric filters, and SO2

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

amount of sulfuric acid that passes through, but is not captured by, each pollution control device. 

The technology factors are used to estimate quantities released to the air. 
 

x 

The current update does not incorporate any new measurement data of SO3 emissions. However, 

this version adds the capability to account for alkali injection, an expanding technique to control 

SO3 emissions. 

As with all estimation procedures, the methodology described in this report and the factors 

developed from the current database will not be applicable to every facility configuration or fuel 

type. Site-specific measurements of SO3 or H2SO4 emissions from a power facility, when 

available, should always be used in place of the estimates derived with this method. 
 

xi 

ERRATA 

Please make the following corrections to the text: 

Page 4-14

Equation 1-12 ERALKINJ = Kalkali • B • SSO3 • F2x• Falkali

Kalkali = Constant, equal to 3,799 

The conversion factor Kalkali, equal to 3,799, considers all relevant constants to yield the result in 

pounds per year of sulfuric acid. 

Page 4-15

Text Box E: Derivation of Conversion Factor, Kalkali. The U.S. Code of Federal Regulations 40, Part 60, Table 

19-1 “F Factors for Various Fuels” lists that 1 million Btu of heat input for bituminous or subbituminous coal will 

produce 10,640 wet standard cubic feet of flue gas, defined at 0% oxygen and on a wet basis at 20oC and 760 mm 

Hg. Correcting this volume to 6% 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 0oC and 760 mm Hg. Converting this to the English 

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

above,

(Kalkali • B • SSO3) = lbs H2

SO4 per yr = 

B TBtu SSO3 scf SO3 1 lb mol H2

SO4 98 lbs H2SO4 106

 MBtu 14,925 scf flue gas 

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

Grouping terms, 

= B • SSO3 • 3,799 

Therefore, the value of Kalkali is equal to 3,799 lbs H2

SO4/(TBtu • ppmv SO3 @ 6% O2 and wet). 

If the value of SO3

 is known in wet flue gas at an O2 content other than 6%, or an H2O content other than 8.1%, 

first convert the SO3 concentration to a 6% O2, 8.1% H2

O wet flue gas basis. The conversion of SO3 at any flue 

gas O2

 content to the value at 6% O2 and 8.1% H2O wet basis uses the following formula: 

SO3

 (6% O2, 8.1% H2O) 

= SSO3 (measured O2

, H2O) • [(100-8.1)/(100-measured H2O)] • [(20.9 – 6.0)/(20.9 – measured O2)] 
 

xii 

Page A-4

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

the result reported on Form R. 

Released 

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

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

The concentration of SO3

 measured at the stack can be converted to a mass emission rate, as 

described by Equation 4-12 

 ERALKINJ = Kalkali • B • SSO3 • Falkali • F2x

where, 

ERALKINJ = Total H2

SO4 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 E). 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. 

The SO3 concentration of 5 ppm in the stack is measured at slightly different conditions of excess 

O2 and moisture, compared to the reference conditions of 6% O2, at 8.1% H2O. 

SSO3 (6% O2, 8.1% H2O) = SSO3 (measured O2, H2O) • [(100-8.1)/(100-measured 

H2

O)] • [(20.9 – 6.0)/(20.9 – measured O2)] 

SSO3 (6% O2, 8.1% H2O) = 5 • [1.0077)• [1.034] 

SSO3 (6% O2, 8.1% H2

O) = 5.2 ppm 

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

 ERALKINJ = [3,799] • [27.05] •[5.2] • [1] • [1] 

 ERALKINJ = 534,367 lbs/yr 

 TSAR = ERALKINJ 

 TSAR = 534,367 lbs/yr 
xiii 

CONTENTS 

1 INTRODUCTION ....................................................................................................................1-1

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

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

2 MEASUREMENT UNCERTAINTY .........................................................................................2-1

SO3/H2sO4 Measurement Accuracy......................................................................................2-1

Correlation Representativeness...........................................................................................2-2

3 BACKGROUND AND METHODOLOGY OVERVIEW...........................................................3-1

Factors Affecting Manufacture and Release........................................................................3-1

Combustion Process............................................................................................................3-2

SCR/SNCR NOx Control......................................................................................................3-2

Flue Gas Conditioning..........................................................................................................3-5

Technology Impact Factors (F2) ..........................................................................................3-5

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

Manufacture and Release from Combustion........................................................................4-1

Manufacture and Release from Flue Gas Conditioning (FGC) ..........................................4-10

Total Manufacture and Release for Source .......................................................................4-13

Total Release Calculation for Sources Employing Alkali Injection .....................................4-13

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

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

Simple Cycle Units...............................................................................................................6-1

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

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

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

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

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

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

Example 4: 500 MW PRB-fired Boiler with ESP, SCR....................................................... A-5

Example 5: FGC Added to Example 1 ............................................................................... A-6

Example 6: SCR and FGC Added to Example 1................................................................ A-7

Example 7: Coal-Fired Boiler with FGC, NG Startup Fuel, and Used Oil Co-Firing........... A-9

Example 8: Natural Gas Combined Cycle Plant .............................................................. A-12

B CHRONOLOGY OF CHANGES TO EPRI SULFURIC ACID ESTIMATION MODEL........ B-13

1-1 

1

INTRODUCTION 

Background 

The ability to estimate sulfuric acid emissions from power plants is a topic of increasing 

importance to the U.S. utility industry. Most significantly, Section 313 of the Emergency 

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

Inventory (TRI), requires 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 in general, the TRI reporting requirements are triggered if a 

facility “manufactures” or “processes” more than 25,000 pounds of this chemical or “otherwise 

uses” more than 10,000 pounds of it in a given calendar year. 

Sulfuric acid is a listed TRI chemical. In June 1995, the U. S. Environmental Protection Agency 

(EPA) modified the list of chemicals subject to the EPCRA § 313 reporting requirements so that 

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

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

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

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

regardless of the physical state of the molecules. 

As of July 1, 1999, certain coal- and oil-fired electric power plants are required to report annual 

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

amounts. Under EPA’s EPCRA § 313 regulations, coal- and oil-fired electric utilities are deemed 

to “manufacture” sulfuric acid. Thus, electric utilities have to submit TRI reports on sulfuric acid 

releases if they “manufacture” more than 25,000 pounds of the chemical in a given reporting 

year (EPA, 1997). 

Significantly, 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 key precursor of sulfuric 

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

as manifested by an increase in stack plume visibility, was attributed to the presence of newly 

retrofit SCR process equipment. The deployment of approximately 105 GW of selective catalytic 

reduction (SCR) from 1997 through 2006 has prompted power plant owners to conduct extensive 

measurements documenting the fate of SO3 and sulfuric acid. 

Objective 

The objective of this document is to present a methodology for estimating sulfuric acid emissions 

from power generating facilities. 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 
1-2 

increased availability of measurements describing the fate of sulfuric acid attributable to the 

retrofit of SCR process equipment on coal-fired steam generators. 

The methodology described in this report was developed by Southern Company Services (SCS). 

Between 2000 and 2005, SCS developed several versions of the estimation methodology and 

released draft reports informally (Hardman, 1998; Hardman, 1999; Monroe, 2001, Harrison, 

2004, and Harrison, 2005). The SCS model is widely used in the electrical power generation 

industry for TRI reporting and other emissions estimation purposes. In 2007, EPRI received 

permission from Southern Company Services to modify the SCS estimation method to include 

additional data and improvements, and to publish this method under EPRI sponsorship. The 

current (2008) version of the model adds the ability to estimate emissions based on a specified 

sulfuric acid flue gas concentration at the stack. This approach can be used when alkali injection 

is employed to reduce sulfuric acid emissions. 

In its basic approach, the methodology employed by this predictive technique is unchanged from 

the previous version (EPRI, 2007). 

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

controlled condensation system (CCS), and the accuracy and representativeness of the data. 

Section 3 outlines the general methodology adopted in this model and summarizes data 

describing the removal of sulfuric acid across air heaters, ESPs, and wet flue gas desulfurization 

(FGD) process equipment. Section 4 describes the details of the methodology, focusing on data 

that predict manufacture by combustion, and outlines the calculation for including the role of the 

air heater and emissions control equipment. Section 5 outlines how to conduct the calculation for 

steam boilers firing a mixture of fuels. Section 6 addresses both simple cycle and combined cycle 

combustion turbine applications. Example calculations for many cases are presented in 

Appendix A. 
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 units is desired to generalize a 

correlation reflecting the broad population of generating units. Both of these factors are key to 

developing a usable predictive method. 

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

conducted predominantly in the last 1-2 years, with some estimates conducted 5-7 years ago. The 

quality of the information is believed to vary widely. It was not possible to obtain quality control 

information for all data sets; thus, it was not possible to critically review all data used in this 

model. 

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

were conducted using the 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. 

SO3/H2sO4 Measurement Accuracy

A recent 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, ashfree 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 actual), 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. Further, 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 was observed for both high sulfur coal 

and low sulfur PRB coal. The magnitude of the bias varied widely; data for high sulfur coal 

suggested a low bias of up to 40% could occur, although most measurements indicated lower 

bias values. A 20% low bias was noted for low sulfur, Power River Basin subbituminous coal. 

The accuracy 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 an accuracy of ± 20% is realistic 

for most conditions. The accuracy of the CCS measurements depends on avoiding stratification 
2-2 

within the gas stream (traversing is very difficult), maintaining correct temperatures in the 

sampling train, and having well trained sampling personnel. The accuracy of the entire data set 

used in this model, which includes data from older studies, is expected to be closer to ± 50%. 

Correlation Representativeness 

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

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

and the correlations provide only rough approximations of the flue gas SO3/H2SO4 for similar 

units. The category with the largest number of data points is dry-bottom boilers firing low sulfur, 

eastern bituminous coal. In general, the plant configurations from which the data are derived are 

considered to be representative of the utility industry generating population. The number of data 

points in each category should be considered when applying the results of these correlations. 

As a consequence of the uncertainty in SO3/H2SO4 measurement accuracy 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. 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 occurring at lower temperatures. 

Recent research activities have been directed to the use of alkali-based sorbents to capture SO3 at 

various points in the power generation process. As of the end of 2007, more than 25,000 MW of 

coal-fired generating capacity will be equipped with some type of sorbent injection method for 

SO3 control. New in this version of the report is a method to calculate sulfuric acid releases for 

units that inject alkali for SO3 reduction. 

Factors Affecting Manufacture and Release 

The method will estimate the manufacture and the subsequent release of sulfuric acid from the 

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

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

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

account for sulfuric acid removal within the system. 

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

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

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

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

manufactured, adjusted by sulfuric acid losses. 

The manufacture of SO3, the precursor to sulfuric acid, is denoted in this model as follows: for 

the combustion process by EMComb; for SCR by EMSCR; and for flue gas conditioning (FGC) by 

EMFGC. The Total Sulfuric Acid Manufactured (TSAM) from a combustion unit equipped with 

SCR NOx control and FGC is represented by Equation 3-1. 

Equation 3-1 TSAM = EMComb + EMSCR + EFGC
3-2 

Combustion Process 

Manufacture 

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

. 

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

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

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

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

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

The observation that most SO3 forms during cooling from post-flame temperatures (2,900-

3,100°F) to temperatures typical of the economizer entrance was also noted by Buckley (2002). 

Senior further quantified the relationship between coal sulfur content, excess air, and SO3

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

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

0.6% of the flue gas SO2 concentration. 

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

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

(EMComb) is expressed as follows: 

Equation 3-2 EMComb = K • F1 • E2 

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

with combustion for a specific fuel type, and E2 is the annual rate of SO2 production. Further 

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

Section 3. 

Release 

The release of sulfuric acid attributable to the combustion process is determined by adjusting the 

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

precipitator (ESP) or other particulate control device (PCD), and flue gas desulfurization (FGD) 

equipment. The release of sulfuric acid is calculated by applying Technology Impact Factors 

(F2) that describe the fraction of sulfuric acid that penetrates each downstream equipment 

component. The sulfuric acid released by combustion (ERComb) is described by the following: 

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

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

addressed later in this section. 

SCR/SNCR NOx Control 

Manufacture 

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

SO3

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

high as 3% of the SO2 concentration. 
3-3 

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 substituting for vanadium pentoxide or 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 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. 

Release 

Both SCR and SNCR can introduce residual ammonia (NH3), also called ammonia slip, into the 

flue gas. This residual ammonia can react with SO3

 or sulfuric acid to form ammonium sulfate 

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

precursor to sulfuric acid, and reducing the amount released. 

For an SCR, ammonia slip is expected to usually range between 0 and 2 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 
3-4 

ash. Any SO3 or H2SO4 that participates in these reactions is no longer chemically present as 

sulfuric acid and is not required to be reported to the EPA TRI program as a release of sulfuric 

acid. 

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

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

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

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

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

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

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

released. 

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

and/or ammonium bisulfate (NH4HSO4). While both chemicals are solids, the bisulfate pairs one 

molecule of ammonia with one of sulfuric acid, while the sulfate requires two ammonia 

molecules for each sulfuric acid. Which reaction product is present is usually determined by the 

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

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

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

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

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

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

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

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

produced is typically adsorbed by the ash and it is likely that residual ammonia will exceed 

sulfuric acid content on a mole basis. Under these conditions, ammonium sulfate is the likely 

product. 

For SNCR-equipped units, ammonia slip levels of 5 ppm and possibly higher will favor 

producing ammonium sulfate, particularly for western U.S. coals where the alkaline fly ash will 

reduce the SO3

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

and lower ash alkalinity, ammonium bisulfate will likely predominate. 

For the purpose of predicting sulfuric acid emissions, these distinctions are not important. A 

single molecule of sulfuric acid will capture a single molecule of ammonia, producing 

ammonium bisulfate. If additional ammonia is available, the ammonium bisulfate can react with 

another ammonia molecule to form ammonium sulfate. It can be assumed that all sulfuric acid 

forms ammonium bisulfate before any further reaction to the ammonium sulfate form occurs. 

This assumption leads to the calculation strategy that ammonia captures all of the sulfuric acid it 

can as ammonium bisulfate, and since the bisulfate form is no longer reportable, the sulfuric acid 

disappears from the release calculation. Additional ammonia reacting with the ammonium 

bisulfate is of no consequence to the sulfuric acid calculation – although this issue will be 

important when estimating ammonia releases. 

Further details of the calculations used in this model to predict sulfuric acid manufacture and 

release by SCR and SNCR are presented in Section 4. 
3-5 

Flue Gas Conditioning 

Manufacture 

Flue gas conditioning (FGC) is a process that is typically used in power plants to assist in 

particulate control in an ESP or baghouse. The conditioning additives can be any of the 

following: 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 O2 content of the flue gas. Section 4 presents an equation to estimate the 

manufacture of sulfuric acid from this source. 

Release 

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

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

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

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

remove sulfuric acid if NH3 is injected alone or in quantities greater than the sulfuric acid. The 

relevant relationships are presented in Section 4. 

The Technology Impact Factors (F2) describe the fraction of sulfuric acid that penetrates the air 

heater (for FGC that is introduced ahead of the air heater), and for the particulate control device 

and FGD (for FGC that is introduced after the air heater). The basis for the F2 factors is 

presented in the subsequent section, and the detailed equations for quantifying the manufacture 

and release of sulfuric acid are presented in Section 4. 

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. Relevant background and the 

derivation of these factors are addressed in this section. 

Air Heater 

The removal of SO3 and/or H2SO4 within the air heater is due to the condensation of sulfuric acid 

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

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

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

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

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

and Bowes, 2006). 

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

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

field tests of commercial equipment (Saranuc, 1999), this temperature profile introduces a strong 
3-6 

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 3-1 presents data obtained from a survey of utility operators and general literature sources 

describing SO3/H2SO4 removal 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 45% 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%. 

Figure 3-1 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 3-1 

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. 

The F2 factor for the air heater, calculated as [1 – Collection Efficiency], 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 3-1. 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. 
3-7 

0%

10%

20%

30%

40%

50%

60%

70%

80%

0 500 1000 1500 2000 2500 3000 3500

Flue Gas SO2Content, ppm 

Air Heater H2SO4 Removal, %

Low S East Bit, Dry Bottom Boiler

High S East Bit, Dry Bottom Boiler

Hamel Full-Scale Tests

PRB Dry Bottom Boiler

Figure 3-1 

Removal of Sulfuric Acid by Ljungstrom-Type Air Heaters

Table 3-1 

Summary of F2 Factors for Air Heater Removal of Sulfuric Acid 

Boiler 

Type Fuel F2 

Standard 

Deviation Comment 

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

All Boilers Med-High S Eastern Bit 

 (S >2.5%) 

0.85 n/a Two data points only. 

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

* Change in factor from Harrison (2005) 

Table 3-1 reports the standard deviation of the reported measurements for the low sulfur eastern 

bituminous coal is about one third the value of the measurement. Inadequate data prevent 

calculating a standard deviation for F2 factors for the other fuels. 
3-8 

Particulate and SO3 Control Processes 

This section discusses the available data on removal of SO3 by ESPs, FGDs, and alkali injection. 

ESP 

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 2-4 aft/s, and 

the opportunity for heat loss at or near the walls, sulfuric acid condensation can be significant. 

Figure 3-2 plots sulfuric acid removal by the ESP 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” datum, although shown in Figure 

3-2, is not used in the analysis. 

Figure 3-2 

Removal of Sulfuric Acid by Cold-Side and One Hot-Side ESP 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 500 1000 1500 2000 2500 3000 3500

Flue Gas SO2, ppm

ESP Flue Gas H2SO4 Removal, %

Low S East Bit, Dry Bottom Boiler

High S East Bit

ESPh Low S EastBit

PRB Dry Bottom Boiler
3-9 

The F2 factor for the cold-side ESP, calculated as [1- Collection Efficiency], is estimated using 

all data except the 0% removal point. The F2 factors for ESP capture for low sulfur eastern 

bituminous, medium-high sulfur eastern bituminous, and PRB coals are listed in Table 3-2. 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. 

Data describing the reduced H2SO4 penetration for one hot-side ESP is the result of a methodical 

and carefully executed test program, and is adopted even though it is inconsistent with earlier 

projections. The standard deviations of the ESP data were not calculated due to the small number 

of data points. Data for baghouses would reside at the extreme point on the chart, corresponding 

to 90% H2

SO4 removal. 

Table 3-2 

Summary of F2 Factors for Particulate Control Devices (ESP, Baghouse) 

Equipment 

Type Coal Type F2 Factor Comment or Observation 

Cold-side ESP Low S Eastern Bit 0.49 Average of measurements at 4 units. 

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

Cold-side ESP Subbituminous (PRB) 0.73 Based on one measurement at one unit. 

Hot-side ESP All 0.63 Based on one measurement at one unit. 

Baghouse Subbituminous coal 0.10 Two data points. 

FGD 

FGD process equipment rapidly cools or 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 3-3 summarizes data reported in the public domain and from utility-specific tests 

describing FGD removal of sulfuric acid. The percent of sulfuric acid removal is depicted as a 

function of FGD inlet SO2 concentration. Removals range from 22% to 78%, with an average of 
3-10 

about 50%. The shaded portion of Figure 3-3 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). 

0%

10%

20%

30%

40%

50%

60%

70%

80%

1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000

FGD Inlet SO2 , ppm

FGD H2SO4 Removal, %

Venturi

LimestoneTower

PRB/Lignite

Buckley, 

2002

Srivastava, 

2004

Figure 3-3 

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

Table 3-3 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 3-3. 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. 
3-11 

Table 3-3 

Summary of F2 Factors for Wet, Dry FGD Equipment and Additives 

FGD Type Coal Type F2 Factor Comment or Observation 

Wet: Spray Tower E. Bituminous 0.47 Seven data points. 

Wet: Spray Tower PRB or Lignite 0.40 Two data points. 

Wet: Venturi Tower All coals 0.65 Based on bituminous coal only; limited data merit 

assigning same factor for other coals. 

Dry FGD and baghouse All coals 0.01 Two data points. 

Mg-Ox mixed w/fuel oil All fuel 0.50 One data point. 

Mg-Ox into furnace All fuel 0.50 One data point. 

Alkali Injection 

Many utility operators inject alkali into the flue gas to control SO3. A wide variety of alkali 

materials based on calcium, sodium, or in some cases magnesium compounds, have been used 

with varying degrees of effectiveness to remove SO3

. These alkali materials include sodium 

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

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

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

maximize residence time and improve SO3

 removal. SBS can be highly effective in removing 

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

performance due to increased ash resistivity associated with SO3 reduction. A detailed summary 

of experience with the SBS concept has recently been published (Moser, 2007). 

Trona is another sodium-containing reagent that is being 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. 
3-12 

Plant units that deploy alkali injection will have conducted field tests to determine the resulting 

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

cases, the alkali injection system is operated to reduce SO3 emissions to between 5 and 15 ppm, 

which is the general range targeted for SO3 mitigating measures. 

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

stack releases from generating units that employ alkali injection for SO3 control, using measured 

or estimated stack gas SO3 concentrations. A procedure to convert measured sulfuric acid 

concentration in flue gas to a mass emission rate is summarized in Section 4, and an example 

application of this method is provided in Appendix A. 

To estimate SO3 manufacture with alkali injection, plant owners should use the standard 

approaches given in Section 4 for the appropriate plant configuration. At this time, EPRI does 

not have sufficient information to estimate the impact on SO3 formation of adding alkali at 

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

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

purposes. 

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

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

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

system, although this method is not currently approved by EPA for this purpose. 
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; and (c) the removal by downstream equipment such as air heaters, 

ESPs or other particulate control devices, and FGD process equipment. 

Each of the subsequent sections in this chapter provides the information to conduct this stepwise 

calculation. 

Manufacture and Release from Combustion 

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

a function of the amount of SO2 released – determined either from coal usage (amount burned 

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

equipped with FGD equipment or other methods of SO2 control are required to use either coal 

data or CEMS measurements from ahead of the scrubber. As described below, it may be 

necessary to correct CEMS SO2

 data for non-ideal stack flow conditions. 

Sulfuric Acid Manufactured by Combustion (EMComb)

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

combustion in utility sources: 

Equation 4-1 EMComb = K • F1 • E2 

where, 

EMComb= total H2SO4 manufactured from combustion, lbs/yr 

K = Molecular weight and units conversion constant, equal to 3,063. This value 

is derived as follows: 98.07/64.04 • 2000 = 3,063. Here, 98.07 is the 

molecular weight of H2SO4; 64.04 is the molecular weight of SO2; 

conversion from tons per year to pounds per year requires multiplying by 

2000. 

F1 = Fuel Impact Factor 

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

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

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

• SO3 concentrations are proportional to SO2 concentrations. 

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

 to SO3. 

• All SO3 that forms is converted to H2

SO4. 
4-2 

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

The fuel impact factor (F1) and estimates of sulfur dioxide emissions (E2) are further described 

in the following sections. 

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

gas SO2

 content, for several coal sources and boiler types. Figure 4-1 depicts a total of 30 data 

points, derived from 21 different units. The coal ranks and boiler types consist of (a) high sulfur 

(>2.5%) eastern bituminous coal, fired in a dry bottom boiler, (b) low sulfur eastern bituminous 

coal, fired in a dry bottom boiler, (c) PRB coal, fired in both a cyclone (1 reference) and two dry 

bottom boilers (4 references), and (d) high sulfur eastern bituminous coal, fired in a cell-fired 

boiler. Data are also shown for units that fire predominantly (75%) lignite (with the balance 

PRB) and PRB alone. 

Figure 4-1 

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

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, 

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

0.016

0.018

0.020

0 1000 2000 3000 4000

Flue Gas SO2Content 

Boiler H2SO4 Production, F1 Factor

High S East Bit, Dry Bottom Boiler

Low S East Bit, Dry Bottom Boiler

High S East Bit, Cell-fired Boiler

PRB Dry Bottom Boiler

75% Lignite
4-3 

in that less than 1 ppm was observed. Even for the low sulfur eastern bituminous coals, a 

significant range of SO3 content is observed. Attempts at correlating the F1 factor with flue gas 

SO2 content provided unacceptable correlation coefficients (R-squared values); thus, correlations 

are not proposed. 

Table 4-1 summarizes the basis of the F1 factors used in this model, denoting any significant 

changes from the most recent guideline published (Harrison, 2005). For two categories of 

equipment for which the most data points exist – dry-bottom boilers firing low sulfur eastern 

bituminous coal, and dry bottom boilers firing medium-high sulfur coal – a standard deviation is 

included for all of the data. 

Sulfur Dioxide (SO2) Emissions from Combustion (E2). Estimating the sulfuric acid production 

from Equation 4-1 requires knowledge of the mass rate of SO2 generated. This rate is designated 

as E2 in Equation 4-1. As noted previously, the value of E2 can be estimated from either (a) the 

EPA CEMS data, or (b) calculated from the coal burn data (EPA, 1995a). 

CEMS can directly quantify the annual SO2

 production rate, in tons/year of SO2. However, it may 

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

used, the factor E2 is defined by the following equation 

Equation 4-2a ( )

⎥

⎦

⎤ ⎢

⎣

⎡ ∗ + ∗ + = − 100

1 2 3 2 1

2 C R C R C E E 

where, 

 E2 = Corrected SO2 mass rate, tons per year 

 E = CEMS-derived SO2 mass rate, tons per year 

 C1 = 0.0264 (non-axial flow bias factor) 

 C2 = 0.183 (non-axial flow bias factor) 

 C3 = 1.5 (wall effects bias factor) – default value for cylindrical stacks 

R = Stack/duct average resultant angle (or swirl angle) from site verification tests, degrees 

In equation 4-2a, the factor C3 represents the wall effects bias factor which is used to specify the 

non-axial properties of flow within the stack, as measured by EPA Method 1 (EPA, 1991). This 

value, which will vary with each site, can be determined using EPA Method 2H (EPA, 1999). 

For most cylindrical stack geometries, a default value of 1.5 can be used; however the R value 

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

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

equipped with flow monitors (EPA, 2006). This proposal has not been finalized as of March 

2007, but some facilities may be allowed to apply this approach as a conditional test method. 
4-4 

Table 4-1 

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

Fuel Equipment F1 

Standard 

Deviation Comment 

Med-High S Eastern 

Bituminous (>2.5%) 

Dry Bottom 

Boiler 

0.011 0.0041 Seven data points. 

Med-High S Eastern 

Bituminous (>2.5%) 

Cyclone 0.016 One data point. 

Low S Eastern Bit. Dry Bottom 

Boiler 

0.0082* 0.0021 Average of measurements at 16 

units; slight increase in 

penetration compared to Harrison 

(2005). 

W. Bituminous Dry Bottom 

Boiler 

0.00111 One data point. 

W. Bituminous Cyclone 0.0022 One data point. 

Subbituminous/PRB All Boilers 0.0018* Average of 7 units; an increase in 

penetration compared to Harrison 

(2005). 

Lignite Dry Bottom 

Boiler 

0.0048 One data point. 

Lignite Cyclone 0.00112 One data point. 

Petroleum coke Boiler 0.04 One data point. 

Natural gas Boiler 0.01 

#2 Fuel oil Boiler 0.01 

#6 Fuel oil Boiler 0.025 

Used oil Boiler 0.0175 

Natural gas CT See Table 

6-1 

 

#2 Fuel oil CT See Table 

6-1 

 

Natural gas CC 0.0555 

#2 Fuel oil CC 0.0555* New category in 2007. 

Other Alternative Fuels Any 0.04 

Other Alternative Fuels, 

co-fired w/coal, >75% 

heat throughput 

NA Use Coal F1, in absence of any 

applicable data. 

* Change in factor from Harrison (2005) 
4-5 

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

used to estimate the rate of SO2 emissions: 

Equation 4-2b E2 = K1 • K2 • C1 • S1 

where, 

E2 = SO2 mass rate, tons/yr 

C1 = Coal burn, tons/yr 

S1 = Coal sulfur weighted average, % 

K1 = Molecular weight and units conversion constant, equal to 0.02. This value is derived 

from (64.04)/(100 • 32.06) = 0.02. Here, 64.04 is the molecular weight of SO2; 

32.06 is the molecular weight of S; and conversion of % S to a fraction requires 

multiplying by 100. 

 K2 = Sulfur conversion to SO2, implicit from EPA AP-42 (EPA, 1995b) 

 = 0.95 for bituminous coals 

 = 0.875 for subbituminous coals 

 = 0.55 to 0.85 for lignite, based on the Na content 

 = 1.0 for oil 

When any source uses FGD equipment or another technology to control SO2 emissions, either the 

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

used but only when the CEMS precedes the FGD or SO2 control equipment. CEMS data after a 

flue gas desulfurization system cannot be used. 

Sulfuric Acid Released from Combustion (ERComb) 

For units that do not employ SCR or SNCR NOx control or FGC, the sulfuric acid released is the 

product of the amount manufactured and the Technology Impact Factors (F2) for all downstream 

equipment (the air heater, the particulate control device, the FGD, etc.). For these units, the total 

sulfuric acid emissions can be calculated from Equation 4-3. 

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

Units that do employ SCR or SNCR, and/or flue gas conditioning, must consider these additional 

sources as described in the following sections. 

Text Box A summarizes calculations for units equipped with an FGD process that employs 

partial flue gas bypass, which must account for the fact that the entire flue gas flow is not subject 

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

employ flue gas bypass. 
4-6 

Manufacture and Release from SCR and SNCR 

This section describes a method to estimate how SCR can contribute to or reduce sulfuric acid 

emissions, while SNCR will only reduce such emissions. 

As discussed in Section 3, SO3 (and ultimately sulfuric acid) is produced by SCR, but can only 

be removed or reduced by SNCR due to the reaction with residual ammonia. The sulfuric acid 

manufactured by SCR is the net result of production by the catalyst and removal by the reaction 

of residual NH3 from the SCR process. 

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

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

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

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

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

releases. 

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

SCR and SNCR are described in the following sections. 

Sulfuric Acid Manufacture by SCR (EMSCR) 

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

boiler or steam generator: 

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

where, 

EMSCR = Total H2SO4 manufactured from SCR, lbs per year 

K = Conversion factor = 3063 

S2 = SCR catalyst SO2 oxidation rate (specified as a decimal, typically from 0.001- 

 0.03) 

Text Box A: Flue Gas Desulfurization Bypass Calculation. Those units equipped with scrubbers where some 

of the flue gas bypasses the scrubber should take this into account in their combustion release calculations. 

No credit for sulfuric acid removal should be taken for the fraction of the flue gas that bypasses the scrubber. 

Therefore, this amount of the flue gas should not be multiplied by the F2 factor for the scrubber. However, 

the flue gas volume should still be multiplied by the F2 factors for the other control devices. 

A modified equation considering partial scrubber bypass is given below and should be used where 

appropriate. 

ERCOMB = [SBf

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

where, SBf

 = fraction of scrubber bypass, as a decimal 

 F2s

 = F2 for scrubber 

 F2x

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

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 base-loaded operation, or 0.43 

for seasonal operation 

E2 = SO2 produced, tons per year 

F3SCR = Technology Impact Factor, for SCR 

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

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

unit documenting SO3 increase across the SCR reactor. 

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

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

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

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

different implications for SO3 produced. One method – based on actual field tests in commercial 

units – does not require adjustment and can be used as reported to predict sulfuric acid. The other 

method is based on laboratory tests of catalyst samples in the absence of ash and alkaline 

materials, and must be adjusted to account for these latter factors. The consequences of each of 

these methods on estimates of sulfuric acid emissions are described as follows: 

Full-Scale Catalyst Performance Tests. Ideally, SO2 conversion data will be determined with 

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

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 4-4 

without adjustment by the F3SCR Technology Impact Factor. 

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

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

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

measurements in the environment of the test laboratory are more accurate and reproducible than 

field tests. However, this method does not expose the catalyst being tested to ash, so there is no 

alkaline component to mitigate or absorb any SO3 generated. Accordingly, SO2 oxidation 

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

coals. SO2 oxidation data from bench-scale tests can be used, but must be adjusted for the role of 

ash alkalinity. This adjustment is provided by the Technology Impact factor F3SCR. 

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

two PRB-fired units. SO3 emitted from these units was lower than specified in the catalyst 

guarantee, which was based on laboratory test data. At present, there are no data to support F3SCR

factors for other coals, so a factor of 1 (full penetration) is recommended. 
4-8 

Table 4-2 

F3SCR Technology Impact Factors for SCR 

Coal Type F3SCR

PRB 0.17 

Other Coals 1 (no data available) 

SNCR will not result in the manufacture of sulfuric acid, thus EMSNCR is by definition zero. 

Sulfuric Acid Released from SCR and SNCR 

The sulfuric acid released from SCR or SNCR is determined by subtracting from the sulfuric 

acid manufactured the amount removed by the residual ammonia, or ammonia slip. For SCR, the 

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

Equation 4-5 ERSCR = [EMSCR – (Ks • B • fsreagent

• SNH3)] • F2x

where, 

ERSCR = Total H2SO4 released from SCR, lbs per year 

EMSCR = Total H2SO4 manufactured from SCR, lbs per year 

Ks = Conversion factor = 3799 

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 4-4. 

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

• SCR averages 0.75 ppmv over catalyst guarantee period 

• SNCR averages 5 ppmv 

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

F2x = Technology Impact Factors, all that apply 

The conversion factor Ks

, equal to 3799, considers all relevant constants to yield the result in 

pounds per year of sulfuric acid. The derivation of this constant, for the case where residual NH3

is reported in terms of 6% oxygen and “wet” flue gas at 8.1% H2

O, is presented in Text Box B. 

The coal burn rate in TBtu/yr is obtained from coal use records, such as those reported to EIA in 

Form 767. The operating factor of the SCR describes the portion of the coal burn that reflects the 

period of SCR operation, based on whether the unit operates seasonally (0.43), annually in a 

base-load duty (0.98), or annually in peaking duty (0.80). 
4-9 

Equation 4-6a specifies the concentration of NH3

 in flue gas (SNH3) in terms of ppmv at 6% O2, 

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

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

Equation 4-6a Ks (O2, H2O ) = 3799 (6% O2, 8.1% H2O) • [(100-8.1)/(100-new H2O)] 

• [(20.9 – 6.0)/(20.9 – new O2)] 

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

oxygen and a dry basis, the value of Ks

 that should be used is: 

Equation 4-6b Ks (O2, H2O) = 3799 (6% O2, 8.1% H2O) • [(100-8.1)/(100-0)] 

 • [(20.9 – 6.0)/(20.9 – new O2)] 

 = 2489 lbs H2SO4/(TBtu • ppmv NH3 @ 0% O2 and dry). 

This formula (Equation 4-6b) is used to calculate the value of Ks at any condition used to define 

the concentration of residual NH3. 

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

(ERSNCR) is a negative term which, when included in the calculations, will result in an overall 

reduction of sulfuric acid emissions. 

Text Box B: Derivation of Conversion Factor, KS. The U.S. Code of Federal Regulations 40, Part 60, Table 19-1 

“F Factors for Various Fuels” lists that 1 million Btu of heat input for bituminous or subbituminous coal will 

produce 10,640 wet standard cubic feet of flue gas, defined at 0% oxygen and on a wet basis at 20C and 760 mm 

Hg. Correcting this volume to 6% O2

 (typical at ESP conditions) yields a volume of 14,925 scf. The standard 

volume of one pound mole of any gas is 359 scf, defined at 0C and 760 mm Hg. Converting this to the English 

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

above,

(Ks • B • fs • SNH3) = lbs H2

SO4 per yr = 

B TBtu SNH3 scf NH3 1 lb mol NH3 1 lb mol H2SO4

 98 lbs H2SO4 14925 scf fg 106

 MBtu 

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

Grouping terms, 

= B • fs • SNH3 • 3799 

Therefore, the value of Ks

 is equal to 3799 lbs H2SO4/(TBtu • ppmv NH3 @ 6% O2 and wet). 

If the value of NH3

 is known in wet flue gas at an O2 content other than 6%, first convert the NH3 concentration to 

a 6% wet flue gas basis in order to use the preceding formula. The conversion of NH3

 at any flue gas O2 content 

to the value at 6% O2

 wet basis uses the following formula: 

NH3 @ 6% = (NH3 content at X%)*(15)/(21-X) 

Where: NH3 content at X% represents that measured at an O2

 concentration of X 
4-10 

Accordingly, total sulfuric acid release (TSAR) is estimated for a generating unit equipped with 

SCR by the following equation: 

Equation 4-7 TSAR = ERComb + ERSCR

Or in the case of SNCR, 

Equation 4-8 TSAR = ERComb + ERSNCR

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

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

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

Manufacture and Release from Flue Gas Conditioning (FGC) 

Sulfuric Acid Manufactured from FGC 

Most SO3–based FGC systems, in order to moderate ash resistivity, strive 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 use the setpoint of the FGC system as the 

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

perhaps startup and low load operation. 

The sulfuric acid manufactured by SO3

-based FGC equipment (EMFGC) is calculated as follows: 

Equation 4-9 EMFGC = Ke • B • fe • Is

 where, 

EMFGC = Total H2SO4

 manufactured from FGC, lbs per year 

Ke

 = Conversion factor = 3799, which is equivalent to 

Ks, as described in Text Box B. 

B = Coal burn in TBtu/yr 

Text Box C: Special Provision for Flue Gas Desulfurization Bypass. Those units equipped with scrubbers 

where some of the flue gas bypasses the scrubber should take this into account in their SCR/SNCR release 

calculations also, as in the combustion release calculations. No credit for sulfuric acid removal should be 

taken for the fraction of the flue gas that bypasses the scrubber. Therefore, this amount of the flue gas should 

not be multiplied by the F2 factor for the scrubber. However, it should still be multiplied by the F2 factors 

for the other control devices.

A modified equation considering partial scrubber bypass is given below and should be used where 

appropriate. 

ERSCR = [SBf

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

where, SBf

 = fraction of scrubber bypass, as a decimal 

F2s

 = F2 factor for scrubber 

F2x

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

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

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

but generally will be about 0.8. 

Is

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

 = 7 ppmv if before the APH 

= 5 ppmv if after the APH 

The conversion of SO3 from measured conditions to 6% O2 and wet basis is conducted using 

Equation 4-6a. 

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

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

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

of sulfuric acid by reacting with SO3 or the resultant H2SO4. The reduction in flue gas sulfuric 

acid by reaction with ammonia determines the sulfuric acid released by FGC, discussed in the 

next section. 

Sulfuric Acid Released from FGC (ERFGC) 

The subsequent release of that portion of sulfuric acid associated with flue gas conditioning can 

be estimated from the sulfuric acid quantity manufactured, adjusted by the amount that reacts 

with ammonia in the particulate control device installed downstream of the FGC. 

Equation 4-10 ERFGC = [EMFGC – (Ke • B • fe • INH3)] • F3FGC • F2 

 where, 

ERFGC = Total H2SO4 released from FGC, lbs per year 

EMFGC = Total H2SO4 manufactured from FGC, lbs per year 

Ke

 = Conversion factor = 3799 

B = Coal burn in TBtu/yr 

Fe

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

system operates. This value will be the same as Fe

 described previously and in 

many cases can be approximated by 0.8. 

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

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

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

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

equipment is installed after the ESP; F2 = 1. 
4-12 

Table 4-3 

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

Location Coals F3FGC

Upstream of APH Bituminous 0.25 

Upstream of APH W. bituminous, subbituminous, & lignite 0.05 

Downstream of APH Bituminous 0.10 

Downstream of APH W. bituminous, subbituminous, & lignite 0.02 

For other fuels, use F3 = 0.5 for startup fuel and F3 = coal factor for fuels co-fired as a minor fraction 

(<25%) with coal. 

This approach leads to a possible contradiction in the behavior of SO3/H2SO4

 depending on the 

place in which the SO3/H2SO4 enters the system. Depending on the source of the SO3, and for 

FGC where it is injected, the predicted removal within the air heater and ESP can differ. No 

mechanistic reason has been identified for these differences – they emerge from the supporting 

data. The following passage describes this apparent anomaly. 

For SO3 manufactured by combustion, SCR, or introduced as FGC ahead of the air preheater, the 

method predicts sulfuric acid removal of 75% for eastern bituminous coals across an air 

preheater/cold-side ESP combination. However, a higher fraction of SO3 or H2SO4 is predicted to 

be removed for FGC if injected downstream of the air preheater. Specifically, as denoted in 

Table 4-3, 90% will be removed in a cold-side ESP for the eastern bituminous coal. Thus, for 

bituminous coals, the F3 factor for FGC introduced upstream of the air heater mirrors the 

behavior of SO3 manufactured from combustion or SCR; the method predicts the same result for 

a molecule of SO3 found ahead of the air preheater, regardless of its origin. However, for the 

same eastern bituminous coal, the F3 factor for FGC introduced downstream of the air heater 

yields a higher SO3 removal (90%) than for SO3 introduced ahead of the air heater. The 

difference in results is likely attributable to the limited number of data points, and uncertainty in 

the measurement. It is recommended that the methodology be executed as described, and future 

versions will attempt to resolve this difference. 

For western or low-rank fuels, SO3 injected ahead of the air heater as FGC is assumed to be 95% 

removed through the air heater and ESP. SO3 is assumed to be 98% removed when injected 

downstream of the air heater. As these western bituminous, subbituminous, and lignite coals 

feature significant alkaline content of ash, any SO3 injected for FGC will likely be captured by 

both physical deposition and chemical reaction. Accordingly, it is reasonable that SO3/H2SO4

removal assumed for these coals be higher than for eastern bituminous coals. Further, as the 

injection of SO3 on the cold-side of the air preheater is typically below the acid dewpoint, it can 

be expected that any injected SO3 will condense on fly ash more readily compared to the slower 

cooling of the flue gas through the air preheater. 

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

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

required. These calculations for FGC are described in Text Box D. 
4-13 

Total Manufacture and Release for Source 

For any given source, the total manufacture and release of sulfuric acid is the sum of the 

individual manufacture or release estimates. Therefore, if a site burns coal and uses both SCR 

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

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

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

Both SCR and/or FGC may contribute a negative effect on sulfuric acid release, as the ammonia 

in the system can remove some or all of the sulfuric acid generated from combustion. Under 

these conditions, ammonia-based FGC can serve to only reduce the release of sulfuric acid. Since 

the release of sulfuric acid from combustion, SCR, and FGC are all additive, any negative values 

calculated as a result of these circumstances will be accounted for in the total release equation. 

Accordingly, total sulfuric acid manufacture (TSAM) and release (TSAR) is estimated for a 

generating unit equipped with SCR and flue gas conditioning by the following equations: 

Equation 4-11a: Manufacture

 TSAM = EMComb + EMSCR/SNCR + EMFGC 

Equation 4-11b: Release 

 TSAR = ERComb + ERSCR/SNCR + ERFGC

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

Total Release Calculation for Sources Employing Alkali Injection 

As described in Section 3, sources that employ alkali injection to mitigate stack opacity or a 

visible plume will have access to field measurements describing SO3

 concentration in flue gas, 

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

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

calculations also, as in the combustion and SCR/SNCR release calculations. No credit for sulfuric acid 

removal should be taken for the fraction of the flue gas that bypasses the scrubber. Therefore, this amount of 

the flue gas should not be multiplied by the F2 factor for the scrubber. However, it should still be multiplied 

by the F2 factors for the other control devices.

A modified equation considering partial scrubber bypass is given below and should be used where appropriate. 

ERFGC = [SBf

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

where, SBf

 = fraction of scrubber bypass, as a decimal 

 F2s

 = F2 factor for scrubber 

 F2x

 = All other applicable F2 factors except for scrubber. 
4-14 

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

mass emission rate using Equation 4-12 

Equation 4-12 ERALKINJ = Kalkali • B • SSO3 • F2x

• Falkali

where, 

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

Kalkali = Constant, equal to 1.46 

B = Coal burn in TBtu/yr 

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

6% O2

, wet 

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

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. 

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 3-2) 

should be selected. 

The conversion factor Kalkali, equal to 1.46, considers all relevant constants to yield the result in 

pounds per year of sulfuric acid. The derivation of this constant, for the case where flue gas SO3

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

The coal burn rate in TBtu/yr is obtained from coal use records, such as those reported to EIA in 

Form 767, for coal analysis on either on a wet or dry basis provides the same result. 
4-15 

Text Box E: Derivation of Conversion Factor, Kalkali. The U.S. Code of Federal Regulations 40, Part 60, Table 

19-1 “F Factors for Various Fuels” lists that 1 million Btu of heat input for bituminous or subbituminous coal will 

produce 10,640 wet standard cubic feet of flue gas, defined at 0% oxygen and on a wet basis at 20oC and 760 mm 

Hg. Correcting this volume to 6% 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 0oC and 760 mm Hg. Converting this to the English 

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

above,

(Kalkali • B • SSO3) = lbs H2

SO4 per yr = 

B TBtu SSO3 scf SO3 98 lbs H2SO4 14925 scf flue gas 

year 106 scf flue gas 1 lb mol H2SO4 1 MBtu 

Grouping terms, 

= B • SSO3 • 1.46 

Therefore, the value of Kalkali is equal to 1.46 lbs H2SO4/(TBtu • ppmv SO3 @ 6% O2 and wet). 

If the value of SO3

 is known in wet flue gas at an O2 content other than 6%, or an H2O content other than 8.1%, 

first convert the SO3

 concentration to a 6% O2, 8.1% H2O wet flue gas basis. The conversion of SO3 at any flue 

gas O2

 content to the value at 6% O2 and 8.1% H2O wet basis uses the following formula: 

SO3

 (6% O2, 8.1% H2O) 

= SSO3 (measured O2

, H2O) • [(100-8.1)/(100-measured H2O)] • [(20.9 – 6.0)/(20.9 – measured O2)] 

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 

e. FGC manufacture 

f. FGC release 
5-2 

3. Used oil 

a. Combustion manufacture 

b. Combustion release 

c. SCR manufacture 

d. SCR release 

e. FGC manufacture 

f. FGC release 

4. Sum manufacture and releases 

a. Manufacture 

= 1a + 1c + 1e + 2a + 2c + 2e + 3a + 3c + 3e 

b. Release 

= 1b + 1d + 1f + 2b + 2d + 2f + 3b + 3d + 3f 

All of the manufactured results would be summed together and the releases summed also to give 

the final result. Example 5 in Appendix A details this calculation procedure. 
6-1 

6

ESTIMATING GUIDELINE: COMBUSTION TURBINES 

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

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

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

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

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

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

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

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

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

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

ppm of sulfur in the raw natural gas. 

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

combined cycle units is provided below. 

Simple Cycle Units 

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

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

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

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

manufacture SO3, the exit gas temperature is too high to allow condensation of SO3 or reaction 

with ammonia slip. Selective non-catalytic reduction (SNCR) is not applied to simple cycle or 

combined cycle combustion turbines; therefore, no estimation procedure is provided for that 

configuration. 

Accordingly, the equations for formation of sulfuric acid from natural gas combustion are: 

Equation 6-1 EMSC = K • F1 • E2NG 

where, 

EMSC = total H2

SO4 manufactured from combustion, lbs/yr 

K = Molecular weight and units conversion 

constant = 98.07 / 64.04 • 2000 = 3,063 

 98.07 = Molecular weight of H2SO4 

 64.04 = Molecular weight of SO2

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

F1 = Fuel Impact Factor for NG 
6-2 

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. 

Equation 6-2a E2NG = Kb • BNG • S

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 F. 

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

Equation 6-2b E2NG = KNG • N1 • S 

where, 

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

KNG = Molecular weight and units conversion constant = 1.427 • 10-7

N1 = NG burn in million standard cubic feet (Mscf) per year 

S = NG sulfur content in grains per million standard cubic feet, use EPA’s value 

of 2000 gr/106

 scf as default 

The derivation of constant KNG is presented in Text Box G 

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

Kb is determined from the following equation. 

(Kb • BNG • S) = tons SO2

 per yr = 

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 

F1 – Fuel Factors for a Simple CT 

Stack T, °F F1 

300 0.055 

400 0.055 

500 0.047 

600 0.022 

700 0.0055 

750 0.0027 

800 0.0013 

850 0.00071 

900 0.00039 

950 0.00022 

1000 0.00013 

1050 0.00008 

1100 0.00005 

1150 0.00003 

1200 0.00002 

Text Box G: Derivation of Molecular Weight and Units Conversion Constant, 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 the case of combined cycle units, the manufacture of sulfuric acid is due to both combustion 

and SCR NOx control. The manufacture due to combustion is estimated using an equation 

similar to Equation 4-11a, but accounting for only combustion and SCR sources. 

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

Equation 6-3. 

Equation 6-3 EMCC = K • F1 • E2NG 

where, 

EMCC= total H2SO4 released from combustion, lbs/yr 

K = Molecular weight and units conversion constant = 98.07/64.04 • 2000 = 3,063 

 98.07 = Molecular weight of H2SO4; 

 64.04 = Molecular weight of SO2; 

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

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

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

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

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

cycle combustion turbines, the SCR catalyst SO2 oxidation rate 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. 

Sulfuric Acid Released 

The total release of sulfuric acid from combined cycle units is described by Equation 6-4, 

summing the sulfuric acid released by both combustion and SCR: 

Equation 6-4 TSAR = ERCCcom + ERCCSCR

The sulfuric acid released by combustion in combined cycle units is estimated using an equation 

analogous to that for simple cycle units. 

Equation 6-5 ERCCcom = EMCCcom • F2CC

The Technology Impact Factor for combined cycle units, F2CC, accounts for removal in the heat 

exchanger. At present a value of 0.5 is assigned to this factor. 

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

is estimated using a relationship similar to Equation 4-5, as follows: 
6-5 

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

where, 

ERCCSCR = Total H2

SO4 released from SCR, lbs per year 

EMCCSCR = Total H2

SO4 manufactured from SCR, lbs per year 

Ks = Conversion factor = 3799 

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. 

Example 7 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, 2006 Federal Register, August 22, 2006. 40 CFR Parts 72 and 75, Revisions to 

the Continuous Emissions Monitoring Rule for the Acid Rain Program 

and the NOx 

Budget Trading Program, [OAR-2005-0132]. 

EPRI, 2001 EPRI Report 1004027, “Flue Gas Sulfuric Acid Measurement 

Improvements,” August, 2001. 

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,” 

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, 
7-3 

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 

 EMComb = 3063 • 0.008 • 42,824 = 1,049,359 lbs H2SO4/yr 

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

the result reported on Form R. 

Released 

 ERcomb = K • F1 • F2 • E2 

 ERcomb = 3063 • 0.008 • (0.49 • 0.49) • 42,824 = 259,951 lbs H2SO4/yr 

 Where F2 = Air Heater • Cold-Side ESP 

 F2 = 0.49 • 0.49 = 0.24 

Example 2: SCR Added to Example 1 

A 500 MW PC boiler, equipped with a cold-side 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. 
A-2

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 

 EMcomb = 3063 • 0.008 • 42,824 = 1,049,359 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 = 1,049,359 + 423,023 lbs H2SO4/yr 

 TSAM = 1,472,382 lbs H2SO4/yr 

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

the result reported on Form R. 

Released 

 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.008 • (0.49 • 0.49) • 42,824 = 251,951 lbs H2SO4/yr 

 Where F2 = Air Heater • Cold-Side ESP 

 F2 = 0.49 • 0.49 = 0.24 

 SCR

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

 B = 27.05 TBtu/yr 

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

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

 ERSCR = 93,611 lbs H2SO4/yr 

 Total
A-3

 TSAR = E1’comb + E1’SCR

 TSAR = 251,951 + 93,611 lbs H2SO4/yr 

 TSAR = 345,562 lbs H2SO4/yr 

Example 3: Alkali Injection Added to Example 1 

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

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

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

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

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

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

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

that no more than 5 ppm of SO3 at the stated conditions of excess O2 and moisture exist in the 

stack. 

The coal burn rate in the reporting year is 1,126,938 tons, with a weighted average sulfur 

concentration of 2.0%, and a heating value of 12,000 Btu/lb. 

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

Solution 

Manufactured 

 E2 = K1 • K2 • C1 • S1 

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

 Combustion

 EMcomb = K • F1 • E2 

 EMcomb = 3063 • 0.008 • 42,824 = 1,049,359 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 = 1,049,359 + 423,023 lbs H2SO4/yr 

 TSAM = 1,472,382 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-4

Released 

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

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

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

described by Equation 4-12 

 ERALKINJ = Kalkali • B • SSO3 • Falkali • F2x

where, 

ERALKINJ = Total H2

SO4 released from unit equipped with alkali injection, lbs per year 

Kalkali = Constant, equal to 1.46, 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 1.46 (see Text Box E). 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. 

The SO3 concentration of 5 ppm in the stack is measured at slightly different conditions of excess 

O2 and moisture, compared to the reference conditions of 5% O2, at 8.1% H2O. 

SSO3 (6% O2, 8.1% H2O) = SSO3 (measured O2, H2O) • [(100-8.1)/(100-measured 

H2O)] • [(20.9 – 6.0)/(20.9 – measured O2)] 

SSO3 (6% O2, 8.1% H2O) = 5 • [1.0077)• [1.034] 

SSO3 (6% O2, 8.1% H2O) = 5.2 ppm 

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

 ERALKINJ = [1.46] • [27.05] •[5.2] • [1] • [1] 

 ERALKINJ = 205.9 lbs/yr 

 TSAR = ERALKINJ TSAR = 205.9 lbs/yr 
A-5

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 • 0.0018 • 9,692 = 53,435 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 = 53,435 + 43,402 lbs H2SO4/yr 

 TSAM = 96,837 lbs H2SO4/yr 

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

the result reported on Form R. 

Released 

 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.008 • (0.56 • 0.73) • 9,692 = 97,087 lbs H2SO4/yr 

 Where F2 = Air Heater • Cold-Side ESP 

 F2 = 0.56 • 0.73 = 0.41 
A-6

 SCR

 B = 47,118 tons/yr • 2000 lbs/ton • 8,500 Btu/lb • 1 TBtu/1012 Btu 

 B = 0.80 TBtu/yr 

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

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

 ERSCR = 17,342 lbs H2SO4/yr 

 Total

 TSAR = E1’comb + E1’SCR

 TSAR = 97,087 + 17,342 lbs H2SO4/yr 

 TSAR = 114,429 lbs H2SO4/yr 

Example 5: FGC Added to Example 1 

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

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

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

the ammonia at 3 ppmv also at 6% O2 wet. The FGC system operates whenever the plant is on, 

except during startup and shutdown, with an operating factor estimated at 0.9. The coal used in 

the reporting year is 1,126,938 tons with a weighted average sulfur concentration of 2.0% and a 

heating value of 12,000 Btu/lb. 

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 

 EMComb = 3063 • 0.008 • 42,824 = 1,049,359 lbs H2

SO4/yr 

 FGC

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

 B = 27.05 TBtu/yr 

 EMFGC = Ke • B • fe • Is

 EMFGC = 3799 • 27.05 • 0.9 • 7 = 647,407 lbs H2

SO4/yr 
A-7

 Total

 TSAM = EMComb + EMFGC

 TSAM = 1,049,359 + 647,407 lbs H2SO4/yr 

 TSAM = 1,696,766 lbs H2SO4/yr 

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

the result reported on Form R. 

Released 

 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.008 • (0.49 • 0.49) • 42,824 = 251,951 lbs H2SO4/yr 

 Where F2 = Air Heater • Cold-Side ESP 

 F2 = 0.49 • 0.49 = 0.24 

 FGC

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

 B = 27.05 TBtu/yr 

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

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

 ERFGC = 92,487 lbs H2SO4/yr 

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

 Total

 ESAR = ERComb + ERFGC

 ESAR = 251,951 + 92,487 lbs H2SO4/yr 

 ESAR = 344,438 lbs H2SO4/yr 

Example 6: SCR and FGC Added to Example 1 

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

bituminous coal. The plant is equipped with an SCR process that operates during the ozone 

season only, so that 0.43 of the coal burn occurred with the SCR operating. The SCR catalyst 

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

ppmv. The plant is also equipped with a FGC process that injects both SO3 and NH3, with the 

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

ammonia at 3 ppmv also at 6% O2 wet. The FGC system operates whenever the plant is on, 
A-8

except during startup and shutdown, with an operating factor estimated at 0.9. The coal used in 

the reporting year is 1,126,938 tons with a weighted average sulfur concentration of 2.0% and a 

heating value of 12,000 Btu/lb. 

Solution 

From previous examples: 

Manufactured 

 Total 

 TSAM = EMComb + EMSCR + EMFGC

 TSAM= 1,049,359 + 423,023 + 647,407 lbs H2SO4/yr 

 TSAM = 2,119,789 lbs H2SO4/yr 

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

the result reported on Form R. 

Released 

 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.008 • (0.49 • 0.49) • 42,824 = 251,951 lbs H2SO4

/yr 

 SCR

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

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

 ERSCR = 93,611 lbs H2SO4/yr 

 FGC

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

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

 ERFGC = 92,487 lbs H2SO4/yr 

 Total

 TSAR = ERComb + ERSCR + ERFGC

 TSAR = 251,951 + 93,611 + 92,487 lbs H2SO4/yr 

 TSAR = 438,049 lbs H2SO4/yr 
A-9

Example 7: Coal-Fired Boiler with FGC, NG Startup Fuel, and Used Oil Co-Firing 

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

bituminous coal as the main fuel. The plant is equipped with an SCR process that operates during 

the ozone season only, so that 0.43 of the coal burn occurred with the SCR operating. The 

ammonia slip is estimated to be 0.75 ppmv. The plant is also equipped with a FGC process that 

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

at 7 ppmv at 6% O2 wet, and the ammonia at 3 ppmv also at 6% O2 wet. The FGC system 

operates whenever the plant is on, except during startup and shutdown, with an operating factor 

estimated at 0.9. The coal used in the reporting year is 1,126,938 tons with a weighted average 

sulfur concentration of 2.0% and a heating value of 12,000 Btu/lb. Natural gas is used as a 

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

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

burned when the unit is at full load, it is burned while the SCR and FGC are both operating. The 

used oil has a sulfur content of 0.1% from analysis. 

Solution

 Coal fuel calculations

Manufactured from coal, from previous examples 

 Total

 TSAM = EMComb + EMSCR + EMFGC

 TSAM = 1,049,359 + 423,023 + 647,407 lbs H2SO4/yr 

 TSAM = 2,119,789 lbs H2SO4/yr 

Released from coal, from previous examples 

 Total

 TSAR = ERComb + ERSCR + ERFGC

 TSAR = 251,951 + 93,611 + 92,487 lbs H2SO4/yr 

 TSAR = 438,049 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 
A-10

 EMComb = 4.16 lbs H2SO4 manufactured 

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

Released from natural gas 

 Combustion

 ERComb = K • F1 • F2 • E2NG 

 ERComb = 3063 • 0.01• 0.49 • 0.49 • 0.136 

 ERComb = 1.00 lbs H2SO4 released 

F2 is taken to be equal to 0.49 for the air heater and 0.49 for the ESP. 

 Used oil fuel calculations

Manufactured from used oil 

 Combustion

 E2 = K1 • K2 • C1 • S1 

 E2 = 0.02 • 1.0 • 483.2 • 0.1 

 E2 = 0.966 tons SO2/year 

 EMComb = K • F1 • E2 

 EMComb = 3063 • 0.0175 • 0.966 

 EMComb = 51.8 lbs H2SO4 manufactured 

 SCR

 EMSCR = K • S2 • fs • E2 

 EMSCR = 3063 • 0.0075 • 1.0 • 0.966 

 EMSCR = 22.2 lbs H2SO4 manufactured 

 FGC

 EMFGC = Ke • B • fe • Is

 EMFGC = 3799 • 0.0185 • 1.0 • 7.0 

 EMFGC = 492 lbs H2

SO4 manufactured 

 Total

 TSAM = EMComb + EMSCR + EMFGC

 TSAM = 51.8 + 22.2 + 492 lbs H2SO4/yr 
A-11

 TSAM = 566 lbs H2SO4/yr 

Released from used oil 

 Combustion

 ERComb = K • F1 • F2 • E2 

 ERComb = 3063 • 0.0175 • 0.49 • 0.49 • 0.966 

 ERComb = 12.43 lbs H2SO4 released 

SCR

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

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

 ERSCR = -7.33 lbs H2SO4/yr 

 F2 is taken to be equal to 0.49 for the air heater and 0.49 for the ESP. 

 FGC

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

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

 ERFGC = 70.3 lbs H2SO4/yr 

 Total

 TSAR = ERComb + ERSCR + ERFGC

 TSAR = 12.43 – 7.33 + 70.3 lbs H2SO4/yr 

 TSAR= 75.4 lbs H2SO4/yr 

Grand totals for all fuels

Manufactured 

 TSAM = TSAMcoal + TSAMNG + TSAMoil

 TSAM = 2,119,789 + 4.16 + 566 lbs H2SO4/yr 

 TSAM = 2,120,359 lbs H2SO4/yr 

Released 

 TSAR = TSARcoal + TSARNG + TSARoil

 TSAR = 438,049 + 1.00 + 75.4 lbs H2

SO4/yr 

 TSAR = 438,125 lbs H2SO4/yr 
A-12

Example 8: Natural Gas Combined Cycle Plant 

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

content. 

Solution 

 Manufactured 

 E2NG = Kb • BNG • S = 0.0001359 • 12.3 • 2000 = 3.343 tons SO2/yr 

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

Released 

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

(F2 = 0.5 because of the low temperature of the back-end tubes of the HRSG, like an air 

heater.) 
B-1

B

CHRONOLOGY OF CHANGES TO EPRI SULFURIC 

ACID ESTIMATION MODEL 

EPRI, 2008 (EPRI Report 1016384) 

Modification Description 

Alkali Injection Added a procedure to estimate a stack release using a measured or 

specified stack gas SO3 concentration, to support estimates on 

units with alkali injection. 

Combustion Turbines Clarified procedures for estimating emissions from simple and 

combined cycle CTs. 

Blended Coals New method calculates SO3 manufacture by calculating the SO3

emission rate separately for each of the component coals, and 

proportioning the contribution of SO3

 from each. The prior 

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

major coal component. 

Examples Provided new example calculations for alkali injection and 

blended coal. 

EPRI, 2007 (Report 1014773) changes from Harrison, 2005. 

Modification Description 

Formatting Adapted Southern Company paper (Harrison, 2005) to EPRI 

format. 

Fuel (F1) Factors Changed the following F1 factors based on additional data: 

Low S E. Bit, Dry Boiler – from 0.0080 to 0.0082 

Subbit. (including PRB), Dry Boiler – from 0.0014 to 0.0018 

 Subbit. (including PRB), Cyclone – from 0.003 to 0.0018 

Technology (F2) Factors Added new F2 Factors: 

 Air Preheater, PRB fuel - 0.56 

 Cold-side ESP, PRB fuel – 0.73 

SCR Added a Technology Impact Factor for SCR, F3SCR


Electric Power Research Institute • 3412 Hillview Avenue, Palo Alto, California 94304 • PO Box 10412, Palo Alto, California 94303 • USA 

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

Export Control Restrictions 

Access to and use of EPRI Intellectual Property is 

granted with the specific understanding and 

requirement that responsibility for ensuring full 

compliance with all applicable U.S. and foreign export 

laws and regulations is being undertaken by you and 

your company. This includes an obligation to ensure 

that any individual receiving access hereunder who is 

not a U.S. citizen or permanent U.S. resident is 

permitted access under applicable U.S. and foreign 

export laws and regulations. In the event you are 

uncertain whether you or your company may lawfully 

obtain access to this EPRI Intellectual Property, you 

acknowledge that it is your obligation to consult with 

your company’s legal counsel to determine whether 

this access is lawful. Although EPRI may make 

available on a case-by-case basis an informal 

assessment of the applicable U.S. export classification 

for specific EPRI Intellectual Property, you and your 

company acknowledge that this assessment is solely 

for informational purposes and not for reliance 

purposes. You and your company acknowledge that it 

is still the obligation of you and your company to make 

your own assessment of the applicable U.S. export 

classification and ensure compliance accordingly. You 

and your company understand and acknowledge your 

obligations to make a prompt report to EPRI and the 

appropriate authorities regarding any access to or use 

of EPRI Intellectual Property hereunder that may be in 

violation of applicable U.S. or foreign export laws or 

regulations. 

The Electric Power Research Institute (EPRI) 

The Electric Power Research Institute (EPRI), with 

major locations in Palo Alto, California, and Charlotte, 

North Carolina, was established in 1973 as an 

independent, nonprofit center for public interest energy 

and environmental research. EPRI brings together 

members, participants, the Institute’s scientists and 

engineers, and other leading experts to work 

collaboratively on solutions to the challenges of electric 

power. These solutions span nearly every area of 

electricity generation, delivery, and use, including 

health, safety, and environment. EPRI’s members 

represent over 90% of the electricity generated in the 

United States. International participation represents 

nearly 15% of EPRI’s total research, development, and 

demonstration program. 

Together...Shaping the Future of Electricity 

© 2008 Electric Power Research Institute (EPRI), Inc. All rights 

reserved. Electric Power Research Institute and EPRI are registered 

service marks of the Electric Power Research Institute, Inc. 

 Printed on recycled paper in the United States of America 1016384