## Estimating Total Sulfuric Acid Emissions from Stationary Power Plants

1023790EPRI Project Manager

N. Goodman

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## Estimating Total Sulfuric Acid Emissions from Stationary Power Plants

1023790

T echnical Update

, March 201 2DISCLAIMER OF WARRAN TIES AND LIMITATION OF LIABILITIES

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manne r:

Estimating Total Sulfuric Acid Emissions from Stationary Power Plants

. EPRI , Palo Alto, CA:

2012

. 1023790.

iii 

## ACKNOWLEDGMENTS

The following organization

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

, prepared this report :

Fossil Energy Research Corporation
23342C South Pointe Laguna Hills , Ca 92653

Principal Investigator J. Muncy

This report describes research sponsored by EPRI.

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

.v 

## PRODUCT DESCRIPTION

This report provides a methodology to estimate sulfuric acid emissions from fossil

- fuel

- fired
electrical power production facilities. The methodology was developed by Southern Company Services (SCS) and modified by EPRI with permission from the developers. The calculations presented in this report allow owners of power plants to estimate the sulfuric acid man ufactured 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 g enerating 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.

Chal lenges 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

es timate 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 sul furic acid removal factors for various coal types and facility configurations.

Keywords

Sulfuric acid Toxics Release Inventory
Air emissionsvii 

## EXECUTIVE SUMMARY

The U. S. Environmental Protection Agency’s (EPA’s) Toxics Release Inventory (TRI) program requires electric utilities to estimate and report annual emissions of 682 chemicals and chemical categories. Sulfuric acid (H 2 SO 4 ) is one of the chemicals included in the TRI reporting requirement, when it is present in an aerosol form. The EPA defines sulfuric acid aerosols as “includ[ing] mists, vapors, gas, fog, and other airborne forms of any particle size.” Sulfuric acid aerosol is formed during combustion of fossil fuels when sulfur trioxide (SO 3 ) in hot combustion gases combines with water to form sulfuric acid, and then cools and condenses to form small droplets of the acid.

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

- fired electrical power production facilities. The methodology described in this report was developed originally by Southern Company Services (SCS). The SCS model was widely used in the electrical power generation industry for TRI reporting and other emissions estimation purposes. In 2007, EPRI received permission from Souther n Company Services to modify the SCS model to include additional data and improvements, and to publish this method under EPRI sponsorship. EPRI has continued to maintain and improve the methodology, and publishes updates on an as

- needed basis. The current report provides clarifications and minor corrections to the previous (2010) version, adds several new technology factors, and incorporates additional sulfuric acid removal measurements. A chronology of changes to the EPRI/SCS model since 2007 is provided i n an appendix to this report.

The method for estimating sulfuric acid emissions considers manufacture of SO 3 and sulfuric acid from three sources: (1) combustion of fuel, (2) the NOx control process selective catalytic reduction (SCR), and (3) flue gas con ditioning (FGC), in which SO 3 is added to flue gas to improve particulate control device performance. These sources are then summed and ammonia slip from SCR, selective noncatalytic reduction ( SNCR )

, or FGC is subtracted from the total SO 3 to account for a mmonium bisulfate ( ABS ) formation

, which is not reportable. Removal through control devices is then accounted for through the use of Technology Factors (F2) which describe

SO 3 removals across downstream devices such as the air preheater ( APH )

, electrostati c precipitator ( ESP ) , baghouse or other particulate control devices. In previous versions of this model, these sources were treated independently and each source was adjusted to account for removal processes; however, this approach sometimes produced negat ive SO 3 releases for the
individual SO 3 sources, due to reactions with ammonia slip from SCR/SNCR that were estimated

to remove more SO 3 than was manufactured. Therefore, the current method first sums the sources and then applies the removal processes in a manner that is more consistent with the actual flue gas flow through the plants ’ control devices. This version of the report changes the approach to estimating releases when FGC is employed. It also introduces new guidelines for

SO 3 mitigation from sorben t injection, a combined cycle carbon monoxide (CO) catalyst oxidation factor, and a wet ESP technology impact factor.

The SCS/EPRI estimation method is an empirical model, i.e., emissions are predicted from
sulfuric acid measurements at full

- scale power p lants. Data are obtained from field tests that measured production of SO 3 from fuel sulfur in various types of combustion equipment, as well
as the removal of SO 3 or H 2 SO 4 from the flue gas stream by air heaters, particulate control
devices such as electro static precipitators (ESPs) and fabric filters, and sulfur dioxide control equipment. The removal data are used to develop “technology factors” that represent the amountviii of sulfuric acid that passes through and is not captured by each pollution control dev ice. The technology factors are used to estimate the amount of sulfuric acid aerosol released to the air.

The 2012 database of measurements of SO 3 emissions from combustion systems includes data from 64 sources, an increase of 14 from the previous version . As mentioned, data are obtained from field tests, and new sources are defined as a new series of test data from a plant during a defined time period. The new data were used to improve estimates for changes in sulfuric acid
emissions due to SO 3 mitigation , CO catalyst oxidation and use of a wet ESP.

As with all estimation procedures, the methodology described in this report and the factors developed from the available data will not be applicable to every facility configuration or fuel type. Site

- specific measurements of SO 3 or H 2 SO 4 emissions from a power facility, if available, should generally be used in place of the estimates derived with this method.ix 

## CONTENTS

**1** INTRODUCTION

................................ ................................ ................................ .................. 1

- 1
Background

................................ ................................ ................................ ........................ 1

- 1
Objective

................................ ................................ ................................ ............................ 1

- 2
Report Organization

................................ ................................ ................................ ........... 1

- 2

**2** MEASUREMENT UNCERTAI NTY

................................ ................................ ........................ 2

- 1
CCS Measurement Uncertainty

................................ ................................ .......................... 2

- 1
Representativeness

................................ ................................ ................................ ............ 2

- 2

**3** BACKGROUND AND METHO DOLOGY OVERVIEW

................................ .......................... 3

- 1
Description of General Methodology

................................ ................................ .................. 3

- 1

Sulfuric Acid Manufacture from Combustion

................................ ................................ . 3

- 2

SCR/SNCR NOx Control

................................ ................................ .............................. 3

- 3
Flue Gas Conditioning

................................ ................................ ................................ .. 3

- 4
Methodology to Estimate Release

................................ ................................ ...................... 3

- 4

SCR/SNCR NOx Control

................................ ................................ .............................. 3

- 5
Flue Gas Conditioning

................................ ................................ ................................ .. 3

- 7
Estimating Release with Alkali Injection

................................ ................................ ........ 3

- 8

**4** ESTIMATING GUIDELINE : STEAM BOILERS

................................ ................................ .... 4

- 1

Sulfuric Acid Manufacture

................................ ................................ ................................ ... 4

- 1
Sulfuric Acid Manufactured by Combustion (EM Comb )

................................ .................... 4

- 1
Sulfuric Acid Manufactured from SCR (EM SCR )

................................ ............................. 4

- 7
Sulfuric Acid Manufactured from FGC (EM FGC )

................................ ............................. 4

- 8

Total Manufacture from All Sources

................................ ................................ ............ 4

- 11

Sulfuric Acid Release

................................ ................................ ................................ ....... 4

- 11
Ammonia Slip from SCR and SNCR (NH3 SCR )

................................ ............................ 4

- 12
Ammonia Injection from FGC (NH3 FGC )

................................ ................................ ....... 4

- 14

Total Release Calculati on for Sources Employing Alkali Injection

............................... 4

- 14
Technology Impact Factors (F2)

................................ ................................ ....................... 4

- 16

Air Heater

................................ ................................ ................................ ................... 4

- 16

Particulate and SO 3 Control Processes

................................ ................................ ...... 4

- 19

FGD

................................ ................................ ................................ ........................... 4

- 21

**5** ESTIMATING GUIDELINE : MULTIPLE FUEL OR B LENDED FUEL BOILERS

.................. 5

- 1

**6** ESTIMATING GUIDELINE : COMBUSTION TURBINE S

................................ ...................... 6

- 1
Manufacture and Release for Simple Cycle Units

................................ ............................... 6

- 1
Combined Cycle Units

................................ ................................ ................................ ........ 6

- 4

Sulfuric Acid Manufactured

................................ ................................ ........................... 6

- 4

**7** REFERENCES

................................ ................................ ................................ ..................... 7

- 1

**A** EXAMPLE CALCULATIONS

................................ ................................ .............................. A

- 1x Example 1: Conventional Coal

- Fired Boiler with an ESP

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

Solution

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

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

Solution

....................................................................................................................... A- 2
Example 3: Alkali Injection Added to Example 1

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

Solution

....................................................................................................................... A-4
Example 4: 500 MW PRB

- fired Boiler with ESP, SCR

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

Solution

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

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

Solution

....................................................................................................................... A-8
Example 6: SCR and FGC Added to Example 1

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

Solution

..................................................................................................................... A- 10
Example 7: SCR and Downstream FGC Added to Example 1

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

Solution

..................................................................................................................... A- 11
Example 8: Coal

- Fired Boiler with FGC, NG Startup Fuel, and Used Oil Co

- Firing

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

Solution

..................................................................................................................... A- 12
Example 9: Natural Gas Combined Cycle Plant

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

Solution

..................................................................................................................... A- 15
Example 10: SCR and CO catalyst added to Example 9

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

Solution

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

**B** CHRONOLOGY OF CHANGES TO EPRI SULFURIC ACID ESTIMATION MODE L

.......... B-1xi 

## LIST OF FIGURES

Figure 3

- 1 Schematic of Methodology Used to Estimate Sulfuric Acid Releases

..................... 3

- 6 Figure 4

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

................................ ................................ ................................ ................................ .......... 4

- 4 Figure 4

- 2 Removal of Sulfuric Acid by Ljungstrom

- Type Air Heaters

................................ ... 4

- 18 Figure 4

- 3 Removal of Sulfuric Acid by Cold

- Side ESPs and One Hot

- Side ESP

.................. 4

- 20 Figure 4

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

................................ ................................ ................................ ...................... 4

- 22xiii 

## LIST OF TABLES

Table 4

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

......................... 4

- 6

Table 4

- 2 F3 SCR Technology Impact Factors for SCR

................................ .............................. 4

- 8

Table 4

- 3 Summary of F2 Factors for Air Hea ter Removal of Sulfuric Acid

........................... 4

- 18

Table 4

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

............ 4

- 20

Table 4

- 5 Summary of F2 Factors for Wet and Dry FGD Equipment and Additives

............... 4

- 22
Table 6

- 1 Fuel Impact (F1) Factors for a Simple CT

................................ ............................... 6

- 31

- 1 

# 1

INTRODUCTION

Background

Esti mation of sulfuric acid emissions from power plants is a topic of increasing importance to the U.S. electric utility industry. Most significantly, Section 313 of the Emergency Planning and Community Right

- to

- Know Act (EPCRA), also known as the Toxics Relea se Inventory (TRI), requires facilities that “manufacture,” “process,” or “otherwise use” a listed chemical above certain threshold amounts to report their annual releases of the chemical to EPA and state agencies. For sulfuric acid, the TRI reporting requ irements are triggered if a facility “manufactures” or “processes” more than 25,000 pounds of this chemical or “otherwise uses” more than 10,000 pounds of it in a given calendar year.

In June 1995, the U. S. Environmental Protection Agency (EPA) modified the list of chemicals subject to the EPCRA § 313 reporting requirements so that only aerosol forms of sulfuric acid would be subject to the TRI reporting requirements (EPA, 1995a). EPA defines sulfuric acid aerosols as “includ[ing] mists, vapors, gas, fog, and other airborne forms of any particle size.” Although initially it appeared that only liquid droplets of sulfuric acid needed to be reported, the present method estimates the sulfuric acid emissions regardless of the physical state of the
molecules.

B eginning on July 1, 1999, certain coal

- and oil

- fired electric power plants have been required to report annual releases of TRI chemicals that they manufacture, process or otherwise use above threshold amounts. Under EPA’s EPCRA § 313 regulations, coal

- an d oil

- fired electric utilities are deemed to “manufacture” sulfuric acid. Thus, electric utilities have to submit TRI reports on sulfuric acid aerosol releases if they “manufacture” more than 25,000 pounds of the chemical in a given reporting year (EPA, 19 97).

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 (SO 3 ), th e precursor of sulfuric acid. Several notable incidents have been witnessed where an increase in sulfuric acid emissions, as manifested by an increase in stack plume visibility, was attributed to the addition of SCR process equipment to an existing power p lant. The deployment of approximately 115 GW of selective catalytic reduction (SCR) from 1997 through 2009 has prompted power plant owners to conduct extensive measurements documenting the fate of SO 3 and sulfuric acid in power plants.

The methodology des cribed 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, a nd Harrison, 2005 ) . The SCS model was widely used in the electrical power generation industry for TRI reporting and other emissions estimation purposes. In 2007, EPRI received permission from Southern Company Services to modify the SCS estimation method to include additional data and improvements, and to publish this method under EPRI sponsorship. The 2008 version of the model added the ability to estimate emissions based on a specified sulfuric acid1-2 flue gas concentration at the stack, which can be used wh en alkali injection is employed to reduce sulfuric acid emissions. The 2010 version updated several of the “technology factors” (F2 factors, used to reflect the impact of pollution control devices) with new SO 3 measurements.

The current version of the model makes minor changes to the calculation procedure to more accurately represent flow through from the boiler and control devices. This version also changes the approach used to account for sulfuric acid from flue gas conditioning (FGC). Finally, the revision makes several corrections and clarifications to technology factors, introduces a new technology factor for units with a wet electrostatic precipitator (ESP), and adds a new sulfuric acid source: oxidation of sulfur dioxide across a carbon monoxide catalyst in combined cycle
units.

Objective

The objective of this report is to present a methodology for estimating sulfuric acid emissions from power generating facilities, for use in Toxics Release Inventory reporting and other applications. The scope of units considered includes c oal - and oil-fired steam generating units, as well as simple cycle and combined cycle natural gas - and oil-fired combustion turbines. To date,
the most authoritative and documented data describe sulfuric acid emissions from coal- fired steam generators. The focus on this category of units is due to the increased availability of measurements describing the fate of sulfuric acid attributable to the retrofit of SCR process equipment on coal- fired steam generators.

Report Organization

Section 2 of this report addresses the uncertainty in measuring SO 3 concentration using the preferred controlled condensation system (CCS) method, and the accuracy and representativeness of the available data. Section 3 outlines the general methodology adopted in
this model while S ection 4 describes the details of the methodology, focusing on data that can be used to predict sulfuric acid manufacture by combustion. This section also summarizes data describing the removal of sulfuric acid across air heaters, ESPs, and wet flue gas desulfurization (FGD) process equipment. Section 5 outlines how to conduct the calculation for steam boilers firing a mixture of fuels. Section 6 addresses simple cycle and combined cycle combustion turbine applications. Example calculations for various power plant configurations are presented in Appendix A. A chronology of changes to the sulfuric acid model is presented in Appendix B.2

- 1 

# 2

MEASUREMENT UNCERTAI NTY

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 measur ements from many electric generating units (EGUs) is desired to obtain a robust predictive method. Both the size and the representativeness of the measurement database are critical to the accuracy of a predictive
method.

The predictive correlations presen ted in this report are based on data obtained from field tests conducted predominantly within the last 10 years, with some estimates conducted in the 1990s. The quality of the data is thought to vary widely. It was not possible to obtain quality control

in formation for all of the available measurements; thus, it was not possible to critically review all
data used in this model.

The technique used to measure SO 3 /H 2 SO 4 is not known for all data sources, but most measurements were conducted using the controlle d condensate system (CCS), a widely used technique that is generally considered the most accurate method for measuring SO 3 /H 2 SO 4 in stack gases from stationary combustion sources. EPA Method 8 is sometimes used for this purpose, but that method has a known positive bias from oxidation of SO 2 to SO 3 in the impinger
solution.

CCS Measurement Uncertainty

A series of field and laboratory trials conducted by EPRI evaluated the measurement bias of the CCS technique by comparing results from both laboratory tests and field trials (EPRI, 2001).

SO 3 /H 2 SO 4 measurements at similar gas compositions were compared in a 1) clean, ash

- free laboratory environment; 2) simulated ash 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

SO 3 /H 2 SO 4 than measured in the ash

- free laboratory environment), due to reactions of SO 3 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 cont rol device produces unbiased measurements, as long as appropriate procedures are followed.

The extent of bias observed in the EPRI study depended on the sampling location, which could be the air heater inlet, air heater outlet, or flue gas desulfurization outlet. Furthermore, the bias depended on the quantity of ash collected, the alkalinity of the ash, and the coal sulfur content (e.g., SO 2 content in the sample gas). Measurement bias in the simulated ash environment was observed for both high sulfur coal and low sulfur Powder River Basin (PRB) coal; however biasing in the PRB coal tests can generally be considered non

- significant in light of already low

SO 3 concentrations and the expected absorption of sulfuric acid with the alkaline ash in actual
field t ests. Data for high sulfur coal suggested a low bias of 20

- 25% could occur in measurement locations upstream of a particulate control device with typical ash loadings, and no significant bias downstream of the particulate control device.2

- 2 The precision of the CCS data used in this estimation model can be estimated from the variability among duplicate measurements believed to be conducted under the same process conditions. Data from recent field trials with experienced test crews suggest a precision of up to ± 20% is realistic for most conditions. The repeatability of the CCS measurements depends on avoiding stratification within the gas stream (traversing is very difficult), maintaining correct temperatures in the sampling train, and having well trained samp ling personnel. Therefore, the precision of the entire data set used in this model, which includes data from older studies of unknown quality, is expected to be closer to ± 50%.

Representativeness

The accuracy of the correlations presented in this report d epends on the representativeness of the constituent data points. For some power plant configurations, only a few measurements are available, and the correlations provide only rough approximations of the flue gas SO 3 /H 2 SO 4 releases for similar units . The ca tegory with the largest number of data points is dry

- bottom boilers, firing low sulfur, eastern bituminous coal. In general, the number of SO 3 measurements for various power plant configurations are proportional to the occurrence of those configurations

am ong the total population of U.S. EGUs. The number of measurements in each power plant category should be considered when applying this model; factors based on one measurement have much higher uncertainty than factors based on dozens of measurements.

As a c onsequence of the uncertainty in SO 3 /H 2 SO 4 measurements and the limited number of data points that comprise the relevant correlations, the predictive technique should be assumed to provide estimates within a ± 50% relative accuracy.3

- 1 

# 3

BACKGROUND AND METHO DOLOGY OVERVIEW

This section provides a brief overview of sulfuric acid production mechanisms in power plants and presents the basic equations for estimating sulfuric acid releases. A detailed review of this topic has been provided by S rivastava (2004) and more recently by Monroe (2006).

The production or manufacture of SO 3 , and ultimately sulfuric acid, is determined initially by processes occurring directly within the flame zone of a boiler, the convective heat transfer sections, or en vironmental 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 remov al mechanisms, including alkali

- based sorbent injection, occurring at lower temperatures.

Description of General Methodology

The method estimates the manufacture and the subsequent release of sulfuric acid from the power generation process. The manufactur e 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

acc ount 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 f lue gas conditioning. All remaining steps in the power generation process reduce sulfuric acid. Therefore, the total sulfuric acid released is the cumulative sum of that manufactured, adjusted by sulfuric acid losses.

The Total Sulfuric Acid M anufacture ( TSAM) of SO 3 , the precursor to sulfuric acid, is calculated in this model as shown in Equation 3

- 1.

TSAM = EM Comb + EM SCR + EM FGC Equation 3

- 1

where,

TSAM = Total manufacture of sulfuric acid

EM Comb = Manufacture of sulfuric acid through combustion

EM SCR = Manufacture of sulfuric acid from SCR

EM FGC = Manufacture of sulfuric acid from FGC3

- 2 The Total Sulfuric Acid Release (TSAR) from a combustion unit equipped with SCR or selective noncatalytic reductio n ( SNCR ) NOx control and FGC is represented in a simplified form in Equation 3

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

TSAR = {[(EM Comb + EM SCR/SNCR + EM FGC_before APH )

– NH 3 Slip] • F2 APH + (EM FGC_afterAPH – NH 3 Slip ) } • F2

x Equation 3

- 2

where,

TSAR = Total sulfuric acid released

EM Comb = Sulfuric acid manufactured through combustion

EM SCR/SNCR = Sulfuric acid manufactured from SCR or SNCR

EM FGC_beforeAPH = Sulfuric acid manufactured from FGC injected upstream of the air preheater ( APH )

EM FGC_afterAPH = Sulfuric acid manufactured from FGC injected downstream of the APH

NH 3 Slip = Calculated ammonia slip that reacts with H 2 SO 4 to form ammonium bisulfate ( ABS ) from SCR/SNCR and/or FGC

F2 APH = Technology Impact Factor for APH

F2

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

**Sulfuric Acid Manufacture from Combustion**

A detailed analytical study by Senior (200 2) explored details of SO 2 oxidation to SO 3 . Specifically, the author modeled the relevant reaction sets employing the temperature

- time history of a typical utility boiler, considering gas phase events only and ignoring catalytic effects.
The results showe d that insignificant SO 3 formed in the early stage of the flame, but SO 3 production increased as the gases exited the flame zone and cooled. The author reported production of SO 3 to be essentially complete prior to flue gas entering the economizer section.
The observation that most SO 3 forms during cooling from post

- flame temperatures (2,900

- 3,100°F) to temperatures typical of the economizer entrance was also noted by Buckley (2002). Senior further quantified the relationship between coal sulfur content, ex cess air, and SO 3 production that has been empirically observed by previous investigators. Specifically, the results showed that after four seconds of residence time, SO 3 production could range from between 0.3

- 0.6% of the flue gas SO 2 concentration.

In the absence of SCR NOx control or FGC, the boiler or turbine combustion process comprises the only source of sulfuric acid. The sulfuric acid manufacture by the combustion process (EM Comb ) is expressed as follows:

EM Comb = K • F1 • E2 Equation 3

- 3

Where K is a constant, F1 is the Fuel Impact Factor describing the SO 3 production associated with combustion for a specific fuel type, and E2 is the an nual rate of SO 2 production. Further details of this relationship and the derivation of constants and other terms are presented in
Section 4.3

- 3 **SCR/SNCR NOx Control**

The SCR process increases the production of SO 3, and therefore, H 2 SO 4 , as a percentage of SO 2 . SO 3 production can range from as low as 0.3%, for the most recent catalyst technology, to as high as 3% of the SO 2 concentration.

The production of SO 3 from SO 2 is a well

- known consequence of SCR, and the degree of SO 2 oxidation is a performance variable that should be part of catalyst procurement specifications. To a degree, SO 3 production can be mitigated by reducing the content of vanadium pentoxide and compensating with other catalyst oxides such as tungsten or molybdenum, which offer improved
selecti vity (e.g., lower SO 2 oxidation) but also lower activity for NOx removal. Alternatively, advanced catalyst formulations can be used that concentrate the vanadium

- containing active ingredients on the catalyst surface and minimize content within the substrat e, lowering SO 2 oxidation. To achieve an equivalent level of NOx and residual ammonia slip, a low SO 2 oxidation catalyst may require a larger volume of catalyst than one for which SO 2 conversion is not constrained. In general, the degree of SO 2 oxidation r anges 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 SO 2 oxidation is acceptable. Depending on how
the measurement of SO 2 oxidation i s performed, the oxidation can be 3% or higher.

In many instances, owners and catalyst suppliers prefer that measurements to quantify SO 2 oxidation for the purpose of commercial guarantees be conducted not with authentic flue gas but in a laboratory

- scale test facility, without fly ash present. This approach has the advantage of improved accuracy and repeatability of the SO 3 concentration. The measurements are generally conducted using CCS. However, particularly for PRB coals, this method will over

- predict SO 3 manufactured by the SCR, as the mitigating role of high fly ash alkalinity is not considered. Consequently, the role of fly ash alkal inity must be considered in predicting SO 3 manufactured by SCR.

The observation that calculated laboratory

- scale SO 3 values at the exit of an SCR reactor exceed measurements in the field has been witnessed on numerous occasions. Specifically, Lindenhoff (2 004) reported that the measured SO 2 oxidation rate for PRB

- generated flue gas of 1.25% was below the 1.6% value predicted based on the boiler and SCR catalyst specifications. Further, tests conducted by this catalyst manufacturer noted significant absorpti on of SO 3 generated within the SCR reactor prior to the air heater. Sufficient data was accumulated to derive both a mathematical model and to project a graphical relationship describing SO 3 removal within an
SCR reactor as a function of both ash content a nd the number of alkaline sites available in the flue gas stream.

An alternative NOx control process, selective non

- catalytic reduction (SNCR), does not use a catalyst and does not promote the oxidation of SO 2 to SO 3 . Accordingly, there is no manufacture
of sulfuric acid attributable to SNCR.

The following relationship describes the total H 2 SO 4 manufactured from an SCR equipped utility boiler or steam generator:

EM SCR = K • S2 • f sops • E2 • F3 SCR Equation 3

- 4

Where K is a constant, S2 is the catalyst SO 2 oxidation rate, f

sops is the fraction of the coal burn in which flue gas is direc ted through the SCR, E2 is the annual rate of SO 2 production, and F3 SCR is the Technology Impact Factor for SCR used to adjust for the presence of alkaline fly ash. Further3

- 4 details of this relationship and the derivation of constants and other terms are pr esented in
Section 4.

**Flue Gas Conditioning**

Flue gas conditioning (FGC) is a process that is typically used in power plants to assist in particulate control in an ESP or baghouse. The conditioning additives can be any of the following: SO 3 , SO 3 plus NH 3 , o r NH 3 alone. In SO 3 - based FGC, SO 3 is introduced into the flue gas either preceding or following the air heater. The SO 3 is typically produced on

- site from sulfurous fuel that is burned to produce SO 2 , which is then catalytically oxidized to SO 3 with a

con version rate typically exceeding 95%. When injected into the flue gas, the SO 3 immediately reacts with water vapor to create sulfuric acid, thus resulting in the manufacture of sulfuric acid. Estimating the manufacture source requires knowledge of the conc entration of SO 3 injected and the associated oxygen content of the flue gas.

Equation 3

- 5 estimates the manufacture of sulfuric acid from FGC, where K

e is a constant, B is the coal burn, f

e is the FGC operating factor, and I

s is the SO 3 injection rate. F3 FGC is the Technology Impact Factor for FGC, and has been added to the manufacture equation in the current version of the model, to adjust for the presence of alkaline fly ash in PRB coals. It should
be noted that the F3 FGC factor has been updated to new v alues, and in the current version is now applied to the manufacture equation, whereas in previous versions of the model it was applied to the release equations. Further details and derivation of the constant are provided in Section 4.

EM FGC = K

e • B • f

e • I

s • F3 FGC Equation 3

- 5

Methodology to Estimate Release

Sources of sulfuric aci d manufactured upstream of the air preheater are calculated separately,
then summed. The combined SO 3 is modified to reflect reactions of SO 3 with residual NH 3 slip from SCR/SNCR equipment and/or FGC ammonia injection, and then adjusted by removal in appli cable downstream equipment such as the air preheater, electrostatic precipitator or other particulate control device (PCD) and flue gas desulfurization (FGD) equipment. The adjustments are made through the use of Technology Impact Factors (F2) which descri be the fraction of sulfuric acid that penetrates each component.

The methodology employs the follow steps, combined into a single release equation, which is shown in Equation 3

- 6, and illustrated schematically in Figure 3

- 1:

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

2. Calculate residual ammonia slip from the SCR/SNCR and FGC and subtract this ammonia from the sum of the sources upstream of the APH to account for ABS formation which is not reportable

3. If the result of S teps 1) and 2) is a positive value , apply the technology factor for APH
removal of SO 3 4. Add downstream sources of sulfuric acid (from FGC, if injected downstream), and subtract downstream ammonia injection (from FGC if injected downstream) to account
for ABS

, which is not reportable

5. Apply all relevant downstream technology factors3

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

- 6.

TSAR = {[(EM Comb + EM SCR/SNCR + EM FGC_beforeAPH )

– (NH3 SCR + NH3 FGC_beforeAPH )] •

F2 APH + (EM FGC_afterAPH – NH3 FGC_afterAPH ) } • F2

x Equation 3

- 6

This approach is a change from the 2010 Sulfuric Acid Emissions model, which applied the Technology Factors independently to each source of sulfuric acid manufacture, then summed the
calculated SO 3 releases to obtain the total release for the unit. The for mer approach sometimes produced negative SO 3 releases for the individual SO 3 sources, due to reactions with ammonia slip from SCR/SNCR that were estimated to remove more SO 3 than was manufactured.

**SCR/SNCR NOx Control**

Both SCR and SNCR can introduce residual ammonia (NH 3 ), also called ammonia slip, into the flue gas. This residual ammonia can react with SO 3 or sulfuric acid to form ammonium sulfate and/or ammonium bisulfate, thereby removing from the flue gas some of the SO 3 that is a precursor to sul furic acid, and reducing the amount released.

For an SCR, ammonia slip is expected to usually range between 0 and 2 parts per million (ppm) for bituminous coal cases. Higher values of ammonia slip are possible if the unit has not been recently tuned, the b oiler 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 SO 3 or H 2 SO 4 occur in the air preheater and result in a solid product that may deposit or accumulate on the surface of the fly ash. Any SO 3 or H 2 SO 4 that participates in these reactions is no longer present as sulfuric acid and is not required to be reported to the EPA TRI program as a release of
sulfuric acid.

SNCR employs ammonia or urea injection in the upper furnace for NOx reduction. The higher temperatures chara cteristic of the upper furnace zone (1,800 to 2,400°F, as compared to 700°F for SCR) do not require reduction catalyst so there is no additional manufacture of SO 3 or sulfuric acid. Typically, SNCR systems operate with higher levels of residual ammonia (5 to 10 ppm), so any sulfuric acid that is present from combustion is reduced through reaction with the ammonia. Consequently, SNCR systems will always reduce the overall amount of sulfuric acid released, while SCR systems can reduce but will likely increase the amount of sulfuric acid
released.3

- 6 Figure 3

- 1 Schematic of Methodology Used to Estimate Sulfuric Acid Releases3

- 7 The reactions between SO 3 and/or H 2 SO 4 and ammonia produce ammonium sulfate [(NH 4 ) 2 SO 4 ] and/or ammonium bisulfate (NH 4 HSO 4 ). While both chemicals are solids, the bisulfate pairs one molecule of ammonia with one of sulfuric acid, while the sulfate requires two ammonia
molecules for each sulfuri c acid. Which reaction product is present is usually determined by the stoichiometry, or the relative amount of each substance on a mole basis, that is present in the flue gas. When ammonia is present in an amount over twice the mole content of sulfuric ac id, the reaction product will always be ammonium sulfate. Conversely, when sulfuric acid is present in an amount on a mole basis greater than ammonia, the product will be ammonium bisulfate. Between these two extremes, a mixture of ammonium sulfate and bis ulfate is produced.

A SCR

- equipped unit firing bituminous coals with low

- to

- medium sulfur content will always produce an excess of sulfuric acid over ammonia slip. Accordingly, ammonium bisulfate is the primary byproduct anticipated. For subbituminous and lignite coals, any sulfuric acid produced is typically adsorbed by the ash and it is likely that residual ammonia will exceed sulfuric acid content on a mole basis. Under these conditions, ammonium sulfate is the likely product.

For SNCR

- equipped units, a mmonia slip levels of 5 ppm and possibly higher will favor ammonium sulfate, particularly for western U.S. coals where the alkaline fly ash will reduce the

SO 3 content. For eastern bituminous coals, which have generally higher 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 ammo nia reacting with the ammonium bisulfate is of no consequence to the sulfuric acid calculation

– although this reaction is important when estimating ammonia releases.

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

or SNCR. This ammonia slip is calculated as follows, and is added to any ammonia injection
from FGC before it is subtracted from the sum of the sulfuric acid manufactured.

NH3 SCR = K

s • B • f sreagent • S NH3 Equation 3

- 7

Where K S is a constant, B is the coal burn in TBtu/yr, f sreagent is the fraction of SCR operation with reagent injection, and S NH3 is the NH 3 slip for the SCR/SCNR. This calculation and factors are
described further in Section 4.

**Flue Gas Conditioning**

Flue gas conditioning may involve injection of NH 3 alone or NH 3 with SO 3 . Thus, FGC can result in sulfuric acid manufacture or may result in sulfuric acid removal, if NH 3 is injected alone or in quantities greater than the sulfuric acid. The following equation describes the calculation of
ammonia that is used to reduce sulfuric acid. If ammonia is injected upstream of the APH, this
value would be added to the residual ammonia from SCR/SNCR. If added downstream of the APH, the value would be subtracted from any downstream SO 3 injection introduced by FGC.3

- 8 NH3 FGC = K

e • B • f

e • I NH3 Equation 3

- 8

Where K

e is a constant, B is the coal burn in TBtu/yr, f

e is the fraction of coal burn with FGC operation, and I NH3 is the NH 3 injected. This calculation and facto rs are described further in
Section 4.

**Estimating Release with Alkali Injection**

Many utility operators inject alkali into the flue gas to control SO 3 . A wide variety of alkali materials based on calcium, sodium, or in some cases magnesium compounds, have been used with varying degrees of effectiveness to remove SO 3 . These alkali materials include sodium bisulfate, trona, and various types of lime (conventional, hydrated, and magnesium enhanced).

Sodium bisulfate (SBS) is the most widely used reagent for c ontrol of SO 3 . 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 SO 3 removal. SBS can be highly effective in removing

SO 3 . Additional sodium can be added t o the flue gas to compensate for any compromise in ESP performance due to increased ash resistivity associated with SO 3 reduction. A detailed summary of experience with SBS usage has recently been published (Moser, 2007).

Trona is another sodium

- containing reagent that is used to control SO 3 . Trona can be injected at several locations within the boiler, but most applications introduce trona at the air heater exit, prior to the particulate collector (Ritzenthaler, 2006). As with SBS, additional sodium introd uced 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 SO 3 control (Gale, 2006), as has lime supplemented with magnesium hydroxide (Benson, 2006b). Calcium

–

based sorbents can be very effective in reducing SO 3 , but may compromise ESP performance, as the reduced SO 3 content in flue gas increases the electrical resistivity of the ash on the collecting plate. For this reason, some operators have proposed using both calcium

- and sodium

- based sorbents, the latter to both augment SO 3 removal and promote ESP performance. In summary, any of several alkali materials can be used
to control SO 3 , with the least cost solution depending on the plant and access to low cost sorbent.

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

SO 3 concentration in flue gas for a specified sorbent injection ra te. In most cases, these tests will be conducted at the stack. The alkali injection system usually is operated to reduce SO 3 emissions to between 5 and 15 ppm, an optimal range to prevent formation of a visible plume. A procedure to convert measured sulfur ic acid concentration in flue gas to a mass emission rate is summarized below and described in more detail in Section 4. An example application of this procedure is provided in Appendix A.

ER ALKINJ = K alkali • B • S SO3 • F2

x • F alkali Equation 3

- 9

Where K alkali is a constant, B is the coal burn, S SO3 is the measured SO 3 content with in jection,

F alkali is the fraction of time alkali injection is in operation, and F2 are any applicable downstream Technology Impact Factors.3

- 9 Users of this approach should be cautioned that the current EPA

- approved test method for SO 3 (EPA Method 8) has a si gnificant positive bias, and that corrections for this bias may be needed to accurately assess flue gas concentrations. A more accurate method is the controlled condensate system (CCS). Although no general

- purpose, EPA

- approved CCS method is currently avai lable, it is widely used by stack test contractors for sulfuric acid measurement and is more accurate than Method 8, if performed correctly.

Some units will not have measured stack emissions. This version of the model adds an alternate approach to estimat e releases with alkali injection if stack SO 3 measurements are not available. Instead of using Equation 3

- 9 for ER ALKINJ , the total sulfuric acid release is calculated by estimating total releases using Equation 3

- 6. An alkali injection factor, F3 ALKINJ , i s then applied to the total release as shown in Equation 3

- 10. This F3 ALKINJ is either the expected fractional
reduction in SO 3 (generally as guaranteed by the vendor) or a default of 0.2. The basis of the 0.2 value is test results indicating that 80% removal is easily achievable (EPRI, 2010b). This method is explained in further detail in Section 4.

TSAR ALKINJ = (TSAR Comb+SCR+FG C ) • F3 ALKINJ Equation 3

- 10

To estimate SO 3 manufacture with alkali injection, plant owners should use the standard approaches given in Section 4 for the appropriate plant con figuration. At this time, EPRI does not have sufficient information to estimate the impact on SO 3 formation of adding alkali at various points in the fuel combustion and stack gas treatment process. Assuming that there is no
reduction of SO 3 formation is c onservative for a threshold determination for TRI reporting

purposes.4

- 1 

# 4

ESTIMATING GUIDELINE : STEAM BOILERS

This section describes an estimation procedure for calculating the manufacture and release of
sulfuric acid from coal

- fired steam generators. The topics addressed are (a) formation within the furnace; (b) the role of SCR, (c) flue gas conditioning (FGC), and (d) alkali injection; and (e) removal by downstream equipment such as air heaters, ESPs or other particulate control devices, and FGD proc ess equipment. Each of the subsequent sections in this chapter provides the information to conduct this stepwise calculation.

Sulfuric Acid Manufacture

**Sulfuric Acid Manufactured by Combustion (EM Comb**  **)**

The premise of the methodology is that the amount of sulfuric acid manufactured by the boiler is
a function of the amount of SO 2 produced

– which may be determined either from coal usage (amount burned and sulfur content) or from continuous emission monitoring system (CEMS) output. Units equipped with FGD eq uipment or other methods of SO 2 control are required to estimate emissions either from coal data or from the output of a CEMS positioned ahead of the scrubber. As described below, it may be necessary to correct SO 2 CEMS data for non

- ideal stack
flow condit ions.

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

EM Comb = K • F1 • E2 Equation 4

- 1

where,

EM Comb = total H 2 SO 4 manufactured from combustion, lbs/yr

K = Molecular weight and units conversion constant

= 98.07 / 64.04 • 2000 = 3,063

98.07 = Molecular weight of H 2 SO 4

64.04 = Molecular weight of SO 2

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

F1 = Fuel Impact Factor

E2 = Sulfur dioxide (SO 2 ) emissions, either: (1) recorded by a continuous emissions monitor, tons/yr, or (2) calculated from coal burn data, tons/yr.

The Fuel Impact Factor (F1) is a numerical value or a mathematical relationship reflecting the
conversion of SO 2 to SO 3 in the boiler for a specific coal type and boiler type. In the derivation of Equation 4

- 1, the following assumptions are made:

• SO 3 concentrations are proportional to SO 2 concentrations.4

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

• All SO 3 that forms is converted to H 2 SO 4 .

• The rate of SO 3 formation is independent of the boiler firing rat e (unit load).

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

Sulfur dioxide (SO 2 ) Emissions from Combustion (E2)

Estimating the sulfuric acid production from Equation 4

- 1 requires knowledge of the mass rate of

SO 2 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 t he annual SO 2 production rate, in tons/year of SO 2 . However, it may be necessary to correct for stack geometry in deriving E2. The user should check with their CEMS operator, as the bias corrections may already be taken care of in the instrument software.
If CEMS SO 2 data are used, the factor E2 is defined by the following equation: 

# ( )       + • + •

− = 100 3 2 1 1 2 2 C R C R C E E Equation 4

- 2

where,

E2 = Corrected SO 2 mass rate, tons per year

E = CEMS

- derived SO 2 mass rate, tons per year

C1 = 0.0264 (non

- axial flow bias factor)

C2 = 0.183 (non

- axial flow bias factor)

C3 = 1.5 (wall effects bias factor)

– default value for cylindrical stacks

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

In Equation 4

- 2, the factor C 3 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 s ite, 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 p roposed a wall effects correction for stacks with rectangular ducts that are equipped with flow monitors (EPA, 2009). This proposal has not been finalized as of March

, 201 2 , but some facilities may be allowed to apply this approach as a conditional test me thod.4-3 As an alternative to using CEMS data, the following relationship based on coal burn data can be
used to estimate the rate of SO 2 emissions:

E2 = K1 • K2 • C1 • S1 Equation 4-3

where,

E2 = SO 2 mass rate, tons/yr

C1 = Dry coal burn, tons/yr. The dry coal can be calculated from wet coal through the following relationship: Dry coal (tons/yr) = wet coal (tons/yr) • (1 -moisture(%)/100%)

S1 = Coal sulfur weighted average, %, dry

K1 = Molecular weight and units conversion constant

= (64.04)/(100 • 32.06) = 0.02 64.04 = molecular weight of SO 2 32.06 = molecular weight of S
100 = conversion of % S to a fraction

K2 = Sulfur conversion to SO 2 , implicit from EPA AP -42 (EPA, 1995b)

= 0.95 for bituminous coals

= 0.875 for subbituminous coals

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

= 1.0 for oil

When any source uses FGD equipment or another technology to control SO 2 emissions, either
the fuel basis must be used for the manufacturing and release calculations, or CEMS data can be used, but only when the CEMS precedes the FGD or SO 2 control equipment. Data from a CEMS located after a flue gas desulfurization system cannot be used

, because the measured SO 2 has already been decreased by the control equipment, and therefore is not an accurate predictor of the

SO 3 emissions rate.

Fuel Impact Factor (F1 ). Figure 4-1 depicts the fraction of H 2 SO 4 produced as a function of flue gas SO 2 content for several coal sources and boiler types. The coal ranks and boiler types consist of (a) high sulfur (>2.5%) eastern bituminous coal, fired in a dry bottom boiler (wall- fired or
cell -fired), (b) low sulfur eastern bituminous coal, fired in a dry bottom boiler, (c) PRB coal, fired in both a cyclone and dry bottom boilers. Data are also shown for one unit that fires 75% lignite with the balance PRB and one unit that fires 100% lignite.

Figure 4-1 shows that a wide range in SO 3 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 SO 3 production or absorbing/neutralizing SO 3 is not fully accounted for. The only consistent results in Figure 4- 1 are for SO 3 from PRB -fired units, regardless of boiler type, in that less than 1 ppm was observed.4-4 The current model uses a linear relationship to estimate SO 3 production for all eastern bituminous, dry bottom boiler data, as shown in Figure 4-1. The equation expressing this relationship is shown in Equation 4-4. This relationship is significant at the 95% confidence level, although the correlation coefficient (R 2 ) is low (0.13) due to scatter in the data. The current
model retains F1 factors based on average fraction of SO 2 converted to SO 3 for all other coal
types.

Figure 4-1 Relationship between Boiler SO3 Production and Flue Gas SO2 (corrected to 3% O2)

F1 ebit = 1.12E

- 6 • SO 2 + 0.0065 Equation 4-4

where,

F1 ebit = Fuel Impact Factor for all Eastern Bituminous coals burned in a dry-bottom
boiler

SO 2 = Boiler SO 2 concentration (ppm), derived from fuel sulfur content (%)

In order to use this approach, it is necessary to relate coal sulfur (%) to the SO 2 concentration in the boiler. Equation 4- 5 is used to calculate that relationship:

HV K SSO F 1

2 1

•= Equation 4-5 Eastern Bituminous y = 1.1163E

- 06x + 6.4877E

- 03

R 2 = 1.3004E

- 01

0.000 0.005 0.010 0.015 0.020

0 1000 2000 3000 4000Boiler SO3Production, F1 Factor

Flue Gas SO 2 Content High S East Bit, Dry Bottom Boiler

Low S East Bit, Dry Bottom Boiler

PRB Dry Bottom Boiler

75% Lignite

100% Lignite

PRB Cyclone4-5 where,

SO 2 = Boiler SO 2 concentration (ppmvd, 3% O 2 , dry) derived from fuel sulfur content (%)

S1 = Coal sulfur weighted average, %, dry

K

F1 = Conversion factor = 10,003,602

HV = Coal heating value, Btu/lb, dry

The convers ion factor K F1 considers all relevant constants to yield the result in ppm of SO 2 . The derivation of this constant is presented in Text Box A.

Table 4

- 1 summarizes the F1 factors. There are no changes to these factors from the previous version of the model (EPRI, 2010a).

Text Box A : Derivation of Conversion Factor, K F1 . The U.S. Code of Federal Regulations 40, Part 60, Table 19

- 1 “F Factors for Various Fuels” states that 1 million Btu of heat input for bituminous or subbituminous coal will produce 10,640 wet standard cubic feet of flue gas, defined at 0% oxygen and on a wet basis at 20 o C and 760 mm Hg. Correcting this volume to 3% O 2 on a dry basis (typical of the SO 2 measurement data used in the Fuel Impact Factors correlation) yields a volume of 11,419 scf. The standard volume of one pound mole of any gas is 359 scf, defined at 0 o C and 760 mm Hg. Converting this to the English units standard of 20C (68°F), one pound mole occupies 385.5 standard cubic feet. The value 0.95 is the AP

- 42 (EPA, 1995b) K2 factor for sulfur
conversion to SO 2 for a bituminous coal

. Equation 4

- 4 above can then be expanded as follows:

S1% 0.95 385.5 scf S 1 lb mol S 1 MBtu 1 lb fuel 10 6 Btu 10 6 ppm

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

Grouping terms,

SO 2 = S1 • 10,003,602 / HV

Therefore, the value of K F1 is equal to 10,003,602 [ ppmvd SO 2 (3% O 2, dry) • Btu/lb]/%S.4

- 6 Table 4

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

Fuel Equipment F1 Comment

E. Bituminous (all) 1 Dry Bottom
Boiler Slope:

1.1163E

- 6

Intercept:

0.0064877 F1 = slope SO 2 + intercept
32 data points

Med

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

W. Bituminous Dry Bottom
Boiler 0.00111 One data point.

W. Bituminous Cyclone 0.0022 One data point.

Subbituminous/PRB All Boilers 0.0019 Average of 8 units

Lignite Dry Bottom
Boiler 0.0044 Two data points.

Lignite Cyclone 0.00112 One data point.

Petroleum coke Boiler 0.04 One data point.

Natural gas Boiler 0.01

#2 Fuel oil Boiler 0.01

#6 Fuel oil Boiler 0.025

Used oil Boiler 0.0175

Natural gas CT See Table

6

- 1

#2 Fuel oil CT See Table

6

- 1

Natural gas CC 0.0555

#2 Fuel oil CC 0.0555

Other Alternative Fuels Any 0.04

Other Alternative Fuels,

co

- fired w/coal, >75% heat throughput NA Use Coal F1, in absence of any applicable data.

1 For eastern bituminous coal, a linear relationship between SO 2 and SO 3 is used instead of an average F1 factor.4

- 7 **Sulfuric Acid Manufactured from SCR (EM SCR**  **)**

This section describes a method to estimate impacts of SCR on sulfuric acid emissions. As discussed in Section 3, SCR produces SO 3 (and ultimately sulfuric aci d), while SNCR removes or reduces it due to the reaction with residual ammonia. As such, only the SCR process will be
addressed in this section. The removal equations will be discussed in subsequent sections, and will address both SCR and SCNR, as residual ammonia from either process contributes to
sulfuric acid removal.

The following relationship estimates the total H 2 SO 4 manufactured from an SCR equipped utility boiler or steam generator:

EM SCR = K • S2 • f sops • E2 • F3 SCR Equation 4

- 6

where,

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

K = Molecular weight and units conversion constant

= 98.07 / 64.04 • 2000 = 3,063

98.07 = Molecular weight of H 2 SO 4

64.04 = Molecular weight of SO 2

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

S2 = SCR catalyst SO 2 oxidation rate (specified as a fraction, typically from

0.001

- 0.03)

f

sops = Operating factor of SCR system, or the fraction of coal burn when the flue gas is directed through the SCR, whether NH 3 reagent is injected to derive NOx
reduction or not. This value 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 operatio n

E2 = SO 2 produced, tons per year

F3 SCR = Technology Impact Factor, for SCR

The Technology Impact Factor for SCR (F3 SCR ) is required to adjust SO 3 content for the presence of alkaline fly ash, as described in Section 3, unless direct measurements exist for the subject unit documenting SO 3 increase across the SCR reactor.

It is important to select the correct SO 2 oxidation rate, S2, for use in Equation 4

- 6. Typically, the

SO 2 oxidation rate from SCR catalysts can range from as low as 0.3% of flue gas SO 2 content, up to 3% for low sulfur, highly alkaline coals (e.g., PRB). There are two means by which SO 2 oxidation is specified and measured for SCR process equipment, and each has significantly different implications for SO 3 produced. One method

– based on 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 alkaline4

- 8 materials, and must be adjusted to account for these latter factors. The consequences of each of
these methods on estimates of sulfuric acid emissions are described as follows:

Full

- Scale Catalyst Performance Tests. Ideally, SO 2 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 SO 3 content, as the impact of ash alkalinity is taken into account. This approach reflects commercial proces s operation, and the resulting fractional oxidation rate can be used as the S2 value in Equation 4

- 6 without adjustment by the F3 SCR Technology Impact Factor.

Laboratory Bench

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

gua rantee measurements for SO 2 oxidation on laboratory

- scale equipment using synthetic flue gases without fly ash. There are good reasons to select this methodology; evidence suggests SO 3 measurements in the environment of the test laboratory are more accurat e and reproducible than field tests. However, this method does not expose the catalyst being tested to ash, so there is no alkaline component to mitigate or absorb any SO 3 generated. Accordingly, SO 2 oxidation reported by this method exceeds that measured in commercial practice, particularly for PRB
coals. SO 2 oxidation data from bench

- scale tests can be used, but must be adjusted for the role of ash alkalinity. This adjustment is provided by the Technology Impact factor F3 SCR .

Table 4

- 2 shows the F3 SCR fac tors. It should be noted that the 0.17 factor for PRB coals when using laboratory

- scale SO 2 conversion (S2) data without fly ash is based on measurements at two

PRB

- fired units. SO 3 emitted from these units was lower than specified in the catalyst guarante e, which was based on laboratory test data. At present, there are no data to support F3 SCR factors for other coals, so a factor of 1 (full penetration) is recommended. Additionally, if full

- scale catalyst performance SO 2 conversion data is used, the F3 SCR factor is 1 for all coal types.

Table 4

- 2

F3 SCR Technology Impact Factors for SCR

Coal Type F3 SCR
Using Laboratory

- Scale SO 2 Conversion Data (S2), Without Fly Ash

PRB 0.17 (n = 2)

Other Coals 1 (no data available)

Using Full

- Scale Catalyst Performance SO 2 Conversion Data (S2)

All Coals 1

SNCR does not result in the manufacture of sulfuric acid; thus, EM SNCR for SNCR is by
definition zero.

**Sulfuric Acid Manufactured from FGC (EM FGC**  **)**

In order to moderate ash resistivity, most SO 3 – based FGC systems attempt to maintain a fixed
concentration of SO 3 in the flue gas, typically between 5 and 7 ppm by volume (ppmv). Calculations to estimate the sulfuric acid manufactured during FGC use the setpoint of th e 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 SO 3 - based FGC equipment (EM FGC ) is calculated as follows:4

- 9 EM FGC = K

e • B • f

e • I

s • F3 FGC Equation 4

- 7

where,

EM FGC = Total H 2 SO 4 manufactured from FGC, lbs per year, either upstream of APH (

EM FGC_beforeAPH ) and/or downstream of APH (EM FGC_afterAPH )

K

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

B = Coal burn in TBtu/yr

f

e = Operating factor of FGC system: the fraction of co al burn when the FGC system operates. This value is site

- specific, must be determined for each unit, but generally will be about 0.8.

I

s = SO 3 injection rate in ppmv at 6% O 2 , wet; generally,

= 7 ppmv if before the APH

= 5 ppmv if after the APH

F3 FG C = Technology Impact Factor for FGC

= 0.17 for PRB coal

= 1 for all other coals

A Technology Impact Factor for FGC (F3 FGC ) is used to adjust the flue gas SO 3 manufacture from FGC injection to account for the presence of alkaline fly ash. The principl e is the same as
for the F3 SCR factor, that is used to adjust the flue gas SO 3 produced by SO 2 oxidation rate on the SCR catalyst.

The current F3 FGC factor is applied differently than in previous versions of the model. In the EPRI (2010) model and all ear lier versions, the F3 FGC factors were substituted for Technology Impact Factors (F2) for the APH and/or ESP when FGC was used. The old F3 FGC factors were
used to account for both SO 3 reductions from adsorption to alkaline fly ash and differential
behavior when FGC was injected before and after the APH. However, this approach led different estimated sulfuric acid releases depending on the source of the SO 3 (e.g., from combustion or FGC). Additionally, as new test measurements were added to the database and used to update the F2 factors, the historical F3 FGC factors became obsolete, as they were based on theoretical understanding of SO 3 behavior rather than empirical data.

The new method first reduces the SO 3 that is injected into a PRB

- fired boiler using a new F3 FGC factor to account for sorption by the alkaline fly ash. Subsequently, SO 3 from FGC is treated the same as all other sources of sulfuric acid with respect to ABS formation or reduction through
control devices. The new F3 FGC factor (0.17) is assume d to be equal to the F3 SCR factor. A F3 SCR of 1.0 is used for eastern bituminous coals (zero reduction), as those coals produce an acidic ash that does not adsorb appreciable amounts of SO 3 .4- 10 The conversion factor K

e , equal to 3,799, considers all relevant constants to yield the result in pounds per year of sulfuric acid. The derivation of this constant, for the case where residual SO 3 is reported in terms of 6% oxygen and “wet” flue gas at 8.1% H 2 O, is presented in Text Box B.

Equation 4-7 specifies the concentration of SO 3 in flue gas (I S ) in terms of ppmv at 6% O 2 , wet flue gas basis. If the concentration of SO 3 is reported at different conditions, the value of the

constant K

e wil l change. The following formula is used to adjust the value of the constant K

e :

K

e (O 2 , H 2 O ) = 3

, 799 (6% O 2 , 8.1% H 2 O) • [(100

- 8.1)/(100

- new H 2 O)]

• [(20.9 – 6.0)/(20.9 – new O 2 )] Equation 4-8

For example, if the SO 3 concentration is quantified at a value (in ppm) that is defined at 0% oxygen and a dry basis, the value of K

e that should be used is:

K

e (O 2 , H 2 O) = 3

, 799 (6% O 2 , 8.1% H 2 O) • [(100

- 8.1)/(100

- 0)] • [(20.9 – 6.0)/(20.9 – 0)]

K

e = 2,489

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

EM FGC_beforeAPH , or downstream of the APH, EM FGC_afterAPH . These values must be kept separate for the release equations.

FGC equipment that employs NH 3 injection alone does not manufacture sulfuric acid and therefore this amount, EM FGC , would be zero. However, the injected NH 3 will reduce the total

Text Box B : Derivation of Conversion Factor, K

e . The U.S. Code of Federal Regulations 40, Part 60, Table 19

- 1 “F Factors for Various Fuels” lists that 1 million Btu of heat input for bituminous or subbituminous coal will produce 10,640 wet standard cubic feet of flue gas, defined at 0% oxygen and on a wet basis at 20 ° C and 760 mm Hg. Correcting this volume to 6% O 2 (typical at ESP conditions) yields a volume of 14,925 scf. The standard volume of one pound mole of any gas is 359 scf, defined at 0 ° C and 760 mm Hg. Converting this to the English
units standard of 20 ° C (6 8°F), one pound mole occupies 385 standard cubic feet. Using these in the equation above,

(K

e • B • f

e • I S ) = lbs H 2 SO 4 per yr =

B TBtu I S (S NH3 ) scf

NH 3 1 lb mol SO 3 1 lb mol H 2 SO 4 98 lbs H 2 SO 4 14925 scf fg 10 6 MBtu

year 10 6 scf flue gas 385 scf SO 3 1 lb mol NH 3 1 lb mol H 2 SO 4 1 MBtu TBtu

Grouping terms,

= B • f

e • I S • 3,799

Therefore, the value of K

e is equal to 3,799 lbs H 2 SO 4 /(TBtu • ppmv SO 3 @ 6% O 2 and wet).4- 11 release of sulfuric acid by reacting with SO 3 or the resultant H 2 SO 4 , and therefore should be used in the release equation, as discussed in subsequent sections.

**Total Manufacture from All Sources**

The total manufacture of sulfuric acid is the sum of the individual manufacture estimates. Therefore, if a site burns coal and uses both SCR and FGC, the amount of sulfuric acid
manufactured – by combustion, SCR, and/or FGC – is summed to determine the total amount.

Accordingly, total sulfuric acid manufacture (TSAM) is estimated for a generating unit equipped with SCR and flue gas conditioning by the following equation:

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

TSAM = EM Comb + EM SCR + (EM FGC_beforeAPH + EM FGC_afterAPH ) Equation 4-9

Sulfuric Acid Release

Both SCR and/or ammonia- based FGC may have a negative effect on sulfuric acid release, as the ammonia slip can combine with some or all of the sulfuric acid generated from combustion to form a non-reportable ammonia salt (ABS or AS). Under these conditions, ammonia- based FGC can serve to only reduce the release of sulf uric acid. Therefore, sources of ammonia are calculated and summed in relation to the APH, and used to adjust the sulfuric acid manufactured. Once adjusted by ammonia, the remaining sulfuric acid is then adjusted by the removals in applicable downstream eq uipment such as the APH, ESP or other particulate control device and FGD equipment through the use of Technology Impact Factors (F2) which describe the fraction of sulfuric acid that penetrates each component.

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

TSAR = {[(EM Comb + EM SCR + EM FGC_beforeAPH ) – (NH3 SCR + NH3 FGC_beforeAPH )] •

F2 APH + (EM FGC_afterAPH – NH3 FGC_afterAPH )} • F2

x Equation 4- 10

where,

TSAR = Total Sulfuric Acid Release, lbs per year

EM Comb = Total sulfuric acid manufactured from combusted, lbs per year

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

EM FGC_beforeAPH = Total sulfuric acid manufactured from FGC upstream of the APH

EM FGC_afterAPH = Total sulfuric acid manufactured from FGC downstream of the APH

NH3 SCR = Total ammonia slip produced from SCR/SNCR, lbs per year

NH3 FGC_beforeAPH = Total ammonia produced from FGC upstream of the APH, lbs per

year

NH3 FGC_afterAPH = Total ammonia produced from FGC downstream of the APH, lbs per

year4- 12 F2 APH = Technology Impact Factor for APH, applied only if subtotal for releases upstream of the APH is non -negative

F2

x = Technology Impact Factors for processes downstream of the APH, all that apply

Examples in Appendix A detail the use of these calculations. Ammonia produced from SCR/SNCR and FGC are calculated using equations from the sections below.

It should be noted that the F2 factor for the APH (F2 APH ) should only be applied if the subtotal of the sum of the sulfuric acid manufactured minus the ammonia slip upstream of the APH [(EM Comb + EM SCR + EM FGC_beforeAPH )

– (NH3 SCR + NH3 FGC_beforeAPH )] is a p ositive value. If this subtotal is negative, this would indicate that excess ammonia slip is still present after all the sulfuric acid from combustion, SCR and FGC has been consumed to form ABS. In this instance, the resulting ammonia slip should not be reduced by the F2 APH factor, as all the ammonia is expected to penetrate the APH. This negative ammonia slip value can then be added to any downstream FGC injection, as summarized in the equation below:

TSAR ExcessNH3 = {[(EM Comb + EM SCR + EM FGC_beforeAPH ) – (NH3 SCR + NH3 FGC_beforeAPH )] + (EM FGC_afterAPH – NH3 FGC_afterAPH )} • F2

x Equation 4- 11

Text Box C summarizes calculations for a unit equipped with a FGD process that employs partial flue gas bypass, to account for the fact that the entire flue gas flow is not subject to sulfuric acid removal by the FGD process. This bypass factor is pertinent only to units that employ flue gas bypass.

**Ammonia Slip from SCR and SNCR (NH3 SCR**  **)**

A key assumption in the calculation methodology is that residual ammonia from either a SCR or SNCR captures all available sulfuric acid in the (ammonium) bisulfate form. The bisul fate form is not reportable under the Toxics Release Inventory rules and thus is not part of the manufacture calculation. If any additional ammonia reacts with bisulfate to form ammonium sulfate, that reaction is of no consequence to the sulfuric acid calculation – although it needs to be taken into account when estimating ammonia releases.

Text Box C : Flue Gas Desulfuriz ation Bypass Calculation

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

TSAR bypass = {[(EM Comb + EM SCR/SNCR + EM FGC_beforeAPH ) – ( NH3 SCR + NH3 FGC_beforeAPH )] • F2 APH +
(E M FGC_afterAPH – NH3 FGC_afterAPH ) } • F2

x TSAR = [SB f + (1

– SB f ) • F2

s ] • TSAR bypass where, SB f = fraction of scrubber bypass, as a decimal

F2

s = F2 for scrubber

F2

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

- 13 The total sulfuric acid released from combustion, SCR, and FGC is determined by subtracting from the sulfuric acid manufactured the amount removed by the residual ammon ia, or ammonia slip. For SCR/SNCR, the ammonia slip is calculated using the following:

NH3 SCR = K

s • B • f sreagent • S NH3 Equation 4

- 12

where,

NH3 SCR = Total ammonia slip produced from SCR/SNCR, lbs per year

K

s = Conversion factor = 3799, which is equivalent to K

e (See Text Box B)

B = Coal burn in TBtu/yr

f sreagent = fraction of SCR operation with re agent injection, when residual NH 3 is produced that will remove SO 3 . The value of f sreagent will be similar to, but slightly less than, the value of f

sops , defined for Equation 4

- 6.

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

• SCR averages 0.75 pp mv over catalyst guarantee period

• SNCR averages 5 ppmv

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

The conversion factor K

s , equal to 3,799, is equivalent to the factor K

e used for SO 3 injected from FGC, and considers all relevant constants to yield the result in pounds per year of ammonia. The derivation of this constant, in the form of K

e , was presented previously in Text Box B.

Equation 4

- 12 specifies the concentration of NH 3 in flue gas (S NH3 ) in terms of ppmv at 6% O 2 , wet flue gas basis. If the concentration of NH 3 is reported at different conditions, the value of the

constant K

s will change. As with K

e , Equation 4

- 8, described previously and repeated again below for reference, is used to adjust the value of the constant K

s :

K

s (O 2 , H 2 O ) = 3799 (6% O 2 , 8.1% H 2 O) • [(100

- 8.1)/(100

- new H 2 O)]

• [(20.9

– 6.0)/(20.9

– new O 2 )] Equation 4

- 8

The operating factor of the SCR describes the portion of the coal burn that reflects the period of SCR operation, based on whether the unit operates seaso nally (0.43), annually in a base

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

The coal burn rate in TBtu/yr can be obtained from coal use records, such as those reported to EIA in Form 767, or can be calculated from the annual coal burn (tons/yr) and the heating value of the coal, as described in the equation below:

B = C1 • HV • K B Equation 4

- 13

where,

B = Coal burn in TBtu/yr4

- 14 C1 = Dry coal burn, tons/yr. The dry coal can be calculated from wet coal through the following relationship: Dry coal (tons/yr) = wet coal (tons/yr) • (1

- moisture(%)/100%)

HV = Coal heating value, Btu/lb, dry

K

B = Conversion factor = 2E

- 9. The factor is calculated from the conversion of tons per year to pounds per year and Btu to TBtu (2000/10 12 = 2E

- 9)

**Ammonia Injection from FGC (NH3 FGC**  **)**

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

w ill react with sulfuric acid manufactured to form ABS. The following equation is used to
calculate ammonia from FGC. Care must be taken to note the location of the ammonia injection, upstream or downstream of the APH, such that the ammonia can be utilized correctly in the release equation.

NH3 FGC = K

e • B • f

e • I NH3 Equation 4

- 14

where,

NH3 FGC = Ammonia produced from FGC, lbs per year, either upstream of APH,

NH3 FGD_beforeAPH , or downstream of APH, NH3 FGC_afterAPH

K

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

B = Coal burn in TBtu/yr

f

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

e described previously and in many cases can be approximated by 0.8.

I NH3 = NH 3 injection for dual flue gas conditioning, ppmv at 6% O 2 , wet; generally 3 ppmv NH 3 if operating, or zero (0 ) if no ammonia is used.

**Total Release Calculation for Sources Employing Alkali Injection**

As described in Section 3, sources that employ alkali injection to mitigate stack opacity or a visible plume will typically have access to field measurements describi ng SO 3 concentration in flue gas, most likely at the stack. The concentration of SO 3 measured at the stack can be converted to a mass emission rate using Equation 4

- 15.

ER ALKINJ = K alkali • B • S SO3 • F2

x • F alkali Equation 4

- 15

where,

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

K alkali = Constant, equal to 3,799, which is equivalent to K

e , as described in Text Box

B.

B = Coal burn in TBtu/yr4

- 15 S SO3 = SO 3 content, as measured in the stack or particulate collector exit, ppmv at

6% O 2 , wet

F alkali = Operating factor for the alkali injectio n system, fraction of coal burn when unit is operated with alkali addition to remove SO 3

F2

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

x is 1 if measurements are conducted at the stack, and there are no control components downstream of the measurement location. If the control device
is an SO 2 scrubber, F2x is denoted as F2s, but is handled the same way.

If the SO 3 content (S SO3 ) is known at conditions other than 6% O 2 and wet, Equation 4

- 8 can be
used to calculate a new value K alkali at the new conditions.

The Technology Impact Factors selected should represent the control equipment between the point of SO 3 measurement and the stack. For e xample, if a unit is equipped with only an ESP,
and the SO 3 measurement is conducted at the ESP inlet, then the F2 factor for an ESP (Table 4

- 5, below) should be selected.

If the utility employing alkali injection does not have access to measured data, the total sulfuric acid releases may be calculated as described by Equation 4

- 10 (i.e., by estimating and summing
the manufacture and applying the technology Impact Factors), and an alkali injection factor,

F3 ALKINJ , is then applied to the total release. This F3 ALKINJ is either the expected fractional
reduction in SO 3 (generally as guaranteed by the vendor), a default value of 0.2, as available data indicates 80% removal is easily achievable (EPRI, 2010b).

ER ALKINJ = (TSAR Comb+SCR+FGC ) • F alkali F3 ALKINJ Equation 4

- 16

where,

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

per year

TSAR Comb+SCR+FGC = Total H 2 SO 4 released from combustion, SCR and FGC, as calculated using Equation 4

- 10.

F alkali = Operating factor for the alkali injection system, fraction of coal
burn when unit is operated with alkali addition to remove SO 3

F3 ALKINJ = Technology Impact Factor fo r alkali injection:; the expected
fractional reduction in SO 3 (generally as guaranteed by the vender). If no vendor information is available, use a default value

of 0.2.4

- 16 Partial Year Injection

If alkali injection is not utilized for the entire operating year (F alkali does not equal 1), then Equation 4

- 15 (or Equation 4

- 16) must be added to the fraction of the total sulfuric acid release (TSAR) calculated from combustion, SCR/SNCR and/or FGC for the remainder of the operating time (Equation 4

- 10). Furtherm ore, in the calculation of TSAR for partial

- year alkali injection, if

SO 3 measurements also exist for operation without alkali injection, these data should be used with Equation 4

- 15 instead of the standard estimation equations, as shown below:

ER NOINJ = K alkali • B • S SO3 • F2

x • (1

- F alkali ) Equation 4

- 17

where,

ER NOINJ = Total H 2 SO 4 released from unit without alkali injection, lbs per year

K alkali = Constant, equal to 3,799, which is equivalent to K

e , as described in Text Box

B.

B = Coal burn in TBtu/yr

S SO3 = SO 3 content without alkali injection, as measured in the stack or particulate collector exit, ppmv at 6% O 2 , wet

F alkali = Operating factor for the alkali injection system, fraction of coal burn when unit is operated with alkali addition to remove SO 3

F2

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

x 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 SO 2 scrubber, F2x is denoted as F2s, but is handled the same way.

Accordingly, total sulfuric acid release (TSAR) for a unit employing partial

- year alkali injection is estimated by one of the following equations:

TSAR = ER ALKINJ + (TSAR Comb+SCR+FGC ) • (1

- F alkali ) Equation 4

- 18

TSAR = ER ALKINJ + ER NOINJ Equation 4

- 19

Technology Impact Factors (F2)

The sulfuric acid estimating methodology employs empirically

- derived Technology Impact Factors (F2). These F2 factors describe sulfate removal observed over the air heater, the ESP or other particulate control device, and FGD process equipment. Background information on these processes and the derivation of these F2 factors are addressed in this section.

**Air Heater**

The removal of SO 3 and/or H 2 SO 4 within the air heater is due to the condensation of sulfuric acid and its removal as discrete individual particles (along with the fly ash) on the surface of thi s 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 in4

- 17 conjunction with limestone injection as a proactive sulfuric acid control strategy (Hamel, 2003, and Bowes, 2006).

Air heater surfaces follow a pattern of alternately heating and cooling as the heat exchange
elements move from the r elatively hot flue gas to the cooler combustion air. As reported during field tests of commercial equipment (Saranuc, 1999), this temperature profile introduces a strong gradient in sulfuric acid concentration across the exit plane of the air heater. The c yclic thermal conditions as described by Hamel (2003) reveal that a significant portion of the air heater basket surface metal is exposed to flue gas temperature below the sulfuric acid dewpoint. This phenomenon may promote sulfuric acid deposition on the heat exchanger metal surface, compared to a tube

- type heat exchanger in which the metal temperature is always above the sulfuric acid dewpoint.

Figure 4

- 2 presents data obtained from a survey of power plant operators and general literature
sources describ ing SO 3 /H 2 SO 4 removal (and the corresponding F2 factors) across commercial, Ljungstrom

- type air heaters. These data are presented as a function of SO 2 content of the flue gas for the host unit. Most data shown are for low sulfur eastern bituminous coal, fo r which air
heater H 2 SO 4 removal varies significantly between 0% and 69%, averaging 50% as indicated by the horizontal line. Two high sulfur (>2.5%) eastern cases are shown, along with limited data for
PRB coal.

The data point showing 0% removal at approxi mately 600 ppm SO 2 is believed suspect, as an identical companion unit firing the same coal exhibited sulfuric acid capture of 38%. This
measurement was not included in the F2 calculation.

Figure 4

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

- fired unit where SO 3 was “spiked” into the flue gas to elevate the concentration entering the air heater to 80 and 122 ppm. These two points are plotted separately on Figure 4

- 2 versus an estimated flue gas SO 2 content that co uld generate such values (using the average SO 2 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 co al cases.4- 18 Figure 4-2 Removal of Sulfuric Acid by Ljungstrom

- Type Air Heaters

The F2 factor for the air heater, calculated as [1

– Percent Removal], is estimated excluding the “spiked” SO 3 and suspect 0% removal measurement. The F2 factors for the air heater for low sulfur eastern bituminous, medium-high sulfur eastern bituminous, and PRB coals are shown in
Table 4 -4. Data are not currently available for other coal types. For those coals, a s well as fuel oils, the model user could consider adopting the F2 factor for PRB if the ash is strongly alkaline and the low sulfur, eastern bituminous value if the ash is acidic.

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

Boiler Type Fuel F2 Standard

Deviation Comment

All Boilers Low S Eastern Bit 0.50 0.15 Average of measurements at 7 units.

All Boilers Med

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

All Boilers PRB 0.36 n/a Based on two data points.

The standard deviation of the reported measurements for low sulfur eastern bituminous coal is about one third of the average measurement. Inadequate data prevent calculating a standard
deviation for F2 factors for the other fuels. 0.0

0.1

0

. 2

0

. 3

0.4

0.5

0.6

0.7

0.8

0.9

1.0 0% 10% 20% 30% 40% 50% 60% 70 % 80 % 90% 100%

0 500 1000 1500 2000 2500 3000 3500Air Heater F2 FactorAir Heater H2SO4Removal, %

Flue Gas SO 2 Content, ppm High S East Bit, Dry Bottom Boiler
Low S East Bit, Dry Bottom Boiler

Hamel Full

- Scale Tests
PRB Dry Bottom Boiler

Series54

- 19 **Particulate and SO 3**  **Control Processes**

This section discusses the available data on removal of SO 3 by ESPs, FGDs, and alkali injection.

ESPs and Baghouses

An ESP provides extended residence time at relatively low temperatures, all owing 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 lo ngest residence time; for large units, usually 10 seconds and in some cases up to 15 seconds. Given the low flue gas velocities of 2 to 4 actual feet per second (0.6

– 1.2 meters per second), and the opportunity for heat loss at or near the walls, sulfuric acid condensation can be significant.

Figure 4

- 3 plots sulfuric acid removal by the ESP and the corresponding F2 factors as a function
of the SO 2 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 SO 2 is suspect, as a companion unit at the same site firing the identical coal had 50% s ulfuric acid removal. Accordingly, this “zero” removal datum, although shown in Figure 4

- 3, is not used in the analysis.

The F2 factor for the cold

- side ESP, calculated as [1

- Percent Removal], is estimated using all data except the 0% removal point. The F2 factors for ESP capture for low sulfur eastern bituminous, medium

- high sulfur eastern bituminous, and PRB coals are listed in Table 4

- 5. Data are not currently available for other coal types. Western subbituminous coals (e.g., non

- PRB)
could consider ad opting the F2 factor for PRB if the ash is strongly alkaline; western coals with acidic ash (e.g., bituminous) may consider adopting the low sulfur, eastern bituminous value. This guidance also applies to for fuel oils or any other coal that is not listed in the table.

Data describing the reduced H 2 SO 4 penetration for one hot

- side ESP (ESPh) is based on only a single test series. It should be noted that although this F2 factor is used for all coals, the measurement is from a power plant burning a low

- sulfur , eastern bituminous coal. Comparison
of F2 factors for a cold

- side ESP burning low and high sulfur eastern bituminous coals show a significant difference between the two coal types. As a result, total H 2 SO 4 releases for hot

- side ESP configurations may hav e a low bias; however there is insufficient data to recommend
alternate values.

The current model adds a F2 factor of 0.12 for a wet ESP, as shown in Table 4

- 5. Wet ESP’s operate in much the same manner as a traditional ESP; however, due to the lower opera ting temperature and saturated environment, higher power levels are achievable, resulting in higher collection efficiency for sulfuric acid mists. The new F2 factor is based on two sets of paired measurements, both of which demonstrated 88% sulfuric acid r emoval across the wet ESP. One data point was from a high sulfur, eastern bituminous, coal

- fired boiler and the other from a petroleum

- coke fired boiler. Flue gas SO 2 was not reported for these tests; therefore, the data points are not included in Figure 4

- 3. Until further data are available, EPRI recommends using a
wet ESP F2 factor of 0.12 for all fuels.

Baghouses show high H 2 SO 4 removal based on very limited data. The average of two data points
is 90% removal.4- 20 Figure 4-3 Removal of Sulfuric Acid by Cold

- Side ESPs and One Hot

- Side ESP

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

Equipment Type Coal Type F2

Factor Standard

Deviation Comment or Observation

Cold

- side

ESP Low S Eastern Bit 0.63 0.15 Average of measurements at 4 units.

Cold

- side

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

Cold

- side

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

Hot

- side ESP All 0.63 n/a Based on one measurement at one unit.

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

Baghouse Subbituminous coal 0.10 n/a Two data points.

* Change in factor from EPRI, 2010a. n/a

– not applicable

– too few points to calculate.

The standard deviation of the reported measurements for low sulfur eastern bituminous coal is about one fourth of the average measurement, while the standard deviation of the measurements for the high sulfur eastern bituminous coal is about one sixth of the average. Inadequate data prevent calculating a standard deviation for F2 factors for the other fuels. 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0 0% 10% 20% 30 % 40 % 50% 60% 70% 80% 90% 100%

0 500 1000 1500 2000 2500 3000 3500ESP F2FactorESP Flue Gas H2SO4Removal, %

Flue Gas SO 2 , ppm High S East Bit

Low S East Bit

ESPh Low S EastBit

PRB Dry Bottom Boiler4

- 21 **FGD**

FGD process equipment rapidly cools or quenches flue gas, condensing a significant portion of the sulfuric acid into submicron droplets that can escape the process environment, confounding capture. Buckley (2002) notes that for condensation to occur, sulfuric acid generally must be supersaturated. However, fly ash particles can provide a nucleus fo r 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 produci ng 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 th e 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 av erage of 50%.

Figure 4

- 4 summarizes data reported in the public domain and from utility

- specific tests describing FGD removal (and corresponding F2 factors) of sulfuric acid. The percent of sulfuric acid removal is depicted as a function of FGD inlet SO 2 c oncentration. Removals range from 14% to 78%, with an average of about 50%. The shaded portion of Figure 4

- 4 represents the upper and lower bounds of the data reported by Buckley (2002), while the solid horizontal line reflects the average reported by Sriv astava (2004).

Table 4

- 6 summarizes the F2 factors for FGD process equipment, including results for a wet spray tower burning bituminous coal, and also one burning a blend of PRB/lignite. Given the limited data, the latter is assumed to serve as the basis of an F2

- factor for 100% firing of PRB or lignite. Data for a wet venturi

- type combined particulate/FGD process is also available, but only for a bituminous coal. Similar to the case for a wet spray tower, the lack of data merits assuming
sulfuric acid r emoval for all coals is described by that measured for bituminous coal.

F2 factors for the use of magnesium

- based additives in oil

- fired boilers are also included in
Table 4

- 6. These additives are used to control furnace slagging caused by the vanadium in the oil or to control sulfuric acid emissions or both. The fuel oil vanadium can also catalyze SO 2 to SO 3 oxidation, but the additive, when added to the oil, tends to effectively bind up the vanadium, partially reducing its catalytic effect. Addition of ma gnesium

- based additives in the fuel oil tend to be less effective in controlling the emissions of sulfuric acid than the same additive sprayed
into the furnace downstream of the flame zone. Previous versions of the report had inadvertently changed the fact or for injection into the furnace to a value of 0.5; thus, the current version
corrects the value back to 0.25.4

- 22 Figure 4

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

Table 4

- 5 Summary of F2 Factors for Wet and Dry FGD Equipment and Additives

FGD Type Coal Type F2 Factor Standard

Deviation Comment or Observation

Wet: Spray Tower E. Bituminous 0.47 0.17 Seven data points.

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

Wet: Venturi Tower All coals 0.73* 0.13 Four data points from three units, bituminous coal only; limited data merit assigning same factor for
other coals.

Dry FGD and baghouse All coals 0.01 n/a Two data points.

Mg

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

Mg

- Ox into furnace All fuel 0.25** n/a One data point.

* Changes from 2010 version due to new data **Correction from previous versions (see text)5

- 1 

# 5

ESTIMATING GUIDELINE : MULTIPLE FUEL OR

BLENDED FUEL BOILERS

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

– such as natural gas, fuel oil, and perhaps coal

– uses the same approach as for single fuels. This will consist of determining the contribution of each source (combustion, SCR or SNCR NOx control, and FGC) for each different fuel, and adjusting for loss or removal. It is assumed for multiple
fuel boilers that the contribution of each fuel ca n 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 accoun ts for the role of alkalinity in PRB ash in mitigating SO 3 . 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 SO 3 emissions when considering PRB coal, in that it
wil l likely project H 2 SO 4 emissions higher than actual. The ability of PRB coal to neutralize SO 3 by an amount that is greater than a direct proportion of the coal blend is due to the extremely high content of alkaline material, particularly CaO. However, dat a 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 calcu lations 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

manufact ure 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 combus tion 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 release5

- 2 e. FGC manufacture

f. FGC release

3. Used oil

a. Combustion manufacture

b. Combustion release

c. SCR manufacture

d. SCR release

e. FGC manufacture

f. FGC release

4. Sum manufacture and releases

a. Manufacture

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

b. Release

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

All of the manufactured results would be summed together and the releases summed also to give the final result. Example 8 in Appendix A details this calculation procedure.6

- 1 

# 6

ESTIMATING GUIDELINE : COMBUSTION TURBINE S

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 t o 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 cyc le 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 t o approximately 3.5 ppm of sulfur in the raw natural gas.

A methodology to estimate manufacture and release of sulfuric acid for simple cycle and combined cycle units is provided below.

Manufacture and Release for Simple Cycle Units

Given the current conf iguration 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 sim ple cycle units can be equipped with SCR, and the use of SCR with sulfur

- containing fuels will
manufacture SO 3 , the exit gas temperature is too high to allow condensation of SO 3 or reaction with ammonia slip. Selective non

- catalytic reduction is not applied to simple cycle or combined cycle combustion turbines; therefore, no estimation procedure is provided for that configuration.

Accordingly, the equations for formation of sulfu ric acid from natural gas (NG) combustion are:

EM SC = K • F1 • E2 NG Equation 6

- 1

where,

EM SC = total H 2 SO 4 manufactured from combustion, lbs/ yr

K = Molecular weight and units conversion constant

= 98.07 / 64.04 • 2000 = 3,063

98.07 = Molecular weight of H 2 SO 4
64.04 = Molecular weight of SO 2

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

F1 = Fuel Impact Factor for NG6-2 E2 NG = Sulfur dioxide (SO 2 ) emissions either: (1) recorded by a continuous emissions monitor, tons/yr, or (2) calculated from fuel burn data, tons/yr.

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

E2 NG = K b • B NG • S Equation 6-2

where,

E2 NG = Total SO 2 production from NG combustion, tons/yr

K

b = Molecular weight and units conversion constant = 0.0001359

B NG = Burn of NG in Tbtu/yr

S = Sulfur content of natural gas, in grains per million standard cubic feet (Mscf), typically 2000 gr/10 6 scf per EPA AP -42.

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

The SO 2 emissions can also be calculated from the volume of natural gas burned:

E2 NG = K NG • N1 • S Equation 6-3

where,

E2 NG = total SO 2 production from NG combustion, tons/yr

K

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

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

S = NG sulfur content in grains per million standard cubic feet; use EPA’s value of 2000 gr/10 6 scf as default

The derivation of constant K NG is presented in Text Box E. Text Box D: Derivation of Molecular Weight and Units Conversion Constant, K b
K

b is determined from the following equation.

(K b • B NG • S) = tons SO 2 per yr =

B NG TBtu S gr S 1 scf nat

gas 10 12 Btu lb S 1 ton S 1 ton mol S 1 ton mole SO 2 64 tons SO 2

Year 10 6 scf
nat gas 1050 Btu TBtu 7000 gr

S 2000 lbs S 32 tons S 1 ton mol S 1 ton mole

SO 2 Grouping terms,

= (B NG • S) • 64 / (1050 • 32 • 14) = (B NG • S) • 0.0001359

Therefore, the va lue of K b is equal to 0.0001359 tons SO 2 /(TBtu • grains S/million SCF NG).6-3 Table 6

- 1 presents the F1 factors for simple 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 SO 3 ), the amount manufactured and released depends on stack temperature. Table 6-1 combines the temperature- based SO 3 to H 2 SO 4 conversion with the SO 2 to SO 3 conversion to give the Fuel Impact Factor, F1.

Table 6-1

Fuel Impact (F1) Factors for a Simple CT

Stack T, °F F1

300 0.055

400 0.055

500 0.047

600 0.022

700 0.0055

750 0.0027

800 0.0013

850 0.00071

900 0.00039

950 0.00022

1000 0.00013

1050 0.00008

1100 0.00005

1150 0.00003

1200 0.00002 Text Box E: Derivation of Molecular Weight and Units Conversion Constant, K NG (K NG • N1 • S) = tons SO 2 per yr =

N1 10 6 scf S gr S lb S 1 ton S 1 ton mol S 1 ton mole SO 2 64 tons SO 2

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

Grouping terms,

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

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

**Sulfuric Acid Manufactured**

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

SO 2 across catalyst used for NOx control and recently, oxidation of SO 2 across catalyst used for
CO control.

For combustion, the manufacture of sulfuric acid for combined-cycle units is described by Equation 6-4.

EM CCcom = K • F1 • E2 NG Equation 6-4

where,

EM CCcom = Total H 2 SO 4 manufactured from combustion, lbs/yr

K = Molecular weight and units conversion constant

= 98.07/64.04 • 2000 = 3,063

98.07 = Molecular weight of H 2 SO 4 ;

64.04 = Molecular weight of SO 2 ;

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

.

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

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

Recently, it has been shown that CO catalysts in combined cycle units can oxidize SO 2 to SO 3 in
a manner similar to SCRs. Equation 6- 5 describes the manufacture of sulfuric acid across the CO catalyst. For the case of combined cycle combustion turbines, the CO catalyst SO 2 oxidation rate (S3) will be approximately 0.1. This value is an estimate based on data from a prominent catalyst

ve ndor. A more accurate value can be obtained from field measurements of SO 2 oxidation, or from the vendor’s specification of the CO catalyst.

EM CC_CO = K • S3 • f COops • E2 Equation 6-5

where,

EM CC_CO = Total H 2 SO 4 manufactured from the CO catalyst, lbs per year

K = Molecular weight and units conversion constant

= 98.07/64.04 • 2000 = 3,063

98.07 = Molecular weight of H 2 SO 4
64.04 = Molecular weight of SO 2
2000 = Conversion from tons per year to pounds per year6

- 5 S3 = CO catalyst SO 2 oxidation rate (specified as a decimal, typically from

0.1

- 0.6)

f COops = Operating facto r of CO catalyst system, or the fraction of fuel burn when the flue gas is directed through the CO catalyst. This value should reflect the fraction of hours that the CO catalyst processed flue gas. This value
will be site

- specific but can be approximated a s 0.8 for year

- round peaking operation, 0.98 for year

- round base

- loaded operation, or 0.43 for seasonal operation.

E2 = SO 2 produced, tons per year

Equation 6

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

manufacture d due to SO 2 oxidation across the CO catalyst (EM CC_CO ) must be subtracted from the
total amount of SO 2 produced (E2), because the CO catalyst will reduce the amount available for conversion by the SCR catalyst. For the case of combined cycle combustion tu rbines, the SCR catalyst SO 2 oxidation rate (S2) will be approximately 0.03. A more precise value can be obtained from either field test reports of SO 2 oxidation, or from the vendor’s specification of the SCR catalyst or process. The Technology Impact Fact or for SCR, F3 SCR , will be 1.0.

EM CCSCR = [(K • E2)

- EM CC

- CO ] • f sops • S2 • F3 SCR Equation 6

- 6

where,

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

K = Molecular weight and units conversion constant

= 98.07/64.04 • 2000 = 3,063

98.07 = Molecular weight of H 2 SO 4 ;

64.04 = Molecular weight of SO 2 ;

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

E2 = SO 2 produced, tons per year

EM CC_CO = Total H 2 SO 4 manufactured from the CO catalyst, lbs per year

S2 = SCR catalyst SO 2 oxidation rate (specified as a decimal, typically from

0.001

- 0.03)

f

sops = Operating factor of SCR system, or the fraction of coal burn when the flue gas is directed through the SCR, whether NH 3 reagent is injected to derive
NOx reduction or not. This value should reflect the hours the SCR reactor

pro cessed 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

F3 SCR = Technology Impact Factor, for SCR (equal to 1.0, ref er to Table 4

- 2)6

- 6 The total sulfuric acid manufacture (TSAM) for a combined cycle unit is estimated using the equation below:

TSAM CC = EM C C com + EM CC_CO + EM CCSCR Equation 6

- 7

**Sulfuric Acid Released**

The sulfuric acid released by all sources in combined cycle units is estimated as shown in Equation 6

- 8. This equation takes into account the reducing effect of ammonia slip from the SCR equipment in a similar method as described in Section 4.:

TSAR CC = [TSA M CC – (K

s • B • f sreagent • S NH3 )] • F2

cc Equation 6

- 8

where,

TSAR CC = Total H 2 SO 4 released, lbs per year

TSAM CC = Total H 2 SO 4 manufactured from all sources, lbs per year

K

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

B = Fuel burn in Tbtu/yr

f sreagent = Fraction of SCR operation with reagent injection, when residual NH 3 is produced that will remove SO 3 .

S NH3 = NH 3 slip from SCR, ppmv at 6% O 2 , wet (averages 0.75 ppmv over catalyst guarantee period. Actual NH 3 slip data should be used if available)

F2 CC = Technology Impact Factor for the combined cycle heat exchanger, equal
to a value of 0.5.

Examples 9 and 10 of Appendix A illustrates a gas

- fired combined cycle plant calculation.7

- 1 

# 7

REFERENCES

Benson, 2006a Benson, L. et al. , “Uses of Lime for Controlling SO 3 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 SO 3 Emissions from Coal

- Fired Power Plan ts,” 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

- S ymposium, August, 2006, Baltimore, MD.

Buckley, 2002 Buckley, W.

, et al., “Acid Mist Causes Problems for FGD Systems

, ” Power Engineering, November, 2002.

Dahlin, 1991 Dahlin, R., et al., “Control of Acid Mist Emissions From FGD Systems

, ” paper presented to the EPRI

- EPA

- DOE 1991 SO 2 Control Symposium, Washington, DC, December, 1991

.
Dombrowski,

2004 Dombrowski, K. et al., “ SO 3 Mitigation Guide and Cost

- Estimating Workbook,” Proceedings of the Combined Power Plant Air Pollution Control Mega

- Symposium, August 30

- September 2, 2004, Washington,

DC.

EPA, 1991 EPA Code of Federal Regulations 40, Part 60, Appendix A, Method 1,
Sectio n 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: Sta tio nary 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 Aci d (acid aerosols including mists vapors, gas, fog, and other airborne forms of any particle size). EPA

- 745

- R

- 97

- 007, November 1997.

EPA, 1999 40 CFR Part 60, Appendix A, Method 2H

- Determination of Stack Gas Velocity Taking into Account Velocity Decay Near the Stack Wall.7

- 2 EPA, 2009 Federal Register, Vol. 74, No. 163, Tuesday, August 25, 2009, 40 CFR

Part 60

- Revisions to Test Method for Det ermining Stack Gas Velocity Taking Into Account Velocity Decay Near the Stack Walls.

EPRI, 2001 EPRI Report 1004027, “Flue Gas Sulfuric Acid Measurement Improvements,” August, 2001.

EPRI, 2008

EPRI, 2010a

EPRI, 2010b Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, EPRI, Palo Alto, CA: 2008. 1016384. (revised April, 2009)

Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, EPRI, Palo Alto, CA: 2010

. 1020636.

Operation and Mainte nance Guidelines for Selective Catalytic Reduction: 2010 Update. EPRI, Palo Alto, CA: 2010. 1019707.

Gale, 2006 Gale. T., et al., “Hydrated Lime for SO 3 Removal,” Proceedings of the Power Plant Air Pollutant Control “Mega Symposium”, Baltimore, MD, August, 2006.

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

, ” Proceedings of the Combined P ower Pl ant 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 Depar tment, 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 & Environme ntal Affairs Department, Southern Company Services, October, 2005.

Lindenhoff, 2004 Lindenhoff, Peter, “SCR Catalyst Developments: SO 2 Oxidation,” presentation to the EPRI 2004 Workshop on Selective Catalytic Reduction, November, 2004, Pittsburgh, PA.

Monroe, 200 1 Monroe, L. and K. Harrison, “An Updated Method for Estimating Total Sulfuric Acid Emissions from Stationary Power Plants : Revision 1, ”7

- 3 White Paper Issued by Souther n 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., “SO 3 ’s Impact on Plant O&M: Part III,” Power Magazine, April, 2007.

Ritzenthaler, 2006 Ritzenth aler, D. et al., “A System Approach to SO 3 Mitigation With Trona,” Proceedings of the Power Plant Air Pollutant Control “Mega Symposium”, Baltimore, MD, August, 2006.

Saranuc, 1999 Saranuc, N.

, et al., “Factors Affecting Sulfu ric Acid Emissions From
Boile rs,” Proceedings of the Combined Power Plant Air Pollutant Control Mega Symposium, Atlanta, GA, August, 1999

.
Senior, 2002 Senior, C.L., et al., “ Simulation of SO 3 Production

, ” Fuel Processing Technology, 2000, 63, 197

- 213

.
Srivastava, 2004 Srivastava, R.

, et al., “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 SO 3 Control,” Proceedings of the Combined Power Plant Air Pollution Control Mega

Symposium, 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 SO 2 /yr

EM Comb = K • F1 • E2

F1 eastbit = 1.1163E-6 • SO2 + 0.0064876

ppm HV K SSO F 1667 000,12 602,003,10 0.21 1 2 =

•=•=

F1 eastbit = 1.1163E-6 • 1667 + 0.0064876 = 0.0083

EM Comb = 3063 • 0.0083 • 42,824 = 1,088,710 lbs H 2 SO 4 /yr

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and the result reported on Form R.

Released

TSAR = EM Comb • F2 APH • F2 ESP

TSAR = 1,088,710 • 0.50 • 0.63 = 342,94 4 lbs H 2 SO 4 /yrA

- 2 Example 2: SCR Added to Example 1

A 500 MW PC boiler, equipped with a cold

- side electrostatic precipitator, burns an Eastern bituminous coal. The plant is equipp ed 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

SO 2 oxidation rate specified in the design is 0.75%, and the ammonia slip is estimated to be 0.75 ppmv. The c oal 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 SO 2 /yr

Combustion

EM comb = K • F1 • E2

F1 eastbit = 1.1163E

- 6 • SO2 + 0.0064877

ppm HV K S SO F 1667 000

, 12 602

, 003

, 10 0

. 2 1 1 2 = • = • =

F1 eastbit = 1.1163E

- 6 • 1667 + 0.0064877 = 0.0083

EM Comb = 3063 • 0.0083 • 42,824 = 1,088,710 lbs H 2 SO 4 /yr

SCR

EM SCR = K • S2 • f

s • E2

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

Total

TSAM = EM comb + EM SCR

TSAM = 1,088,710 + 423,023 lbs H 2 SO 4 /yr

TSAM = 1,511,733 lbs H 2 SO 4 /yr

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and the result reported on Form R.

Released

Coal Burn

B = C1 • HV • K BA

- 3 B = 1,126,938 tons/yr • 2000 lbs/ton • 12,000 Btu/lb • 1 Tbtu/10 12 Btu

B = 27.05 Tbtu/yr

Ammonia Slip

NH3 SCR = K

s • B • f sreagent • S NH3

NH3 SCR = 3799 • 27.05 • 0.43 • 0.75 = 33,141 lbs NH 3 /yr

Total Releases
TSAR = [(EM Comb + EM SCR/SNCR )

– (NH3 SCR )] • F2 APH • F2 ESP

TSAR = [( 1,088,710 + 423 ,023 )

– ( 33,141 )] • 0.50 • 0.63

TSAR = 465,75 6 lbs H 2 SO 4 /yrA-4 Example 3: Alkali Injection Added to Example 1

A 500 MW PC boiler, equipped with a cold-side electrostatic precipitator, burns an Eastern bituminous coal. The plant employs injection of alkali material (e.g., lime, sodium bicarbonate, sodium bisulfate, etc.) to control SO 3 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 SO 3 concentration at the stack. The test contractor has issued a report defining the amount of
alkali that should be added to limit the stack SO 3 to 5 ppm, as measured in the flue gas at 6.6%

O 2 , and 8.8% moisture. The alkali injection system will be operated throughout the entire year, so that no more than 5 ppm of SO 3 at the stated conditions of excess O 2 and moisture exist in the
stack.

The coal burn rate in the reporting year is 1,126,938 tons, with a weighted average sulfur concentration of 2.0%, and a heating value of 12,000 Btu/lb.

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

**Solution**

Manufactured

E2 = K1 • K2 • C1 • S1

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

Combustion

EM comb = K • F1 • E2

F1 eastbit = 1.1163E-6 • SO 2 + 0.0064877

ppm1667 000,12 602,003,10 0.2 HV K 1S2 SO 1F

= •=•=

F1 eastbit = 1.1163E-6 • 1667 + 0.0064877 = 0.0083

EM Comb = 3063 • 0.0083 • 42,824 = 1,088,710 lbs H 2 SO 4 /yr

SCR

EM SCR = K • S2 • f

s • E2

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

Total

TSAM = EM comb + EM SCR

TSAM = 1,088,710 + 423,023 lbs H 2 SO 4 /yr

TSAM = 1,511,733 lbs H 2 SO 4 /yr

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and
the r esult reported on Form R.A

- 5 Released

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

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

- 15

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

x where,

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

K alkali = Constant, equal to 3,799, with units of lbs H 2 SO 4 /(Tbtu ppmv SO 3 ) (SO 3 measured at @ 6% O 2 and 8.1% H 2 O)

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

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

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

F2

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

The conversion factor K alkali is equal to 3,799 (see Text Box B). This constant is derived for the case where flue gas SO 3 is reported in terms of 6% oxygen and wet flue gas at 8.1% H 2 O. However, the SO 3 concentration of 5 ppm in the stack is measured at slightly different conditions
of excess O 2 and moisture (6.6% oxygen and 8.8% moisture and therefore, a new value of K alkali must be calculated:

K alkali (O 2 , H 2 O ) = 3799 (6% O 2 , 8.1% H 2 O) • [(100

- 8.1)/(100

- new H 2 O)]

• [(20.9

– 6.0)/(20.9

– new O 2 )]

K alkali (O 2 , H 2 O ) = 3799 (6% O 2 , 8.1% H 2 O) • [(100

- 8.1)/(100

- 8.8)]

• [(20.9

– 6.0)/(20.9

– 6.6)]

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

K alkali (6.6%, 8.8%) =3958

Total sulfuric acid release is then calculated as follows:

ER ALKINJ = [ 3,958 ] • [27.05] • [5. 0 ] • [1] • [1]

ER ALK INJ = 535,320 lbs/yr

TSAR = ER ALKINJ

T SAR = 535,320 lbs/yrA-6 Example 4: 500 MW PRB

- fired Boiler with ESP, SCR

A 500 MW PC boiler, equipped with a cold- side electrostatic precipitator, burns a PRB coal. The plant is equipped with an SCR process that operates during the ozone season only, so that 0.43 of the coal burn occurred with the SCR operating. The SCR catalyst SO 2 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 SO 2 /yr

Combustion

EM comb = K • F1 • E2

EM comb = 3063 • 0.0019 • 9,692 = 56,405 lbs H 2 SO 4 /yr

SCR

EM SCR = K • S2 • f

s • f 3SCR • E2

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

Total

TSAM = EM comb + EM SCR

TSAM = 56,404 + 43,402 lbs H 2 SO 4 /yr

TSAM = 99,806 lbs H 2 SO 4 /yr

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and the result reported on Form R.

Released

Coal Burn

B = C1 • HV • K B

B = 1,384,552 tons/yr • 2000 lbs/ton • 8,500 Btu/lb • 1 Tbtu/10 12 Btu

B =23.54 Tbtu/yr

Ammonia Slip

NH3 SCR = K

s • B • f sreagent • S NH3

NH3 SCR = 3799 • 23.54 • 0.43 • 0.75 = 28,841 lbs NH 3 /yrA

- 7 Total Releases
TSAR = [(EM Comb + EM SCR/SNCR )

– (NH3 SCR )] • F2 APH • F2 ESP

TSAR = [( 56,404 + 43,402 )

– (28,841 )] • 0.36 • 0.72

TSAR = 18,394 lbs H 2 SO 4 /yrA

- 8 Example 5: FGC Added to Example 1

A 500 MW PC boiler, equipped with a cold

- side electrostatic precipitator, burns an Eastern bituminous coal. The plant is equipped with a FGC process that injects both SO 3 and NH 3 upstream of the air preheater. The SO 3 is injected at 7 ppmv at 6% O 2 wet, and the ammonia at 3 ppmv also at 6% O 2 wet. The FGC system operates whenever the plant is on, except during startup and shutdown, with an operating factor estimated at 0.9. The coal used in the reporting year is 1,126,938 tons with a weighted average sulfur concentration of 2.0% and a heating value of 12,000 Btu/lb.

**Solution**

Manufactured

E2 = K1 • K2 • C1 • S1

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

Combustion

EM Comb = K • F1 • E2

F1 eastbit = 1.1163E

- 6 • SO 2 + 0.0064877

ppm HV K S SO F 1667 000

, 12 602

, 003

, 10 0

. 2 1 1 2 = • = • =

F1 eastbit = 1.1163E

- 6 • 1667 + 0.0064877 = 0.0083

EM Comb = 3063 • 0.0083 • 42,824 = 1,088,710 lbs H 2 SO 4 /yr

FGC

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

B = 27.05 Tbtu/yr

EM FGC = K

e • B • f

e • I

s • F3 FGC

EM FGC = 3799 • 27.05 • 0.9 • 7 • 1 = 647,407 lbs H 2 SO 4 /yr

Total

TSAM = EM Comb + EM FGC
TSAM = 1,088,710 + 647,407 lbs H 2 SO 4 /yr

TSAM = 1,736,117 lbs H 2 SO 4 /yr

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and the result reported on Form R.A

- 9 Released

Coal Burn

B = C1 • HV • K B

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

B = 27.05 Tbtu/yr

FGC A mmonia Injection

NH3 FGC = K

e • B • f

e • I NH3

NH3 FGC = 3799 • 27.05 • 0.9 • 3.0 = 277,460 lbs NH 3 /yr

Total Releases
TSAR = [(EM Comb + EM FGC )

– (NH3 FGC )] • F2 APH • F2 ESP

TSAR = [( 1,088,710 + 647,407 )

– ( 277,460 )] • 0.50 • 0.63

TSAR = 4 59

, 477 lbs H 2 SO 4 /yrA

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

A 500 MW PC boiler, equipped with a cold

- side electrostatic precipitator, burns an Eastern bituminous coal. The plant is equipped with an SCR process that operates during the ozone

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

SO 2 oxidation rate specified in the design is 0.75%, and the ammonia slip is estimated to be 0.75 ppmv. The plant is also equipped with a FGC process that injects b oth SO 3 and NH 3 upstream of the air preheater. The SO 3 is injected at 7 ppmv at 6% O 2 wet, and the ammonia at 3 ppmv also at

6% O 2 wet. The FGC system operates whenever the plant is on, except during startup and shutdown, with an operating factor estimated at 0.9. The coal used in the reporting year is 1,126,938 tons with a weighted average sulfur concentration of 2.0% and a heating value of 12,000 Btu/lb.

**Solution**

Manufactured

Tota l (from previous examples)

TSAM = EM Comb + EM SCR + EM FGC

TSAM= 1,088,71 0 + 423,023 + 647,407 lbs H 2 SO 4 /yr

TSAM = 2,159,14 0 lbs H 2 SO 4 /yr

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and the result reported on Form R.

Released

Total Releases (from previous examples)

TSAR = [(EM Comb + EM SCR + EM FGC )

– ( NH3 SCR + NH3 FGC )] • F2 APH • F2 ESP

TSAR = [( 1,088,71 0 + 423,023 + 647,407 )

– ( 33,141 + 277,460 )] • 0.50 • 0.63

TSAR = 582,290 lbs H 2 SO 4 /yrA

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

A 500 MW PC boiler, equipped with a cold

- side electrostatic precipitator, burns an Eastern bituminous coal. The plant is equipped with an SCR process that operates during t he ozone season only, so that 0.43 of the coal burn occurred with the SCR operating. The SCR catalyst

SO 2 oxidation rate specified in the design is 0.75%, and the ammonia slip is estimated to be 0.75 ppmv. The plant is also equipped with a FGC process that injects both SO 3 and NH 3 downstream

of the air preheater. The SO 3 is injected at 7 ppmv at 6% O 2 wet, and the ammonia at 3 ppmv
also at 6% O 2 wet. The FGC system operates whenever the plant is on, except during startup and shutdown, with an operating factor estimated at 0.9. The coal used in the reporting year is 1,126,938 tons with a weighted average sulfur concentration of 2.0% and a heating value of 12,000 Btu/lb.

**Solution**

Manufactured

Tota l (from previous examples)

TSAM = EM Comb + EM SCR + EM FGC

TSAM= 1,088,71 0 + 423,023 + 647,407 lbs H 2 SO 4 /yr

TSAM = 2,159,14 0 lbs H 2 SO 4 /yr

The 25,000 lbs/yr threshold has been exceeded; therefore, a release estimate must be made and the result reported on Form R.

Released

Total Releases (from previous examples)

TSAR = {[(EM Comb + EM SCR )

– NH3 SCR ] • F2 APH + (EM FGC_afterAPH – NH3 FGC_afterAPH )} • F2 ESP
Check that subtotal from upstream sources is positive:

TSAR upstream = [( 1,088,71 0 + 423,023 )

– 33,141 ] = 1,478,592 > 0

TSAR = [( 1,088,71 0 + 423,023 )

– 33,141 ] • 0.50 + (647,407

– 277,460)} • 0.63

TSAR = 698,823 lbs H 2 SO 4 /yrA- 12 Example 8: Coal

- Fired Boiler with FGC, NG Startup Fuel, and Used Oil Co

- Firing

A 500 MW PC boiler, equipped with a cold-side electrostatic precipitator, burns an Eastern bituminous coal as the main fuel. The plant is equipped with an SCR process that operates during the ozone season only, so that 0.43 of the coal burn occurred with the SCR operating. The SCR catalyst SO 2 oxidation rate specified in the design is 0.75%, and the ammonia slip is estimated to be 0.75 ppmv. The plant is also equipped with a FGC process that injects both SO 3 and NH 3 upstream of the air preheater. The SO 3 is injected at 7 ppmv at 6% O 2 wet, and the ammonia at 3 ppmv also at 6% O 2 wet. The FGC system operates whenever the plant is on, except during startup and shutdown, with an operating factor estimated at 0.9. The coal used in the reporting year is 1,126,938 tons with a weighted average sulfur concentration of 2.0% and a heating value of 12,000 Btu/lb. Natural gas is used as a startup fuel, w ith 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

Manufacture d from coal

Total (from previous examples)

TSAM = EM Comb + EM SCR + EM FGC

TSAM= 1,088,710 + 423,023 + 647,407 lbs H 2 SO 4 /yr

TSAM = 2,159,140 lbs H 2 SO 4 /yr

Released from coal

Total Releases (from previous examples)

TSAR coal = 582,290 lbs H 2 SO 4 /yr

Natural gas fuel calculations

Manufacture d from natural gas

Combustion

E2 NG = K b • B NG • S

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

E2 NG = 0.136 tons SO 2 /year

EM Comb = K • F1 • E2 NG

EM Comb = 3063 • 0.01 • 0.136

EM Comb = 4.17 lbs H 2 SO 4 manufacturedA- 13 No sulfuric acid is manufactured in either the SCR or FGC.

Released from natural gas

Total Releases

TSAR NG = EM Comb • F2 APH • F2 ESP

TSAR NG = 4.17 • 0.50 • 0.63

TSAR NG = 1.31 lbs H 2 SO 4 /yr

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

Used oil fuel calculations

Manufactured from used oil

Combustion

E2 = K1 • K2 • C1 • S1

E2 = 0.02 • 1.0 • 483.2 • 0.1

E2 = 0.966 tons SO 2 /year

EM Comb = K • F1 • E2

EM Comb = 3063 • 0.0175 • 0.966

EM Comb = 51.8 lbs H 2 SO 4 manufactured

SCR

EM SCR = K • S2 • f

s • E2

EM SCR = 3063 • 0.0075 • 1.0 • 0.966

EM SCR = 22.2 lbs H 2 SO 4 manufactured

FGC

EM FGC = K

e • B • f

e • I

s • F3 FGC

EM FGC = 3799 • 0.0185 • 1.0 • 7.0 • 1

EM FGC = 492 lbs H 2 SO 4 manufactured

Total Manufactured

TSAM = EM Comb + EM SCR + EM FGC

TSAM = 51.8 + 22.2 + 492 lbs H 2 SO 4 /yr

TSAM = 566 lbs H 2 SO 4 /yrA- 14 Released from used oil

Ammonia Slip

NH3 SCR = K

s • B • f sreagent • S NH3

NH3 SCR = 3799 • 0.0185 • 1.0 • 0.75 = 52.7 lbs NH 3 /yr

FGC A mmonia Injection

NH3 FGC = K

e • B • f

e • I NH3

NH3 FGC = 3799 • 0.0185 • 1.0 • 3.0 = 211 lbs NH 3 /yr

Total Releases

TSAR oil = [(EM Comb + EM SCR + EM FGC ) – ( NH3 SCR + NH3 FGC )] • F2 APH • F2 ESP

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

TSAR oil = 95 lbs H 2 SO 4 /yr

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

Grand totals for all fuels

Manufactured

TSAM = TSAM coal + TSAM NG + TSAM oil

TSAM = 2,159,140 + 4.17 + 566 lbs H 2 SO 4 /yr

TSAM = 2,159,710 lbs H 2 SO 4 /yr

Released

TSAR = TSAR coal + TSAR NG + TSAR oil

TSAR = 582,290 + 1.31 + 95 lbs H 2 SO 4 /yr

TSAR = 582,386 lbs H 2 SO 4 /yrA

- 15 Example 9: Natural Gas Combined Cycle Plant

A natural gas

- fired combined

- cycle unit uses 12.3 Tbtu /yr. of natural gas, with the standard
sulfur content.

**Solution**

Manufactured

E2 NG = K b • B NG • S

E2 NG = 0.0001359 • 12.3 • 2000

E2 NG = 3.343 tons SO 2 /yr

Combustion

EM CC = K • F1 • E2 NG

EM CC = 3063 • 0.0555 • 3.343

EM CC = 568 lbs H 2 SO 4 /yr

Released

TSAR NG = EM Comb • F2 CC

TSAR NG = 568 • 0.5

TSAR NG = 284.5 lbs H 2 SO 4 /yr

F2 CC = 0.5 because the low temperature of the back

- end tubes of the HRSG act like an air heater.A

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

A natural gas

- fired combined

- cycle unit uses 12.3 Tbtu /yr. of natural gas, with the standard sulfur content. The plant is equipped with an SCR process that operates continually (operating factor of 1.0). The SCR catalyst SO 2 oxidation rate specified in the design is 2.0%, and the ammonia slip is estimated to be 0.75 ppmv. The plant is also equipped with a CO catalyst, which also is in continuous operation, and has an estimated SO 2 oxidation rate of 10%.

**Solution**

Manufactured

E2 NG = K b • B NG • S

E2 NG = 0.0001359 • 12.3 • 2000

E2 NG = 3.343 tons SO 2 /yr

Combustion

EM CC = K • F1 • E2 NG

EM CC = 3063 • 0.0555 • 3.343

EM CC = 568 lbs H 2 SO 4 /yr

CO Catalyst

EM CC_CO = K • S3 • f C O ops • E2

EM CC_CO = 3063 • 0.1 • 1.0 • 3.343

EM CC_CO = 1024 lbs H 2 SO 4 /yr

SCR

EM CCSCR = [(K • E2)

- EM CC

- CO ] • f

sops • S2 • F3 SCR

EM CCSCR = [(3063 • 3.343)

– 1024] • 1.0 • 0.02 • 1.0

EM CCSCR = 184 lbs H 2 SO 4 /yr

Total

TSAM CC = EM Comb + EM CC_CO + EM SCR

TSAM CC = 568 + 1024 + 184

TSAM CC = 1776 lbs H 2 SO 4 /yr

Released

TSAR CC = [TSAM

– (K

s • B • f sreagent • S NH3 )] • F2

cc

TSAR CC = [ 1776

– ( 3799 • 12.3 • 1.0 • 0.75 )] • 0.5

TSAR CC =

- 16,635 = 0 lbs H 2 SO 4 /yrA

- 17 The total releases are zero because the actual result is a negative value, indicating that the ammonia slip is greater than the sulfuric acid, thereby forming ABS, which is not reportable.

F2 CC = 0.5 because the low temperature of the back

- end tubes o f th e HRSG act like an air heater.B

- 1 

# B

CHRONOLOGY OF CHANGE S TO EPRI SULFURIC

ACID ESTIMATION MODE L

EPRI, 2012 (EPRI Report 1023790)

Modification Description SCR Factor (F3 SCR ) Changes made to Table 4

- 2 to clarify proper use of the F3 SCR factor Alkali Injection Changed description of F alkali such that it is fraction of coal burn instead of fraction of operating year, to be consistent with other operating factors
Added alternat e approach for calculating releases with alkali injection to be used if the utility does not have measured data.

F3 ALKINJ factor is introduced.

Total Sulfuric Acid Release Methodology (TSAR) Reorganized release equations such that sources are summed upstream of the APH and ammonia from SCR/SNCR is applied to reduce releases based on ABS formation, then the F2 factor for the APH is applied. Then, any downstream source of SO 3 or ammonia from downstream FGC is added, followed by application of all remain ing F2 factors. FGC Factor (F3 FGC ) Corrected the F3 FGC factor. The F3 FGC factor was introduced in the 2001 version of the report, but as actual data has become available to update the F2 factors, the F3 FGC factor has become
outdated. F3 FGC will now accou nt only for alkalinity in PRB coal, and be applied directly to the manufacture equation.

Combined Cycle Introduced a potential third source of sulfuric acid manufacture and release from oxidation across CO catalysts Technology Factors (F2) Added Wet ESP, all fuels: 0.1 Changed FGD, venturi, all coals from 0.65 to 0.73 (2 new data points) Updated and corrected Figure 4

- 4 to reflect two new data points, change the shaded area to reflect the proper data range, and deleted an inaccurate PRB/lignite data p oint Changed the F2 factor in Table 4

- 6 for Mg

- Ox into furnace from 0.5 to 0.25 to rectify an error introduced in the 2004 version of the report Examples Updated examples to account for new release equation methodologyB-2 EPRI, 2010a (EPRI Report 1020636)

Modification Description Fuel Impact Factor (F1) Combined low and high

- sulfur eastern bituminous coals into a single category with a linear curve fit. F1 factor based on fuel SO 2 content calculated from fuel sulfur content:

F1 ebit = 1.1163E-6 • SO 2 + 0.0065 Changed the following F1 factors based on additional data: Subbit/PRB – changed from 0.0018 to 0.0019 Lignite

– changed from 0.0048 to 0.0044 Technology Factors (F2) Changed factors for APH and ESP due to addition and re

evaluation of da ta: APH, low -sulfur east. bit. – changed from 0.49 to 0.50 APH, PRB – changed from 0.56 to 0.36 ESP, low-sulfur east. bit – changed from 0.49 to 0.63 ESP, PRB

– changed from 0.73 to 0.72 Alkali Injection Added a procedure to determine total releases from partial year injection. Incorporated correction to alkali injection conversion factor, K alkali Report Organization Moved F2 Factors from Section 3 to Section 4 Examples Updated examples to account for new F1 and F2 factors

EPRI, 2008 (EPRI Report 1016384 )

Modification Description Alkali Injection Added a procedure to estimate a stack release using a measured or specified stack gas SO 3 concentration, to support estimates on units with alkali injection. Errata page published to correct error in alkali injection conversion factor, K alkali Combustion Turbines Clarified procedures for estimating emissions from simple and combined cycle CTs.

Blended Coals New method calculates SO 3 manufacture by calculating the SO 3 emission rate separately for each of the component coals, and proportioning the contribution of SO 3 from each. The prior
method assumed the SO 3 production was the same as that of the major coal component. Examples Provided new example calculations for alkali injection and
blended coal.B

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

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

format. Fuel (F1) Factors Changed the following F1 factors based on additional data: Low S E. Bit, Dry Bo iler

– 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, F3 SCRElectric Power Research Institute 3420 Hillview Avenue, Palo Alto, California 94304

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