Estimating Total Sulfuric Acid Emissions

from Stationary Power Plants:  Revision 3 (2005)

Keith E. Harrison and Larry S. Monroe, Ph.D.

Research and Environmental Affairs

Southern Company Generation

Post Office Box 2641

Birmingham, AL  35291

J. Edward Cichanowicz

Consultant

236 N. Santa Cruz Ave., Suite #202

Los Gatos, CA  95030

October  2005

Estimating Total Sulfuric Acid Emissions

from Stationary Power Plants:  Revision 3 (2005)

SECTION	TOPIC	PAGE

1	Executive Summary	3

2	Introduction 	4

3	Measurement Uncertainty 	6

4	Background and Methodology Overview	8

5	Estimating Guideline:  Steam Boilers	17

6	Estimating Guideline:  Multiple Fuel Boilers	27

7	Estimating Guideline:  Combustion Turbines	28

8

	References	31

Appendix A	Example Calculations

	32

SECTION 1

EXECUTIVE SUMMARY

This paper presents a third update to the Southern Company method of
estimating both the manufacturing threshold value and release of
sulfuric acid (H2SO4) from stationary utility sources.  The U. S.
Environmental Protection Agency’s Toxic Release Inventory (TRI)
reporting system requires that, beginning in 1998, electric utilities
estimate their emissions of over 600 chemical compounds.  Sulfuric acid
is one of the compounds included in the TRI requirement.  EPA defines
sulfuric acid aerosols as “includ[ing] mists, vapors, gas, fog, and
other airborne forms of any particle size.”  This 2005 update
addresses both dry-bottom and cyclone–fired boilers, oil- and
gas-fired boilers and turbines, and accounts for the influence of
emissions control equipment effects on sulfuric acid manufacture and
release.  The most notable of the latter is the manufacture of sulfuric
acid by selective catalytic reduction processes installed for NOx
emissions control, and by flue gas conditioning systems used to assist
electrostatic precipitators.

The methodology remains unchanged: first calculating the combustion
manufacture and release estimates, and then the contribution to
manufacture and release by SCR or flue gas conditioning systems in use.
This approach is repeated for each fuel utilized at the site for the
year, with the results summed to yield the final values.

This update includes data submitted by approximately 15 utilities to
improve the accuracy and depth of the database.  Inherent to this
approach is a wide variety in the uncertainty of the data – many
results were obtained in the last 1-2 years with test crews experienced
with the controlled condensation system measurement methodology.
However, some of the data contributed is 5 years old or greater, and
quality assurance/quality control actions (if any) are unknown.  As a
consequence, the uncertainty in the data could be as high as +/- 50 %.

As with all generalized estimating procedures, this approach and the
various suggested factors may not be appropriate for every installation.
 When site-specific data are available, they should obviously be used in
place of the estimates derived with this method.  Any data that either
confirm or contradict the predictions of this method are desired by the
authors in order to increase the accuracy of the predictions.  Southern
Company offers this method as a guideline only and expressly offers no
warranty for the method and consequently does not assume any
responsibility or liability resulting from the use of this procedure.

SECTION 2

INTRODUCTION

BACKGROUND

The ability to estimate sulfuric acid emissions from power plants is a
topic of increasing importance to the U.S. utility industry. Most
significantly, Section 313 of the Emergency Planning and Community
Right-to-Know Act (EPCRA), also known as the Toxic Release Inventory
(TRI), requires facilities that “manufacture,” “process,” or
“otherwise use” a listed chemical above certain threshold amounts to
report their annual releases of the chemical to EPA and state agencies.
For sulfuric acid in general, the TRI reporting requirements are
triggered if a facility “manufactures” or ”processes” more than
25,000 pounds of this chemical or “otherwise uses” more than 10,000
pounds of it in a given calendar year.

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

As of July 1, 1999, certain coal- and oil-fired electric power plants
are required to report annual releases of TRI chemicals that they
manufacture, process or otherwise use above threshold amounts.  Under
EPA’s EPCRA § 313 regulations, coal- and oil-fired electric
utilities are deemed to “manufacture” sulfuric acid.  Thus, electric
utilities will have to submit TRI reports on sulfuric acid releases if
they “manufacture” more than 25,000 pounds of the chemical in a
given reporting year (EPA, 1997).

Significantly, emissions of sulfuric acid have received considerable
attention in recent years with the broad application of selective
catalytic reduction (SCR) NOx control technology.  The use of SCR
unavoidably contributes to production of sulfur trioxide (SO3), the key
precursor of sulfuric acid.   Several notable incidents have been
witnessed where an increase in sulfuric acid emissions, as manifested by
an increase in stack plume visibility, and was believed to be
attributable to the presence of newly retrofit SCR process equipment.
The deployment of approximately 100 GW of SCR from 1997 through 2004 has
prompted utility owners to conduct extensive measurements documenting
the fate of SO3 and sulfuric acid.

OBJECTIVE

The objective of this document is to present an updated methodology for
estimating sulfuric acid emissions from power generating facilities.
Although the scope of units considered includes coal and oil-fired steam
generating units, as well as simple cycle and combined cycle natural gas
and oil-fired combustion turbines, most of the revisions focus on
coal-fired steam generators.  This focus 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.

This document represents an update of previous papers published by
Southern Company detailing a predictive method for estimating sulfuric
acid manufacture and emissions from coal-fired power plants (Hardman,
1998; Hardman, 1999; Monroe, 2001).  In general, the methodology
employed by this predictive technique is unchanged.  The number of data
points employed in the correlations has increased, consistent with the
availability of data.

This report updates the state of understanding by reporting the results
of field trials by various utilities.  Section 3 addresses measurement
uncertainty inherent to this method and the controlled condensation
system.  Section 4 outlines the general methodology adopted and
summarizes recent data procured describing the removal of sulfuric acid
across air heaters, ESPs, and wet flue gas desulfurization (FGD) process
equipment.  Section 5 describes the details of the methodology,
including the data that predicts manufacture by combustion, and outlines
the calculation for including the role of the air heater and emissions
control equipment.  Section 6 outlines how to conduct the calculation
for steam boilers firing a mixture of fuels.  Section 7 addresses both
simple cycle and combined cycle combustion turbine applications.
Example calculations for many cases are presented in the Appendix.

SECTION 3

MEASUREMENT UNCERTAINTY

A predictive method for sulfuric acid emissions requires knowledge of
sulfuric acid production and the fate of emissions from specific boilers
and combustion turbines, to an acceptable degree of measurement
accuracy.   In addition, a large database of units is desired to
generalize a correlation reflecting the broad population of generating
units.  Both of these factors are key to developing a usable predictive
method.

The predictive correlations presented in this report are based on data
obtained from field tests conducted predominantly in the last 1-2 years,
with some estimates conducted 5-7 years ago.  The quality of the
information is believed to vary widely, as it was not practical to
critically review the measurement methods employed by the various
inputs.  The specific technique used to measure SO3/H2SO4 is not known
for all sources, but most measurements were conducted using the
Controlled Condensation System (CCS), a widely used technique.

SO3/H2SO4 MEASUREMENT ACCURACY

The ability of the CCS to measure SO3/H2SO4 is notoriously uncertain,
due to the numerous steps which introduce opportunities for error into
the measurement.  A recent series of field and laboratory trials
conducted by EPRI evaluated the measurement bias of the CCS technique by
comparing results from both laboratory tests and field trials (EPRI,
2001).  Specifically, SO3/H2SO4 measurements at similar gas compositions
were compared in a (1) clean, ash-free laboratory environment; (b)
simulated ash environment, and (c) actual field duty.

The results showed the CCS technique imposed a bias low (e.g. indicating
lower SO3/H2SO4 than actual), due to reactions of SO3 or sulfuric acid
in the filter thimble holder.  The bias depended on several factors,
among them the location of the measurement – either the air heater
inlet, air heater outlet, or flue gas desulfurization outlet.   Further,
the bias depended on the quantity of ash collected, the alkalinity of
the ash, and the coal sulfur content (e.g. SO2 content in the sample
gas).  The bias was greatest for high sulfur coal (up to 40%), but also
notable (20%) for low sulfur Power River Basin coals.

The results of the EPRI program show that a high degree of accuracy
cannot be expected from the industry-standard method of measuring flue
gas SO3/H2SO4.  Almost all elements involved with the measurement –
the location in the flue gas train, the composition of the coal, and the
experience of the test crews – can influence the measurement and
results.

The measurement accuracy of the CCS method can only be estimated from
the spread among duplicate measurements believed to be conducted at the
same process conditions.  Data from recent field trials with experienced
test crews suggests an accuracy of +/-20% is realistic for most
conditions.

CORRELATION REPRESENTATIVENESS

The accuracy of using the correlations presented in this report depends
on the representativeness of the constituent data points. For some
predictive cases, there are only several constituent data points, and
the estimation of correlations will only approximate the flue gas
SO3/H2SO4.  The category with the largest number of constituent data
points is for dry-bottom boilers firing low sulfur eastern bituminous
coals, which exhibits a standard deviation of 50%.  These factors should
be considered when applying the results of these correlations.

As a consequence of the uncertainty in SO3/H2SO4 measurement accuracy
and the limited number of data points that comprise the relevant
correlations, the predictive technique should be assumed to provide
estimates within a +/- 50% relative accuracy.

SECTION 4

BACKGROUND AND METHODOLOGY OVERVIEW

INTRODUCTION

This section provides a brief overview of sulfuric acid production
mechanisms to provide a framework for discussions regarding this
predictive tool.  A detailed review of this topic has been provided in a
recent paper by Srivastava (2003).

The initial step determining flue gas SO3/H2SO4 production or
manufacture within the furnace and convective sections are events
directly within the flame zone, or catalyzed on surfaces of fly ash, or
for heat removal.  Mechanisms to remove sulfuric acid from the flue gas
exist both in the gas phase and on surfaces such as for heat transfer,
usually promoted by deposits.  The release of sulfuric acid at the stack
is the aggregate result of production mechanisms, generally at
temperatures above 650°F, and removal mechanisms at lower temperatures.

FACTORS AFFECTING MANUFACTURE AND RELEASE

The method will employ estimating first the manufacture and the
subsequent release of sulfuric acid from the power generation process.
The manufacture of sulfuric acid is defined as any process step that
increases the flue gas content of sulfuric acid, regardless of the
ultimate fate.  The release of sulfuric acid requires correcting the
manufactured estimate by a factor or series of factors to account for
sulfuric acid loss or removal within the system.

Three process steps are known ultimately leading to the manufacture of
sulfuric acid:  the combustion process, selective catalytic reduction
(SCR) for NOx control, and flue gas conditioning.  The remaining steps
in the power generation process reduce sulfuric acid;.  Accordingly, the
total sulfuric acid released by the power generation process is the
cumulative sum of that manufactured adjusted by the sulfuric acid
losses.

The manufacture of SO3, the precursor to sulfuric acid, is denoted for
the combustion process by EMComb, for SCR by EMSCR, and for flue gas
conditioning (FGC) by EMFGC.  Accordingly, the Total Sulfuric Acid
Manufactured (TSAM) from a combustion unit equipped with SCR NOx control
and flue gas conditioning would manufacture sulfuric acid according to
the following:

			TSAM = EMComb +  EMSCR  + EFGC

COMBUSTION PROCESS

Manufacture

A detailed analytical study by Senior (2002) explored details of SO2
oxidation to SO3.  Specifically, the author modeled the relevant
reaction sets employing the temperature-time history of a typical
utility boiler, considering gas phase actions only and ignoring
catalytic effects.  The results showed that insignificant SO3 formed in
the early stage of the flame, but SO3 production increased as the gases
exit the flame zone and cool.  The author reported production of SO3 to
be essentially complete prior to flue gas entering the economizer
section.  The observation that most SO3 forms during cooling from
post-flame temperatures (2900-3100°F) to those typical of the
economizer entrance was also noted by Buckley (2002).  Senior further
quantified the relationship between coal sulfur content, excess air, and
SO3 production that has been empirically observed by previous
investigators.  Specifically, the results showed that after four seconds
of residence time, SO3 production could be from 0.3 - 0.6% of the SO2
concentration.

F1 E2

Where K is a constant, F1 is the Fuel Impact Factor describing the SO3
production associated with combustion, and E2 is the annual rate of SO2
production.  Further details of this relationship and the derivation of
constants and other terms will be presented in Section 4.

Release

The release of sulfuric acid attributable to the combustion process is
determined by adjusting the manufactured SO3/H2SO4 by the removal by any
or all of the air heater, particulate control device (PCD), and flue gas
desulfurization (FGD) equipment (as relevant). The release of sulfuric
acid is calculated by the Technology Impact Factors (F2) that describe
the fraction of sulfuric acid that penetrate each downstream equipment
component.  The Technology Impact Factors account for removal of
sulfuric acid by the air heater, the ESP, or other PCD, and/or the FGD
process.  The sulfuric acid released by combustion (ERComb) is described
by the following:

				ERComb = EMComb *  F2 (all that apply)

The values for the Technology Impact Factors (F2) for each downstream
component are presented later in this section.

SCR/SNCR NOx CONTROL

Manufacture

The SCR process increases the production of SO3, and therefore H2SO4, as
a percent of SO2 that can range from 0.50% to as high as 3%.

The production of SO3 from SO2 is a well-known side reaction of SCR, and
the degree of SO2 oxidation is a performance variable that should be
part of catalyst procurement specifications.  To a degree, SO3
production can be mitigated by substituting for vanadium pentoxide
either oxides of tungsten or molybdenum which offers improved
selectivity but lower activity for NOx.  As a consequence, for the same
level of NOx and residual ammonia slip, a low SO2 oxidation catalyst
will require a larger volume than one for which SO2 conversion is not
constrained.   In general, the degree of SO2 oxidation ranges from
approximately 0.75 to 1.5% for most catalysts.  With the use of SCR on
extremely low sulfur, high alkalinity coals such as PRB, SO2 oxidation
is usually not constrained and can be as high as 3% or more.  The
consequence of not limiting SO2 oxidation is the ability to use higher
vanadium content, thus minimizing catalyst volume and cost.

SNCR, since it does not use a catalyst, will not promote the oxidation
of SO2 to SO3, so there is no manufacture of sulfuric acid attributable
to SNCR.

Release

Both SCR and SNCR can introduce residual ammonia (NH3), also called
ammonia slip, into the flue gas which reacts with SO3 or sulfuric acid
to form ammonium sulfates and/or bisulfates, thereby removing some
sulfuric acid from the flue gas and reducing the amount released.

Regarding SCR, the ammonia slip is expected to range between 0 and 2
ppm, with higher values possible under unoptimized or upset conditions.
The reactions between the residual ammonia and SO3/H2SO4 will occur in
the air preheater and will result in a solid product that may deposit or
accumulate on the surface of the fly ash.  Any SO3/H2SO4 that
participates in these reactions is effectively no longer chemically
sulfuric acid and is not required to be reported as a release of
sulfuric acid.  (Under some circumstances, this solid product may
require reporting under TRI as an ammonia release, but that subject is
not explored in this paper.  For more information, see “A Method for
Estimating Total Ammonia Emissions from Stationary Power Plants,”
Wilson, et al, October 2005.)

SNCR employs ammonia or urea injection in the upper furnace for NOx
reduction.  At the higher temperatures characteristic of the upper
furnace zone (1800 to 2400°F, as compared to 700°F for SCR) the need
for reduction catalyst is eliminated, so there is no additional
manufacture of sulfuric acid.  Typically, SNCR systems operate with
higher levels of residual ammonia (5 to 10 ppm), so sulfuric acid will
be reduced through reactions with the ammonia.  Consequently, SNCR
systems will reduce the overall amount of sulfuric acid released, while
SCR systems will likely increase the amount of sulfuric acid released.

The reactions between SO3/H2SO4 and ammonia produce two products,
ammonium sulfate (NH4)2SO4 and/or ammonium bisulfate NH4HSO4.  While
both are solids, the bisulfate pairs one ammonia molecule with one of
sulfuric acid and the sulfate requires two ammonia molecules for each
sulfuric acid.  Usually, the reaction product is determined by the
stoichiometry, the relative amount of each substance that is present.
When ammonia is present in an amount over twice the concentration of the
sulfuric acid, the reaction product will always be the ammonium sulfate.
 Conversely, when sulfuric acid is present in concentrations greater
than ammonia, the product will be ammonium bisulfate.  Between these two
extremes, a mixture of ammonium sulfate and bisulfate is produced.

For bituminous coals with low-to-medium sulfur levels, an SCR system
will always produce an excess of sulfuric acid as compared to any
possible ammonia slip, and thus it is expected to produce ammonium
bisulfate.  For lower rank U.S. coals, the sulfuric acid is typically
adsorbed by the ash, and it is likely that the ammonia will be in higher
concentrations than the sulfuric acid.  Then, ammonium sulfate is the
likely product.  For SNCR systems, ammonia slip levels are higher, so
the probability is higher of producing more ammonium sulfate.  Certainly
with coals from the Western U.S., the alkaline nature of the ash will
sharply reduce the amount of SO3 present and usually the sulfate form
will predominate.  For Eastern bituminous coals, it is likely that the
bisulfate chemical form will be the product of the reactions.

For the purposes of predicting sulfuric acid emissions, these
distinctions are not important.  The sulfuric acid will capture a single
ammonia molecule producing the bisulfate form.  If additional ammonia is
available, the bisulfate can react with another ammonia molecule to form
the sulfate.  It is assumed that all of the sulfuric acid forms the
bisulfate before any further reaction to the sulfate form occurs.  That
assumption leads to the calculation strategy where the ammonia captures
all of the sulfuric acid it can as the bisulfate form.  Since the
bisulfate is no longer reportable, the sulfuric acid disappears from the
calculation.  If any additional ammonia reacts with the bisulfate, it is
of no consequence to the sulfuric acid calculation -- although this
issue will be important when estimating ammonia releases.

The details of the calculations to predict sulfuric acid manufacture and
release by SCR and SNCR are presented in Section 5.

FLUE GAS CONDITIONING

Manufacture

Flue gas conditioning (FGC) is typically used in power plants to inject
any of the following: SO3, SO3 plus NH3, or NH3 alone, to assist in
particulate control in an ESP or baghouse.  SO3-based flue gas
conditioning (FGC) introduces SO3 into the flue gas either preceding or
following the air heater.  The SO3 injected is typically made on-site
from sulfurous fuel that is burned to produce SO2 which is then
catalytically oxidized to SO3 with a conversion typically > 95%.  When
injected into the flue gas, the SO3 immediately reacts with water vapor
to create sulfuric acid vapors, thus resulting in the manufacture of
sulfuric acid that may require reporting for TRI purposes.  Estimating
the manufacture source requires knowledge of the concentration of SO3
injected and the associated O2 content of the flue gas.  Section 5
presents an equation to estimate the manufacture of sulfuric acid from
this source.

Release

The release of sulfuric acid attributable to FGC requires adjusting for
the reaction with NH3 that may be introduced as part of a flue gas
conditioning scheme, either with or without sulfuric acid.  Analogous to
the case of SCR and SNCR, the concentration of NH3 and the associated O2
content of the reported flue gas must be estimated.  Accordingly, FGC
can manufacture sulfuric acid, but also remove sulfuric acid if NH3 is
injected alone, or in quantities greater than the sulfuric acid.  The
relevant relationships are presented in Section 5.

The Technology Impact Factors (F2) describe the fraction of sulfuric
acid that penetrates the air heater (for FGC that is introduced ahead of
the air heater), and for the particulate control device and FGD (for FGC
that is introduced after the air heater. The basis for quantifying the
F2 factors is presented in Section 4, and the detailed equations for the
manufacture and release of sulfuric acid are presented in Section 5.

TECHNOLOGY IMPACT FACTORS

The sulfuric acid estimating methodology described in the previous
section, and presented in detail in Section 5, employs empirically
derived Technology Impact Factors (F2).  These describe the sulfate
removal observed over the air heater, the ESP or other particulate
control device, and FGD process equipment.  Relevant background and the
derivation of these factors are addressed in this section.

Air Heater

The removal of SO3/H2SO4 within the air heater is due to the
condensation of sulfuric acid and its removal as discrete individual
particles (along with the fly ash) on the surface of this heat
exchanger.  The conventional Ljungstrom-type air heater has been
documented to provide a removal sink for sulfuric acid (Saranuc, 1999).
In fact, the largest supplier of Ljungstrom air heaters has evaluated
the feasibility of employing the air heater process environment in
conjunction with limestone injection as a proactive sulfuric acid
control strategy (Hamel, 2003).

As noted in Section 4, the thermal history of air heater surfaces
follows a pattern of alternatively heating and cooling as the heat
exchange elements move from the relatively hot flue gas to the cooler
combustion air.  This temperature profile introduces a strong gradient
in sulfuric acid concentration across the exit plane of the air heater.
This gradient has been observed during field tests of commercial
equipment (Saranuc, 1999).  The cyclic 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 factor may be accountable for deposition, compared to a
tube-type heat exchanger in which steady state conditions are attained
and the metal temperature does is not fall below the sulfuric acid
dewpoint.

Figure 4-1.  Removal of Sulfuric Acid by Ljungstrom-Type Air Heaters

The  “zero” data point displayed in Figure 4-1 at approximately 600
ppm SO2 is believed suspect, as an identical companion unit firing the
same coal exhibits sulfuric acid capture of 38%.

Figure 4-1 presents two points reported by Hamel (2003) based on a low
sulfur eastern bituminous fired unit where SO3 was “spiked” into the
flue gas to elevate the concentration entering the air heater to 80 and
122 ppm.  These two points are plotted separately on Figure 4-1 versus
an estimated flue gas SO2 content that could generate such values.  It
should be noted these values measured for the “spiked” flue gas
significantly exceed those measured for the two high sulfur eastern coal
cases.

The F2 factor for the air heater, calculated as [1 - Collection
Efficiency], is estimated for the air heater, excluding the “spiked”
SO3 and suspect “zero” 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 4-1.  Western subbituminous
coals could consider adopting the F2 factor for PRB if strongly
alkaline; eastern subbituminous coals may consider adopting the low
sulfur eastern bituminous value.

Table 4-1.  Summary of F2 Factors for Air Heater Removal of Sulfuric
Acid

Boiler Type	Fuel	F2	Standard Deviation	Comment

All Boilers	Low S Eastern Bit	0.49

	0.16	Average of measurements at 6 units.  Represents a slight derease
in penetration compared to earlier estimates

All Boilers	Med-High S Eastern bit	0.85	n/a

	Two data points only; considerable increase in penetration from 2001;
consistent with EPRI

All Boilers	PRB	0.90	n/a

	No additional data, thus no change from 2001

Table 4-1 shows that the standard deviation of the reported measurements
for the low sulfur eastern bituminous coal is significant, representing
about 1/3 the value of the measurement.

ESP, AND OTHER PARTICULATE CONTROL DEVICES

The ESP provides extended residence time at relatively low temperatures
allowing contact between sulfuric acid and fly ash particles as well as
collecting plates.  These conditions contribute to the removal of
sulfuric acid either due to condensation on fly ash particles or the
collecting plates.  The ESP is the flue gas contacting device with
perhaps the longest residence time - for large units, usually 10 seconds
and in some cases up to 15 seconds.  Given the low flue gas velocities
of 2-4 aft/s, and the opportunity for heat loss, sulfuric acid
condensation can be significant.

Figure 4-2 depicts the relationship between sulfuric acid removed by the
ESP, as a function of SO2 content of the flue gas for the host unit as
obtained from the survey of utility operators.  Most data shown is for a
cold–side ESP and low sulfur eastern bituminous coal; three reference
points are shown for high sulfur coal.  A single data point for a
hot-side ESP and four data points for low sulfur eastern bituminous coal
are displayed.  Similar to the case for the air heater, the datum
reporting “zero” sulfuric acid removal at approximately 800 ppm SO2
is suspect, as a companion unit at the same site firing the identical
coal experienced a 50% sulfuric acid removal.  Accordingly, this
“zero” datum although shown in Figure 4-2 is not used in the
analysis.

 Figure 4-2.  Removal of Sulfuric Acid by Cold-Side and One Hot-Side ESP

The F2 factor for the ESP, calculated as [1- Collection Efficiency], is
estimated for the ESP using all data but the discarded “zero”
measurement.  The F2 factor for ESP capture for low sulfur eastern
bituminous, medium-high sulfur eastern bituminous, and PRB coals are
shown in Table 4-2.  Western subbituminous coals could consider adopting
the F2 factor for PRB if strongly alkaline; eastern subbituminous coals
may consider adopting the low sulfur east bituminous value.  Data
describing the reduced H2SO4 penetration for the hot-side ESP is the
result of a methodical and carefully executed test program, and is
adopted even though it is inconsistent with earlier projections. The
standard deviation of these data was not calculated due to the small
number of data points.

Table 4-2.  Summary of F2 Factors for Particulate Control Devices (ESP,
Baghouse)

Equipment Type	Coal Type	F2 Factor	Comment or Observation

Cold-side ESP	Low S Eastern Bit	0.49

	Average of measurements at 3 units.  Represents a decrease in
penetration compared to 2001 estimates

Cold-side ESP	High S Eastern Bit	0.77	Average of measurements at 3
units.  Represents an increase in penetration compared to 2001 estimates

Cold-side ESP	Subbituminous (PRB)	0.5	No additional data, thus no change
from 0.5 factor assumed for all coals in 2001

Hot-side ESP	All	0.63	One data point only; comprises a new category;
Represents a decrease in penetration from 2001 est.

Baghouse	All fuels	0.10	No additional data, thus no change from 2001

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 concentration
generally must be supersaturated.  However, fly ash particles can
provide a nucleus for condensation of sulfuric acid, even at conditions
that are not thermodynamically supersaturated.  Buckley also projects
sulfuric acid condensation on surfaces where equipment walls are lower
in temperature than the flue gas (common in commercial equipment).
However, the thin laminar boundary layer at the wall limits mass
transfer, and this mechanism for FGD equipment provides no appreciable
removal.  Ironically, it is the high saturation conditions in this
laminar layer near surfaces that is key to producing fine sulfuric acid
mist.

Srivastava (2004) suggests that the condensed submicron droplets, once
formed, are sufficiently small so that they follow the flow streamlines
and avoid contact with the remaining wetted walls, liquid sheets, and
droplets in the flow path.  Although some degree of sulfuric acid
removal is observed in FGD equipment, the specific amount is highly
variable and depends on the design of the system.  Buckley (2002)
projects FGD equipment removes 40-70% of the sulfuric acid, and
Srivastava an average of 50%.

Figure 4-3 summarizes the limited data reported in the public domain and
elsewhere describing FGD removal of sulfuric acid.  Data is shown to
range from approximately 22 to 78%, with an average of approximately
50%.

Figure 4-3.  Removal of Sulfuric Acid by Flue Gas Desulfurization
Equipment:

                 Various FGD Designs, Coals

Table 4-3 summarizes the F2 factors for FGD equipment, considering a wet
spray tower on bituminous coal, and a wet venturi tower on bituminous
coal.  The one datum recorded for a wet spray tower with PRB/lignite
coal is adopted to serve as the basis of an F2-factor.  The three
combinations of wet FGD and fuel cited represent new categories.  The
data for the wet spray tower cases report lower F2 factors in comparison
to the assumed value of 0.5 for all FGD equipment, while the venturi
tower data results in an increase in the previously assumed 0.5 F2
factor.

F2 factors for the use of magnesium-based additives in oil-fired boilers
have been proposed.  These additives are used to control furnace
slagging caused by the vanadium in the oil or to control sulfuric acid
emissions or both.  The fuel oil vanadium can also catalyze SO2 to SO3
oxidation, but the additive, when added to the oil, tends to effectively
bind up the vanadium, partially reducing its catalytic effect.  Addition
of magnesium-based additives in the fuel oil tend to be less effective
in controlling the emissions of sulfuric acid than the same additive
sprayed into the furnace downstream of the flame zone.

Table 4-3.  Summary of F2 Factors for Wet, Dry FGD Equipment and
Additives

FGD Type 	Coal Type	F2 Factor	Comment or Observation

Wet:  Spray Tower 	E. Bituminous	0.47	New category; small decrease from
2003 assumed value of 0.50 for all equipment types.

Wet Spray Tower	PRB/Lignite	0.40	New category; decrease from 2003
assumed value of 0.50 for all equipment types.

Wet:  Venturi Tower 	All fuel	0.65	New category; increase from 2003
assumed value of 0.50 for all equipment types.

Dry FGD and baghouse	All fuel	0.01	No additional data, thus no change
from 2001

Mg-Ox mixed w/fuel oil	All fuel	0.50	No additional data, thus no change
from 2001

Mg-Ox into furnace 	All fuel	0.50	No additional data, thus no change
from 2001

SECTION 5

ESTIMATING GUIDELINE:  STEAM BOILERS

INTRODUCTION

This section describes the estimating procedure for calculating the
manufacture and release of sulfuric acid from coal-fired steam
generators.  The topics addressed are (a) formation within the furnace,
(b) the role of SCR, and (c) the removal by downstream equipment such as
air heaters, ESP’s or other particulate control devices, and FGD
process equipment.

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

MANUFACTURE AND RELEASE FROM COMBUSTION

The premise of the methodology is that the amount of sulfuric acid
manufactured by the boiler is a function of the amount of SO2 released
– determined either from the coal data (amount burned and sulfur
content) or according to the CEMS data.  Units equipped with FGD
equipment (scrubbers) or other methods of SO2 control are required to
use the coal data, or at least CEMS data ahead of the scrubber.  It
should be noted that an earlier version of this document (Hardman, 1999)
included a method to correct the CEMS data for non-ideal stack flow
conditions; that calculation would apply but is not repeated here.

Sulfuric Acid Manufactured by Combustion (EMComb)

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

F1 E2

where,	EMComb =  total H2SO4 manufactured from combustion, lbs/yr

			    K  =  Molecular weight and units conversion constant = 98.07 /
64.04  symbol 183 \f "Symbol" \s 12 ·  2000 = 3,063;

				       98.07 = Molecular weight of H2SO4; 64.04 = Molecular weight
of SO2;

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

			    F1 =  Fuel Impact Factor

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

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

In the derivation of this relationship, the following assumptions are
made:

SO3 concentrations are proportional to SO2 concentrations.

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

All SO3 that forms is converted to H2SO4.

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

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

Fuel Impact Factor (F1).  Figure 5-1 depicts the results of the
additional data obtained in 2004 describing the relationship between the
Fuel Impact Factor (F1) and flue gas SO2 content by coal rank and boiler
type.  Figure 5-1 depicts a total of 30 data points, derived from 21
different units.  The different coal ranks and boiler types represented
are shown in the legend which consists of (a) high sulfur eastern
bituminous coal, fired in a dry bottom boiler, (b) low sulfur eastern
bituminous coal, fired in a dry bottom boiler, (c) PRB coal, fired in
both a cyclone (1 reference) and two dry bottom boilers (4 references),
and (d) high sulfur eastern bituminous coal, fired in a cell-fired
boiler. A single data point is also shown for a unit that fires
predominantly lignite (with the balance PRB).

Figure 5-1.  Relationship between Boiler SO3 Production and Flue Gas SO2
(corrected to 3% O2)

Figure 5-1 shows that a wide range in SO3 production is witnessed for
all coals and boiler types.   This range exceeds the theoretical
predictions by Senior (2000), suggesting that the role of ash in either
catalyzing SO3 production or absorbing/neutralizing SO3 is not fully
accounted for.  As noted in Section 2, describing the tests conducted by
EPRI, both the quantity and composition of ash can influence the amount
of flue gas SO3 that is absorbed.  In Figure 5-1, the only consistent
results were obtained describing SO3 from PRB-fired units, regardless of
boiler type, in that less than 1 ppm was observed (3 distinct data
points reside near the 350 ppm, 0.000556 point).  Even for the low
sulfur eastern bituminous coals, a significant range of data is
observed.  Attempts at correlating the F1 factor with flue gas SO2
content provided correlation coefficients (e.g. the R-squared values)
that were unacceptable; thus correlations are not proposed.

Table 5-1 presents a comprehensive summary of the F1 factors from both
the 2004 survey and earlier publications.  For two categories of
equipment – dry-bottom boilers firing low sulfur eastern bituminous
coal, and dry bottom boilers firing medium-high sulfur coal – the
standard deviation is included for the recent measurements.

Table 5-1.  Summary of Fuel Impact Factors (F1) for Steam Generating
Units

Fuel	Equipment	F1	Standard Deviation	Comment

Low S Eastern Bit.	DB Boilers	0.0080	0.0020	Average of measurements at
15 units

W. Bituminous	DB Boiler	0.00111

No additional data, thus no change from 2001

Subbituminous (PRB) 	Any boiler	0.0014

Average of 4 data points and represent an increase compared to 2001

Lignite	DB Boiler	0.0048

Additional data represents increase from 2001

High S Eastern Bit	DB Boiler 	 0.011	0.0041	Average of 5 data points
comprise a new category

E. Bituminous	Cyclone	0.016

No additional data, thus no change from 2001

W. Bituminous	Cyclone	0.0022

No additional data, thus no change from 2001

Subbituminous/PRB	Cyclone	0.003

One measurement from a PRB-fired cyclone

Lignite	Cyclone	0.00112

No additional data, thus no change from 2001

Petroleum coke	Boiler	0.04

No change from 2001

Natural gas	Boiler	0.01

No change from 2001

#2 Fuel oil	Boiler	0.01

No change from 2001

#6 Fuel oil	Boiler	0.025

No change from 2001

Used Oil	Boiler	0.0175

No change from 2001

Other Alternative Fuels	Any	0.04

No change from 2001

Other Alternative Fuels, Co-fired w/Coal, >75% heat throughput	NA

	Use same F1 as Coal F1

Sulfur Dioxide (SO2) Emissions from Combustion (E2).  Estimating the
sulfuric acid production from Equation 5-1 requires knowledge of the
mass rate of SO2 produced, referred to in Equation 5-1 as E2, and can be
calculated from the coal burn data (EPA, 1995a).  The following
relationship is used to estimate the rate of SO2 emissions:

Equation 5-2 				E2 = K1  symbol 183 \f "Symbol" \s 12 ·  K2  symbol
183 \f "Symbol" \s 12 ·  C1  symbol 183 \f "Symbol" \s 12 ·  S1

where,	E2 = SO2 mass rate, tons/yr

		C1 = Coal burn, tons/yr

		S1 = Coal sulfur weighted average, %

		K1 = Molecular weight and units conversion constant = (64.04)/(100
symbol 183 \f "Symbol" \s 12 ·  32.06) = 0.02

			    64.04 = molecular weight of SO2; 32.06 = molecular weight of S;

			    100 = conversion of % S to fraction

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

							    = 0.95 for bituminous coals

							    = 0.875 for subbituminous coals

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

							    = 1.0 for oil

When any source uses FGD equipment or another technology to control SO2
emissions, the fuel basis must be used for the manufacturing and release
calculations.  CEMS data after a flue gas desulfurization system cannot
be used.

Sulfuric Acid Released from Combustion (ERComb)

For units that do not employ SCR or SNCR NOx control or flue gas
conditioning, the sulfuric acid released is the product of the amount
manufactured and the Technology Impact Factors (F2) for all downstream
equipment (the air heater, the particulate control device, the FGD,
etc.).

Equation 5-3			ERComb = EMComb * F2 (all that apply)

Units that do employ SCR or SNCR, and/or flue gas conditioning, must
consider these additional sources as described in the following
sections.  If a unit is not equipped with SCR or SNCR NOx control, or
flue gas conditioning processes, the total sulfuric acid emissions can
be calculated from Equation 5-3.

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

gas bypass which  must account for the fact that the entire flue gas
flow is not subject to sulfuric acid removal by the FGD process.  This
factor is pertinent only to units that employ flue gas bypass.

MANUFACTURE AND RELEASE FROM SCR AND SNCR

This section describes a method to estimate how SCR can contribute to or
reduce sulfuric acid emissions, while SNCR will only reduce such
emissions.

As discussed in Section 4, SO3 (and ultimately sulfuric acid) is
produced by SCR, but can only be removed or reduced by SNCR due to the
reaction with residual ammonia.  The sulfuric acid manufactured by SCR
is the net result of production by the catalyst and removal by the
reaction of residual NH3 from the SCR process.

A key assumption in the calculation strategy is that residual ammonia
from either SCR or SNCR captures all of the sulfuric acid it can as the
(ammonium) bisulfate form.  The bisulfate form is not reportable under
the TRI reporting requirement and thus is considered removed and not
part of the calculation.  If any additional ammonia reacts with the
bisulfate, it is of no consequence to the sulfuric acid calculation --
although this issue will be important when estimating ammonia releases
(see “A Method for Estimating Total Ammonia Emissions from Stationary
Power Plants,” Wilson, et al, October 2005.).

The calculations for the manufacture of sulfuric acid by SCR and the
release of sulfuric acid by SCR and SNCR are shown in the following
sections.

Sulfuric Acid Manufacture by SCR (EMSCR)

The following relationship is proposed to estimate the total H2SO4
manufactured from a SCR equipped coal-fired utility boiler:

Equation 5-4				EMSCR = K  symbol 183 \f "Symbol" \s 12 ·  S2  symbol
183 \f "Symbol" \s 12 ·  fs  symbol 183 \f "Symbol" \s 12 ·  E2

where,	EMSCR = Total H2SO4 manufactured from SCR, lbs per year

		K = Conversion factor = 3063

		S2 = SCR catalyst SO2 oxidation rate (specified as a decimal,
typically from 0.001-0.03)

		fs = Operating factor of SCR system, fraction of coal burn when SCR
operates

				generally, 	= 0.8 for year-round peaking operation

						= 0.98 for year-round base-loaded operation

						= 0.43 for seasonal operation

		E2 = SO2 produced, tons per year

Typically, data describing S2 can be obtained from acceptance or startup
tests conducted for the SCR process equipment or simply from the
engineering design specification.  Typically, the SO2 oxidation rate can
range from as low as 0.1% of flue gas SO2 content, up to 3% for low
sulfur, highly alkaline coals (e.g. PRB).

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

Sulfuric Acid Released from SCR and SNCR

The sulfuric acid released from SCR or SNCR is determined by adjusting
the sulfuric acid manufactured by the removal by the residual ammonia,
or ammonia slip.  For SCR, the sulfuric acid released (ERSCR) is
estimated with the following relationship:

Equation 5-5			ERSCR = [EMSCR – (Ks  symbol 183 \f "Symbol" \s 12 ·
B  symbol 183 \f "Symbol" \s 12 ·  fs  symbol 183 \f "Symbol" \s 12 ·
SNH3)]  symbol 183 \f "Symbol" \s 12 ·  F2x

where,	ERSCR = Total H2SO4 released from SCR, lbs per year

		EMSCR = Total H2SO4 manufactured from SCR, lbs per year

		Ks = Conversion factor = 3799

		B  = Coal burn in TBtu/yr

		fs  = Operating factor of SCR system, fraction of coal burn when SCR
operates

				generally, 	= 0.8 for year-round peaking operation

						= 0.98 for year-round base-loaded operation

						= 0.43 for seasonal operation

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

				SCR averages 0.75 ppmv over catalyst guarantee period

				SNCR averages 5 ppmv

				Note: actual NH3 slip data should be used if available

		F2x = Technology Impact Factors, all that apply

The derivation of the conversion factor Ks corrects all of the various
units to yield the result in pounds per year of sulfuric acid.  The
derivation of this constant, for the case where residual NH3 is reported
in terms of 6% oxygen and “wet” flue gas at 8.1% H2O, is equal to
3799, for which the basis is presented in Text Box B.

The coal burn rate in TBtu/yr is obtained from coal use records, such as
those reported to EIA in Form 767.  The operating factor of the SCR
describes the portion of the coal burn that reflects the period of SCR
operation, based on whether the unit operates seasonally (0.43),
annually in a base-load duty (0.98), or annually in peaking duty (0.80).

Equation 5-6a specifies the concentration of NH3 in flue gas (SNH3) in
terms of ppmv at 6% O2, wet flue gas basis. If the concentration of NH3
is reported at different conditions, the value of the constant Ks will
change.  The following formula is used to adjust the value of the
constant Ks:

 [(100-8.1)/(100-new H2O)] 

   [(20.9 – 6.0)/(20.9 – new O2)]

As an example, if the ammonia concentration is quantified at a value (in
ppm) that is defined at 0% oxygen and a dry basis, the value of Ks that
should be used is:

Equation 5-6b               Ks (O2, H2O) = 3799 (6% O2, 8.1% H2O) 
[(100-8.1)/(100-0)]

   [(20.9 – 6.0)/(20.9 – 0)]

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

This formula (Equation 5-6b) is used to calculate the value of Ks at any
condition used to define the concentration of residual NH3.

For SNCR, as there is no sulfuric acid manufacture term, the sulfuric
acid release estimate (ERSNCR) is a negative term which when included in
the calculations will result in an overall reduction of sulfuric acid
emissions.

Accordingly, total sulfuric acid release (TSAR) is estimated for a
generating unit equipped with SCR by the following equation:

Equation 5-7          TSAR = ERComb + ERSCR

Or in the case of SNCR,

Equation 5-8          TSAR = ERComb + ERSNCR

For units equipped with flue gas desulfurization bypass, a series of
calculations analogous to those described in the previous section for
combustion-derived sulfuric acid are required.  These calculations for
SCR or SNCR are described in Text Box C.

MANUFACTURE AND RELEASE FROM FLUE GAS CONDITIONING (FGC)

Sulfuric Acid Manufactured from FGC

Most SO3–based flue gas conditioning systems to moderate ash
resistivity strive to maintain a fixed concentration of added SO3 in the
flue gas, typically between 5 and 7 parts per million by volume (ppmv).
Calculations to estimate the sulfuric acid manufactured use the setpoint
of the FGC system as the key input. The FGC system is assumed to operate
during most of the plant’s duty, although perhaps excluding startup
and low load operation.

The sulfuric acid manufactured by SO3-based FGC equipment (EMFGC) is
calculated as follows:

Equation 5-9          			EMFGC = Ke  symbol 183 \f "Symbol" \s 12 ·  B
symbol 183 \f "Symbol" \s 12 ·  fe  symbol 183 \f "Symbol" \s 12 ·  Is

where,	EMFGC = Total H2SO4 manufactured from FGC, lbs per year

		Ke = Conversion factor = 3799

		B = Coal burn in TBtu/yr

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

			   generally = 0.8

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

				generally, = 7 ppmv if before the APH

					     = 5 ppmv if after the APH

FGC equipment that employs both SO3 and NH3 must be reported to
manufacture sulfuric acid at the rate of SO3 injection, regardless of
whether ammonia is used or not.  FGC equipment that employs NH3 alone
does not manufacture sulfuric acid, and any ammonia will reduce the
release of sulfuric acid by reacting with SO3/H2SO4.  The reduction in
flue gas sulfuric acid by reaction with ammonia determines the sulfuric
acid released by FGC, discussed in the next section.

Sulfuric Acid Released from FGC (ERFGC)

The subsequent release of that portion of sulfuric acid associated with
flue gas conditioning can be estimated from the quantity manufactured,
adjusted by the amount that reacts with ammonia in the particulate
control device installed downstream of the FGC.

Equation 5-10			ERFGC = [EMFGC – (Ke  symbol 183 \f "Symbol" \s 12 ·
B  symbol 183 \f "Symbol" \s 12 ·  fe  symbol 183 \f "Symbol" \s 12 ·
INH3)] ( F3  symbol 183 \f "Symbol" \s 12 ·  F2

where,	ERFGC  = Total H2SO4 released from FGC, lbs per year

		EMFGC = Total H2SO4 manufactured from FGC, lbs per year

		Ke =  Conversion factor = 3799

		B  =  Coal burn in TBtu/yr

             fe = Operating factor of FGC system, fraction of fuel burn
when FGC operates

	 	       generally = 0.8

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

		          generally 3 ppmv NH3 if operating, = 0 if no ammonia is used

	 F3  =  Technology Impact Factors for FGC, see Table 5-2

	 F2  =  Technology Impact Factors for equipment after ESP only

		If no control after ESP, F2 = 1.

Table 5-2.  F3 – Technology Impact Factors for FGC With Cold-Side ESPs

Location	Coals	F3

Upstream of APH	bituminous	0.25 modify

Upstream of APH	W. bit., subbit., & lignite	0.05

Downstream of APH	Bituminous	0.10

Downstream of APH	W. bit., subbit., & lignite	0.02

For other fuels, use F3 = 0.5 for startup fuel and F3 = coal factor for
fuels co-fired as a minor fraction (<25%) with coal.

This approach leads to a possible contradiction in the behavior of
SO3/H2SO4 depending on the place in which the SO3/H2SO4 enters the
system.  For SO3 created in combustion, SCR, or introduced as FGC ahead
of the air preheater, the method predicts removals of 75% for eastern
bituminous coals across an air preheater/cold-side ESP combination.
However, for SO3/H2SO4 injected for FGC downstream of the air preheater,
90% will be removed in a cold-side ESP for the eastern bituminous coal.
For bituminous coals, the F3 numbers for upstream injection of SO3
mirror the behavior of SO3 formed from combustion or SCR, that is, the
method predicts the same result for a molecule of SO3 found ahead of the
air preheater, regardless of its origin.  However, for western
bituminous or subbituminous and lignite coals, SO3 originating from
combustion or an SCR is collected with 75% efficiency in the air heater
and cold-side ESP.

For SO3 injected as FGC for these western or low-ranked fuels, SO3
injected ahead of the air heater is assumed to be removed with a 95%
efficiency through the air heater and ESP, and 98% when injected
downstream of the air heater.  Since these western bituminous,
subbituminous, and lignite coals have alkaline ash, any SO3 injected for
FGC will likely be captured by both physical deposition, and by chemical
reaction.  For this reason, SO3/H2SO4 removal assumed for these coals is
much higher than for eastern bituminous coals. The injection of SO3 on
the cold-side of the air preheater is typically below the acid dewpoint,
so it is expected that the injected SO3 is condensed on fly ash more
readily than through the slower cooling of the flue gas through the air
preheater.

For units equipped with flue gas desulfurization bypass, a series of
calculations analogous to those described in the previous sections for
combustion- and SCR-derived sulfuric acid are required.  These
calculations for FGC are described in Text Box D.

TOTAL MANUFACTURE AND RELEASE FOR SOURCE

Total manufacture and release of sulfuric acid for the source is the sum
of the three manufacture or release results.  Therefore, if a site burns
coal and uses both SCR and FGC, the amount of sulfuric acid manufactured
in combustion, the SCR, and the FGC system would be added together to
result in the total amount manufactured for this source.  The amount
released calculated for combustion, SCR, and FGC are also summed to
arrive at a total.  It is possible for a calculated release from SCR
and/or FGC to be negative, which implies that the net result of the
ammonia in the system is to remove some or all of the sulfuric acid
generated from combustion.  Under this approach, it is also possible to
calculate a negative amount for the release of sulfuric acid,
particularly in circumstances where ammonia alone is used for FGC, or
where relatively low-sulfur coals are burned, for instance PRB.  Since
the release of sulfuric acid from combustion, SCR, and FGC are all
additive, any negative values calculated as a result of these
circumstances will be accounted for in the total release equation.

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

Equation 5-10a:  Manufacture

				TSAM = EMComb + EMSCR/SNCR + EMFGC

Equation 5-10b:  Release

				TSAR = ERComb + ERSCR/SNCR + ERFGC

Examples 1 through 4 detail the use of these calculations.

SECTION 6

ESTIMATING GUIDELINE: MULTIPLE FUEL BOILERS

Estimating the sulfuric acid production of steam boilers firing multiple
fuels uses the same approach as for single fuel steam boilers, by
determining the contribution of the combustion, SCR or SNCR NOx control,
and flue gas conditioning steps.  It is assumed for multiple fuel
boilers the contribution of each fuel is separable, and can be treated
individually.

The sequence of calculations is performed for the first fuel, followed
by the calculations for SCR and FGC, if applicable, for the first fuel.
The sequence is repeated for each of the subsequent fuels.  When
complete, the total manufacture of sulfuric acid is calculated by adding
all of the manufacture totals for all fuels from all processes.
Likewise, the release is summed over all processes and fuels.

As an example, if a unit with a SCR and FGC burns mostly coal, but uses
natural gas in a NOx reburn process and also disposes of used oil by
combustion in the furnace, then the following sequence of calculations
would be required:

Coal fuel

Combustion manufacture

Combustion release

SCR manufacture

SCR release

FGC manufacture

FGC release

Natural gas

Combustion manufacture

Combustion release

SCR manufacture

SCR release

FGC manufacture

FGC release

Used oil

Combustion manufacture

Combustion release

SCR manufacture

SCR release

FGC manufacture

FGC release

Sum manufacture and releases

Manufacture

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

Release

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

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

Example 5 details this calculation procedure.

SECTION 7

ESTIMATING GUIDELINE: COMBUSTION TURBINES

INTRODUCTION

Natural gas-fired sources typically have negligible content of sulfur in
the fuel thus sulfuric acid production is negligible.  However, such
sources that are co-located with coal units will need to be included in
the total release estimates for the site.  The calculation of sulfuric
acid manufacture and release to estimate sulfuric acid emissions for PSD
review of new gas generation sites can also use the methodology
described in this section.

The structure of the calculations for gas-fired units is very much the
same as for coal and oil-fired sources.  For simple cycle combustion
turbines, the only source of sulfuric acid is the sulfur in the natural
gas.  The EPA AP-42 emissions factor document suggests a value of 2000
grains of sulfur per million cubic feet of natural gas as a default
value of sulfur content.  This value is equivalent to approximately 3.5
ppm of sulfur in the raw natural gas.

The methodology is described for simple cycle and combined cycle units
below.

SIMPLE CYCLE UNITS

Table 6-1.  F1 – Fuel Factors for 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

Given the current configuration of simple cycle units, any sulfuric acid
manufactured is released, thus the estimates of sulfuric acid are the
same.  This is because there is no equipment located following the
simple cycle arrangement that removes sulfuric acid.

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

Equation 7-1		EMSC = K F1 E2NG

where,	EMSC =  total H2SO4 manufactured from

				   combustion, lbs/yr

		K  =	Molecular weight and units conversion

				constant = 98.07 / 64.04  symbol 183 \f "Symbol" \s 12 ·  2000 =
3,063	98.07 = Molecular weight of H2SO4;

				64.04 = Molecular weight of SO2

				Conversion from tons per year to pounds

				per year – multiply by 2000.

		F1	=	Fuel Impact Factor for NG

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

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

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

BNG S

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

		Kb  =	Molecular weight and units conversion constant = 0.0001359

		BNG = Burn of NG in TBtu/yr

		S	=	Sulfur content of natural gas, in grains per million standard
cubic feet (Mscf), typically

			      2000 gr/106 scf per EPA AP-42.

The derivation of calculation constant Kb is presented in Text Box E.

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

N1 S

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

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

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

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

				 2000 gr/106 scf as default

The derivation of calculation constant KNG is presented in Text Box F.

Table 6-1 presents the F1 factors for simple cycle units as a function
of stack temperature, as sulfuric acid vapor is related to the
temperature of the exhaust.  As simple cycle combustion turbines (CT)
exhaust is usually around 1000°F, and TRI rules require the reporting
of sulfuric acid (not of SO3), the amount of manufactured and released
depends on stack temperature.  Table 6-1 combines the temperature-based
SO3 to H2SO4 conversion with the SO2 to SO3 conversion to give the Fuel
Impact Factor, F1.

COMBINED CYCLE UNITS

Sulfuric Acid Manufactured

For the case of combined cycle units, the manufacture of sulfuric acid
is estimated using the same equation as for simple cycle.  The
combined-cycle equation is shown below.

Equation 7-3				EMCC = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol
183 \f "Symbol" \s 12 ·  E2NG

where,	EMCC	= total H2SO4 released from combustion, lbs/yr

		K = Molecular weight and units conversion constant = 98.07 / 64.04
symbol 183 \f "Symbol" \s 12 ·  2000 = 3,063

			98.07 = Molecular weight of H2SO4;

			64.04 = Molecular weight of SO2;

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

		F1		= Fuel Impact Factor for NG

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

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

It should be noted that for gas-fired combined cycle plants that exhaust
at low temperatures, less than 200°F, an F2 factor equal to 0.5 should
be used to account for any removal in the heat transfer sections.

Sulfuric Acid Released

The release of sulfuric acid from combined cycle units is estimated
using equation analogous to that for previous units.

Equation 7-4					ERCC = EMCC  symbol 183 \f "Symbol" \s 12 ·  F2CC

The Technology impact Factor, F2CC for combined cycle units, is the heat
exchanger, for which at present a value of 0.5 is assigned.

Example 6 illustrates a gas-fired combined cycle plant calculation.

SECTION 8

REFERENCES

Author, Date	Citation

Buckley, 2002	Buckley, W. et. al., “Acid Mist Causes Problems for FGD
Systems”, Power Engineering, November, 2002.

Dahlin, 1991	Dahlin, R. et. al., “Control of Acid Mist Emissions From
FGD Systems”, paper presented to the EPRI-EPA-DOE 1991 SO2 Control
Symposium, Washington, DC, December, 1991

EPA, 1995a	EPA, “Sulfuric Acid: Toxic Chemical Release Reporting:
Community Right-To-Know.  Final Rule.  60 FR 34182.  June 30, 1995.

EPA, 1995b	EPA, “Compilation of Air Pollutant Emission Factors AP-42,
Fifth Edition, Volume I:  Stationary Point and Area Sources”,
HYPERLINK "http://www.epa.gov/ttnchie1/ap42pdf/c01s01.pdf"
http://www.epa.gov/ttnchie1/ap42pdf/c01s01.pdf .

EPA, 1997	EPA, Emergency Planning and Community Right-to-Know Act  -
Section 313. Guidance for Reporting Sulfuric Acid (acid aerosols
including mists vapors, gas, fog, and other airborne forms of any
particle size). EPA-745-R-97-007, November 1997.

EPRI, 2002	EPRI Report 1004027, “Flue Gas Sulfuric acid Measurement
Improvements”, August, 2001.

Hamel, 2003	Hamel, B., “The Role of the Combustion Air Preheater in an
Effective Multipollutant Control Strategy”, Proceedings of the
Combined Power Plant Air Pollutant Control “Mega” Symposium,
Washington, DC, May, 2003

Hardman, 1998	Hardman, R., Stacy R., Dismukes, E.  Estimating Total
Sulfuric Acid Emissions from Coal-Fired Power Plants.  Internal Report
of Research & Environmental Affairs Department, Southern Company
Services, March 1998.

Hardman, 1999	Hardman, R., Stacy, R., Dismukes, E., Harrison, K.,
Monroe, L.  Estimating Total Sulfuric Acid Emissions from Coal-Fired
Power Plants.  Revised Internal Report of Research & Environmental
Affairs Department, Southern Company Services, February 1999.

Saranuc, 1999	Saranuc, N. et. al., “Factors Affecting Sulfuric Acid
Emissions From Boilers’, Proceedings of the Combined Power Plant Air
Pollutant Control “Mega” Symposium, Atlanta, GA, August, 1999

Monroe, 2003	Monroe, L. and K. Harrison, “An Updated Method for
Estimating Total Sulfuric Acid Emissions from Stationary Power
Plants”, White Paper Issued by Southern Company Services, March ,
2003.

Senior, 2002	Senior, C.L., et. al., ‘Simulation of SO3 Production”,
Fuel Processing Technology, 2000, , 63, 197-213

Srivastava, 2004	Srivastava, R. et. al., “Emissions of Sulfur Trioxide
from Coal-Fired Power Plants”, Journal of the Air & Waste Management
Association, Volume 54, June 2004.

APPENDIX A

EXAMPLE CALCULATIONS

Example 1:  Comparison of Previous and Current Method

	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  symbol 183 \f "Symbol" \s 12 ·  K2  symbol 183 \f "Symbol"
\s 12 ·  C1  symbol 183 \f "Symbol" \s 12 ·  S1

		E2 = 0.02  symbol 183 \f "Symbol" \s 12 ·  0.95  symbol 183 \f
"Symbol" \s 12 ·  1,126,938  symbol 183 \f "Symbol" \s 12 ·  2.0 =
42,824 tons SO2/yr

		EMComb = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol 183 \f
"Symbol" \s 12 ·  E2

		EMComb = 3063  symbol 183 \f "Symbol" \s 12 ·  0.008  symbol 183 \f
"Symbol" \s 12 ·  42,824 = 1,049,359 lbs H2SO4/yr

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

	Released

		ERcomb = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol 183 \f
"Symbol" \s 12 ·  F2  symbol 183 \f "Symbol" \s 12 ·  E2

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

		Where F2 = Air Heater  Cold-Side ESP

		F2 = 0.49  0.49 = 0.24

Example 2:  SCR Added to Example 1

	A 500-MW PC boiler equipped with a cold-side electrostatic precipitator
burns an Eastern bituminous coal.  The plant is equipped with a SCR
process that operates during the ozone season only, so that 0.43 of the
coal burn occurred with the SCR operating.  The SCR catalyst SO2
oxidation rate specified in the design is 0.75%, and the ammonia slip is
estimated to be 0.75 ppmv.  The coal used in the reporting year is
1,126,938 tons with a weighted average sulfur concentration of 2.0% and
a heating value of 12,000 Btu/lb.

Solution

	Manufactured

		E2 = K1  symbol 183 \f "Symbol" \s 12 ·  K2  symbol 183 \f "Symbol"
\s 12 ·  C1  symbol 183 \f "Symbol" \s 12 ·  S1

		E2 = 0.02  symbol 183 \f "Symbol" \s 12 ·  0.95  symbol 183 \f
"Symbol" \s 12 ·  1,126,938  symbol 183 \f "Symbol" \s 12 ·  2.0 =
42,824 tons SO2/yr

			Combustion

		EMcomb = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol 183 \f
"Symbol" \s 12 ·  E2

		EMcomb = 3063  symbol 183 \f "Symbol" \s 12 ·  0.008  symbol 183 \f
"Symbol" \s 12 ·  42,824 = 1,049,359 lbs H2SO4/yr

			SCR

		EMSCR = K  symbol 183 \f "Symbol" \s 12 ·  S2  symbol 183 \f "Symbol"
\s 12 ·  fs  symbol 183 \f "Symbol" \s 12 ·  E2

		EMSCR = 3063  symbol 183 \f "Symbol" \s 12 ·  0.0075  symbol 183 \f
"Symbol" \s 12 ·  0.43  symbol 183 \f "Symbol" \s 12 ·  42,824 =
423,023 lbs H2SO4/yr

		Total

		TSAM = EMcomb + EMSCR

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

		TSAM = 1,472,382 lbs H2SO4/yr

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

	Released

		Combustion

		ERComb = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol 183 \f
"Symbol" \s 12 ·  F2  symbol 183 \f "Symbol" \s 12 ·  E2

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

		Where F2 = Air Heater  Cold-Side ESP

		F2 = 0.49  0.49 = 0.24

		SCR

		B = 1,126,938 tons/yr  symbol 183 \f "Symbol" \s 12 ·  2000 lbs/ton
symbol 183 \f "Symbol" \s 12 ·  12,000 Btu/lb  symbol 183 \f "Symbol"
\s 12 ·  1 TBtu/1012 Btu

		B = 27.05 TBtu/yr

		ERSCR = [EMSCR – (Ks  symbol 183 \f "Symbol" \s 12 ·  B  symbol 183
\f "Symbol" \s 12 ·  fs  symbol 183 \f "Symbol" \s 12 ·  SNH3)]
symbol 183 \f "Symbol" \s 12 ·  F2  symbol 183 \f "Symbol" \s 12 ·  F2

		ERSCR = [423,023 – (3799  symbol 183 \f "Symbol" \s 12 ·  27.05
symbol 183 \f "Symbol" \s 12 ·  0.43  symbol 183 \f "Symbol" \s 12 ·
0.75)]  symbol 183 \f "Symbol" \s 12 ·  0.49  symbol 183 \f "Symbol" \s
12 ·  0.49

		ERSCR = 93,611 lbs H2SO4/yr

		Total

		TSAR = E1’comb + E1’SCR

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

		TSAR = 345,562 lbs H2SO4/yr

Example 3:  FGC Added to Example 1

	A 500-MW PC boiler equipped with a cold-side electrostatic precipitator
burns an Eastern bituminous coal.  The plant is equipped with a FGC
process that injects both SO3 and NH3, with the SO3 injected upstream of
the air preheater.  The SO3 is injected at 7 ppmv at 6% O2 wet, and the
ammonia at 3 ppmv also at 6% O2 wet.  The FGC system operates whenever
the plant is on, except during startup and shutdown, with an operating
factor estimated at 0.9.  The coal used in the reporting year is
1,126,938 tons with a weighted average sulfur concentration of 2.0% and
a heating value of 12,000 Btu/lb.

Solution

	Manufactured

		E2 = K1  symbol 183 \f "Symbol" \s 12 ·  K2  symbol 183 \f "Symbol"
\s 12 ·  C1  symbol 183 \f "Symbol" \s 12 ·  S1

		E2 = 0.02  symbol 183 \f "Symbol" \s 12 ·  0.95  symbol 183 \f
"Symbol" \s 12 ·  1,126,938  symbol 183 \f "Symbol" \s 12 ·  2.0 =
42,824 tons SO2/yr

			Combustion

		EMComb = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol 183 \f
"Symbol" \s 12 ·  E2

		EMComb = 3063  symbol 183 \f "Symbol" \s 12 ·  0.008  symbol 183 \f
"Symbol" \s 12 ·  42,824 = 1,049,359 lbs H2SO4/yr

			FGC

		B = 1,126,938 tons/yr  symbol 183 \f "Symbol" \s 12 ·  2000 lbs/ton
symbol 183 \f "Symbol" \s 12 ·  12000 Btu/lb  symbol 183 \f "Symbol" \s
12 ·  1 TBtu/1012 Btu

		B = 27.05 TBtu/yr

		EMFGC = Ke  symbol 183 \f "Symbol" \s 12 ·  B  symbol 183 \f "Symbol"
\s 12 ·  fe  symbol 183 \f "Symbol" \s 12 ·  Is

		EMFGC = 3799  symbol 183 \f "Symbol" \s 12 ·  27.05  symbol 183 \f
"Symbol" \s 12 ·  0.9  symbol 183 \f "Symbol" \s 12 ·  7 = 647,407 lbs
H2SO4/yr

		Total

		TSAM = EMComb + EMFGC

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

		TSAM = 1,696,766 lbs H2SO4/yr

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

	Released

		Combustion

		ERComb = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol 183 \f
"Symbol" \s 12 ·  F2  symbol 183 \f "Symbol" \s 12 ·  E2

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

		Where F2 = Air Heater  Cold-Side ESP

		F2 = 0.49  0.49 = 0.24

		FGC

		B = 1,126,938 tons/yr  symbol 183 \f "Symbol" \s 12 ·  2000 lbs/ton
symbol 183 \f "Symbol" \s 12 ·  12000 Btu/lb  symbol 183 \f "Symbol" \s
12 ·  1 TBtu/1012 Btu

		B = 27.05 TBtu/yr

		ERFGC = [EMFGC – (Ke  symbol 183 \f "Symbol" \s 12 ·  B  symbol 183
\f "Symbol" \s 12 ·  fe  symbol 183 \f "Symbol" \s 12 ·  INH3)]
symbol 183 \f "Symbol" \s 12 ·  F3  symbol 183 \f "Symbol" \s 12 ·  F2

		ERFGC = [647,407 – (3799  symbol 183 \f "Symbol" \s 12 ·  27.05
symbol 183 \f "Symbol" \s 12 ·  0.9  symbol 183 \f "Symbol" \s 12 ·
3.0)]  symbol 183 \f "Symbol" \s 12 ·  0.25  symbol 183 \f "Symbol" \s
12 ·  1.0

		ERFGC = 92,487 lbs H2SO4/yr

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

		Total

		ESAR = ERComb + ERFGC

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

		ESAR = 344,438 lbs H2SO4/yr

Example 4:  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 a SCR
process that operates during the ozone season only, so that 0.43 of the
coal burn occurred with the SCR operating.  The SCR catalyst SO2
oxidation rate specified in the design is 0.75%, and the ammonia slip is
estimated to be 0.75 ppmv.  The plant is also equipped with a FGC
process that injects both SO3 and NH3, with the SO3 injected upstream of
the air preheater.  The SO3 is injected at 7 ppmv at 6% O2 wet, and the
ammonia at 3 ppmv also at 6% O2 wet.  The FGC system operates whenever
the plant is on, except during startup and shutdown, with an operating
factor estimated at 0.9.  The coal used in the reporting year is
1,126,938 tons with a weighted average sulfur concentration of 2.0% and
a heating value of 12,000 Btu/lb.

Solution

From previous examples,

	Manufactured

		Total

		TSAM = EMComb + EMSCR + EMFGC

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

		TSAM = 2,119,789 lbs H2SO4/yr

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

	Released

		Combustion

		ERComb = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol 183 \f
"Symbol" \s 12 ·  F2  symbol 183 \f "Symbol" \s 12 ·  E2

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

		SCR

		ERSCR = [EMSCR – (Ks  symbol 183 \f "Symbol" \s 12 ·  B  symbol 183
\f "Symbol" \s 12 ·  fs  symbol 183 \f "Symbol" \s 12 ·  SNH3)]
symbol 183 \f "Symbol" \s 12 ·  F2  symbol 183 \f "Symbol" \s 12 ·  F2

		ERSCR = [423,023 – (3799  symbol 183 \f "Symbol" \s 12 ·  27.05
symbol 183 \f "Symbol" \s 12 ·  0.43  symbol 183 \f "Symbol" \s 12 ·
0.75)]  symbol 183 \f "Symbol" \s 12 ·  0.49  symbol 183 \f "Symbol" \s
12 ·  0.49

		ERSCR = 93,611 lbs H2SO4/yr

		FGC

		ERFGC = [EMFGC – (KE  symbol 183 \f "Symbol" \s 12 ·  B  symbol 183
\f "Symbol" \s 12 ·  fE  symbol 183 \f "Symbol" \s 12 ·  INH3)]
symbol 183 \f "Symbol" \s 12 ·  F3  symbol 183 \f "Symbol" \s 12 ·  F2

		ERFGC = [647,407 – (3799  symbol 183 \f "Symbol" \s 12 ·  27.05
symbol 183 \f "Symbol" \s 12 ·  0.9  symbol 183 \f "Symbol" \s 12 ·
3.0)]  symbol 183 \f "Symbol" \s 12 ·  0.25  symbol 183 \f "Symbol" \s
12 ·  1.0

		ERFGC = 92,487 lbs H2SO4/yr

			Total

		TSAR = ERComb + ERSCR + ERFGC

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

		TSAR = 438,049 lbs H2SO4/yr

Example 5:  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 a SCR process that operates during the ozone season only,
so that 0.43 of the coal burn occurred with the SCR operating.  The
ammonia slip is estimated to be 0.75 ppmv.  The plant is also equipped
with a FGC process that injects both SO3 and NH3, with the SO3 injected
upstream of the air preheater.  The SO3 is injected at 7 ppmv at 6% O2
wet, and the ammonia at 3 ppmv also at 6% O2 wet.  The FGC system
operates whenever the plant is on, except during startup and shutdown,
with an operating factor estimated at 0.9.  The coal used in the
reporting year is 1,126,938 tons with a weighted average sulfur
concentration of 2.0% and a heating value of 12,000 Btu/lb.  Natural gas
is used as a startup fuel, with 0.5 TBtu per year.  During startup,
neither the SCR nor the FGC system is used.  Used oil is also burned,
with 483.2 tons burned (0.0185 TBtu/yr) in the year.  Since the used oil
is burned when the unit is at full load, it is burned while the SCR and
FGC are both operating.  The used oil has a sulfur content of 0.1% from
analysis.

Solution

	Coal fuel calculations

	Manufactured from coal, from previous examples

		Total

		TSAM = EMComb + EMSCR + EMFGC

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

		TSAM = 2,119,789 lbs H2SO4/yr

	Released from coal, from previous examples

		Total

		TSAR = ERComb + ERSCR + ERFGC

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

		TSAR = 438,049 lbs H2SO4/yr

	Natural gas fuel calculations

	Manufactured from natural gas

		Combustion

E2NG = Kb BNG S

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

E2NG = 0.136 tons SO2/year

EMComb = K F1 E2NG

EMComb = 3063  0.01  0.136

EMComb = 4.16 lbs H2SO4 manufactured

None manufactured in either the SCR or FGC

	Released from natural gas

		Combustion

				ERComb = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol 183 \f
"Symbol" \s 12 ·  F2  symbol 183 \f "Symbol" \s 12 ·  E2NG

				ERComb = 3063  0.01 0.49  0.49  0.136

				ERComb = 1.00 lbs H2SO4 released

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

	Used oil fuel calculations

	Manufactured from used oil

		Combustion

E2 = K1 K2  C1  S1

E2 = 0.02  1.0  483.2  0.1

E2 = 0.966 tons SO2/year

EMComb = K F1 E2

EMComb = 3063  0.0175  0.966

EMComb = 51.8 lbs H2SO4 manufactured

SCR

	EMSCR = K  S2  fs  E2

	EMSCR = 3063  0.0075  1.0  0.966

	EMSCR = 22.2 lbs H2SO4 manufactured

FGC

	EMFGC = Ke  B  fe  Is

	EMFGC = 3799  0.0185  1.0  7.0

	EMFGC = 492 lbs H2SO4 manufactured

Total

				TSAM = EMComb + EMSCR + EMFGC

				TSAM = 51.8 + 22.2 + 492 lbs H2SO4/yr

				TSAM = 566 lbs H2SO4/yr

	Released from used oil

		Combustion

ERComb = K F1 F2  E2

ERComb = 3063  0.0175  0.49  0.49  0.966

ERComb = 12.43 lbs H2SO4 released

SCR

				ERSCR = [EMSCR – (Ks  symbol 183 \f "Symbol" \s 12 ·  B  symbol
183 \f "Symbol" \s 12 ·  fs  symbol 183 \f "Symbol" \s 12 ·  SNH3)]
symbol 183 \f "Symbol" \s 12 ·  F2  symbol 183 \f "Symbol" \s 12 ·  F2

				ERSCR = [22.2 – (3799  symbol 183 \f "Symbol" \s 12 ·  0.0185
symbol 183 \f "Symbol" \s 12 ·  1.0  symbol 183 \f "Symbol" \s 12 ·
0.75)]  symbol 183 \f "Symbol" \s 12 ·  0.49  symbol 183 \f "Symbol" \s
12 ·  0.49

				ERSCR = -7.33 lbs H2SO4/yr

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

FGC

				ERFGC = [EMFGC – (Ke  symbol 183 \f "Symbol" \s 12 ·  B  symbol
183 \f "Symbol" \s 12 ·  fe  symbol 183 \f "Symbol" \s 12 ·  INH3)]
symbol 183 \f "Symbol" \s 12 ·  F3  symbol 183 \f "Symbol" \s 12 ·  F2

				ERFGC = [492 – (3799  symbol 183 \f "Symbol" \s 12 ·  0.0185
symbol 183 \f "Symbol" \s 12 ·  1.0  symbol 183 \f "Symbol" \s 12 ·
3.0)]  symbol 183 \f "Symbol" \s 12 ·  0.25  symbol 183 \f "Symbol" \s
12 ·  1.0

				ERFGC = 70.3 lbs H2SO4/yr

Total

				TSAR = ERComb + ERSCR + ERFGC

				TSAR = 12.43 – 7.33 + 70.3 lbs H2SO4/yr

				TSAR= 75.4 lbs H2SO4/yr

Grand totals for all fuels

	Manufactured

			TSAM = TSAMcoal + TSAMNG + TSAMoil

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

			TSAM = 2,120,359 lbs H2SO4/yr

	Released

			TSAR = TSARcoal + TSARNG + TSARoil

			TSAR = 438,049 + 1.00 + 75.4 lbs H2SO4/yr

			TSAR = 438,125 lbs H2SO4/yr

BNG S

		= 0.0001359  12.3  2000

= 3.343 tons SO2/yr

EMCC = K F1 E2NG

		= 3063  0.0555  3.343

		= 568 lbs H2SO4 manufactured

	Released

		ERCC = K  symbol 183 \f "Symbol" \s 12 ·  F1  symbol 183 \f "Symbol"
\s 12 ·  F2  symbol 183 \f "Symbol" \s 12 ·  E2NG

			= 3063  0.0555  0.5 3.343

			= 284.5 lbs H2SO4 released

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

 PAGE   13

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tion Bypass Calculation.  Those units equipped with scrubbers where some
of the flue gas bypasses the scrubber should take this into account in
their combustion release calculations.  No credit for sulfuric acid
removal should be taken for the fraction of the flue gas that bypasses
the scrubber.  Therefore, this amount of the flue gas should not be
multiplied by the F2 factor for the scrubber.  However, the flue gas
volume should still be multiplied by the F2 factors for the other
control devices.

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

ERCOMB = [SBf + (1 – SBf) (  F2s] (  K ( F1  symbol 183 \f "Symbol" \s
12 ·  E2 ( F2x

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

		F2s 	=  F2 for scrubber

		F2x   =  All other applicable F2 factors except for scrubber.

Text Box B: Derivation of Conversion Factor,  KS.  The U.S. Code of
Federal Regulations 40, Part 60, Table 19-1 “F Factors for Various
Fuels” lists that 1 million Btu of heat input for bituminous or
subbituminous coal will produce 10,640 wet standard cubic feet of flue
gas, defined at 0% oxygen and on a wet basis at 20C and 760 mm Hg.
Correcting this volume to 6% O2 (typical at ESP conditions) yields a
volume of 14,925 scf.  The standard volume of one pound mole of any gas
is 359 scf, defined at 0C and 760 mm Hg.  Converting this to the English
units standard of 20C (68°F), one pound mole occupies 385 standard
cubic feet.  Using these in the equation above,

(Ks  symbol 183 \f "Symbol" \s 12 ·  B  symbol 183 \f "Symbol" \s 12 ·
 fs  symbol 183 \f "Symbol" \s 12 ·  SNH3) = lbs H2SO4 per yr =

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

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

Grouping terms,

 fs  SNH3  3799

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

Text Box C:  Special Provision for Flue Gas Desulfurization Bypass.
Those units equipped scrubbers where some of the flue gas bypasses the
scrubber should take this into account in their SCR/SNCR release
calculations also, as in the combustion release calculations.  No credit
for sulfuric acid removal should be taken for the fraction of the flue
gas that bypasses the scrubber.  Therefore, this amount of the flue gas
should not be multiplied by the F2 factor for the scrubber.  However, it
should still be multiplied by the F2 factors for the other control
devices.

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

ERSCR = [SBf + (1 – SBf) (  F2s]  symbol 183 \f "Symbol" \s 12 ·
[EMSCR – (Ks  symbol 183 \f "Symbol" \s 12 ·  B  symbol 183 \f
"Symbol" \s 12 ·  fs  symbol 183 \f "Symbol" \s 12 ·  SNH3)]  symbol
183 \f "Symbol" \s 12 ·  F2x

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

		F2s 	=  F2 factor for scrubber

		F2x 	=  All other applicable F2 factors except for scrubber.

Text Box D:  Special Provision for Flue Gas Desulfurization Bypass.
Those units equipped scrubbers where some of the flue gas bypasses the
scrubber should take this into account in their FGC release calculations
also, as in the combustion and SCR/SNCR release calculations.  No credit
for sulfuric acid removal should be taken for the fraction of the flue
gas that bypasses the scrubber.  Therefore, this amount of the flue gas
should not be multiplied by the F2 factor for the scrubber.  However, it
should still be multiplied by the F2 factors for the other control
devices.

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

ERFGC = [SBf + (1 – SBf) (  F2s]  symbol 183 \f "Symbol" \s 12 ·
[EMFGC – (Ke  symbol 183 \f "Symbol" \s 12 ·  B  symbol 183 \f
"Symbol" \s 12 ·  fe  symbol 183 \f "Symbol" \s 12 ·  INH3)]  symbol
183 \f "Symbol" \s 12 ·  F3  symbol 183 \f "Symbol" \s 12 ·  F2x

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

		F2s 	=  F2 factor for scrubber

		F2x 	=  All other applicable F2 factors except for scrubber.

Text Box E:  Derivation of Molecular Weight And Units Conversion
Constant, Kb

Kb is determined from the following analysis of the equation.

(Kb  symbol 183 \f "Symbol" \s 12 ·  BNG  symbol 183 \f "Symbol" \s 12
·  S) = tons SO2 per yr =

BNG TBtu	S gr S	1 scf nat gas	1012 Btu	lb S	1 ton S	1 ton mol S	1 ton
mole SO2	64 tons SO2

Year	106 scf

nat gas	1050 Btu	TBtu	7000 gr S	2000 lbs S	32 tons S	1 ton mol S	1 ton
mole SO2

Grouping terms,

= (BNG  symbol 183 \f "Symbol" \s 12 ·  S)  symbol 183 \f "Symbol" \s
12 ·  64 / (1050  symbol 183 \f "Symbol" \s 12 ·  32  symbol 183 \f
"Symbol" \s 12 ·  14) = (BNG  symbol 183 \f "Symbol" \s 12 ·  S)
symbol 183 \f "Symbol" \s 12 ·  0.0001359

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

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

(KNG  symbol 183 \f "Symbol" \s 12 ·  N1  symbol 183 \f "Symbol" \s 12
·  S) = tons SO2 per yr =

N1 106 scf	S gr S	lb S	1 ton S	1 ton mol S	1 ton mole SO2	64 tons SO2

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

Grouping terms,

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*symbol 183 \f "Symbol" \s 12 ·  S)  symbol 183 \f "Symbol" \s 12 ·
1.427  symbol 183 \f "Symbol" \s 12 ·  10-7

Therefore, the value of KNG is equal to 1.427  symbol 183 \f "Symbol" \s
12 ·  10-7  tons SO2/(grains S)