Estimating Sulfuric Acid Aerosol Emissions

from Coal-Fired Power Plants

R. Hardman

R. Stacy

Southern Company Services

E. Dismukes, retired

Southern Research Institute

U. S. Department of Energy-FETC

Conference on

Formation, Distribution, Impact, and Fate

of Sulfur Trioxide in Utility Flue Gas Streams

March 1998

ABSTRACT

This paper presents a proposed method for estimating the release of sulfuric acid (H2SO4) aerosol

from coal-fired power plants. The U. S. Environmental Protection Agency’s Toxic Release

Inventory (TRI) reporting system requires that, beginning in 1998, electric utilities must estimate

their emissions of over 600 chemical compounds. Aerosols of H2SO4 are one of the compounds

included in the TRI. In coal-fired plants, H2SO4 vapor is created in the ductwork downstream of

the boiler by the combination of water vapor and sulfur trioxide (SO3), both of which are

produced during the coal combustion process. In some cases, the vapor condenses as an aerosol,

which makes it a reportable compound. Since the TRI system does not require the collection of

any new data, the method presented herein was developed to use data and information already

available at most coal-fired plants. These factors include the SO2 emission rate, the type of fuel

being burned, and the particulate control device used to control dust emissions.
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INTRODUCTION

In June 1995, the U. S. Environmental Protection Agency modified the list of chemicals subject

to reporting requirements under Section 313 of the Emergency Planning and Community Rightto-Know Act (EPCRA) [1]. At that time, the reportable forms of sulfuric acid (H2SO4) were

changed to include only acid aerosols. Beginning in 1998, most electric utilities are required to

report emissions of these sulfuric acid aerosols if they meet any of the following annual

threshold requirements [2]:

1. If the facility manufactures 25,000 pounds of sulfuric acid aerosols

2. If the facility processes 25,000 pounds of sulfuric acid aerosols

3. If the facility otherwise uses 10,000 pounds of sulfuric acid aerosols.

This paper presents a proposed method for estimating the release of H2SO4 aerosols from coalfired utility boilers (item 1 above). In coal-fired plants, H2SO4 vapor forms in the ductwork

downstream of the boiler by the combination of water vapor and sulfur trioxide (SO3), both of

which are produced during the coal combustion process. After formation, some of the H2SO4

may condense and be emitted as an aerosol (the reportable quantity) depending on the flue gas

temperature.

Following the presentation of the proposed prediction method, supporting information regarding

the impact of fuel grade on the formation of SO3, the conversion of SO3 to an H2SO4 vapor, the

effect of particulate control equipment on H2SO4 collection, and the condensation of H2SO4 to an

acid aerosol is presented. The effect of coal sulfur content is also shown. Sample calculations

are provided.

PREDICTION METHOD

The following set of relationships is proposed to predict the H2SO4 aerosol concentrations in the

flue gas exiting a coal-fired power plant:

E1= E2 - E3 (1)

where,

E1 = H2SO4 aerosol concentration, ppm (parts per million)

E2 = Total H2SO4 concentration, ppm

E3 = H2SO4 vapor concentration, ppm

The total H2SO4 concentration is determined with the following relationship:

E2 = K ⋅ F1⋅ F2 ⋅E4 (2)

where,

K = Molecular weight and units conversion constant = 98.07 / 64.04 = 1.53

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

F1 = Fuel Impact Factor

F2 = Technology Impact Factor

E4 = Sulfur dioxide (SO2) emissions concentration, ppm
-3-

The H2SO4 vapor fraction (E3) is based on the total H2SO4 concentration and the flue gas exit

temperature.

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

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

• All SO3 is converted to an H2SO4 vapor.

• The type of particulate control device at the plant impacts the flue gas concentration of

H2SO4.

• The boiler is wall-fired or tangentially fired.

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

Supporting information and specific values for determining the SO2 concentration (E4), the

H2SO4 vapor fraction (E3), the Fuel Impact Factor (F1), and the Technology Impact Factor (F2)

are provided in the section below. Finally, a method to determine the portion of H2SO4 vapor

that forms an acid aerosol is provided. Sample calculations with applications of this relationship

to a specific plant configuration are provided in the following section.

SUPPORTING INFORMATION

SO2 Concentration (E4)

The concentration of SO2 in the flue gas is determined by conversion from the annual emissions

rate as shown in the relationship below [3]:















 −

⋅

⋅ ⋅

⋅

=

20.9

20.9 %O

F k HI

2000 E5 E4 

2,d

SO2

(3)

where:

E4 = SO2 flue gas concentration, ppm

E5 = Annual SO2 emissions as recorded by a continuous emissions monitor, tons per

year

F = Fuel factor

= 9780 dscf / MBtu for bituminous and sub-bituminous coals

SO2

k = Conversion factor

= 1.660 x 10-7 (lb/scf)/ppm SO2

HI = Annual heat input for the unit, MBtu / year

%O2,d = Concentration of oxygen at the stack (dry). A typical flue gas oxygen

concentration at the stack is 6 percent.

Fuel Impact Factor (F1)

In coal-fired electric utility boilers, gaseous sulfur-bearing compounds are generated during the

combustion process. The majority of the sulfur in the coal combines with oxygen to form SO2.

However, a small minority of the sulfur is further oxidized to form SO3. The formation of SO3 is

a complex process that is not thoroughly understood even after many years of

investigation [4, 5]. The rate of formation is dependent upon a number of factors such as the

sulfur content of the fuel, amount of excess air, and the presence of some form of catalyst.
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Three mechanisms have been proposed to explain the oxidation of SO2 to SO3 [6, 7].

1. Oxidation of SO2 in the flame by atomic oxygen

SO2 + O ÷ SO3

2. Oxidation of SO2 by molecular oxygen

SO2 + 1⁄2 O2 ÷ SO3

3. Catalytic oxidation via molecular oxygen.

This last mechanism is a result of catalytic oxidation of SO2 to SO3 by both ash particles and

metal heat transfer surfaces. This oxidation occurs at the temperature range (800 – 1100°F)

found in the economizer section of utility boilers.

In the literature, varying and sometimes conflicting estimates exist regarding the conversion of

SO2 to SO3. For example, in one publication the conversion rate is estimated to vary from 3 to

5 percent, from 1.25 to 5 percent, and from 1 to 4 percent, depending on the section of the book

being read [8]. In other reports, which focus on the performance of cold-side ESPs, the ratio of

SO2 to SO3 at the air heater outlet is presented. These ratios are lower since a portion of the SO3

generated during the coal combustion process condenses onto the cold sections of the air heater

baskets as the flue gas temperature drops. For example, in one evaluation average flue gas SO3

concentrations dropped from 25 ppm to 11 ppm (56 percent) across a hot-side ESP and an air

heater [9]. Other reports, such as an EPA-documented SO2 to SO3 ratio of 0.4 percent [10],

confirm these pilot-scale results. The same EPA study reports that the SO3 levels from six

different power stations varied from undetectable levels to 0.67 percent of the SO2 concentration

(Table 1). Other full-scale experimental results based on measurements during 16 field tests

showed concentrations ranging from 0.1 to 0.41 percent of the SO2 levels (Table 2) [11]. In both

of these examples, the SO3 concentrations when burning western coals were lower than the SO3

concentrations when burning eastern coals. Laboratory analyses have confirmed the directly

proportional relationship between the SO2 to SO3 conversion rate and the sulfur content of the

fuel [12].

Based on the data provided above, proposed values for the Fuel Impact Factor (F1) are provided

in Table 3. These factors are based on the full-scale plant data presented previously and account

for SO3 condensation that occurs in the air heater. In proposing these factors, corroborating

and / or conflicting information regarding the Fuel Impact Factor for these and other fuels is

sought.

Table 1. SO2 and SO3 measurements from 6 different power plants

Station Number SO2, ppm SO3, ppm SO3 / SO2 ratio

1 (western coal) 262 <1 <0.0038

5 (western coal) 480 <1 <0.0021

13 (western coal) 430 <1 <0.0023

3 (eastern coal) 2440 6-9 0.0025 – 0.0037

4 (eastern coal) 755 2-3 0.0026 – 0.0040

7 (eastern coal) 600 3-4 0.0050 – 0.0067
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Table 2. Ratio of SO3 / SO2 based on in situ measurements for 16 field tests

SO3 / SO2 ratio

Coals Burned average standard deviation

9 eastern bituminous coals 0.0041 0.0027

7 western subbituminous and lignite coals 0.0011 0.0005

Table 3. Fuel Impact Factors for various coals

Coal F1

Eastern bituminous 0.004

Western bituminous 0.001

Powder River Basin (PRB) 0.0005

Technology Impact Factor (F2)

Electrostatic precipitators and baghouses remove particulates from the flue gas stream. In the

process, they also remove acid gases that have condensed onto the particulate matter. Hot-side

ESPs function at temperatures where little H2SO4 has formed. However, in cold-side ESPs and

baghouses, a majority of the SO3 has converted to H2SO4 vapor. As the flue gas temperature is

reduced, H2SO4 aerosols adsorb onto the fly ash to form an acid layer that allows electrical

currents to flow more easily, thereby lowering the ash resistivity. The amount of H2SO4

interacting with the fly ash increases as the temperature decreases [13].

Little definitive data are available describing the SO3 / H2SO4 collection rate in cold-side

particulate collection equipment. However, anecdotal evidence suggests that acid aerosol

collection does occur. For example, in flue gas from the combustion of low-sulfur coal (low

native SO3 concentrations), SO3 injection systems are used for flue gas treatment to improve

particulate collection efficiency. The SO3 injection rate is controlled to provide optimal

performance with minimal SO3 utilization. In doing this, SO3 injection is increased to the point

where no appreciable increases in ESP performance occur (i.e., no additional H2SO4 is being

adsorbed by the ash). With respect to baghouses, the dust cake on the bags acts as a barrier filter

through which all H2SO4 vapor must pass. It is assumed that a majority of the H2SO4 condenses

and is adsorbed by the fly ash as it passes through the dust cake.

Technology Impact Factors (F2) for ESPs and baghouses are proposed (Table 4). In sites where

multiple devices are installed, the factor for the device nearest the stack should be used. These

factors are engineering estimates based on available data and operational experience. In

proposing these factors, corroborating and / or conflicting information is sought.

Table 4. Technology Impact Factors

for particulate control devices

Particulate Control Device F2

Hot-side ESP 1.00

Cold-side ESP 0.75

Baghouse 0.10
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Sulfuric Acid (H2SO4) Vapor Formation

This analysis assumes that all of the SO3 forms an H2SO4 vapor prior to reaching the stack exit.

Sulfur trioxide is a hygroscopic material and will absorb moisture at temperatures well above its

dewpoint [14, 15, 16]. By definition, a hygroscopic material has solvent properties, and its

moisture content will approach equilibrium with the moisture content of the surrounding air. As

the flue gas temperature drops, the concentration of H2SO4 increases and the concentration of

SO3 decreases. For example, in 400°F flue gas with a moisture content of 8 percent, nearly 99

percent of the SO3 has combined with water to form an H2SO4 vapor (Table 5, Figure 1) [17]:

SO3 + H2O ÷ H2SO4

Table 5. SO3 conversion to H2SO4 vapor at various

flue gas temperatures

Temperature, °F SO3 converted to H2SO4 , %

800 3.85

700 14.30

600 47.54

550 70.54

500 87.50

400 98.86

350 99.74

0

20

40

60

80

100

120

300 400 500 600 700 800 900

Temperature, F

SO3 Conversion to H SO 2 4 Vapor, %

H2SO4

SO3

Figure 1. Portion of SO3 that is converted to H2SO4 vapor at various flue gas temperatures

assuming flue gas moisture content of 8 percent.

H2SO4 Vapor Fraction (E3)

The portion of H2SO4 that condenses from the vapor to an aerosol (the reportable quantity) is a

function of the total H2SO4 concentration, the flue gas temperature, and the flue gas moisture

content. In cases where the stack flue gas exit temperature exceeds the H2SO4 dew point, no acid

aerosols are formed. In other words, the total H2SO4 concentration, E2, is equal to the H2SO4

vapor concentration, E3, and the reportable quantity is zero.
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However, when the stack flue gas exit temperature is at or below the H2SO4 dew point, an acid

aerosol / vapor mixture is present. As a result, the vapor fraction must be calculated to determine

the reportable acid aerosol concentration. To accomplish this, the H2SO4 dew point must be

calculated.

The H2SO4 dew point is a function of the partial pressures of the H2SO4 and the moisture in the

flue gas. It can be approximated by the following relationship [18]:

1/DP 2.276 10 2.943 10 ln(pp ) 8.58 10 ln(pp ) 6.20 10 ln(pp )ln(pp )

2 2 4 H2O H2SO4

6

H SO

5

H O

−3 −5 − −

= x − x − x + x

(4)

where:

DP = H2SO4 dew point, °Kelvin

ppH2O = partial pressure of the flue gas moisture, mm Hg

= 760 ⋅(flue gas moistue content, %)

H2SO4

pp = partial pressure of the H2SO4, mm Hg

=

-6 760 ⋅(H2SO4 concentration, ppm) ⋅1x10

This relationship is shown graphically for flue gas with a moisture content of 10 percent in

Figure 2. Above the curve, all H2SO4 exists as a vapor. Below the curve, an aerosol/vapor

mixture is present. Dew points for various H2SO4 concentrations at two different flue gas

moisture contents are provided in Table 6.

Using Table 6 or Figure 3, the vapor fraction (E3) for a specific flue gas temperature can be

determined. This vapor fraction also can be used to determine the H2SO4 aerosol fraction in the

flue gas. An example graphical determination of the vapor fraction and the aerosol fraction is

provided in Figure 3. In a flue gas determined to have a 9-ppm H2SO4 concentration (E2), a

moisture content of 10 percent, and a stack exit gas temperature of 250°F, the vapor fraction (E3)

is approximately 1.7 ppm. The aerosol fraction would be approximately 7.3 ppm.

Table 6. H2SO4 dew points (°F) for two different flue gas moisture contents

H2SO4 vapor concentration, ppm 8% moisture 10% moisture

0.1 200.6 205.4

0.5 224.9 229.5

1 236.0 240.5

3 254.3 258.5

5 263.1 267.3

10 275.4 279.5

15 282.9 286.8

20 288.2 292.1
-8-

175

200

225

250

275

300

0.1 1 10 100

H2SO4 Vapor Concentration

Flue Gas Temperature, F

H2SO4 vapor

H2SO4 aerosol / vapor 

mixture 

flue gas moisture content = 10%

Figure 2. H2SO4 aerosol formation diagram (log-linear scale).

175

200

225

250

275

300

0.1 1 10

H2SO4 Concentration, ppm

Flue Gas Temperature, F

vapor fraction = 1.7 ppm

aerosol 

fraction

aerosol fraction = 9 - 1.7 = 7.3 ppm

Figure 3. Relationship between vapor fraction and aerosol fraction (log-linear scale).

H2SO4 Emission Rate

Once the H2SO4 aerosol concentration (ppm) is determined, the H2SO4 emissions rate (pounds

per year) can be calculated using the following relationship [19]:

















−

= ⋅ ⋅ ⋅ ⋅

2,d

H SO 20.9 %O

20.9

E6 E1 k F HI

2 4

(5)
-9-

where:

E6 = H2SO4 aerosol emissions rate, pounds per year

H2SO4

k = Conversion factor = 2

SO K ⋅ k

= 2.54 x 10-7 (lb/scf)/ppm H2SO4

EXAMPLE CALCULATIONS

This section presents a series of example calculations based on the solution process provided

above. 

Example 1. A base-loaded, 700-MW coal-fired boiler equipped with a cold-side ESP burns an

eastern bituminous coal. SO2 emissions are 33,700 tons per year. Annual heat input

is 43,800,000 MBtu. Flue gas moisture content is 10 percent and stack oxygen

concentration is 6 percent (dry). Based on data from continuous emissions monitor

RATA tests, the stack exit gas temperature at full load is 297°F.

Solution 1. Determine flue gas SO2 concentration (Equation 3).

675 ppm

20.9

20.9 6

9780 1.660 10 43,800,000

2000 33,700 E4 7

 =









 −

⋅

⋅ ⋅

⋅

= −

x

Determine total H2SO4 concentration in the flue gas at the stack (Equation 2).

E2 = 1.53⋅ 0.004 ⋅ 0.75⋅ 675 = 3.1ppm

Using Table 6, the dew point for an H2SO4 concentration of 3.1 ppm is

approximately 260°F. Since, the stack exit temperature exceeds the dew point,

H2SO4 aerosol emissions are zero.

Example 2. Use the same information from example 1; however, in this case unit operation

cycles. Stack exit gas conditions and unit operations data for three different load

points are available (below).

Condition Stack Temperature, °F Heat Input, MBtu

Full load (700 MW) 297 30,000,000

Mid load (500 MW) 249 7,000,000

Low load (340 MW) 229 6,800,000

Solution 2. From Example 1, the total H2SO4 concentration in the flue gas at the stack is

3.1 ppm. Now, consider H2SO4 the vapor / aerosol fractions for each operating

condition.

Full-load operation. From Example 1, all H2SO4 emissions are in the vapor state at

297°F. There are no aerosol H2SO4 emissions.

Mid-load operation. Using Table 6, the mid-load stack exit gas temperature is

below the dew point for an H2SO4 concentration of 3.1 ppm. Some aerosols will be
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present. By interpolation in Table 6, the vapor concentration is approximately

2 ppm at 249°F. Applying Equation 1, the H2SO4 aerosol concentration is 3.1 – 2.0

= 1.1 ppm. Applying Equation 5, the H2SO4 aerosol emissions rate for this load bin

can be determined:

24,400 pounds per year.

20.9 6.0

20.9

E6 1.1 2.54 10 9780 7,000,000 7

 =











−

= ⋅ ⋅ ⋅ ⋅

−

x

Low-load operation. Using Table 6, the low-load stack exit gas temperature is

below the dew point for an H2SO4 concentration of 3.1 ppm. Some aerosols will be

present. By interpolation in Table 6, the vapor concentration is approximately

0.7 ppm at 229°F. Applying Equation 1, the H2SO4 aerosol concentration is 3.1 –

0.7 = 2.4 ppm. Applying Equation 5, the H2SO4 aerosol emissions for this load bin

can be determined:

56,900 pounds per year.

20.9 6.0

20.9

E6 2.4 2.54 10 9780 6,800,000 7

 =











−

= ⋅ ⋅ ⋅ ⋅

−

x

The total H2SO4 aerosol emission is the sum of the emissions from the three load

bins: 0 + 24,400 + 56,900 = 81,300 pounds per year.

OTHER IMPACTS

In addition to the factors considered above, the following site-specific characteristics may impact

H2SO4 emissions rates. These factors are not considered in this proposed method.

1. NOx reduction catalysts. Typically, catalysts used to reduce NOx emissions increase flue

gas SO3 concentrations. Results from a DOE-sponsored evaluation of several different

catalysts treating flue gas from the combustion of high-sulfur U.S. coals reported average

SO3 oxidation levels of 0.31 percent [20].

2. Ammonia injection systems. Ammonia injection systems are used to improve the

performance of cold-side ESPs and in NOx control technologies (selective catalytic reduction

and selective non-catalytic reduction.) At temperatures below approximately 500°F,

ammonia preferentially reacts with SO3 to form ammonium sulfate and ammonium bisulfate.

These reactions can act to reduce or eliminate the presence of SO3 (and subsequently H2SO4)

in the flue gas stream.

3. SO3 injection systems. SO3 injection systems (sometimes called sulfur burners) are used to

improve the particulate collection capabilities of cold-side ESPs. The SO3 is injected into the

flue gas upstream of the ESP. The SO3 reacts with moisture in the flue gas to create H2SO4,

which improves the resistivity of the fly ash making it easier to collect. Some of the H2SO4

(~1 ppm) generated by the sulfur burners may slip through the ESP resulting in higher flue

gas H2SO4 concentrations at the stack.

4. Natural gas co-firing. Since natural gas does not contain sulfur, co-firing or reburning

natural gas in a boiler may change the SO3 to SO2 production ratio.

CONCLUSIONS

This paper presents a method for predicting the emissions of sulfuric acid aerosols from coalfired power plants. The calculation is based on the unit’s SO2 emission rate as recorded by a

continuous emissions monitor. The method accounts for the rank of coal being burned and the
-11-

type of particulate control device installed at the facility. The effects of H2SO4 vapor

condensation at the dew point and subsequent aerosol formation are included in the analysis.

Influencing factors not accounted for in the process include catalytic conversion across NOx

reducing catalysts, reactions with ammonia injected for NOx control or flue gas conditioning,

additional SO3 injected for flue gas conditioning, and natural gas co-firing.

 

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Rule. 60 FR 34182. June 30, 1995.

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any particle size). EPA-745-R-97-007. November 1997.

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5 Black, B. A., Clarkson, R. J., Practical Control of Acid Dewpoint Corrosion, Research and

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11 Bickelhaupt, Roy E., A Study to Improve A Technique for Predicting Fly Ash Resistivity with

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56.

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18 Banchero, J. T., and Verhoff, F. H., J. Ins. Fuel, June 1975, p 76.

19 EPA Code of Federal Regulations 40, Part 60, Appendix A, Method 19, 1997 Edition.

20 Southern Company Services, Inc. Demonstration of Selective Catalytic Reduction Technology for

the Control of Nitrogen Oxide (NOx) Emissions from High-Sulfur Coal Fired Boilers. Final Report.

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