## 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 (H 2 SO 4 ) 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 H 2 SO 4 are one of the compounds included in the TRI. In coal-fired plants, H 2 SO 4 vapor is created in the ductwork downstream of the boiler by the combination of water vapor and sulfur trioxide (SO 3 ), 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 SO 2 emission rate, the type of fuel being burned, and the particulate control device used to control dust emissions.- 2

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INTRODUCTION In June 1995, the U. S. Environmental Protection Agency modified the list of chemicals subjectto 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 (H 2 SO 4 ) 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 H 2 SO 4 aerosols from coalfired utility boilers (item 1 above). In coal-fired plants, H 2 SO 4 vapor forms in the ductwork downstream of the boiler by the combination of water vapor and sulfur trioxide (SO 3 ), both of which are produced during the coal combustion process. After formation, some of the H 2 SO 4 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 SO 3 , the conversion of SO 3 to an H 2 SO 4 vapor, the effect of particulate control equipment on H 2 SO 4 collection, and the condensation of H 2 SO 4 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 H 2 SO 4 aerosol concentrations in the flue gas exiting a coal-fired power plant:
E3

- E2 E1 = (1) where,
E1 = H 2 SO 4 aerosol concentration, ppm (parts per million) E2 = Total H 2 SO 4 concentration, ppm E3 = H 2 SO 4 vapor concentration, ppm The total H 2 SO 4 concentration is determined with the following relationship:
E4 F2 F1 K E2
⋅

⋅ ⋅ = (2) where,
K = Molecular weight and units conversion constant = 98.07 / 64.04 = 1.53

98.07 = Molecular weight of H 2 SO 4 ; 64.04 = Molecular weight of SO 2 F1 = Fuel Impact Facto r F2 = Technology Impact Factor E4 = Sulfur dioxide (SO 2 ) emissions concentration, ppm- 3

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The H 2 SO 4 vapor fraction (E3) is based on the total H 2 SO 4 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 SO 2 to SO 3 . • All SO 3 is converted to an H 2 SO 4 vapor.
• The type of particulate control device at the plant impacts the flue gas concentration of H 2 SO 4 . • The boiler is wall-fired or tangentially fired.
• The rate of SO 3 formation is independent of the boiler firing rate (unit load). Supporting information and specific values for determining the SO 2 concentration (E4), the H 2 SO 4 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 H 2 SO 4 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 SO 2 in the flue gas is determined by conversion from the annual emissions rate as shown in the relationship below [ 3 ]:        

−

⋅

⋅ ⋅ ⋅ = 9

. 20%O 9

. 20 HI k F E5 2000 E4 d 2,
SO 2 (3)
where:
E4 = SO 2 flue gas concentration, ppm E5 = Annual SO 2 emissions as recorded by a continuous emissions monitor, tons per

year F = Fuel factor

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

2 SO k = Conversion factor

= 1.660 x 10 -7 ( lb/ scf)/ppm SO 2 HI = Annual heat input for the unit, MBtu / year %O 2 ,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 SO 2 . However, a small minority of the sulfur is further oxidized to form SO 3 . The formation of SO 3 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.- 4

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Three mechanisms have been proposed to explain the oxidation of SO 2 to SO 3 [ 6 , 7 ]. 1. Oxidation of SO 2 in the flame by atomic oxygen

SO 2 + O ÷ SO 3 2. Oxidation of SO 2 by molecular oxygen

SO 2 + 1⁄2 O 2 ÷SO 3 3. Catalytic oxidation via molecular oxygen. This last mechanism is a result of catalytic oxidation of SO 2 to SO 3 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 SO 2 to SO 3 . 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 t o 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 SO 2 to SO 3 at the air heater outlet is presented. These ratios are lower since a portion of the SO 3 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 SO 3 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 SO 2 to SO 3 ratio of 0.4 percent [ 10 ], confirm these pilot-scale results. The same EPA study reports that the SO 3 levels from six different power stations varied from undetectable levels to 0.67 percent of the SO 2 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 SO 2 levels (Table2) [ 11 ]. In both of these examples, the SO 3 concentrations when burning western coals were lower than the SO 3 concentrations when burning eastern coals. Laboratory analyses have confirmed the directly proportional relationship between the SO 2 to SO 3 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 SO 3 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. SO 2and SO 3 measurements from 6 different power plants Station Number SO 2 , ppm SO 3 , ppm SO 3 / SO 2ratio 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- 5

- Table 2 . Ratio of SO 3 / SO 2 based on in situ measurements for 16 field tests SO 3 / SO 2ratio 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 H 2 SO 4 has formed. However, in cold-side ESPs and baghouses, a majority of the SO 3 has converted to H 2 SO 4 vapor. As the flue gas temperature is reduced, H 2 SO 4aerosols 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 H 2 SO 4 interacting with the fly ash increases as the temperature decreases [ 13 ]. Little definitive data are available describing the SO 3 / H 2 SO 4 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 SO 3 concentrations), SO 3 injection systems are used for flue gas treatment to improve particulate collection efficiency. The SO 3 injection rate is controlled to provide optimal performance with minimal SO 3 utilization. In doing this, SO 3 injection is increased to the point where no appreciable increases in ESP performance occur (i.e., no additional H 2 SO 4 is being adsorbed by the ash). With respect to baghouses, the dust cake on the bags acts as a barrier filter through which all H 2 SO 4 vapor must pass. It is assumed that a majority of the H 2 SO 4 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 (Table4). In si tes 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- 6

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Sulfuric Acid (H 2 SO 4

) Vapor Formation This analysis assumes that all of the SO 3 forms an H 2 SO 4 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 H 2 SO 4 increases and the concentration of SO 3 decreases. For example, in 400 ° F flue gas with a moisture content of 8 percent, nearly 99 percent of the SO 3 has combined with water to form an H 2 SO 4 vapor (Table 5, Figure 1) [ 17 ]: SO 3 + H 2 O ÷H 2 SO 4 Table 5 . SO 3 conversion to H 2 SO 4 vapor at various

flue gas temperatures Temperature, ° F SO 3 converted to H 2 SO 4, % 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, FSO3Conversion to H2SO4Vapor, %

H 2 SO 4 SO 3

Figure 1. Portion of SO 3 that is converted to H 2 SO 4 vapor at various flue gas temperatures

assuming flue gas moisture content of 8 percent.
H 2 SO 4Vapor Fraction (E3) The portion of H 2 SO 4 that condenses from the vapor to an aerosol (the reportable quantity) is a function of the total H 2 SO 4 concentration, the flue gas temperature, and the flue gas moisture content. In cases where the stack flue gas exit temperature exceeds the H 2 SO 4 dew point, no acid aerosols are formed. In other words, the total H 2 SO 4 concentration, E2, is equal to the H 2 SO 4 vapor concentration, E3, and the reportable quantity is zero.- 7

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However, when the stack flue gas exit temperature is at or below the H 2 SO 4 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 H 2 SO 4 dew point must be calculated. The H 2 SO 4 dew point is a function of the partial pressures of the H 2 SO 4 and the moisture in the flue gas. It can be approximated by the following relationship [ 18 ]: ) pp ln( ) pp ln( 10 20

. 6 ) pp ln( 10 58

. 8 ) pp ln( 10 943

. 2 10 276

. 2 /DP 1 4 2 2 4 2 2 SO H O H 6 SO H 5 O H 5 3

− − − − +

− − = x x x x (4) where: DP = H 2 SO 4 dew point, ° Kelvin

O H 2 pp = partial pressure of the flue gas moisture, mm Hg

= %) content, moistue gas (flue 760
⋅

4 2 SO H pp = partial pressure of the H 2 SO 4 , mm Hg

= -6 4 2 1x10

ppm) ion, concentrat SO (H 760
⋅ ⋅ This relationship is shown graphically for flue gas with a moisture content of 10 percent in Figure2. Above the curve, all H 2 SO 4 exists as a vapor. Below the curve, an aerosol/vapor mixture is present. Dew points for various H 2 SO 4 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 H 2 SO 4 aerosol fraction in the flue gas. An example graphical determination of the vapor fraction and the aerosol fraction is provided in Figure3. In a flue gas determined to have a 9-ppm H 2 SO 4 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 . H 2 SO 4 dew points ( ° F) for two different flue gas moisture contents H 2 SO 4vapor 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

H 2 SO 4 Vapor ConcentrationFlue Gas Temperature, F H 2 SO 4 v apor

H 2 SO 4aerosol / vapor

mixture flue gas moisture content = 10%

Figure 2. H 2 SO 4 aerosol formation diagram (log-linear scale).

175 200 225 250 275 300

0.1 1 10

H 2 SO 4Concentration, ppmFlue 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).

H 2 SO 4Emission Rate Once the H 2 SO 4 aerosol concentration (ppm) is determined, the H 2 SO 4 emissions rate (pounds per year) can be calculated using the following relationship [ 19 ]:

       

− ⋅ ⋅ ⋅ ⋅ = d 2, SO H %O

9

. 20 9

. 20 HI F k E1 E6 4 2 (5)- 9

-

where:
E6 = H 2 SO 4 aerosol emissions rate, pounds per year

4 2 SO H k = Conversion factor = 2 SO k K
⋅

= 2.54 x 10 -7 ( lb/ scf)/ppm H 2 SO 4 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. SO 2 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 SO 2 concentration (Equation 3). ppm 675 9

. 20 6 9

. 20 000 , 800 , 3 4 10 660

. 1 780 9 700

, 3 3 2000 E4 7 =      

−

⋅

⋅ ⋅ ⋅ =

−

x Dete rmine total H 2 SO 4 concentration in the flue gas at the stack (Equation 2). ppm 1

. 3 675 75

. 0 004

. 0 53

. 1 E2 =

⋅ ⋅ ⋅ = Using Table 6, the dew point for an H 2 SO 4 concentration of 3.1 ppm is approximately 260 ° F. Since, the stack exit temperature exceeds the dew point, H 2 SO 4 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 H 2 SO 4 concentration in the flue gas at the stack is

3.1 ppm. Now, consider H 2 SO 4 the vapor / aerosol fractions for each operating condition. Full-load operation. From Example 1, all H 2 SO 4 emissions are in the vapor state at 297 ° F. There are no aerosol H 2 SO 4 emissions. Mid-load operation. Using Table 6, the mid-load stack exit gas temperature is below the dew point for an H 2 SO 4 concentration of 3.1 ppm. Some aerosols will be- 10

- present. By interpolation in Table 6, the vapor concentration is approximately 2 ppm at 249 ° F. Applying Equation 1, the H 2 SO 4 aerosol concentration is 3.1 – 2.0 = 1.1 ppm. Applying Equation 5, the H 2 SO 4 aerosol emissions rate for this load bin can be determined: year. per pounds 400 , 24 0

. 6 9

. 20 9

. 20 000 , 000 , 7 9780 10 54

. 2 1.1 E6 7 =      

− ⋅ ⋅ ⋅ ⋅ = −

x Low-load operation. Using Table 6, the low-load stack exit gas temperature is below the dew point for an H 2 SO 4 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 H 2 SO 4 aerosol concentration is 3.1 – 0.7 = 2.4 ppm. Applying Equation 5, the H 2 SO 4 aerosol emissions for this load bin can be determined: year. per pounds 900 , 56 0

. 6 9

. 20 9

. 20 000 , 800 , 6 9780 10 54

. 2 2.4 E6 7 =      

− ⋅ ⋅ ⋅ ⋅ = −

x

The total H 2 SO 4 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 H 2 SO 4 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 SO 3 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 SO 3 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 SO 3 to form ammonium sulfate and ammonium bisulfate. These reactions can act to reduce or eliminate the presence of SO 3 (and subsequently H 2 SO 4 ) in the flue gas stream. 3. SO 3 injection systems . SO 3 injection systems (sometimes called sulfur burners) are used to improve the particulate collection capabilities of cold-side ESPs. The SO 3 is injected into the flue gas upstream of the ESP. The SO 3 reacts with moisture in the flue gas to create H 2 SO 4 , which improves the resistivity of the fly ash making it easier to collect. Some of the H 2 SO 4 (~1 ppm) generated by the sulfur burners may slip through the ESP resulting in higher flue gas H 2 SO 4 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 SO 3 to SO 2production ratio. CONCLUSIONSThis paper presents a method for predicting the emissions of sulfuric acid aerosols from coalfired power plants. The calculation is based on the unit’s SO 2 emission rate as recorded by a continuous emissions monitor. The method accounts for the rank of coal being burned and the- 11

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type of particulate control device installed at the facility. The effects of H 2 SO 4 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 SO 3 injected for flue gas conditioning, and natural gas co-firing.

1 EPA. 1995. Sulfuric Acid: Toxic Chemical Release Reporting: Community Right-To-Know. Final Rule. 60 FR 34182. June 30, 1995. 2 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. 3 EPA Code of Federal Regulations 40 , Part 60, Appendix A, Method 19, 1997 Edition. 4 Plumley , A. L., Jonakin , J., Vuia , R. E. A Review Study of Fire-Side Corrosion in Utility and Industrial Boilers . Paper presented at Corrosion Seminar, McMaster University and Engineering Institute of Canada, May 19-20, 1966. 5 Black, B. A., Clarkson, R. J., Practical Control of Acid Dewpoint Corrosion, Research and Development Department, Southern Company Services, August 1983. 6 Plumley, et al

.. 7 Reid, W. T. External Corrosion and Deposits

. Boiler Tubes and Gas Turbines

. American Elsevier Publishing Company, New York (1971), pp. 84-94. 8 Combustion Fossil Power , pp. 14-36, 15-27, and 15-3, edited by Joseph P. Singer, 1991. 9 Dismukes, E. B., Measurement of Chemical Emissions Under the Influence of Low-NOx Combustion Modifications. Final Report. Southern Research Institute. SRI-ENV-92-796-7436. October 8, 1993, pp. 82-85. 10 EPA. A Technique for Predicting Fly Ash Resistivity . Interagency Energy / Environment R&D Program Report, EPA-600 / 7-79-204. August 1979. 11 Bickelhaupt, Roy E., A Study to Improve A Technique for Predicting Fly Ash Resistivity with Emphasis on the Effects of Sulfur Trioxide , Southern Research Institute Report Number SoRI-EAS85-851, November 1985. Later published as EPA 600 / 7-86-010. 12 Rendle, L. K., et al., Prevention of Residual Oil Combustion Problems by Use of Low Excess Air and Magnesium Additive

. Journal of Engineering for Power. April 1965, pp. 229-265. 13 Landham, Jr., E. C., Faulkner, M. G., Nichols, G. B., ESP Performance with Low-NOx Burners and Advanced Overfire Air, Volume 1, Results and Analysis, 500 MW Demonstration of Advanced WallFired Combustion Techniques for the Reduction of Nitrogen Oxide Emissions from Coal-Fired Utility Boilers , Southern Research Institute. SRI-ENV-94-128-6958-iv, September 1994, pp. 10-11. 14 Cadrecha , M., Preventing Acid Corrosion in Air Heaters

. Power Engineering , January 1980, pp. 54- 56. 15 Methods of Air Samplings and Analysis, 3 rd Ed., James P. Lodge, editor, Lewis Publishers, 1989. 16 Krigmont, H., Applied Electrostatic Precipitation, K. R. Parker, editor, Blackie Academic and Professional, 1997, p 437. 17 JANAF Thermochemical Tables , 1985. 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. October 1996.