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**US EPA Method 19 - Determination Of Sulfur Dioxide Removal Efficiency And Particulate Matter, Sulfur Dioxide, And Nitrogen Oxide Emission Rates**

This method provides data reduction procedures relating to the following pollutants, but does not include any sample collection or analysis procedures.

Where specified by an applicable subpart of the regulations, this method is applicable for the determination of (a) PM, SO2, and NOx emission rates; (b) sulfur removal efficiencies of fuel pretreatment and SO2 control devices; and (c) overall reduction of potential SO2 emissions.

Oxygen (O2) or carbon dioxide (CO2) concentrations and appropriate F factors (ratios of combustion gas volumes to heat inputs) are used to calculate pollutant emission rates from pollutant concentrations.

An overall SO2 emission reduction efficiency is computed from the efficiency of fuel pretreatment systems, where applicable, and the efficiency of SO2 control devices.

2.2.1 The sulfur removal efficiency of a fuel pretreatment system is determined by fuel sampling and analysis of the sulfur and heat contents of the fuel before and after the pretreatment system.

2.2.2 The SO2 removal efficiency of a control device is determined by measuring the SO2 rates before and after the control device.

2.2.2.1 The inlet rates to SO2 control systems (or, when SO2 control systems are not used, SO2 emission rates to the atmosphere) are determined by fuel sampling and analysis.

Bwa = Moisture fraction of ambient air, percent.

Bws = Moisture fraction of effluent gas, percent.

%C = Concentration of carbon from an ultimate analysis of fuel, weight percent.

Cd = Pollutant concentration, dry basis, ng/scm (lb/scf).

%CO2d,%CO2w = Concentration of carbon dioxide on a dry and wet basis, respectively, percent.

Cw = Pollutant concentration, wet basis, ng/scm (lb/scf).

D = Number of sampling periods during the performance test period.

E = Pollutant emission rate, ng/J (lb/million Btu).

Ea = Average pollutant rate for the specified performance test period, ng/J (lb/million Btu).

Eao, Eai = Average pollutant rate of the control device,outlet and inlet, respectively, for the performance test period, ng/J (lb/million Btu).

Ebi = Pollutant rate from the steam generating unit, ng/J (lb/million Btu)

Ebo = Pollutant emission rate from the steam generating unit, ng/J (lb/million Btu).

Eci = Pollutant rate in combined effluent, ng/J (lb/million Btu).

Eco = Pollutant emission rate in combined effluent, ng/J (lb/million Btu).

Ed = Average pollutant rate for each sampling period (*e.g.*, 24-hr Method 6B sample or 24-hr fuel sample) or for each fuel lot (*e.g.*, amount of fuel bunkered), ng/J (lb/million Btu).

Edi = Average inlet SO2 rate for each sampling period d, ng/J (lb/million Btu)

Eg = Pollutant rate from gas turbine, ng/J (lb/million Btu).

Ega = Daily geometric average pollutant rate, ng/J (lbs/million Btu) or ppm corrected to 7 percent O2.

Ejo,Eji = Matched pair hourly arithmetic average pollutant rate, outlet and inlet, respectively, ng/J (lb/million Btu) or ppm corrected to 7 percent O2.

Eh = Hourly average pollutant, ng/J (lb/million Btu).

Ehj = Hourly arithmetic average pollutant rate for hour "j," ng/J (lb/million Btu) or ppm corrected to 7 percent O2.

EXP = Natural logarithmic base (2.718) raised to the value enclosed by brackets.

Fd, Fw, Fc = Volumes of combustion components per unit of heat content, scm/J (scf/million Btu).

GCV = Gross calorific value of the fuel consistent with the ultimate analysis, kJ/kg (Btu/lb).

GCVp, GCVr = Gross calorific value for the product and raw fuel lots, respectively, dry basis, kJ/kg (Btu/lb).

%H = Concentration of hydrogen from an ultimate analysis of fuel, weight percent.

H = Total number of operating hours for which pollutant rates are determined in the performance test period.

Hb = Heat input rate to the steam generating unit from fuels fired in the steam generating unit, J/hr (million Btu/hr).

Hg = Heat input rate to gas turbine from all fuels fired in the gas turbine, J/hr (million Btu/hr).

%H2O = Concentration of water from an ultimate analysis of fuel, weight percent.

Hr = Total numbers of hours in the performance test period (*e.g.*, 720 hours for 30-day performance test period).

K = Conversion factor, 10-5 (kJ/J)/(%) [106 Btu/million Btu].

Kc = (9.57 scm/kg)/% [(1.53 scf/lb)/%].

Kcc = (2.0 scm/kg)/% [(0.321 scf/lb)/%].

Khd = (22.7 scm/kg)/% [(3.64 scf/lb)/%].

Khw = (34.74 scm/kg)/% [(5.57 scf/lb)/%].

Kn = (0.86 scm/kg)/% [(0.14 scf/lb)/%].

Ko = (2.85 scm/kg)/% [(0.46 scf/lb)/%].

Ks = (3.54 scm/kg)/% [(0.57 scf/lb)/%].

Kw = (1.30 scm/kg)/% [(0.21 scf/lb)/%].

ln = Natural log of indicated value.

Lp,Lr = Weight of the product and raw fuel lots, respectively, metric ton (ton).

%N = Concentration of nitrogen from an ultimate analysis of fuel, weight percent.

N = Number of fuel lots during the averaging period.

n = Number of fuels being burned in combination.

nd = Number of operating hours of the affected facility within the performance test period for each Ed determined.

nt = Total number of hourly averages for which paired inlet and outlet pollutant rates are available within the 24-hr midnight to midnight daily period.

%O = Concentration of oxygen from an ultimate analysis of fuel, weight percent.

%O2d, %O2w = Concentration of oxygen on a dry and wet basis, respectively, percent.

Ps = Potential SO2 emissions, percent.

%Rf = SO2 removal efficiency from fuel pretreatment, percent.

%Rg = SO2 removal efficiency of the control device, percent.

%Rga = Daily geometric average percent reduction.

%Ro = Overall SO2 reduction, percent.

%S = Concentration of sulfur from an ultimate analysis of fuel, weight percent.

%Sf = Sulfur content of as-fired fuel lot, dry basis, weight percent.

Se = Standard deviation of the hourly average pollutant rates for each performance test period, ng/J (lb/million Btu).

Si = Standard deviation of the hourly average inlet pollutant rates for each performance test period, ng/J (lb/million Btu).

So = Standard deviation of the hourly average emission rates for each performance test period, ng/J (lb/million Btu).

%Sp, %Sr = Sulfur content of the product and raw fuel lots respectively, dry basis, weight percent.

t0.95 = Values shown in Table 19-3 for the indicated number of data points n.

Xk = Fraction of total heat input from each type of fuel k.

Select from the following sections the applicable procedure to compute the PM, SO2, or NOx emission rate (E) in ng/J (lb/million Btu). The pollutant concentration must be in ng/scm (lb/scf) and the F factor must be in scm/J (scf/million Btu). If the pollutant concentration (C) is not in the appropriate units, use Table 19-1 in Section 17.0 to make the proper conversion. An F factor is the ratio of the gas volume of the products of combustion to the heat content of the fuel. The dry F factor (Fd) includes all components of combustion less water, the wet F factor (Fw) includes all components of combustion, and the carbon F factor (Fc) includes only carbon dioxide.

**NOTE:** Since Fw factors include water resulting only from the combustion of hydrogen in the fuel, the procedures using Fw factors are not applicable for computing E from steam generating units with wet scrubbers or with other processes that add water (*e.g.,* steam injection).

12.2.1 Oxygen-Based F Factor, Dry Basis. When measurements are on a dry basis for both O (%O2d) and pollutant (Cd) concentrations, use the following equation:

12.2.2 Oxygen-Based F Factor, Wet Basis. When measurements are on a wet basis for both O2 (%O2w) and pollutant (Cw) concentrations, use either of the following:

12.2.2.1 If the moisture fraction of ambient air (Bwa) is measured: Instead of actual measurement, Bwa may be estimated according to the procedure below.

**NOTE:** The estimates are selected to ensure that negative errors will not be larger than -1.5 percent. However, positive errors, or over-estimation of emissions by as much as 5 percent may be introduced depending upon the geographic location of the facility and the associated range of ambient moisture.

12.2.2.1.1 Bwa = 0.027. This value may be used at any location at all times.

12.2.2.1.2 Bwa = Highest monthly average of Bwa that occurred within the previous calendar year at the nearest Weather Service Station. This value shall be determined annually and may be used as an estimate for the entire current calendar year.

12.2.2.1.3 Bwa = Highest daily average of Bwa that occurred within a calendar month at the nearest Weather Service Station, calculated from the data from the past 3 years. This value shall be computed for each month and may be used as an estimate for the current respective calendar month.

12.2.2.2 If the moisture fraction (Bws) of the effluent gas is measured:

12.2.3 Oxygen-Based F Factor, Dry/Wet Basis.

12.2.3.1 When the pollutant concentration is measured on a wet basis (Cw) and O2 concentration is measured on a dry basis (%O2d), use the following equation:

12.2.3.2 When the pollutant concentration is measured on a dry basis (Cd) and the O2 concentration is measured on a wet basis (%O2w), use the following equation:

12.2.4 Carbon Dioxide-Based F Factor, Dry Basis. When measurements are on a dry basis for both CO2 (%CO2d) and pollutant (Cd) concentrations, use the following equation:

12.2.5 Carbon Dioxide-Based F Factor, Wet Basis. When measurements are on a wet basis for both CO2 (%CO2w) and pollutant (Cw) concentrations, use the following equation:

12.2.6 Carbon Dioxide-Based F Factor, Dry/Wet Basis.

12.2.6.1 When the pollutant concentration is measured on a wet basis (Cw) and CO2 concentration is measured on a dry basis (%CO2d), use the following equation:

12.2.6.2 When the pollutant concentration is measured on a dry basis (Cd) and CO2 concentration is measured on a wet basis (%CO2w), use the following equation:

12.2.7 Direct-Fired Reheat Fuel Burning. The effect of direct-fired reheat fuel burning (for the purpose of raising the temperature of the exhaust effluent from wet scrubbers to above the moisture dew-point) on emission rates will be less than 1.0 percent and, therefore, may be ignored.

12.2.8 Combined Cycle-Gas Turbine Systems. For gas turbine-steam generator combined cycle systems, determine the emissions from the steam generating unit or the percent reduction in potential SO2 emissions as follows:

12.2.8.1 Compute the emission rate from the steam generating unit using the following equation:

12.2.8.1.1 Use the test methods and procedures section of 40 CFR Part 60, Subpart GG to obtain Eco and Eg. Do not use Fw factors for determining Eg or Eco. If an SO2 control device is used, measure Eco after the control device.

12.2.8.1.2 Suitable methods shall be used to determine the heat input rates to the steam generating units (Hb) and the gas turbine (Hg).

12.2.8.2 If a control device is used, compute the percent of potential SO2 emissions (Ps) using the following equations:

**NOTE:** Use the test methods and procedures section of Subpart GG to obtain Eci and Eg. Do not use Fw factors for determining Eg or Eci.

Use an average F factor according to Section 12.3.1 or determine an applicable F factor according to Section 12.3.2. If combined fuels are fired, prorate the applicable F factors using the procedure in Section 12.3.3.

12.3.1 Average F Factors. Average F factors (Fd, Fw, or Fc) from Table 19-2 in Section 17.0 may be used.

12.3.2 Determined F Factors. If the fuel burned is not listed in Table 19-2 or if the owner or operator chooses to determine an F factor rather than use the values in Table 19-2, use the procedure below:

12.3.2.1 Equations. Use the equations below, as appropriate, to compute the F factors:

**NOTE:** Omit the %H2O term in the equations for Fw if %H and %O include the unavailable hydrogen and oxygen in the form of H2O.)

12.3.2.2 Use applicable sampling procedures in Section 12.5.2.1 or 12.5.2.2 to obtain samples for analyses.

12.3.2.3 Use ASTM D 3176-74 or 89 (all cited ASTM standards are incorporated by reference - see 60.17) for ultimate analysis of the fuel.

12.3.2.4 Use applicable methods in Section 12.5.2.1 or 12.5.2.2 to determine the heat content of solid or liquid fuels. For gaseous fuels, use ASTM D 1826-77 or 94 (incorporated by reference - see 60.17) to determine the heat content.

12.3.3 F Factors for Combination of Fuels. If combinations of fuels are burned, use the following equations, as applicable unless otherwise specified in an applicable subpart:

12.4.1 Average Pollutant Rates from Hourly Values. When hourly average pollutant rates (Eh), inlet or outlet, are obtained (*e.g.,* CEMS values), compute the average pollutant rate (Ea) for the performance test period (*e.g.,* 30 days) specified in the applicable regulation using the following equation:

12.4.2 Average Pollutant Rates from Other than Hourly Averages. When pollutant rates are determined from measured values representing longer than 1-hour periods (*e.g.*, daily fuel sampling and analyses or Method 6B values), or when pollutant rates are determined from combinations of 1-hour and longer than 1-hour periods (*e.g.*, CEMS and Method 6B values), compute the average pollutant rate (Ea) for the performance test period (*e.g.*, 30 days) specified in the applicable regulation using the following equation:

12.4.3 Daily Geometric Average Pollutant Rates from Hourly Values. The geometric average pollutant rate (Ega) is computed using the following equation:

12.5.1 Overall Percent Reduction. Compute the overall percent SO2 reduction (%Ro) using the following equation:

12.5.2 Pretreatment Removal Efficiency (Optional). Compute the SO2 removal efficiency from fuel pretreatment (%Rf) for the averaging period (*e.g.*, 90 days) as specified in the applicable regulation using the following equation:

**NOTE:** In calculating %Rf, include %S and GCV values for all fuel lots that are not pretreated and are used during the averaging period.

12.5.2.1 Solid Fossil (Including Waste) Fuel)Sampling and Analysis.

**NOTE:** For the purposes of this method, raw fuel (coal or oil) is the fuel delivered to the desulfurization (pretreatment) facility. For oil, the input oil to the oil desulfurization process (*e.g.*, hydrotreatment) is considered to be the raw fuel.

12.5.2.1.1 Sample Increment Collection. Use ASTM D 2234-76, 96, 97a, or 98 (incorporated by reference - see 60.17), Type I, Conditions A, B, or C, and systematic spacing. As used in this method, systematic spacing is intended to include evenly spaced increments in time or increments based on equal weights of coal passing the collection area. As a minimum, determine the number and weight of increments required per gross sample representing each coal lot according to Table 2 or Paragraph 7.1.5.2 of ASTM D 2234. Collect one gross sample for each lot of raw coal and one gross sample for each lot of product coal.

12.5.2.1.2 ASTM Lot Size. For the purpose of Section 12.5.2 (fuel pretreatment), the lot size of product coal is the weight of product coal from one type of raw coal. The lot size of raw coal is the weight of raw coal used to produce one lot of product coal. Typically, the lot size is the weight of coal processed in a 1-day (24-hour) period. If more than one type of coal is treated and produced in 1 day, then gross samples must be collected and analyzed for each type of coal. A coal lot size equaling the 90-day quarterly fuel quantity for a steam-generating unit may be used if representative sampling can be conducted for each raw coal and product coal.

**NOTE:** Alternative definitions of lot sizes may be used, subject to prior approval of the Administrator.

12.5.2.1.3 Gross Sample Analysis. Use ASTM D 2013-72 or 86 to prepare the sample, ASTM D 3177-75 or 89 or ASTM D 4239-85, 94, or 97 to determine sulfur content (%S), ASTM D 3173-73 or 87 to determine moisture content, and ASTM D 2015-77 (Reapproved 1978) or 96, D 3286-85 or 96, or D 5865-98 to determine gross calorific value (GCV) (all standards cited are incorporated by reference - see 60.17 for acceptable versions of the standards) on a dry basis for each gross sample.

12.5.2.2 Liquid Fossil Fuel-Sampling and Analysis. See Note under Section 12.5.2.1.

12.5.2.2.1 Sample Collection. Follow the procedures for continuous sampling in ASTM D 270 or D 4177-95 (incorporated by reference - see 60.17) for each gross sample from each fuel lot.

12.5.2.2.2 Lot Size. For the purpose of Section 12.5.2 (fuel pretreatment), the lot size of a product oil is the weight of product oil from one pretreatment facility and intended as one shipment (ship load, barge load, etc.). The lot size of raw oil is the weight of each crude liquid fuel type used to produce a lot of product oil.

**NOTE:** Alternative definitions of lot sizes may be used, subject to prior approval of the Administrator.

12.5.2.2.3 Sample Analysis. Use ASTM D 129-64, 78, or 95, ASTM D 1552-83 or 95, or ASTM D 4057-81 or 95 to determine the sulfur content (%S) and ASTM D 240-76 or 92 (all standards cited are incorporated by reference) see 60.17) to determine the GCV of each gross sample. These values may be assumed to be on a dry basis. The owner or operator of an affected facility may elect to determine the GCV by sampling the oil combusted on the first steam generating unit operating day of each calendar month and then using the lowest GCV value of the three GCV values per quarter for the GCV of all oil combusted in that calendar quarter.

12.5.2.3 Use appropriate procedures, subject to the approval of the Administrator, to determine the fraction of total mass input derived from each type of fuel.

12.5.3 Control Device Removal Efficiency. Compute the percent removal efficiency (%Rg) of the control device using the following equation:

12.5.3.1 Use continuous emission monitoring systems or test methods, as appropriate, to determine the outlet SO2 rates and, if appropriate, the inlet SO2 rates. The rates may be determined as hourly (Eh) or other sampling period averages (Ed). Then, compute the average pollutant rates for the performance test period (Eao and Eai) using the procedures in Section 12.4.

12.5.3.2 As an alternative, as-fired fuel sampling and analysis may be used to determine inlet SO2 rates as follows:

12.5.3.2.1 Compute the average inlet SO2 rate (Edi) for each sampling period using the following equation:

where:

After calculating Edi, use the procedures in Section 12.4 to determine the average inlet SO2 rate for the performance test period (Eai).

12.5.3.2.2 Collect the fuel samples from a location in the fuel handling system that provides a sample representative of the fuel bunkered or consumed during a steam generating unit operating day. For the purpose of as-fired fuel sampling under Section 12.5.3.2 or Section 12.6, the lot size for coal is the weight of coal bunkered or consumed during each steam generating unit operating day. The lot size for oil is the weight of oil supplied to the "day" tank or consumed during each steam generating unit operating day. For reporting and calculation purposes, the gross sample shall be identified with the calendar day on which sampling began. For steam generating unit operating days when a coal-fired steam generating unit is operated without coal being added to the bunkers, the coal analysis from the previous "as bunkered" coal sample shall be used until coal is bunkered again. For steam generating unit operating days when an oil-fired steam generating unit is operated without oil being added to the oil "day" tank, the oil analysis from the previous day shall be used until the "day" tank is filled again. Alternative definitions of fuel lot size may be used, subject to prior approval of the Administrator.

12.5.3.2.3 Use ASTM procedures specified in Section 12.5.2.1 or 12.5.2.2 to determine %S and GCV.

12.5.4 Daily Geometric Average Percent Reduction from Hourly Values. The geometric average percent reduction (%Rga) is computed using the following equation:

**NOTE:** The calculation includes only paired data sets (hourly average) for the inlet and outlet pollutant measurements.

If fuel sampling and analysis procedures in Section 12.5.2.1 are being used to determine average SO2 emission rates (Eas) to the atmosphere from a coal-fired steam generating unit when there is no SO2 control device, the following equation may be used to adjust the emission rate for sulfur retention credits (no credits are allowed for oil-fired systems) (Edi) for each sampling period using the following equation:

where:

After calculating Edi, use the procedures in Section 12.4.2 to determine the average SO2 emission rate to the atmosphere for the performance test period (Eao).

12.7.1 Adjusted Emission Rates and Control Device Removal Efficiency. When the minimum data requirement is not met, the Administrator may use the following adjusted emission rates or control device removal efficiencies to determine compliance with the applicable standards.

12.7.1.1 Emission Rate. Compliance with the emission rate standard may be determined by using the lower confidence limit of the emission rate (Eao *) as follows:

12.7.1.2 Control Device Removal Efficiency. Compliance with the overall emission reduction (%Ro) may be determined by using the lower confidence limit of the emission rate (Eao*) and the upper confidence limit of the inlet pollutant rate (Eai*) in calculating the control device removal efficiency (%Rg) as follows:

12.7.2 Standard Deviation of Hourly Average Pollutant Rates. Compute the standard deviation (Se) of the hourly average pollutant rates using the following equation:

Equation 19-19 through 19-31 may be used to compute the standard deviation for both the outlet (So) and, if applicable, inlet (Si) pollutant rates.

**TABLE 19-1. CONVERSION FACTORS FOR CONCENTRATION**

**TABLE 19-2. F FACTORS FOR VARIOUS FUELS ^{1}**

**TABLE 19-3. VALUES FOR T _{0.95}.**