1122

METHOD 19 - DETERMINATION OF SULFUR DIOXIDE REMOVAL

EFFICIENCY AND PARTICULATE MATTER, SULFUR DIOXIDE,

AND NITROGEN OXIDE EMISSION RATES

1.0 Scope and Application

1.1 Analytes. This method provides data reduction procedures relating to the following

pollutants, but does not include any sample collection or analysis procedures.

Analyte CAS No. Sensitivity

Nitrogen oxides (NOx),

including:

Nitric oxide (NO)

Nitrogen dioxide (NO2)

10102-43-9

10102-44-0

N/A

Particulate matter (PM) None assigned N/A

Sulfur dioxide (SO2) 7499-09-05 N/A

1.2 Applicability. 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.

2.0 Summary of Method.

2.1 Emission Rates. 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.

2.2 Sulfur Reduction Efficiency and SO2 Removal Efficiency. An overall SO2 emission

reduction efficiency is computed from the efficiency of fuel pretreatment systems, where

applicable, and the efficiency of SO2 control devices. 
1123

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.

3.0 Definitions. [Reserved]

4.0 Interferences. [Reserved]

5.0 Safety. [Reserved]

6.0 Equipment and Supplies. [Reserved]

7.0 Reagents and Standards. [Reserved]

8.0 Sample Collection, Preservation, Storage, and Transport. [Reserved]

9.0 Quality Control. [Reserved]

10.0 Calibration and Standardization. [Reserved]

11.0 Analytical Procedures. [Reserved]

12.0 Data Analysis and Calculations.

12.1 Nomenclature.

Bwa = Moisture fraction of ambient air, percent.

Bws = Moisture fraction of effluent gas, percent.
1124

%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). 
1125

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). 
1126

%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. 
1127

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.
1128

%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.

12.2 Emission Rates of PM, SO2, and NOx. 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. 
1129

Eq. 19-1

Eq. 19-2

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. 
1130

Eq. 19-3

Eq. 19-4

Eq. 19-5

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: 
1131

Eq. 19-6

Eq. 19-8

Eq. 19-9

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: 

Eq. 19-7

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: 
1132

Eq. 19-10

Eq. 19-11

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:
1133

Eq. 19-13

Eq. 19-14

Eq. 19-12

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. 

12.3 F Factors. 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:
1134

Eq. 19-15

Eq. 19-16

Eq. 19-17

Eq. 19-18

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 Determination of Average Pollutant Rates. 
1135

Eq. 19-19

Eq. 19-20

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:
1136

Eq. 19-22

Eq. 19-23

Eq. 19-21

12.5 Determination of Overall Reduction in Potential Sulfur Dioxide Emission.

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. 
1137

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. 
1138

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
1139

Eq. 19-24

Eq. 19-25

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:
1140

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. 
1141

Eq. 19-26

Eq. 19-27

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.

12.6 Sulfur Retention Credit for Compliance Fuel. 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:
1142

Eq. 19-28

Eq. 19-29

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 Determination of Compliance When Minimum Data Requirement Is Not Met.

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:
1143

Eq. 19-30

Eq. 19-31

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.

13.0 Method Performance. [Reserved]

14.0 Pollution Prevention. [Reserved]

15.0 Waste Management. [Reserved]

16.0 References. [Reserved]

17.0 Tables, Diagrams, Flowcharts, and Validation Data.

TABLE 19-1. CONVERSION FACTORS FOR CONCENTRATION

From To Multiply by

g/scm ng/scm 109

mg/scm ng/scm 106

lb/scf ng/scm 1.602 x 1013

ppm SO2 ng/scm 2.66 x 106

ppm NOx ng/scm 1.912 x 106

ppm SO2 lb/scf 1.660 x 10-7

ppm NOx lb/scf 1.194 x 10-7
1144

TABLE 19-2. F FACTORS FOR VARIOUS FUELS1

Fuel Type Fd Fw Fc

dscm/J dscf/106 Btu wscm/J wscf/106 Btu scm/J scf/106

Btu

Coal:

Anthracite2

Bituminus2

Lignite

2.71x10-7

2.63x10-7

2.65x10-7

10,100

9,780

9,860

2.83x10-7

2.86x10-7

3.21x10-7

10,540

10,640

11,950

0.530x10-7

0.484x10-7

0.513x10-7

1,970

1,800

1,910

Oil3 2.47x10-7 9,190 2.77x10-7 10,320 0.383x10-7 1,420

Gas:

Natural

Propane

Butane

2.34x10-7

2.34x10-7

2.34x10-7

8,710

8,710

8,710

2.85x10-7

2.74x10-7

2.79x10-7

10,610

10,200

10,390

0.287x10-7

0.321x10-7

0.337x10-7

1,040

1,190

1,250

Wood 2.48x10-7 9,240 -- -- 0.492x10-7 1,830

Wood Bark 2.58x10-7 9,600 -- -- 0.516x10-7 1,920

Municipal 2.57x10-7 9,570 -- -- 0.488x10-7 1,820

Solid Waste --

1

Determined at standard conditions: 20 °C (68 °F) and 760 mm Hg (29.92 in. Hg)

2

As classified according to ASTM D 388.

3

Crude, residual, or distillate.
1145

TABLE 19-3. VALUES FOR T0.95.

n1 t0.95 n1 t0.95 n1 t0.95

2 6.31 8 1.89 22-26 1.71

3 2.42 9 1.86 27-31 1.70

4 2.35 10 1.83 32-51 1.68

5 2.13 11 1.81 52-91 1.67

6 2.02 12-16 1.77 92-151 1.66

7 1.94 17-21 1.73 152 or more 1.65

1 The values of this table are corrected for n-1 degrees of freedom. Use n equal to the

number (H) of hourly average data points.