NR 440.19(6)(f)4.b.
b. For subbituminous and bituminous coal as classified according to ASTM D388-99 (reapproved 2004), incorporated by reference in
s. NR 440.17 (2) (a) 12., F = 2.637
10
-7 dscm/J (9,820 dscf/million Btu) and F
c = 0.486
10
-7 scm CO
2/J (1,810 scf CO
2/million Btu).
NR 440.19(6)(f)4.c.
c. For liquid fossil fuels including crude, residual and distillate oils, F = 2.476
10
-7 dscm/J (9,220 dscf/million Btu) and F
c = 0.384
10
-7 scm CO
2/J (1,430 scf CO
2/million Btu).
NR 440.19(6)(f)4.d.
d. For gaseous fossil fuels, F = 2.347
10
-7 dscm/J (8,740 dscf/million Btu). For natural gas, propane and butane fuels, F
c = 0.279
10
-7 scm CO
2/J (1,040 scf CO
2/million Btu) for natural gas, 0.322
10
-7 scm CO
2/J (1,200 scf CO
2/million Btu) for propane, and 0.338
10
-7 scm CO
2/J (1,260 scf CO
2/million Btu) for butane.
NR 440.19(6)(f)4.e.
e. For bark, F = 2.589
10
-7 dscm/J (9,640 dscf/million Btu) and F
c = 0.500
10
-7 scm CO
2/J (1,840 scf CO
2/million Btu). For wood residue other than bark, F = 2.492
10
-7 dscm/J (9,280 dscf/million Btu) and F
c = 0.494
10
-7 scm CO
2/J (1,860 scf CO
2/million Btu).
NR 440.19(6)(f)4.f.
f. For lignite coal as classified according to ASTM D388-99 (reapproved 2004), incorporated by reference in
s. NR 440.17 (2) (a) 12., F = 2.659
10
-7 dscm/J (9900 dscf/million Btu) and F
c = 0.516
10
-7 scm CO
2/J (1,920 scf CO
2/million Btu).
NR 440.19(6)(f)5.
5. The owner or operator may use the following equation to determine an F factor (dscm/J or dscf/million Btu) on a dry basis (if it is desired to calculate F on a wet basis, consult the department) or F
c factor (scm CO
2/J, or scf CO
2/million Btu) on either basis in lieu of the F or F
c factors specified in
subd. 4.: -
See PDF for diagram 
NR 440.19(6)(f)5.a.
a. H, C, S, N and O are content by weight of hydrogen, carbon, sulfur, nitrogen and oxygen (expressed as percent), respectively, as determined on the same basis as GCV by ultimate analysis of the fuel fired, using ASTM method D3178-89 or D3176-89 (solid fuels), or computed from results using ASTM method D1137-75, D1945-96 or D1946-90 (reapproved 1994) (gaseous fuels) as applicable. These 5 ASTM methods are incorporated by reference in
s. NR 440.17 (2) (a) 43., 41., 16., 23. and 24., respectively.
NR 440.19(6)(f)5.b.
b. GCV is the gross calorific value (kJ/kg, Btu/lb) of the fuel combusted, determined by the ASTM test methods D2015-96 or D5865-98 for solid fuels and D1826-94 for gaseous fuels as applicable. These 2 ASTM methods are incorporated by reference in
s. NR 440.17 (2) (a) 26. and 21., respectively.
NR 440.19(6)(f)5.c.
c. For affected facilities which fire both fossil fuels and nonfossil fuels, the F or F
c value shall be subject to the department's approval.
NR 440.19(6)(f)6.
6. For affected facilities firing combinations of fossil fuels or fossil fuels and wood residue, the F or F
c factors determined by
subd. 4. or
5. shall be prorated in accordance with the applicable formulas as follows: -
See PDF for diagram
Xi is the fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood residue, etc.)
Fi or (Fc)i is the applicable F or Fc factor for each fuel type determined in accordance with subd. 4. or 5.
n is the number of fuels being burned in combination
NR 440.19(6)(g)
(g) Excess emission and monitoring system performance reports shall be submitted to the department semiannually for each 6-month period in the calendar year. All semiannual reports shall be postmarked by the 30th day following the end of each 6-month period. Each excess emission and monitoring system performance report shall include the information required in
s. NR 440.07 (3). Periods of excess emissions and monitoring systems downtime that shall be reported are defined as follows:
NR 440.19(6)(g)1.
1. Opacity. Excess emissions are defined as any 6-minute period during which the average opacity of emissions exceeds 20% opacity, except that one 6-minute average per hour of up to 27% opacity need not be reported.
NR 440.19(6)(g)2.
2. Sulfur dioxide. Excess emissions for affected facilities are defined as:
NR 440.19(6)(g)2.a.
a. Any 3-hour period during which the average emissions (arithmetic average of 3 contiguous one-hour periods) of sulfur dioxide as measured by a continuous monitoring system exceed the applicable standard under
sub. (4).
NR 440.19(6)(g)3.
3. Nitrogen oxides. Excess emissions for affected facilities using a continuous monitoring system for measuring nitrogen oxides are defined as any 3-hour period during which the average emissions (arithmetic average of 3 contiguous one-hour periods) exceed the applicable standards under
sub. (5).
NR 440.19(7)(a)(a) In conducting the performance tests required in
s. NR 440.08, the owner or operator shall use as reference methods and procedures the test methods in Appendix A of
40 CFR part 60, incorporated by reference in
s. NR 440.17, or other methods and procedures as specified in this subsection, except as provided in
s. NR 440.08 (2). Acceptable alternative methods and procedures are given in
par. (d).
NR 440.19(7)(b)
(b) The owner or operator shall determine compliance with the particulate matter, SO
2 and NO
x standards in
subs. (3),
(4) and
(5) as follows:
NR 440.19(7)(b)1.
1. The emission rate (E) of particulate matter, SO
2 or NO
x shall be computed for each run using the following equation:
E = CFd (20.9)/(20.9 - %02)
where:
E is the emission rate of pollutant, ng/J (lb/million Btu)
C is the concentration of pollutant, ng/dscm (lb/dscf)
%O2 is the oxygen concentration, percent dry basis
Fd is the factor as determined from Method 19
NR 440.19(7)(b)2.
2. Method 5 shall be used to determine the particulate matter concentration (C) at affected facilities without wet flue-gas-desulfurization (FGD) systems and Method 5B shall be used to determine the particulate matter concentration (C) after FGD systems.
NR 440.19(7)(b)2.a.
a. The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder heating systems in the sampling train shall be set to provide an average gas temperature of 160
"14
°C (320
"25
°F).
NR 440.19(7)(b)2.b.
b. The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 3B shall be used to determine the O
2 concentration (%O
2). The O
2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate sample. If the grab sampling procedure is used, the O
2 concentration for the run shall be the arithmetic mean of the sample O
2 concentrations at all traverse points.
NR 440.19(7)(b)2.c.
c. If the particulate run has more than 12 traverse points, the O
2 traverse points may be reduced to 12 provided that Method 1 is used to locate the 12 O
2 traverse points.
NR 440.19(7)(b)4.a.
a. The sampling site shall be the same as that selected for the particulate sample. The sampling location in the duct shall be at the centroid of the cross section or at a point no closer to the walls than 1 m (3.28 ft). The sampling time and sample volume for each sample run shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples shall be taken during a 1-hour period, with each sample taken within a 30-minute interval.
NR 440.19(7)(b)4.b.
b. The emission rate correction factor, integrated sampling and analysis procedure of Method 3B shall be used to determine the O
2 concentration (%O
2). The O
2 sample shall be taken simultaneously with, and at the same point as, the SO
2 sample. The SO
2 emission rate shall be computed for each pair of SO
2 and O
2 samples. The SO
2 emission rate (E) for each run shall be the arithmetic mean of the results of the 2 pairs of samples.
NR 440.19(7)(b)5.a.
a. The sampling site and location shall be the same as for the SO
2 sample. Each run shall consist of 4 grab samples, with each sample taken at about 15-minute intervals.
NR 440.19(7)(b)5.b.
b. For each NO
x sample, the emission rate correction factor, grab sampling and analysis procedure of Method 3B shall be used to determine the O
2 concentration (%O
2). The sample shall be taken simultaneously with, and at the same point as, the NO
x sample.
NR 440.19(7)(b)5.c.
c. The NO
x emission rate shall be computed for each pair of NO
x and O
2 samples. The NO
x emission rate (E) for each run shall be the arithmetic mean of the results of the 4 pairs of samples.
NR 440.19(7)(c)
(c) When combinations of fossil fuels or fossil fuel and wood residue are fired, the owner or operator, in order to compute the prorated standard as shown in
subs. (4) (b) and
(5) (b), shall determine the percentage (w, x, y, or z) of the total heat input derived from each type of fuel as follows:
NR 440.19(7)(c)1.
1. The heat input rate of each fuel shall be determined by multiplying the gross calorific value of each fuel fired by the rate of each fuel burned.
NR 440.19(7)(c)2.
2. ASTM method D2015-96 or D5865-98 (solid fuels), D240-92 (liquid fuels) or D1826-94 (gaseous fuels), incorporated by reference in
s. NR 440.17 (2) (a) 26., 66., 9. and 21., respectively, shall be used to determine the gross calorific values of the fuels. The method used to determine the calorific value of wood residue shall be approved by the department.
NR 440.19(7)(c)3.
3. Suitable methods shall be used to determine the rate of each fuel burned during each test period, and a material balance over the steam generating system shall be used to confirm the rate.
NR 440.19(7)(d)
(d) The owner or operator may use the following as alternatives to the reference methods and procedures in this subsection or in other subsections as specified:
NR 440.19(7)(d)1.
1. The emission rate (E) of particulate matter, SO
2 and NO
x may be determined by using the F
c factor, provided that the following procedure is used:
E = CFc (100/%CO2)
where:
E is the emission rate of pollutant, ng/J (lb/million Btu)
C is the concentration of pollutant, ng/dscm (lb/dscf)
%CO2 is the carbon dioxide concentration, percent dry basis
Fc is the factor as determined in appropriate sections of Method 19
NR 440.19(7)(d)1.b.
b. If and only if the average F
c factor in Method 19 is used to calculate E and either E is from 0.97 to 1.00 of the emission standard or the relative accuracy of a continuous emission monitoring system is from 17 to 20%, then 3 runs of Method 3 shall be used to determine the O
2 and CO
2 concentration according to the procedures in
sub. (7) (b) 2. b.,
4. b. or
5. b. Then if F
o (average of 3 runs), as calculated from the equation in Method 3B, is more than
"3% than the average F
o value, as determined from the average values of F
d and F
c in Method 19, that is, F
oa = 0.209 (F
da/F
ca), then the following procedure shall be followed:
1) When Fo is less than 0.97 Foa, then E shall be increased by that proportion under 0.97 Foa. For example, if Fo is 0.95 Foa, E shall be increased by 2%. This recalculated value shall be used to determine compliance with the emission standard.
2) When Fo is less than 0.97 Foa and when the average difference (d) between the continuous monitor minus the reference methods is negative, then E shall be increased by that proportion under 0.97 Foa. For example, if Fo is 0.95 Foa, E shall be increased by 2%. This recalculated value shall be used to determine compliance with the relative accuracy specification.
3) When Fo is greater than 1.03 Foa and when the average difference d is positive, then E shall be decreased by that proportion over 1.03 Foa. For example, if Fo is 1.05 Foa, E shall be decreased by 2%. This recalculated value shall be used to determine compliance with the relative accuracy specification.
NR 440.19(7)(d)2.
2. For Method 5 or 5B, Method 17 may be used at facilities with or without wet FGD systems if the stack gas temperature at the sampling location does not exceed an average temperature of 160
°C (320
°F). The procedures of sections 2.1 and 2.3 of Method 5B may be used with Method 17 only if it is used after wet FGD systems. Method 17 may not be used after wet FGD systems if the effluent gas is saturated or laden with water droplets.
NR 440.19(7)(d)3.
3. Particulate matter and SO
2 may be determined simultaneously with the Method 5 train provided that the following changes are made:
NR 440.19(7)(d)3.a.
a. The filter and impinger apparatus in sections 2.1.5 and 2.1.6 of Method 8 is used in place of the condenser (section 2.1.7) of Method 5.
NR 440.19(7)(d)3.b.
b. All applicable procedures in Method 8 for the determination of SO
2, including moisture, are used.
NR 440.19(7)(d)4.
4. For Method 6, Method 6C may be used. Method 6A may also be used whenever Methods 6 and 3B data are specified to determine the SO
2 emission rate, under the conditions in
par. (d) 1.
NR 440.19(7)(d)5.
5. For Method 7, Method 7A, 7C, 7D or 7E may be used. If Method 7C, 7D or 7E is used, the sampling time for each run shall be at least 1 hour and the integrated sampling approach shall be used to determine the O
2 concentration (%O
2) for the emission rate correction factor.
NR 440.19 History
History: Cr.
Register, January, 1984, No. 337, eff. 2-1-84; am. (6) (c) 1., (7) (a) 2., 4. and 5., (7) (c), (e), (f) 2., 3. (intro.) and a.,
Register, September, 1986, No. 369, eff. 10-1-86; am. (1) (b), (2) (intro.), (5) (a) 1. and 2., (6) (c) 1. and (f) 5. a., (7) (a) 1. to 5., (b); (c) and (f) 3.,
Register, September, 1990, No. 417, eff. 10-1-90; r. and recr. (6) (c) 1., (g) (intro.) and (7), am. (6) (c) 3., (f) 1. to 3., 4. a. and 5. (intro.),
Register, July, 1993, No. 451, eff. 8-1-93; am. (6) (f) 5. (intro.), a., (7) (b) 2. (intro.),
Register, December, 1995, No. 480, eff. 1-1-96;
CR 06-109: am. (2) (a), (6) (b) 2., (c) 3. a. to d., (f) 4. a., b. and f., 5. a. and b., (g) (intro.), (7) (b) 2. a. and b. and (c) 2. Register May 2008 No. 629, eff. 6-1-08. NR 440.20
NR 440.20 Electric steam generating units for which construction is commenced after September 18, 1978. NR 440.20(1)(1)
Applicability and designation of affected facility. NR 440.20(1)(a)(a) The affected facility to which this section applies is each electric utility steam generating unit:
NR 440.20(1)(a)1.
1. That is capable of combusting more than 73 megawatts (250 million Btu/hour) heat input of fossil fuel, either alone or in combination with any other fuel; and
NR 440.20(1)(a)2.
2. For which construction or modification is commenced after September 18, 1978.
NR 440.20(1)(b)
(b) Unless and until
s. NR 440.50 extends the applicability of
s. NR 440.50 to electric utility steam generators, this section applies to electric utility combined cycle gas turbines that are capable of combusting more than 73 megawatts (250 million Btu/hour) heat input of fossil fuel in the steam generator. Only emissions resulting from combustion of fuels in the steam generating unit are subject to this section.
NR 440.20 Note
Note:
The gas turbine emissions are subject to s.
NR 440.50.
NR 440.20(1)(c)
(c) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels, will not bring that unit under the applicability of this section.
NR 440.20(1)(d)
(d) Any change to an existing steam generating unit originally designed to fire gaseous or liquid fossil fuels, to accommodate the use of any other fuel (fossil or nonfossil) will not bring that unit under the applicability of this section.
NR 440.20(2)
(2) Definitions. As used in this section, terms not defined in this subsection have the meanings given in
s. NR 440.02.
NR 440.20(2)(a)
(a) “24-hour period" means the period of time between 12:01 a.m. and 12:00 midnight.
NR 440.20(2)(b)
(b) “Anthracite" means coal that is classified as anthracite according to the ASTM Standard Specification for Classification of Coals by Rank, D388-99 (reapproved 2004), incorporated by reference in
s. NR 440.17 (2) (a) 12.
NR 440.20(2)(c)
(c) “Available purchase power" means the lesser of the following:
NR 440.20(2)(c)1.
1. The sum of available system capacity in all neighboring companies.
NR 440.20(2)(c)2.
2. The sum of the rated capacities of the power interconnection devices between the principal company and all neighboring companies, minus the sum of the electric power load on these interconnections.
NR 440.20(2)(c)3.
3. The rated capacity of the power transmission lines between the power interconnection devices and the electric generating units (the unit in the principal company that has the malfunctioning flue gas desulfurization system and the unit or units in the neighboring company supplying replacement electrical power) less the electric power load on these transmission lines.
NR 440.20(2)(d)
(d) “Available system capacity" means the capacity determined by subtracting the system load and the system emergency reserves from the net system capacity.
NR 440.20(2)(e)
(e) “Boiler operating day" means a 24-hour period during which fossil fuel is combusted in a steam generating unit for the entire 24 hours.
NR 440.20(2)(f)
(f) “Coal refuse" means waste products of coal mining, physical coal cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.
NR 440.20(2)(g)
(g) “Combined cycle gas turbine" means a stationary turbine combustion system where heat from the turbine exhaust gases is recovered by a steam generating unit.
NR 440.20(2)(gr)
(gr) “Duct burner" means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary gas turbine, internal combustion engine or kiln, to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit.
NR 440.20(2)(h)
(h) “Electric utility combined cycle gas turbine" means any combined cycle gas turbine used for electric generation that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. Any steam distribution system that is constructed for the purpose of providing steam to a steam-electric generator that would produce electrical power for sale is also considered in determining the electrical energy output capacity of the affected facility.
NR 440.20(2)(i)
(i) “Electric utility company" means the largest interconnected organization, business or governmental entity that generates electric power for sale (e.g., a holding company with operating subsidiary companies).
