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, SO2 and NOx standards in subs. (3), (4) and (5) as follows: NR 440.19(7)(b)1.1. The emission rate (E) of particulate matter, SO2 or NOx 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 O2 concentration (%O2). The O2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate sample. If the grab sampling procedure is used, the O2 concentration for the run shall be the arithmetic mean of the sample O2 concentrations at all traverse points. NR 440.19(7)(b)2.c.c. If the particulate run has more than 12 traverse points, the O2 traverse points may be reduced to 12 provided that Method 1 is used to locate the 12 O2 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 O2 concentration (%O2). The O2 sample shall be taken simultaneously with, and at the same point as, the SO2 sample. The SO2 emission rate shall be computed for each pair of SO2 and O2 samples. The SO2 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 SO2 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 NOx sample, the emission rate correction factor, grab sampling and analysis procedure of Method 3B shall be used to determine the O2 concentration (%O2). The sample shall be taken simultaneously with, and at the same point as, the NOx sample. NR 440.19(7)(b)5.c.c. The NOx emission rate shall be computed for each pair of NOx and O2 samples. The NOx 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, SO2 and NOx may be determined by using the Fc 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 Fc 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 O2 and CO2 concentration according to the procedures in sub. (7) (b) 2. b., 4. b. or 5. b. Then if Fo (average of 3 runs), as calculated from the equation in Method 3B, is more than ±3% than the average Fo value, as determined from the average values of Fd and Fc in Method 19, that is, Foa = 0.209 (Fda/Fca), 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 SO2 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 SO2, 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 SO2 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 O2 concentration (%O2) for the emission rate correction factor. NR 440.19 HistoryHistory: 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 440.20NR 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 NoteNote: 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). NR 440.20(2)(j)(j) “Electric utility steam generating unit” means any steam electric generating unit 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 supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is also considered in determining the electrical energy output capacity of the affected facility. NR 440.20(2)(k)1.1. The electric generation output of an affected facility with a malfunctioning flue gas desulfurization system cannot be reduced or electrical output must be increased because: NR 440.20(2)(k)1.a.a. All available system capacity in the principal company interconnected with the affected facility is being operated, and NR 440.20(2)(k)1.b.b. All available purchase power interconnected with the affected facility is being obtained, or NR 440.20(2)(k)2.2. The electric generation demand is being shifted as quickly as possible from an affected facility with a malfunctioning flue gas desulfurization system to one or more electrical generating units held in reserve by the principal company or by a neighboring company, or NR 440.20(2)(k)3.3. An affected facility with a malfunctioning flue gas desulfurization system becomes the only available unit to maintain a part or all of the principal company’s system emergency reserves and the unit is operated in spinning reserve at the lowest practical electric generation load consistent with not causing significant physical damage to the unit. If the unit is operated at a higher load to meet load demand, an emergency condition would not exist unless the conditions under subd. 1. apply. NR 440.20(2)(L)(L) “Fossil fuel” means natural gas, petroleum, coal, and any form of solid, liquid or gaseous fuel derived from such material for the purpose of creating useful heat. NR 440.20(2)(Lm)(Lm) “Gross output” means the gross useful work performed by the steam generated. For units generating only electricity, the gross useful work performed is the gross electrical output from the turbine or generator set. For cogeneration units, the gross useful work performed is the gross electrical output plus one half the useful thermal output (that is, steam delivered to an industrial process). NR 440.20(2)(m)(m) “Interconnected” means that 2 or more electric generating units are electrically tied together by a network of power transmission lines, and other power transmission equipment. NR 440.20(2)(n)(n) “Lignite” means coal that is classified as lignite A or B 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)(o)(o) “Neighboring company” means any one of those electric utility companies with one or more electric power interconnections to the principal company and which have geographically adjoining service areas. NR 440.20(2)(p)(p) “Net system capacity” means the sum of the net electric generating capability (not necessarily equal to rated capacity) of all electric generating equipment owned by an electric utility company (including steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and all other electric generating equipment) plus firm contractual purchases that are interconnected to the affected facility that has the malfunctioning flue gas desulfurization system. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement.
