NR 440.20(8)(b)
(b) The owner or operator shall determine compliance with the particulate matter standards in
sub. (3) as follows:
NR 440.20(8)(b)1.
1. The dry basis F factor (O
2) procedures in Method 19 shall be used to compute the emission rate of particulate matter.
NR 440.20(8)(b)2.
2. For the particulate matter concentration, Method 5 shall be used at affected facilities without wet FGD systems and Method 5B shall be used after wet FGD systems.
NR 440.20(8)(b)2.a.
a. The sampling time and sample volume for each run shall be at least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder heating system in the sampling train may be set to provide an average gas temperature of no greater than 160
"14
°C (320
"25
°F).
NR 440.20(8)(b)2.b.
b. For each particulate run, the emission rate correction factor, integrated or grab sampling and analysis procedures of Method 3B shall be used to determine the O
2 concentration. The O
2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate run. If the particulate run has more than 12 traverse points, the O
2 simultaneous traverse points may be reduced to 12 provided that Method 1 is used to locate the 12 O
2 traverse points. 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 440.20(8)(c)
(c) The owner or operator shall determine compliance with the SO
2 standards in
sub. (4) as follows:
NR 440.20(8)(c)1.
1. The percent of potential SO
2 emissions (% P
s) to the atmosphere shall be computed using the following equation:
% Ps = [(100 - %Rf) (100 - %Rg)]/100
where:
%Ps is the percent of potential SO2 emissions, percent
%Rf is the percent reduction from fuel pretreatment, percent
%Rg is the percent reduction by SO2 control system, percent
NR 440.20(8)(c)2.
2. The procedures in Method 19 may be used to determine percent reduction (%R
f) of sulfur by such processes as fuel pretreatment (physical coal cleaning, hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom and flyash interactions. This determination is optional.
NR 440.20(8)(c)3.
3. The procedures in Method 19 shall be used to determine the percent SO
2 reduction (%R
g) of any SO
2 control system. Alternatively, a combination of an`as fired' fuel monitor and emission rates measured after the control system, following the procedures in Method 19, may be used if the percent reduction is calculated using the average emission rate from the SO
2 control device and the average SO
2 input rate from the `as fired' fuel analysis for 30 successive boiler operating days.
NR 440.20(8)(c)4.
4. The appropriate procedures in Method 19 shall be used to determine the emission rate.
NR 440.20(8)(c)5.
5. The continuous monitoring system in
sub. (7) (b) and
(d) shall be used to determine the concentrations of SO
2 and CO
2 or O
2.
NR 440.20(8)(d)
(d) The owner or operator shall determine compliance with the NO
x standard in
sub. (5) as follows:
NR 440.20(8)(d)1.
1. The appropriate procedures in Method 19 shall be used to determine the emission rate of NO
x.
NR 440.20(8)(d)2.
2. The continuous monitoring system in
sub. (7) (c) and
(d) shall be used to determine the concentrations of NO
x and CO
2 or O
2.
NR 440.20(8)(e)
(e) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this subsection:
NR 440.20(8)(e)1.
1. For Method 5 or 5B, Method 17 may be used at facilities with or without wet FGD systems if the stack 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 in Method 17 only if it is used after wet FGD systems. Method 17 may not be used after wet FGD systems if the effluent is saturated or laden with water droplets.
NR 440.20(8)(e)2.
2. The F
c factor (CO
2 ) procedures in Method 19 may be used to compute the emission rate of particulate matter under the stipulations of
s. NR 440.19 (7) (d) 1. The CO
2 shall be determined in the same manner as the O
2 concentration.
NR 440.20(8)(f)
(f) Electric utility combined cycle gas turbines are performance tested for particulate matter, sulfur dioxide and nitrogen oxides using the procedures of Method 19 of
40 CFR part 60, Appendix A, incorporated by reference in
s. NR 440.17 (1). The sulfur dioxide and nitrogen oxides emission rates from the gas turbine used in Method 19 calculations are determined when the gas turbine is performance tested under
s. NR 440.50. The potential uncontrolled particulate matter emission rate from a gas turbine is defined as 17 ng/J (0.04 lb/million Btu) heat input.
NR 440.20(9)(a)(a) For sulfur dioxide, nitrogen oxides and particulate matter emissions, the performance test data from the initial performance test and from the performance evaluation of the continuous monitors (including the transmissometer) shall be submitted to the department.
NR 440.20(9)(b)
(b) For sulfur dioxide and nitrogen oxides the following information shall be reported to the department for each 24-hour period.
NR 440.20(9)(b)2.
2. The average sulfur dioxide and nitrogen oxide emission rates (ng/J or lb/million Btu) for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for noncompliance with the emission standards; and description of corrective actions taken.
NR 440.20(9)(b)3.
3. Percent reduction of the potential combustion concentration of sulfur dioxide for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for noncompliance with the standard; and description of corrective actions taken.
NR 440.20(9)(b)4.
4. Identification of the boiler operating days for which pollutant or diluent data have not been obtained by an approved method for at least 18 hours of operation of the facility; justification for not obtaining sufficient data; and description of corrective actions taken.
NR 440.20(9)(b)5.
5. Identification of the times when emissions data have been excluded from the calculation of average emission rates because of startup, shutdown, malfunction (NO
x only), emergency conditions (SO
2 only) or other reasons, and justification for excluding data for reasons other than startup, shutdown, malfunction or emergency conditions.
NR 440.20(9)(b)6.
6. Identification of “F" factor used for calculations, method of determination and type of fuel combusted.
NR 440.20(9)(b)7.
7. Identification of times when hourly averages have been obtained based on manual sampling methods.
NR 440.20(9)(b)8.
8. Identification of the times when the pollutant concentration exceeded full span of the continuous monitoring system.
NR 440.20(9)(b)9.
9. Description of any modifications to the continuous monitoring system which could affect the ability of the continuous monitoring system to comply with Performance Specification 2 or 3 of
40 CFR part 60, Appendix B, incorporated by reference in
s. NR 440.17.
NR 440.20(9)(c)
(c) If the minimum quantity of emission data as required by
sub. (7) is not obtained for any 30 successive boiler operating days, the following information obtained under the requirements of
sub. (6) (h) shall be reported to the department for that 30-day period:
NR 440.20(9)(c)1.
1. The number of hourly averages available for outlet emissions rates (n
o) and inlet emission rates (n
i), as applicable.
NR 440.20(9)(c)2.
2. The standard deviation of hourly averages for outlet emission rates (S
o) and inlet emission rates (S
i), as applicable.
NR 440.20(9)(c)3.
3. The lower confidence limit for the mean outlet emission rate (E
o*) and the upper confidence limit for the mean inlet emission rate (E
i*), as applicable.
NR 440.20(9)(c)5.
5. The ratio of the upper confidence limit for the mean outlet emission rate (E
o*) and the allowable emission rate (E
std), as applicable.
NR 440.20(9)(d)
(d) If any standards under
sub. (4) are exceeded during emergency conditions because of control system malfunction, the owner or operator of the affected facility shall submit a signed statement:
NR 440.20(9)(d)1.
1. Indicating if emergency conditions existed and requirements under
sub. (6) (d) were met during each period, and
NR 440.20(9)(d)2.b.
b. Electrical output and demand on the owner or operator's electric utility system and the affected facility;
NR 440.20(9)(d)2.c.
c. Amount of power purchased from interconnected neighboring utility companies during the emergency period;
NR 440.20(9)(e)
(e) If fuel pretreatment credit toward the sulfur dioxide emission standard under
sub. (4) is claimed, the owner or operator of the affected facility shall submit a signed statement:
NR 440.20(9)(e)1.
1. Indicating what percentage cleaning credit was taken for the calendar quarter, and whether the credit was determined in accordance with the provisions of
sub. (8) and Method 19 of
40 CFR part 60, Appendix A, incorporated by reference in
s. NR 440.17; and
NR 440.20(9)(e)2.
2. Listing the quantity, heat content, and date each pretreated fuel shipment was received during the previous quarter; the name and location of the fuel pretreatment facility; and the total quantity and total heat content of all fuels received at the affected facility during the previous quarter.
NR 440.20(9)(f)
(f) For any periods for which opacity, sulfur dioxide or nitrogen oxides emissions data are not available, the owner or operator of the affected facility shall submit a signed statement indicating if any changes were made in operation of the emission control system during the period of data unavailability. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before and following the period of data unavailability.
NR 440.20(9)(g)
(g) The owner or operator of the affected facility shall submit a signed statement indicating whether:
NR 440.20(9)(g)1.
1. The required continuous monitoring system calibration, span, and drift checks or other periodic audits have or have not been performed as specified.
NR 440.20(9)(g)2.
2. The data used to show compliance was or was not obtained in accordance with approved methods and procedures of this chapter and is representative of plant performance.
NR 440.20(9)(g)3.
3. The minimum data requirements have or have not been met; or, the minimum data requirements have not been met for errors that were unavoidable.
NR 440.20(9)(g)4.
4. Compliance with the standards has or has not been achieved during the reporting period.
NR 440.20(9)(h)
(h) For the purposes of the reports required under
s. NR 440.07, periods of excess emissions are defined as all 6-minute periods during which the average opacity exceeds the applicable opacity standards under
sub. (3) (b). Opacity levels in excess of the applicable opacity standard and the date of such excesses shall be submitted to the department each calendar quarter.
NR 440.20(9)(i)
(i) The owner or operator of an affected facility shall submit the written reports required under this subsection and
ss. NR 440.01 to
440.15 to the department semiannually for each 6-month period. All semiannual reports shall be postmarked by the 30th day following the end of each 6-month period.
NR 440.20(9)(j)
(j) The owner or operator of an affected facility may submit electronic quarterly reports for SO
2, NO
x and opacity in lieu of submitting the written reports required under
pars. (b) and
(h). The format of each quarterly electronic report shall be coordinated with the department. The electronic report shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a certification statement from the owner or operator, indicating whether compliance with the applicable emission standards and minimum data requirements of this section was achieved during the reporting period. Before submitting reports in the electronic format, the owner or operator shall coordinate with the department to obtain agreement to submit reports in this alternative format.
NR 440.20 History
History: Cr.
Register, January, 1984, No. 337, eff. 2-1-84; am. (7) (h) 1., 3., 4., (L) 1. and (8) (a) 1.,
Register, September, 1986, No. 369, eff. 10-1-86; am. (2) (intro.), (7) (h) 1. to 3., (i) 1., (8) (a) 1. to 6., r. (8) (a) 7.,
Register, September, 1990, No. 417, eff. 10-1-90; am. (4) (h) 1. and 2., (5) (a) 1., (c), (6) (d) 3. (intro.) and (h), r. and recr. (7) (f), (h), (i) (intro.) to 2. and (8), cr. (7) (j),
Register, July, 1993, No. 451, eff. 8-1-93; am. (2) (n), (y), (5) (a) 1., (7) (h) 2., (8) (b) 2.,
Register, December, 1995, No. 480, eff. 1-1-96
; correction in (4) (b) (intro.) made under s. 13.93 (2m) (b) 7., Stats.,
Register, November, 1999, No. 527;
CR 06-109: am. (1) (b), (2) (b), (n), (q) 1. b. and (y), (4) (d) 2., (f), (5) (a) (intro.), 1. and 2., (b) and (c), (7) (e) and (i) 1. and 3., (8) (title) and (b) 2. b. and (9) (i), cr. (2) (gr) and (Lm), (5) (d), (6) (a) (title), (b) (title), (c) (title), (d) (title), (e) (title), (f) (title), (g) (title) and (h) (title), (i) to (k), (7) (c) 2. and (k) to (n), (8) (f) and (9) (j), renum. (7) (c) to be (7) (c) 1. Register May 2008 No. 629, eff. 6-1-08.
NR 440.205
NR 440.205 Industrial - commercial - institutional steam generating units. NR 440.205(1)(a)(a) The affected facility to which this section applies is each steam generating unit that commences construction, modification, or reconstruction after June 19, 1984, and that has a heat input capacity from fuels combusted in the steam generating unit of more than 29 MW (100 million Btu/hour).
NR 440.205(1)(b)
(b) Any affected facility meeting the applicability requirements under
par. (a) and commencing construction, modification, or reconstruction after June 19, 1984, but on or before June 19, 1986, is subject to the following standards:
NR 440.205(1)(b)1.
1. Coal-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 million Btu/hour), inclusive, are subject to the particulate matter and nitrogen oxides standards under this section.
NR 440.205(1)(b)2.
2. Coal-fired affected facilities having a heat input capacity greater than 73 MW (250 million Btu/hour) and meeting the applicability requirements under
s. NR 440.19 (standards of performance for fossil fuel-fired steam generators) are subject to the particulate matter and nitrogen oxides standards under this section and to the sulfur dioxide standards in
s. NR 440.19 (4).
NR 440.205(1)(b)3.
3. Oil-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 million Btu/hour), inclusive, are subject to the nitrogen oxides standards in this section.
NR 440.205(1)(b)4.
4. Oil-fired affected facilities having a heat input capacity greater than 73 MW (250 million Btu/hour) and meeting the applicability requirements in
s. NR 440.19 (standards of performance for fossil fuel-fired steam generators) are also subject to the nitrogen oxides standards in this section and the particulate matter and sulfur dioxide standards in
s. NR 440.19 (3) and
(4).
NR 440.205(1)(c)
(c) Affected facilities which also meet the applicability requirements under
s. NR 440.26 (standards of performance for petroleum refineries) are subject to the particulate matter and nitrogen oxides standards under this section and the sulfur dioxide standards under
s. NR 440.26 (5).
NR 440.205(1)(d)
(d) Affected facilities which also meet the applicability requirements in
s. NR 440.21 (standards of performance for incinerators) are subject to the nitrogen oxides and particulate matter standards in this section.
NR 440.205(1)(e)
(e) Steam generating units meeting the applicability requirements in
s. NR 440.20 (standards of performance for electric utility steam generating units) are not subject to this section.
NR 440.205(1)(f)
(f) Any change to an existing steam generating unit for the sole purpose of combusting gases containing TRS as defined in
s. NR 440.45 (2) is not considered a modification under
s. NR 440.14 and the steam generating unit is not subject to this section.
NR 440.205(1)(h)
(h) Unless and until
s. NR 440.50 is revised to extend the applicability of
s. NR 440.50 to steam generator units subject to this section, this section will continue to apply to combined cycle gas turbines that are capable of combusting more than 29 MW (100 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. (The gas turbine emissions are subject to
s. NR 440.50.)
NR 440.205(2)
(2) Definitions. As used in this section, terms not defined in this subsection have the meanings given in
s. NR 440.02.
NR 440.205(2)(a)
(a) “Annual capacity factor" means the ratio between the actual heat input to a steam generating unit from the fuels listed in
sub. (3) (a),
(4) (a) or
(5) (a), as applicable, during a calendar year and the potential heat input to the steam generating unit had it been operated for 8,760 hours at the maximum steady state design heat input capacity. In the case of steam generating units that are rented or leased, the actual heat input shall be determined based on the combined heat input from all operations of the affected facility in a calendar year.
NR 440.205(2)(b)
(b) “Byproducts/waste" means any liquid or gaseous substance produced at chemical manufacturing plants, petroleum refineries or pulp and paper mills (except natural gas, distillate oil, or residual oil) and combusted in a steam generating unit for heat recovery or for disposal. Gaseous substances with carbon dioxide levels greater than 50% or carbon monoxide levels greater than 10% are not byproduct/waste for the purposes of this section.
NR 440.205(2)(c)
(c) “Chemical manufacturing plants" means industrial plants which are classified by the department of commerce under SIC code 28 in the Standard Industrial Classification Manual, incorporated by reference in
s. NR 440.17.
NR 440.205(2)(d)
(d) “Coal" means all solid fuels classified as an anthracite, bituminous, subbituminous, or lignite by the American Society for Testing and Materials in ASTM D388-99 (reapproved 2004), Standard Specification for Classification of Coals by Rank, incorporated by reference in
s. NR 440.17 (2) (a) 12., coal refuse, and petroleum coke. Coal-derived synthetic fuels, including but not limited to solvent refined coal, gasified coal, coal-oil mixtures, and coal-water mixtures, are also included in this definition for the purposes of this section.
NR 440.205(2)(e)
(e) “Coal refuse" means any byproduct of coal mining or coal cleaning operations with an ash content greater than 50%, by weight, and a heating value less than 13,900 kJ/kg (6,000 Btu/lb) on a dry basis.
NR 440.205(2)(f)
(f) “Combined cycle system" means a system where a separate source, such as a gas turbine, internal combustion engine, kiln, etc., provides exhaust gas to a heat recovery steam generating unit.
NR 440.205(2)(g)
(g) “Conventional technology" means wet flue gas desulfurization (FGD) technology, dry FGD technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology.
NR 440.205(2)(h)
(h) “Distillate oil" means fuel oils which contain 0.05 weight percent nitrogen or less and comply with the specifications for fuel oils number 1 and 2, as defined by the American Society for Testing and Materials in ASTM D396-98, Standard Specification for Fuel Oils, incorporated by reference in
s. NR 440.17 (2) (a) 13.
NR 440.205(2)(i)
(i) “Dry flue gas desulfurization technology" means a sulfur dioxide control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline slurries or solutions used in dry flue gas desulfurization technology include but are not limited to lime and sodium.
NR 440.205(2)(j)
(j) “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, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit.
