NR 440.207(7)(c)1.1. All CEMS shall be operated in accordance with the applicable procedures under Performance Specifications 1, 2 and 3 of 40 CFR part 60 Appendix B, incorporated by reference in s. NR 440.17. NR 440.207(7)(c)2.2. Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 1 of 40 CFR part 60 Appendix F, incorporated by reference in s. NR 440.17. NR 440.207(7)(c)3.3. For affected facilities subject to the percent reduction requirements under sub. (3), the span value of the SO2 CEMS at the inlet to the SO2 control device shall be 125% of the maximum estimated hourly potential SO2 emission rate of the fuel combusted, and the span value of the SO2 CEMS at the outlet from the SO2 control device shall be 50% of the maximum estimated hourly potential SO2 rate of the fuel combusted. NR 440.207(7)(c)4.4. For affected facilities that are not subject to the percent reduction requirements of sub. (3), the span value of the SO2 CEMS at the outlet from the SO2 control device, or outlet of the steam generating unit if no SO2 control device is used, shall be 125% of the maximum estimated hourly potential SO2 emission rate of the fuel combusted. NR 440.207(7)(d)(d) As an alternative to operating a CEMS at the inlet to the SO2 control device, or outlet of the steam generating unit if no SO2 control device is used, as required under par. (a), an owner or operator may elect to determine the average SO2 emission rate by sampling the fuel prior to combustion. As an alternative to operating a CEMS at the outlet from the SO2 control device, or outlet of the steam generating unit if no SO2 control device is used, as required under par. (a), an owner or operator may elect to determine the average SO2 emission rate by using Method 6B. Fuel sampling shall be conducted pursuant to either subd. 1. or 2. Method 6B shall be conducted pursuant to subd. 3. NR 440.207(7)(d)1.1. For affected facilities combusting coal or oil, coal or oil samples shall be collected daily in an as-fired condition at the inlet to the steam generating unit and analyzed for sulfur content and heat content according to Method 19. Method 19 provides procedures for converting these measurements into the format to be used in calculating the average SO2 input rate. NR 440.207(7)(d)2.2. As an alternative fuel sampling procedure for affected facilities combusting oil, oil samples may be collected from the fuel tank for each steam generating unit immediately after the fuel tank is filled and before any oil is combusted. The owner or operator of an affected facility shall analyze the oil sample to determine the sulfur content of the oil. If a partially empty fuel tank is refilled, a new sample and analysis of the fuel in the tank is required upon filling. Results of the fuel analysis taken after each new shipment of oil is received shall be used as the daily value when calculating the 30-day rolling average until the next shipment is received. If the fuel analysis shows that the sulfur content in the fuel tank is greater than 0.5 weight percent sulfur, the owner or operator shall ensure that the sulfur content of subsequent oil shipments is low enough to cause the 30-day rolling average sulfur content to be 0.5 weight percent sulfur or less. NR 440.207(7)(d)3.3. Method 6B may be used in lieu of CEMS to measure SO2 at the inlet or outlet of the SO2 control system. An initial stratification test is required to verify the adequacy of the Method 6B sampling location. The stratification test shall consist of 3 paired runs of a suitable SO2 and carbon dioxide measurement train operated at the candidate location and a second similar train operated according to the procedures in s. 3.2 and the applicable procedures in section 7 of Performance Specification 2 of 40 CFR part 60 Appendix B, incorporated by reference in s. NR 440.17. Method 6B, Method 6A or a combination of Methods 6 and 3 or Methods 6C and 3A are suitable measurement techniques. If Method 6B is used for the second train, sampling time and timer operation may be adjusted for the stratification test as long as an adequate sample volume is collected; however, both sampling trains are to be operated similarly. For the location to be adequate for Method 6B 24-hour tests, then the mean of the absolute difference between the 3 paired runs shall be less than 10% (0.10). NR 440.207(7)(e)(e) The monitoring requirements of pars. (a) and (d) do not apply to affected facilities subject to sub. (3) (h) 1., 2. or 3. where the owner or operator of the affected facility seeks to demonstrate compliance with the SO2 standards based on fuel supplier certification, or as described under sub. (9) (f) 1., 2. or 3., as applicable. NR 440.207(7)(f)(f) The owner or operator of an affected facility operating a CEMS pursuant to par. (a), or conducting as-fired fuel sampling pursuant to par. (d) 1., shall obtain emission data for at least 75% of the operating hours in at least 22 out of 30 successive steam generating unit operating days. If this minimum data requirement is not met with a single monitoring system, the owner or operator of the affected facility shall supplement the emission data with data collected with other monitoring systems as approved by the department. NR 440.207(8)(a)(a) The owner or operator of an affected facility combusting coal, residual oil or wood that is subject to the opacity standards under sub. (4) shall install, calibrate, maintain and operate a CEMS for measuring the opacity of the emissions discharged to the atmosphere and record the output of the system. NR 440.207(8)(b)(b) All CEMS for measuring opacity shall be operated in accordance with the applicable procedures under Performance Specification 1 of 40 CFR part 60 Appendix B, incorporated by reference in s. NR 440.17. The span value of the opacity CEMS shall be between 60 and 80%. NR 440.207(9)(a)(a) The owner or operator of each affected facility shall submit notification of the date of construction or reconstruction, anticipated startup and actual startup, as provided by s. NR 440.07. This notification shall include: NR 440.207(9)(a)1.1. The design heat input capacity of the affected facility and identification of fuels to be combusted in the affected facility. NR 440.207(9)(a)2.2. If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or mixture of fuels under sub. (3) or (4). NR 440.207(9)(a)3.3. The annual capacity factor at which the owner or operator anticipates operating the affected facility based on all fuels fired and based on each individual fuel fired. NR 440.207(9)(a)4.4. Notification if an emerging technology will be used for controlling SO2 emissions. The administrator shall examine the description of the control device and determine whether the technology qualifies as an emerging technology. In making this determination, the administrator may require the owner or operator of an affected facility to submit additional information concerning the control device. The affected facility is subject to the provisions of sub. (3) (a) or (b) 1., unless and until this determination is made by the administrator. NR 440.207(9)(b)(b) The owner or operator of each affected facility subject to the SO2 emission limits of sub. (3), or the PM or opacity limits of sub. (4), shall submit to the department the performance test data from the initial and any subsequent performance tests and, if applicable, the performance evaluation of the CEMS and COMS using the applicable performance specifications in Appendix B of 40 CFR part 60, incorporated by reference in s. NR 440.17 (1). NR 440.207(9)(c)(c) The owner or operator of each coal-fired, residual oil-fired, or wood-fired affected facility subject to the opacity limits under sub. (4) (c) shall submit excess emission reports for any excess emissions from the affected facility which occur during the reporting period. NR 440.207(9)(d)(d) The owner or operator of each affected facility subject to the SO2 emission limits, fuel oil sulfur limits or percent reduction requirements under sub. (3) shall submit reports to the department. NR 440.207(9)(e)(e) The owner or operator of each affected facility subject to the SO2 emission limits, fuel oil sulfur limits or percent reduction requirements under sub. (3) shall keep records and submit reports as required under par. (d), including the following information, as applicable: NR 440.207(9)(e)2.2. Each 30-day average SO2 emission rate (ng/J or lb/million Btu), or 30-day average sulfur content (weight percent), calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of corrective actions taken. NR 440.207(9)(e)3.3. Each 30-day average percent of potential SO2 emission rate calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of corrective actions taken. NR 440.207(9)(e)4.4. Identification of any steam generating unit operating days for which SO2 or diluent, oxygen or carbon dioxide, data have not been obtained by an approved method for at least 75% of the operating hours; justification for not obtaining sufficient data; and a description of corrective actions taken. NR 440.207(9)(e)5.5. Identification of any times when emissions data have been excluded from the calculation of average emission rates; justification for excluding data; and a description of corrective actions taken if data have been excluded for periods other than those during which coal or oil were not combusted in the steam generating unit. NR 440.207(9)(e)6.6. Identification of the F factor used in calculations, method of determination and type of fuel combusted. NR 440.207(9)(e)7.7. Identification of whether averages have been obtained based on CEMS rather than manual sampling methods. NR 440.207(9)(e)8.8. If a CEMS is used, identification of any times when the pollutant concentration exceeded the full span of the CEMS. NR 440.207(9)(e)9.9. If a CEMS is used, description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specifications 2 or 3 in Appendix B of 40 CFR part 60, incorporated by reference in s. NR 440.17. NR 440.207(9)(e)10.10. If a CEMS is used, results of daily CEMS drift tests and quarterly accuracy assessments as required under Appendix F, Procedure 1 of 40 CFR Part 60, incorporated by reference in s. NR 440.17. NR 440.207(9)(e)11.11. If fuel supplier certification is used to demonstrate compliance, records of fuel supplier certification as described under par. (f) 1., 2. or 3., as applicable. In addition to records of fuel supplier certifications, the report shall include a certified statement signed by the owner or operator of the affected facility that the records of fuel supplier certifications submitted represent all of the fuel combusted during the reporting period. NR 440.207(9)(f)(f) Fuel supplier certification shall include the following information: NR 440.207(9)(f)1.b.b. A statement from the oil supplier that the oil complies with the specifications under the definition of distillate oil in sub. (2). NR 440.207(9)(f)2.b.b. The location of the oil when the sample was drawn for analysis to determine the sulfur content of the oil, specifically including whether the oil was sampled as delivered to the affected facility, or whether the sample was drawn from oil in storage at the oil supplier’s or oil refiner’s facility, or other location; NR 440.207(9)(f)2.c.c. The sulfur content of the oil from which the shipment came, or of the shipment itself; and NR 440.207(9)(f)3.b.b. The location of the coal when the sample was collected for analysis to determine the properties of the coal, specifically including whether the coal was sampled as delivered to the affected facility or whether the sample was collected from coal in storage at the mine, at a coal preparation plant, at a coal supplier’s facility or at another location. The certification shall include the name of the coal mine, and coal seam, coal storage facility or coal preparation plant, where the sample was collected; NR 440.207(9)(f)3.c.c. The results of the analysis of the coal from which the shipment came, or of the shipment itself, including the sulfur content, moisture content, ash content and heat content; and NR 440.207(9)(g)(g) The owner or operator of each affected facility shall record and maintain records of the amounts of each fuel combusted during each day. NR 440.207(9)(h)(h) The owner or operator of each affected facility subject to a federally enforceable requirement limiting the annual capacity factor for any fuel or mixture of fuels under sub. (3) or (4) shall calculate the annual capacity factor individually for each fuel combusted. The annual capacity factor is determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end of the calendar month. NR 440.207(9)(i)(i) All records required under this subsection shall be maintained by the owner or operator of the affected facility for a period of 2 years following the date of such record. NR 440.207(9)(j)(j) The reporting period for the reports required under this section is each 6-month period. All reports shall be submitted to the department and shall be postmarked by the 30th day following the end of the reporting period. NR 440.207 HistoryHistory: Cr. Register, June, 1993, No.450, eff. 8-1-93; r. (2) (k), am. (3) (a) (intro.), (b) 1. (intro.), 2. (intro.), (c) (intro.), (d), (e) (intro.), 2., (4) (a) (intro.), 1., (b) (intro.), (c), (5) (j), Register, December, 1995, No. 480, eff. 1-1-96; correction in (g) (e) (intro.) made under s. 13.93 (2m) (b) 7., Stats., Register, December, 1995, No., 480; CR 06-109: renum. (1) to be (1) (a) and am., cr. (1) (c) and (d), (2) (em), (6) (a) 4. and (9) (j), am. (2) (g), (q) 2., (v), (4) (a) 1., (b) (intro.), (5) (i), (6) (a) 1. and 3. a and b., (7) (b) and (d) (intro.), (9) (b), (c), (d), (e) (intro.), 2., 3. and 11., renum. (6) (a) 4. to 7. to be 5. to 8. and am. 5. Register May 2008 No. 629, eff. 6-1-08. NR 440.21(1)(1) Applicability and designation of affected facility. NR 440.21(1)(a)(a) The provisions of this section are applicable to each incinerator of more than 45 metric tons per day charging rate (50 tons/day), which is the affected facility. NR 440.21(1)(b)(b) Any facility under par. (a) that commences construction or modification after August 17, 1971, is subject to the requirements of this section. NR 440.21(2)(2) Definitions. As used in this section, terms not defined in this subsection have the meanings given in s. NR 440.02. NR 440.21(2)(b)(b) “Incinerator” means any furnace used in the process of burning solid waste for the purpose of reducing the volume of the waste by removing combustible matter. NR 440.21(2)(c)(c) “Solid waste” means refuse, more than 50% of which is municipal type waste consisting of a mixture of paper, wood, yard wastes, food wastes, plastics, leather, rubber and other combustibles, and noncombustible materials such as glass and rock. NR 440.21(3)(3) Standard for particulate matter. On and after the date on which the initial performance test is completed or required to be completed under s. NR 440.08, whichever date comes first, no owner or operator subject to the provisions of this section may cause to be discharged into the atmosphere from any affected facility any gases which contain particulate matter in excess of 0.18 g/dscm (0.08 gr/dscf) corrected to 12% CO2. NR 440.21(4)(4) Monitoring of operations. The owner or operator of any incinerator subject to the provisions of this section shall record the daily charging rates and hours of operation. NR 440.21(5)(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). NR 440.21(5)(b)(b) The owner or operator shall determine compliance with the particulate matter standard in sub. (3) as follows: NR 440.21(5)(b)1.1. The concentration (C12) of particulate matter, corrected to 12% CO2, shall be computed for each run using the following equation: C12 = Cs (12/%CO2)
where:
C12 is the concentration of particulate matter corrected to 12% CO2 g/dscm (gr/dscf)
Cs is the concentration of particulate matter, g/dscm (gr/dscf)
%CO2 is the CO2 concentration, percent dry basis
NR 440.21(5)(b)2.2. Method 5 shall be used to determine the particulate matter concentration (Cs). The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 dscf). NR 440.21(5)(b)3.3. The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 3B shall be used to determine CO2 concentration (%CO2). NR 440.21(5)(b)3.a.a. The CO2 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 CO2 traverse points may be reduced to 12 if Method 1 is used to locate the 12 CO2 traverse points. If individual CO2 samples are taken at each traverse point, the CO2 concentration (%CO2) used in the correction equation shall be the arithmetic mean of the sample CO2 concentrations at all traverse points. NR 440.21(5)(b)3.b.b. If sampling is conducted after a wet scrubber, an “adjusted” CO2 concentration, (%CO2)adj, which accounts for the effects of CO2 absorption and dilution air, may be used instead of the CO2 concentration determined in this paragraph. The adjusted CO2 concentration shall be determined by either of the procedures in par. (c). NR 440.21(5)(c)(c) The owner or operator may use either of the following procedures to determine the adjusted CO2 concentration. NR 440.21(5)(c)1.1. The volumetric flow rates at the inlet and outlet of the wet scrubber and the inlet CO2 concentration may be used to determine the adjusted concentration, (%CO2)adj, using the following equation: (%CO2)adj, = (%CO2)di (Qdi/Qdo)
where:
(%CO2)adj is the adjusted outlet CO2 concentration, percent dry basis
(%CO2)di is the CO2 concentration measured before the scrubber, percent dry basis
Qdi is the volumetric flow rate of effluent gas before the wet scrubber, dscm/min (dscf/min)
Qdo is the volumetric flow rate of effluent gas after the wet scrubber, dscm/min (dscf/min)
NR 440.21(5)(c)1.a.a. At the outlet, Method 5 is used to determine the volumetric flow rate (Qdo) of the effluent gas. NR 440.21(5)(c)1.b.b. At the inlet, Method 2 is used to determine the volumetric flow rate (Qdi) of the effluent gas as follows: Two full velocity traverses are conducted, one immediately before and one immediately after each particulate run conducted at the outlet, and the results are averaged. NR 440.21(5)(c)1.c.c. At the inlet, the emission rate correction factor, integrated sampling and analysis procedure of Method 3B is used to determine the CO2 concentration, (%CO2)di, as follows: At least 9 sampling points are selected randomly from the velocity traverse points and are divided randomly into 3 sets, equal in number of points; the first set of 3 or more points is used for the first run, the second set for the second run, and the third set for the third run. The CO2 sample is taken simultaneously with each particulate run being conducted at the outlet, by traversing the 3 sampling points, or more, and sampling at each point for equal increments of time. NR 440.21(5)(c)2.2. Excess air measurements may be used to determine the adjusted CO2 concentration, (%CO2)adj, using the following equation: (%CO2)adj = (%CO2)di [(100 + %EAi)/ (100 + %EAo)]
