Xk is the fraction of the total heat input from fuel combustion derived from coal and oil, as determined by applicable procedures in Method 19
NR 440.207(5)(e)2.2. The owner or operator of an affected facility that qualifies under the provisions of sub. (3) (c) or (d), where percent reduction is not required, does not have to measure the parameters Ew or Xk if the owner or operator of the affected facility elects to measure emission rates of the coal or oil using the fuel sampling and analysis procedures under Method 19. NR 440.207(5)(f)(f) Affected facilities subject to the percent reduction requirements under sub. (3) (a) or (b) shall determine compliance with the SO2 emission limits under sub. (3) pursuant to par. (d) or (e), and shall determine compliance with the percent reduction requirements using the following procedures: NR 440.207(5)(f)1.1. If only coal is combusted, the percent of potential SO2 emission rate is computed using the following formula: %Ps = 100 (1 - %Rg/100) (1 - %Rf/100)
where:
%Ps is the percent of potential SO2 emission rate, in percent
%Rg is the SO2 removal efficiency of the control device as determined by Method 19, in percent
%Rf is the SO2 removal efficiency of fuel pretreatment as determined by Method 19, in percent
NR 440.207(5)(f)2.2. If coal, oil, or coal and oil are combusted with other fuels, the same procedures required in subd. 1. are used, except as provided for in the following: NR 440.207(5)(f)2.a.a. To compute the %Ps, an adjusted %Rg (%Rgo) is computed from Eaoo from par. (e) 1. and an adjusted SO2 inlet rate (Eaio) using the following formula: %Rgo = 100 [1.0 - (Eaoo/Eai)]
where:
%Rgo is the adjusted %Rg, in percent
Eaoo is the adjusted Eao, ng/J (lb/million Btu)
Eaio is the adjusted average SO2 inlet rate, ng/J (lb/million Btu)
NR 440.207(5)(f)2.b.b. To compute Eaio, an adjusted hourly SO2 inlet rate (Ehio) is used. The Ehio is computed using the following formula: Ehio = [Ehi - Ew (1 - Xk)]/Xk
where:
Ehio is the adjusted Ehi, ng/J (lb/million Btu)
Ehi is the SO2 concentration in fuels other than coal and oil combusted in the affected facility, as determined by fuel sampling and analysis procedures in Method 19, ng/J (lb/million Btu). The value Ew for each fuel lot is used for each hourly average during the time that the lot is being combusted. The owner or operator does not have to measure Ew if the owner or operator elects to assume Ew = 0
Xk is the fraction of the total heat input from fuel combustion derived from coal and oil, as determined by applicable procedures in Method 19
NR 440.207(5)(g)(g) For oil-fired affected facilities where the owner or operator seeks to demonstrate compliance with the fuel oil sulfur limits under sub. (3) based on shipment fuel sampling, the initial performance test shall consist of sampling and analyzing the oil in the initial tank of oil to be fired in the steam generating unit to demonstrate that the oil contains 0.5 weight percent sulfur or less. Thereafter, the owner or operator of the affected facility shall sample the oil in the fuel tank after each new shipment of oil is received, as described under sub. (7) (d) 2. NR 440.207(5)(h)(h) For affected facilities subject to sub. (3) (h) 1., 2. or 3. where the owner or operator seeks to demonstrate compliance with the SO2 standards based on fuel supplier certification, the performance test shall consist of the certification, the certification from the fuel supplier, as described under sub. (9) (f) 1., 2. or 3., as applicable. NR 440.207(5)(i)(i) The owner or operator of an affected facility seeking to demonstrate compliance with the SO2 standards under sub. (3) (c) 2. shall demonstrate the maximum design heat input capacity of the steam generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial performance test, and a subsequent demonstration may be requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the maximum design heat input capacity stated by the manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall be used. NR 440.207(5)(j)(j) The owner or operator of an affected facility shall use all valid SO2 emissions data in calculating %Ps and Eho under par. (d), (e) or (f), as applicable, whether or not the minimum emissions data requirements under sub. (7) (f) are achieved. All valid emissions data, including valid data collected during periods of startup, shutdown and malfunction shall be used in calculating %Ps or Eho pursuant to par. (d), (e) or (f), as applicable. NR 440.207(6)(6) Compliance and performance test methods and procedures for particulate matter. NR 440.207(6)(a)(a) The owner or operator of an affected facility subject to the PM standards, opacity standards, or both, under sub. (4) shall conduct an initial performance test as required under s. NR 440.08, and shall conduct subsequent performance tests as requested by the department, to determine compliance with the standards using the following procedures and reference methods. Unless otherwise indicated, these procedures and reference methods are in 40 CFR part 60, Appendix A, which is incorporated by reference in s. NR 440.17. NR 440.207(6)(a)1.1. Method 1 shall be used to select the sampling site and the number of traverse sampling points. NR 440.207(6)(a)2.2. Method 3 shall be used for gas analysis when applying Method 5, Method 5B or Method 17. NR 440.207(6)(a)3.3. Method 5, Method 5B or Method 17 shall be used to measure the concentration of PM as follows: NR 440.207(6)(a)3.a.a. Method 5 may be used only at affected facilities without wet scrubber systems. NR 440.207(6)(a)3.b.b. Method 17 may be used at affected facilities with or without wet scrubber systems provided the stack gas temperature does not exceed a temperature of 160°C (320°F). The procedures of Sections 8.1 and 11.1 of Method 5B may be used in Method 17 only if Method 17 is used in conjunction with a wet scrubber system. Method 17 may not be used in conjunction with a wet scrubber system if the emissions are saturated or laden with water droplets. NR 440.207(6)(a)4.4. The sampling time for each run shall be at least 120 minutes and the minimum sampling volume shall be 1.7 dscm (60 dscf) except that smaller sampling times or volumes may be approved by the department when necessitated by process variables or other factors. NR 440.207(6)(a)5.5. For Method 5 or Method 5B, the temperature of the sample gas in the probe and filter holder shall be monitored and maintained at 160 ± 14°C (320 ± 25°F). NR 440.207(6)(a)6.6. For determination of PM emissions, an oxygen or carbon dioxide measurement shall be obtained simultaneously with each run of Method 5, Method 5B or Method 17 by traversing the duct at the same sampling location. NR 440.207(6)(a)7.7. For each run using Method 5, Method 5B or Method 17, the emission rates expressed in ng/J (lb/million Btu) heat input shall be determined using: NR 440.207(6)(a)7.a.a. The oxygen or carbon dioxide measurements and PM measurements obtained under this subsection, NR 440.207(6)(a)8.8. Method 9 (6-minute average of 24 observations) shall be used for determining the opacity of stack emissions. NR 440.207(6)(b)(b) The owner or operator of an affected facility seeking to demonstrate compliance with the PM standards under sub. (4) (b) 2. shall demonstrate the maximum design heat input capacity of the steam generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial performance test, and a subsequent demonstration may be requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the maximum design heat input capacity stated by the manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to the determine annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall be used. NR 440.207(7)(a)(a) Except as provided in pars. (d) and (e), the owner or operator of an affected facility subject to the SO2 emission limits under sub. (3) shall install, calibrate, maintain and operate a CEMS for measuring SO2 concentrations and either oxygen or carbon dioxide concentrations at the outlet of the SO2 control device (or the outlet of the steam generating unit if no SO2 control device is used), and shall record the output of the system. The owner or operator of an affected facility subject to the percent reduction requirements under sub. (3) shall measure SO2 concentrations and either oxygen or carbon dioxide concentrations at both the inlet and outlet of the SO2 control device. NR 440.207(7)(b)(b) The 1-hour average SO2 emission rates measured by a CEMS shall be expressed in ng/J or lb/million Btu heat input and shall be used to calculate the average emission rates under sub. (3). Each 1-hour average SO2 emission rate shall be based on at least 30 minutes of operation and include at least 2 data points representing 2 15-minute periods. Hourly SO2 emission rates are not calculated if the affected facility is operated less than 30 minutes in a 1-hour period and are not counted toward determination of a steam generating unit operating day. NR 440.207(7)(c)(c) The procedure under s. NR 440.13 shall be followed for installation, evaluation and operation of the CEMS. 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
