NR 440.24 HistoryHistory: Cr. Register, January, 1984, No. 337, eff. 2-1-84; cr. (5) (d) and (6) (e), Register, September, 1986, No. 369, eff. 10-1-86; am. (2) (intro.) and (3) (a), Register, September, 1990, No. 417, eff. 10-1-90; am. (5) (a) and (b), r. and recr. (5) (d) and (6), Register, July, 1993, No. 451, eff. 8-1-93; cr. (5) (e), Register, December, 1995, No. 480, eff. 1-1-96; CR 06-109: am. (5) (d) Register May 2008 No. 629, eff. 6-1-08. NR 440.25(1)(1) Applicability and designation of affected facility. NR 440.25(1)(a)(a) The affected facility to which the provisions of this section apply is each hot mix asphalt facility. For the purpose of this section, a hot mix asphalt facility is comprised only of any combination of the following: dryers; systems for screening, handling, storing and weighing hot aggregate; systems for loading, transferring and storing mineral filler; systems for mixing hot mix asphalt; and the loading, transfer and storage systems associated with emission control systems. NR 440.25(1)(b)(b) Any facility under par. (a) that commences construction or modification after June 11, 1973, is subject to the requirements of this section. NR 440.25(2)(2) Definitions. As used in this section, terms not defined in this subsection have the meanings given in s. NR 440.02. NR 440.25(2)(a)(a) “Hot mix asphalt facility” means any facility, as described in sub. (1), used to manufacture hot mix asphalt by heating and drying aggregate and mixing with asphalt cement. NR 440.25(3)(a)(a) On and after the date on which the performance test required to be conducted by s. NR 440.08 is completed, no owner or operator subject to the provisions of this section may discharge or cause the discharge into the atmosphere from any affected facility any gases which: NR 440.25(3)(a)1.1. Contain particulate matter in excess of 90 mg/dscm (0.039 gr/dscf). NR 440.25(4)(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 440.25(4)(b)(b) The owner or operator shall determine compliance with the particulate matter standards in sub. (3) as follows: NR 440.25(4)(b)1.1. Method 5 shall be used to determine the particulate matter concentration. The sampling time and sample volume for each run shall be at least 60 minutes and 0.90 dscm (31.8 dscf). NR 440.25 HistoryHistory: Cr. Register, January, 1984, No. 337, eff. 2-1-84; am. (1) (a), (2) (intro.) and (a), (3) (a) 1., Register, September, 1990, No. 417, eff. 10-1-90; r. and recr. (4), Register, July, 1993, No. 451, eff. 8-1-93. NR 440.26(1)(1) Applicability, designation of affected facility, and reconstruction. NR 440.26(1)(a)(a) The provisions of this section are applicable to the following affected facilities in petroleum refineries: fluid catalytic cracking unit catalyst regenerators, fuel gas combustion devices, and all Claus sulfur recovery plants except Claus plants of 20 long tons per day (LTD) or less. The Claus sulfur recovery plant need not be physically located within the boundaries of a petroleum refinery to be an affected facility, provided it processes gases produced within a petroleum refinery. NR 440.26(1)(b)(b) Any fluid catalytic cracking unit catalyst regenerator or fuel gas combustion device under par. (a) which commences construction or modification after June 11, 1973 or any Claus sulfur recovery plant under par. (a) which commences construction or modification after October 4, 1976, is subject to the requirements of this section except as provided under pars. (c) and (d). NR 440.26(1)(c)(c) Any fluid catalytic cracking unit catalyst regenerator under par. (b) which commences construction or modification on or before January 17, 1984, is exempted from sub. (5) (b). NR 440.26(1)(d)(d) Any fluid catalytic cracking unit in which a contact material reacts with petroleum derivatives to improve feedstock quality and in which the contact material is regenerated by burning off coke, other deposits, or both and that commences construction or modification on or before January 17, 1984, is exempt from this section. NR 440.26(1)(e)(e) For purposes of this section, under s. NR 440.15, the “fixed capital cost of the new components” includes the fixed capital cost of all depreciable components which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following January 17, 1984. For purposes of this paragraph, “commenced” means that an owner or operator has undertaken a continuous program of component replacement or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of component replacement. NR 440.26(2)(2) Definitions. As used in this section, terms not defined in this subsection have the meanings given in s. NR 440.02. NR 440.26(2)(a)(a) “Claus sulfur recovery plant” means a process unit which recovers sulfur from hydrogen sulfide by a vapor-phase catalytic reaction of sulfur dioxide and hydrogen sulfide. NR 440.26(2)(b)(b) “Coke burn-off” means the coke removed from the surface of the fluid catalytic cracking unit catalyst by combustion in the catalyst regenerator. The rate of coke burn-off is calculated by the formula specified in sub. (7). NR 440.26(2)(c)(c) “Contact material” means any substance formulated to remove metals, sulfur, nitrogen or any other contaminant from petroleum derivatives. NR 440.26(2)(d)(d) “Fluid catalytic cracking unit” means a refinery process unit in which petroleum derivatives are continuously charged; hydrocarbon molecules in the presence of a catalyst suspended in a fluidized bed are fractured into smaller molecules or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing; and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material recovery equipment, and regenerator equipment for controlling air pollutant emissions and for heat recovery. NR 440.26(2)(e)(e) “Fluid catalytic cracking unit catalyst regenerator” means one or more regenerators (multiple regenerators) which comprise that portion of the fluid catalytic cracking unit in which coke burn-off and catalyst or contact material regeneration occurs, and includes the regenerator combustion air blower or blowers. NR 440.26(2)(f)(f) “Fresh feed” means any petroleum derivative feedstock stream charged directly into the riser or reactor of a fluid catalytic cracking unit except for petroleum derivatives recycled within the fluid catalytic cracking unit, fractionator or gas recovery unit. NR 440.26(2)(g)(g) “Fuel gas” means any gas which is generated at a petroleum refinery and which is combusted. Fuel gas also includes natural gas when the natural gas is combined and combusted in any proportion with a gas generated at a refinery. Fuel gas does not include gases generated by catalytic cracking unit catalyst regenerators and fluid coking burners. NR 440.26(2)(h)(h) “Fuel gas combustion device” means any equipment, such as process heaters, boilers and flares used to combust fuel gas, except facilities in which gases are combusted to produce sulfur or sulfuric acid. NR 440.26(2)(i)(i) “Oxidation control system” means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to sulfur dioxide. NR 440.26(2)(j)(j) “Petroleum” means the crude oil removed from the earth and the oils derived from tar sands, shale and coal. NR 440.26(2)(k)(k) “Petroleum refinery” means any facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants or other products through distillation of petroleum or through redistillation, cracking or reforming of unfinished petroleum derivatives. NR 440.26(2)(L)(L) “Process gas” means any gas generated by a petroleum refinery process unit, except fuel gas and process upset gas as defined in this subsection. NR 440.26(2)(m)(m) “Process upset gas” means any gas generated by a petroleum refinery process unit as a result of startup, shutdown, upset or malfunction. NR 440.26(2)(n)(n) “Reduced sulfur compounds” means hydrogen sulfide (H2S), carbonyl sulfide (COS) and carbon disulfide (CS2). NR 440.26(2)(o)(o) “Reduction control system” means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to hydrogen sulfide. NR 440.26(2)(p)(p) “Refinery process unit” means any segment of the petroleum refinery in which a specific processing operation is conducted. NR 440.26(2)(q)(q) “Valid day” means a 24-period in which at least 18 valid hours of data are obtained. A “valid hour” is one in which at least 2 valid data points are obtained. NR 440.26(3)(3) Standard for particulate matter. Each owner or operator of any fluid catalytic cracking unit catalyst regenerator that is subject to the requirements of this section shall comply with the emission limitations set forth in this subsection on and after the date on which the initial performance test, required by s. NR 440.08, is completed, but not later than 60 days after achieving the maximum production rate at which the fluid catalytic cracking unit catalyst regenerator will be operated, or 180 days after initial startup, whichever comes first. NR 440.26(3)(a)(a) No owner or operator subject to the provisions of this section may discharge or cause the discharge into the atmosphere from any fluid catalytic cracking unit catalyst regenerator: NR 440.26(3)(a)1.1. Particulate matter in excess of 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in the catalyst regenerator. NR 440.26(3)(a)2.2. Gases exhibiting greater than 30% opacity, except for one 6-minute average opacity reading in any one hour period. NR 440.26(3)(b)(b) Where the gases discharged by the fluid catalytic cracking unit catalyst regenerator pass through an incinerator or waste heat boiler in which auxiliary or supplemental liquid or solid fossil fuel is burned, particulate matter in excess of that permitted by par. (a) 1. may be emitted to the atmosphere, except that the incremental rate of particulate matter emissions may not exceed 43.0 g/MJ (0.10 lb/million Btu) of heat input attributable to such liquid or solid fossil fuel. NR 440.26(4)(4) Standard for carbon monoxide. Each owner or operator of any fluid catalytic cracking unit catalyst regenerator that is subject to the requirements of this section shall comply with the emission limitations set forth in this subsection on and after the date on which the initial performance test, required by s. NR 440.08, is completed, but not later than 60 days after achieving the maximum production rate at which the fluid catalytic cracking unit catalyst regenerator will be operated, or 180 days after initial startup, whichever comes first. NR 440.26(4)(a)(a) No owner or operator subject to the provisions of this section may discharge or cause the discharge into the atmosphere from any fluid catalytic cracking unit catalyst regenerator any gases that contain carbon monoxide (CO) in excess of 500 ppm by volume (dry basis). NR 440.26(5)(5) Standard for sulfur dioxide. Each owner or operator that is subject to the requirements of this section shall comply with the emission limitations set forth in this subsection on and after the date on which the initial performance test, required by s. NR 440.08, is completed, but not later than 60 days after achieving the maximum production rate at which the affected facility will be operated, or 180 days after initial startup, whichever comes first. NR 440.26(5)(a)(a) No owner or operator subject to the provisions of this section may: NR 440.26(5)(a)1.1. Burn in any fuel gas combustion device any fuel gas that contains hydrogen sulfide (H2S) in excess of 230 mg/dscm (0.10 gr/dscf). The combustion in a flare of process upset gases or fuel gas that is released to the flare as a result of relief valve leakage or other emergency malfunctions is exempt from this paragraph. NR 440.26(5)(a)2.2. Discharge or cause the discharge of any gases into the atmosphere from any Claus sulfur recovery plant containing in excess of: NR 440.26(5)(a)2.a.a. For an oxidation control system or a reduction control system followed by incineration, 250 ppm by volume (dry basis) of sulfur dioxide (SO2) at zero percent excess air. NR 440.26(5)(a)2.b.b. For a reduction control system not followed by incineration, 300 ppm by volume of reduced sulfur compounds and 10 ppm by volume of hydrogen sulfide (H2S), each calculated as ppm SO2 by volume (dry basis) at zero percent excess air. NR 440.26(5)(b)(b) Each owner or operator that is subject to the provisions of this section shall comply with one of the following conditions for each affected fluid catalytic cracking unit catalyst regenerator: NR 440.26(5)(b)1.1. With an add-on control device, reduce sulfur dioxide emissions to the atmosphere by 90% or maintain sulfur dioxide emissions to the atmosphere less than or equal to 50 ppm by volume (ppmv), whichever is less stringent. NR 440.26(5)(b)2.2. Without the use of an add-on control device, maintain sulfur oxides emissions calculated as sulfur dioxide to the atmosphere less than or equal to 9.8 kg/Mg (20 lb/ton) coke burn-off. NR 440.26(5)(b)3.3. Process in the fluid catalytic cracking unit fresh feed that has a total sulfur content no greater than 0.30% by weight. NR 440.26(5)(c)(c) Compliance with par. (b) 1., 2. or 3. is determined daily on a 7-day rolling average basis using the appropriate procedures outlined in sub. (7). NR 440.26(5)(d)(d) A minimum of 22 valid days of data shall be obtained every 30 rolling successive calendar days when complying with par. (b) 1. NR 440.26(6)(a)(a) Continuous monitoring systems shall be installed, calibrated, maintained and operated by the owner or operator subject to the provisions of this section as follows: NR 440.26(6)(a)1.1. For fluid catalytic cracking unit catalyst regenerators subject to sub. (3) (a) 2., an instrument for continuously monitoring and recording the opacity of emission into the atmosphere. The instrument shall be spanned at 60, 70 or 80% opacity. NR 440.26(6)(a)2.2. For fluid catalytic cracking unit catalyst regenerators subject to sub. (4) (a), an instrument for continuously monitoring and recording the concentration by volume (dry basis) of CO emission into the atmosphere, except as provided in subd. 2. b. NR 440.26(6)(a)2.b.b. A CO continuous monitoring system need not be installed if the owner or operator demonstrates that the average CO emission are less than 50 ppm on a dry basis and also files a written request for exemption to the department and receives an exemption. The demonstration shall consist of continuously monitoring CO emissions for 30 days using an instrument that shall meet the requirements of Performance Specification 4 of Appendix B of 40 CFR part 60, incorporated by reference in s. NR 440.17. The span value shall be 100 ppm CO instead of 1,000 ppm, and the relative accuracy limit shall be 10% of the average CO emission or 5 ppm CO, whichever is greater. For instruments that are identical to Method 10 of Appendix A of 40 CFR part 60, incorporated by reference in s. NR 440.17, and employ the sample conditioning system of Method 10A of Appendix A, the alternative relative accuracy test procedure in s. 10.1 of Performance Specification 2 of Appendix B may be used in place of the relative accuracy test. NR 440.26(6)(a)3.3. For fuel gas combustion devices subject to sub. (5) (a) 1., an instrument for continuously monitoring and recording the concentration by volume (dry basis, zero percent excess air) of SO2 emissions into the atmosphere, except where an H2S monitor is installed under par. (a) 4. The monitor shall include an oxygen monitor for correcting the data for excess air. NR 440.26(6)(a)3.b.b. The SO2 monitoring level equivalent to the H2S standard under sub. (5) (a) 1. shall be 20 ppm (dry basis, zero percent excess air). NR 440.26(6)(a)3.c.c. The performance evaluations for this SO2 monitor under s. NR 440.13 (3) shall use Performance Specification 2 of 40 CFR part 60, Appendix B, incorporated by reference in s. NR 440.17 (1). Methods 6 or 6C and 3 or 3A of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17 (1), shall be used for conducting the relative accuracy evaluations. Method 6 samples shall be taken at a flow rate of approximately 2 liters/min for at least 30 minutes. The relative accuracy limit shall be 20% or 4 ppm, whichever is greater, and the calibration drift limit shall be 5% of the established span value. NR 440.26(6)(a)3.d.d. Fuel gas combustion devices having a common source of fuel gas may be monitored at only one location, that is, after one of the combustion devices, if monitoring at this location accurately represents the SO2 emission into the atmosphere from each of the combustion devices. NR 440.26(6)(a)4.4. In place of the SO2 monitor in par. (a) 3., an instrument for continuously monitoring and recording the concentration (dry basis) of H2S in fuel gases before being burned in any fuel gas combustion device. NR 440.26(6)(a)4.b.b. Fuel gas combustion devices having a common source of fuel gas may be monitored at only one location, if monitoring at this location accurately represents the concentration of H2S in the fuel gas begin burned. NR 440.26(6)(a)5.5. For Claus sulfur recovery plants with oxidation control systems or reduction control systems followed by incineration subject to sub. (5) (a) 2. a., an instrument for continuously monitoring and recording the concentration (dry basis, zero percent excess air) of SO2 emissions into the atmosphere. The monitor shall include an oxygen monitor for correcting the data for excess air. NR 440.26(6)(a)6.6. For Claus sulfur recovery plants with reduction control systems not followed by incineration subject to sub. (5) (a) 2. b., an instrument for continuously monitoring and recording the concentration of reduced sulfur and O2 emissions into the atmosphere. The reduced sulfur emission shall be calculated as SO2 (dry basis, zero percent excess air). NR 440.26(6)(a)6.b.b. The performance evaluations for this reduced sulfur (and O2) monitor under s. NR 440.13 (3) shall use Performance Specification 5 (and Performance Specification 3 for the O2 analyzer) of 40 CFR part 60, Appendix B, incorporated by reference in s. NR 440.17 (1). Methods 15 or 15A and Method 3 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17 (1), shall be used for conducting the relative accuracy evaluations. If Method 3 yields O2 concentrations below 0.25% during the performance specification test, the O2 concentration may be assumed to be zero and the reduced sulfur CEMS need not include an O2 monitor. NR 440.26(6)(a)7.7. In place of the reduced sulfur monitor under subd. 6., an instrument using an air or O2 dilution and oxidation system to convert the reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry basis, zero percent excess air) of the resultant SO2. The monitor shall include an oxygen monitor for correcting the data for excess oxygen. NR 440.26(6)(a)7.b.b. For reporting purposes, the SO2 exceedance level for this monitor is 250 ppm (dry basis, zero percent excess air). NR 440.26(6)(a)7.c.c. The performance evaluations for the SO2 (and O2) monitor under s. NR 440.13 (3) shall use Performance Specification 5. Methods 15 or 15A and Method 3 shall be used for conducting the relative accuracy evaluations. NR 440.26(6)(a)8.8. An instrument for continuously monitoring and recording concentrations of sulfur dioxide in the gases at both the inlet and outlet of the sulfur dioxide control device from any fluid catalytic cracking unit catalyst regenerator for which the owner or operator seeks to comply with sub. (5) (b) 1. NR 440.26(6)(a)8.a.a. The span value of the inlet monitor shall be set at 125% of the maximum estimated hourly potential sulfur dioxide emission concentration entering the control device, and the span value of the outlet monitor shall be set at 50% of the maximum estimated hourly potential sulfur dioxide emission concentration entering the control device.
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