Wis. Admin. Code Department of Natural Resources NR 440.26

Current through November 25, 2024

Section NR 440.26 - Petroleum refineries

(1) APPLICABILITY, DESIGNATION OF AFFECTED FACILITY, AND RECONSTRUCTION.

(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.

(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).

(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).

(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.

(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.

(2) DEFINITIONS. As used in this section, terms not defined in this subsection have the meanings given in s. NR 440.02.

(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.

(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).

(c) "Contact material" means any substance formulated to remove metals, sulfur, nitrogen or any other contaminant from petroleum derivatives.

(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.

(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.

(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.

(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.

(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.

(i) "Oxidation control system" means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to sulfur dioxide.

(j) "Petroleum" means the crude oil removed from the earth and the oils derived from tar sands, shale and coal.

(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.

(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.

(m) "Process upset gas" means any gas generated by a petroleum refinery process unit as a result of startup, shutdown, upset or malfunction.

(n) "Reduced sulfur compounds" means hydrogen sulfide (H2S), carbonyl sulfide (COS) and carbon disulfide (CS2).

(o) "Reduction control system" means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to hydrogen sulfide.

(p) "Refinery process unit" means any segment of the petroleum refinery in which a specific processing operation is conducted.

(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.

(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.

(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:

1. Particulate matter in excess of 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in the catalyst regenerator.

2. Gases exhibiting greater than 30% opacity, except for one 6-minute average opacity reading in any one hour period.

(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.

(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.

(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).

(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.

(a) No owner or operator subject to the provisions of this section may:

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.

2. Discharge or cause the discharge of any gases into the atmosphere from any Claus sulfur recovery plant containing in excess of:

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.

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.

(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:

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.

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.

3. Process in the fluid catalytic cracking unit fresh feed that has a total sulfur content no greater than 0.30 % by weight.

(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).

(d) A minimum of 22 valid days of data shall be obtained every 30 rolling successive calendar days when complying with par. (b) 1.

(6) MONITORING OF EMISSIONS AND OPERATIONS.

(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:

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.

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.

a. The span value for this instrument is 1,000 ppm CO.

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.

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.

a. The span values for this monitor are 50 ppm SO2 and 25% oxygen (O2).

b. The SO 2 monitoring level equivalent to the H2S standard under sub. (5) (a) 1. shall be 20 ppm (dry basis, zero percent excess air).

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.

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.

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.

a. The span value for this instrument is 425 mg/dscm H2S.

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.

c. The performance evaluations for this H2S monitor under s. NR 440.13(3) shall use Performance Specification 7 of 40 CFR part 60, Appendix B, incorporated by reference in s. NR 440.17(1). Method 11, 15, 15A or 16 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.

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.

a. The span values for this monitor are 500 ppm SO2 and 25% O2.

b. The performance evaluations for the 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.

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).

a. The span values for this monitor are 450 ppm reduced sulfur and 25% O2.

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.

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.

a. The span values for this monitor are 375 ppm SO2 and 25% O2.

b. For reporting purposes, the SO2 exceedance level for this monitor is 250 ppm (dry basis, zero percent excess air).

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.

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.

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.

b. The performance evaluations for these sulfur dioxide monitors 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.

9. An instrument for continuously monitoring and recording concentrations of sulfur dioxide in the gases discharged into the atmosphere from any fluid catalytic cracking unit catalyst regenerator for which the owner or operator seeks to comply specifically with the 50 ppmv emission limit under sub. (5) (b) 1.

a. The span value of the monitor shall be set at 50% of the maximum hourly potential sulfur dioxide emission concentration of the control device.

b. The performance evaluation for this sulfur dioxide 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.

10. An instrument for continuously monitoring and recording concentrations of oxygen (O2) in the gases at both the inlet and outlet of the sulfur dioxide control device (or the outlet only if specifically complying with the 50 ppmv standard) from any fluid catalytic cracking unit catalyst regenerator for which the owner or operator has elected to comply with sub. (5) (b) 1. The span of the continuous monitoring system shall be set at 10%.

11. The continuous monitoring systems under par. (a) 8., 9. and 10. are operated and data recorded during all periods of operation of the affected facility including periods of startup, shutdown or malfunction, except for continuous monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments.

12. The owner or operator shall use the following procedures to evaluate the continuous monitoring systems under subds. 8., 9. and 10.:

a. Method 3 or 3A and Method 6 or 6C of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), for the relative accuracy evaluations under the s. NR 440.13(5) performance evaluation.

b. Procedure 1 of 40 CFR part 60, Appendix F, incorporated by reference in s. NR 440.17(1), including quarterly accuracy determinations and daily calibration drift tests.

13. When seeking to comply with sub. (5) (b) 1., when emission data are not obtained because of continuous monitoring system breakdowns, repairs, calibration checks and zero and span adjustments, emission data will be obtained by using one of the following methods to provide emission data for a minimum of 18 hours per day in at least 22 out of 30 following successive calendar days:

a. The test methods as described in 40 CFR 60.106(k);

b. A spare continuous monitoring system; or

c. Other monitoring systems as approved by the administrator.

(c) The average coke burn-off rate (Mg (tons) per hour) and hours of operation shall be recorded daily for any fluid catalytic cracking unit catalyst regenerator subject to sub. (3), (4) or (5) (b) 2.

(d) For any fluid catalytic cracking unit catalyst regenerator under sub. (3) that uses an incinerator-waste heat boiler to combust the exhaust gases from the catalyst regenerator, the owner or operator shall record daily the rate of combustion of liquid or solid fossil-fuels and the hours of operation during which liquid or solid fossil-fuels are combusted in the incinerator-waste heater boiler.

(e) For the purpose of reports under s. NR 440.07(3), periods of excess emissions that shall be determined and reported are defined as follows:

Note: All averages, except for opacity, shall be determined as the arithmetic average of the applicable 1-hour averages, e.g., the rolling 3-hour average shall be determined as the arithmetic average of 3 contiguous 1-hour averages.

1. Opacity. All 1-hour periods that contain 2 or more 6-minute periods during which the average opacity as measured by the continuous monitoring system under par. (a) 1. exceeds 30%.

2. Carbon monoxide. All 1-hour periods during which the average CO concentration as measured by the CO continuous monitoring system under par. (a) 2. exceeds 500 ppm.

3. Sulfur dioxide from fuel gas combustion.

a. All rolling 3-hour periods during which the average concentration of SO2 as measured by the SO2 continuous monitoring system under par. (a) 3. exceeds 20 ppm (dry basis, zero percent excess air); or

b. All rolling 3-hour periods during which the average concentration of H2S as measured by the H2S continuous monitoring system under par. (a) 4. exceeds 230 mg/dscm (0.10 gr/dscf).

4. Sulfur dioxide from Claus sulfur recovery plants.

a. All 12-hour periods during which the average concentration of SO2 as measured by the SO2 continuous monitoring system under par. (a) 5. exceeds 250 ppm (dry basis, zero percent excess air); or

b. All 12-hour periods during which the average concentration of reduced sulfur (as SO2) as measured by the reduced sulfur continuous monitoring system under par. (a) 6. exceeds 300 ppm; or

c. All 12-hour periods during which the average concentration of SO2 as measured by the SO2 continuous monitoring system under par. (a) 7. exceeds 250 ppm (dry basis, zero percent excess air).

(7) TEST METHODS AND PROCEDURES.

(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).

(b)

1. The emission rate (E) of PM shall be computed for each run using the following equation:

See PDF for diagram

where:

E is the emission rate of PM, kg/Mg (lb/ton) of coke burn-off

cs is the concentration of PM, g/dscm (gr/dscf)

Qsd is the volumetric flow rate of exhaust gas, dscm/hr (dscf/hr)

Rc is the coke burn-off rate, Mg/hr (ton/hr) coke

K is a conversion factor, 1,000 g/kg (7000 gr/lb)

2. Method 5B or 5F shall be used to determine particulate matter emissions and associated moisture content from affected facilities without wet FGD systems; only Method 5B shall be used after wet FGD systems. The sampling time for each run shall be at least 60 minutes and the sampling time for each run shall be at least 0.015 dscm/min (0.53 dscf/min) except that shorter sampling times may be approved by the department when process variables or other factors preclude sampling for at least 60 minutes.

3. The coke burn-off rate (Rc) shall be computed for each run using the following equation:

See PDF for diagram

where:

Rc is the coke burn-off rate, Mg/hr (ton/hr)

Qr is the volumetric flow rate of exhaust gas from catalyst regenerator before entering the emission control system, dscm/min (dscf/min)

Qa is the volumetric flow rate of air to FCCU regenerator, as determined from the fluid catalytic cracking unit control room instrumentation, dscm/min (dscf/min)

%CO2 is the carbon dioxide concentration, percent by volume (dry basis)

%CO is the carbon monoxide concentration, percent by volume (dry basis)

%O2 is the oxygen concentration, percent by volume (dry basis)

K1 is the material balance and conversion factor, 2.982 x 10-4 (Mg-min)/hr-dscm-%) [9.31 x 10-6 (ton-min)/(hr-dscf-%)]

K2 is the material balance and conversion factor, 2.088 x 10-3 (Mg-min)/(hr-dscm-%) [6.52 x 10-5 (ton-min)/(hr-dscf-%)]

K3 is the material balance and conversion factor, 9.94 x 10-5 (Mg-min)/(hr-dscm-%) [3.1 x 10-6 (ton-min)/(hr-dscf-%)]

a. Method 2 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), shall be used to determine the volumetric flow rate (Qr).

b. The emission correction factor, integrated sampling and analysis procedure of Method 3B of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), shall be used to determine CO2, CO and O2 concentrations.

4. Method 9 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), and the procedures of s. NR 440.11 shall be used to determine opacity.

(c) If auxiliary liquid or solid fossil fuels are burned in an incinerator-waste heat boiler, the owner or operator shall determine the emission rate of PM permitted in sub. (3) (b) as follows:

1. The allowable emission rate (Es) of PM shall be computed for each run using the following equation:

See PDF for diagram

where:

Es is the emission rate of PM allowed, kg/Mg (lb/ton) of coke burn-off in catalyst regenerator

F is the emission standard, 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in catalyst regenerator

A is the allowable incremental rate of PM emission, 7.5 x 10-4 kg/million J (0.10 lb/million Btu)

H is the heat input rate from solid or liquid fossil fuel, million J/hr (million Btu/hr)

Rc is the coke burn-off rate, Mg coke/hr (ton coke/hr)

2. Procedures subject to the approval of the department shall be used to determine the heat input rate.

3. The procedure in par. (b) 3. shall be used to determine the coke burn- off rate (Rc).

(d) The owner or operator shall determine compliance with the CO standard in sub. (4) (a) by using the integrated sampling technique of Method 10 to determine the CO concentration (dry basis). The sampling time for each run shall be 60 minutes.

(e)

1. The owner or operator shall determine compliance with the H2S standard in sub. (5) (a) 1. as follows: Method 11, 15, 15A or 16 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), shall be used to determine the H2S concentration. The gases entering the sampling train should be at about atmospheric pressure. If the pressure in the refinery fuel gas lines is relatively high, a flow control valve may be used to reduce the pressure. If the line pressure is high enough to operate the sampling train without a vacuum pump, the pump may be eliminated from the sampling train. The sample shall be drawn from a point near the centroid of the fuel gas line.

a. For Method 11, the sampling time and sample volume shall be at least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal sampling time shall be taken at about 1-hour intervals. The arithmetic average of these 2 samples shall constitute a run.

Note: For most fuel gas, sampling time exceeding 20 minutes may result in depletion of the collection solution, although fuel gases containing low concentrations of H2S may necessitate sampling for longer periods of time.

b. For Method 15 or 16, at least 3 injects over a 1-hour period shall constitute a run.

c. For Method 15A, a 1-hour sample shall constitute a run.

2. Where emissions are monitored by sub. (6) (a) 3., compliance with sub. (6) (a) 1. shall be determined using Method 6 or 6C and Method 3 or 3A of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1). A 1-hour sample shall constitute a run. Method 6 samples shall be taken at a rate of approximately 2 liters/min. The ppm correction factor (Method 6) and the sampling location in par. (f) 1. apply. Method 4 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), shall be used to determine the moisture content of the gases. The sampling point for Method 4 shall be adjacent to the sampling point for Method 6 or 6C.

(f) The owner or operator shall determine compliance with the SO2 and the H2S and reduced sulfur standards in sub. (5) (a) 2. as follows:

1. Method 6 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), shall be used to determine the SO2 concentration. The concentration in mg/dscm obtained by Method 6 or 6C is multiplied by 0.3754 to obtain the concentration in ppm. The sampling point in the duct shall be the centroid of the cross section if the cross-sectional area is less than 5.00 m2 (53.8 ft2) or at a point no closer to the walls than 1.00 m (39.4 in.) if the cross-sectional area is 5.00 m2 or more and the centroid is more than 1 m from the wall. The sampling time and sample volume shall be at least 10 minutes and 0.010 dscm (0.35 dscf) for each sample. Eight samples of equal sampling times shall be taken at about 30-minute intervals. The arithmetic average of these 8 samples shall constitute a run. For Method 6C, a run shall consist of the arithmetic average of 4 1-hour samples. Method 4 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), shall be used to determine the moisture content of the gases. The sampling point for Method 4 shall be adjacent to the sampling point for Method 6 or 6C. The sampling time for each sample shall be equal to the time it takes for 2 Method 6 samples. The moisture content from this sample shall be used to correct the corresponding Method 6 samples for moisture. For documenting the oxidation efficiency of the control device for reduced sulfur compounds, Method 15 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), shall be used following the procedures of subd. 2.

2. Method 15 shall be used to determine the reduced sulfur and H2S concentrations. Each run shall consist of 16 samples taken over a minimum of 3 hours. The sampling point shall be the same as the described for Method 6 in subd. 1. To ensure minimum residence time for the sample inside the sample lines, the sampling rate shall be at least 3.0 lpm (0.10 cfm). The SO2 equivalent for each run shall be calculated after being corrected for moisture and oxygen as the arithmetic average of the SO2 equivalent for each sample during the run. Method 4 shall be used to determine the moisture content of the gases as in subd. 1. The sampling time for each sample shall be equal to the time it takes for 4 Method 15 samples.

3. The oxygen concentration used to correct the emission rate for excess air shall be obtained by the integrated sampling and analysis procedure of Method 3 or 3A of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1). The samples shall be taken simultaneously with the SO2 reduced sulfur and H2S, or moisture samples. The SO2, reduced sulfur and H2S samples shall be corrected to zero percent excess air using the equation in par. (h) 6.

(g) Each performance test conducted for the purpose of determining compliance under sub. (5) (b) shall consist of all testing performed over a 7-day period using Method 6 or 6C and Method 3 or 3A of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1). To determine compliance, the arithmetic mean of the results of all the tests shall be compared with the applicable standard.

(h) For the purpose of determining compliance with sub. (5) (b) 1., the following calculation procedures shall be used:

1. Calculate each 1-hour average concentration (dry, zero percent oxygen, ppmv) of sulfur dioxide at both the inlet and the outlet to the add-on control device as specified in s. NR 440.13(8). These calculations are made using the emission data collected under sub. (6) (a).

2. Calculate a 7-day average (arithmetic mean) concentration of sulfur dioxide for the inlet and for the outlet to the add-on control device using all of the 1-hour average concentration values obtained during 7 successive 24-hour periods.

3. Calculate the 7-day average percent reduction using the following equation:

See PDF for diagram

100 is the conversion factor, decimal to percent

4. Outlet concentrations of sulfur dioxide from the add-on control device for compliance with the 50 ppmv standard, reported on a dry, O2-free basis, shall be calculated using the procedures outlined in subds. 1. and 2., but for the outlet monitor only.

5. If supplemental sampling data are used for determining the 7-day averages under this paragraph and the data are not hourly averages, then the value obtained for each supplemental sample shall be assumed to represent the hourly average for each hour over which the sample was obtained.

6. For the purpose of adjusting pollutant concentrations to zero percent oxygen, the following equation shall be used:

Cadj = Cmeas[20.9c/(20.9 - %O2)]

where:

Cadj is the pollutant concentration adjusted to zero percent oxygen, ppm or g/dscm

Cmeas is the pollutant concentration measured on a dry basis, ppm or g/dscm

20.9c is the 20.9% oxygen-0.0% oxygen (defined oxygen correction basis), percent

20.9 is the oxygen concentration in air, percent

%O2 is the oxygen concentration measured on a dry basis, percent

(i) For the purpose of determining compliance with sub. (5) (b) 2., the following reference methods from 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17, and calculation procedures shall be used except as provided in subd. 12.:

1. One 3-hour test shall be performed each day.

2. For gases released to the atmosphere from the fluid catalytic cracking unit catalyst regenerator:

a. Method 8 as modified in subd. 3. for moisture content and for the concentration of sulfur oxides calculated as sulfur dioxide.

b. Method 1 for sample and velocity traverses.

c. Method 2 calculation procedures, data obtained from Methods 3 and 8, for velocity and volumetric flow rate.

d. Method 3 for gas analysis.

3. Method 8 shall be modified by the insertion of a heated glass fiber filter between the probe and first impinger. The probe liner and glass fiber filter temperature shall be maintained above 160°C (320°F). The isopropanol impinger shall be eliminated. Sample recovery procedures described in Method 8 for container No. 1 shall be eliminated. The heated glass fiber filter also shall be excluded; however, rinsing of all connecting glassware after the heated glass fiber filter shall be retained and included in container No. 2. Sampled volume shall be at least 1 dscm.

4. For Method 3, the integrated sampling technique shall be used.

5. Sampling time for each run shall be at least 3 hours.

6. All testing shall be performed at the same location. Where the gases discharged by the fluid catalytic cracking unit catalyst regenerator pass through an incinerator-waste heat boiler in which auxiliary or supplemental gaseous, liquid or solid fossil fuel is burned, testing shall be conducted at a point between the regenerator outlet and the incinerator-waste heat boiler. An alternative sampling location after the waste heat boiler may be used if alternative coke burn-off rate equations, and, if requested, auxiliary/supplemental fuel SOx credits, have been submitted to and approved by the department prior to sampling.

7. Coke burn-off rate shall be determined using the procedures specified under par. (b) 3., unless subd. 6. applies.

8. Calculate the concentration of sulfur oxides as sulfur dioxide using equation 8-3 in Section 6.5 of Method 8 to calculate and report the total concentration of sulfur oxides as sulfur dioxide (C_SOx).

9. Sulfur oxides emission rate calculated as sulfur dioxide shall be determined for each test run by the following equation:

See PDF for diagram

11. Calculate the 7-day average sulfur oxides emission rate as sulfur dioxide per Mg (ton) of coke burn-off by dividing the sum of the individual daily rates by the number of daily rates summed.

12. An owner or operator may, upon approval by the administrator, use an alternative method for determining compliance with sub. (5) (b) 2., as provided in s. NR 440.08(2). Any requests for approval shall include data to demonstrate to the administrator that the alternative method would produce results adequate for the determination of compliance.

(j) For the purpose of determining compliance with sub. (5) (b) 3., the following analytical methods and calculation procedures shall be used:

1. One fresh feed sample shall be collected once per 8-hour period.

2. Fresh feed samples shall be analyzed separately by using any one of the following applicable analytical test methods: ASTM D129-00, ASTM D1552-01, ASTM D2622-98 or ASTM D1266-98. These methods are incorporated by reference in s. NR 440.17(2) (a) 8., 20., 34. and 18., respectively. The applicable range of some of these ASTM methods is not adequate to measure the levels of sulfur in some fresh feed samples. Dilution of samples prior to analysis with verification of the dilution ratio is acceptable upon prior approval of the department.

3. If a fresh feed sample cannot be collected at a single location, then the fresh feed sulfur content shall be determined as follows:

a. Individual samples shall be collected once per 8-hour period for each separate fresh feed stream charged directly into the riser or reactor of the fluid catalytic cracking unit. For each sample location the fresh feed volumetric flow rate at the time of collecting the fresh feed sample shall be measured and recorded. The same method for measuring volumetric flow rate shall be used at all locations.

b. Each fresh feed sample shall be analyzed separately using the methods specified under subd. 2.

c. Fresh feed sulfur content shall be calculated for each 8-hour period using the following equation:

See PDF for diagram

where:

Sf is the fresh feed sulfur content expressed in percent by weight of fresh feed

n is the number of separate fresh feed streams charged directly to the riser or reactor of the fluid catalytic cracking unit

Qf is the total volumetric flow rate of fresh feed charged to the fluid catalytic cracking unit

Si is the fresh feed sulfur content expressed in percent by weight of fresh feed for the "ith" sampling location

Qi is the volumetric flow rate of fresh feed stream for the "ith" sampling location

4. Calculate a 7-day average (arithmetic mean) sulfur content of the fresh feed using all of the fresh feed sulfur content values obtained during 7 successive 24-hour periods.

(8) REPORTING AND RECORDKEEPING REQUIREMENTS.

(a) Each owner or operator subject to sub. (5) (b) shall notify the department of the specific provisions of sub. (5) (b) with which the owner or operator elects to comply. Notification shall be submitted with the notification of initial startup required by s. NR 440.07(1) (c). If an owner or operator elects at a later date to comply with an alternative provision of sub. (5) (b), then the department shall be notified by the owner or operator in the report described in par. (c).

(b) Each owner or operator subject to sub. (5) (b) shall record and maintain the following information:

1. If complying with sub. (5) (b) 1.:

a. All data and calibrations from continuous monitoring systems located at the inlet and outlet to the control device, including the results of the daily drift tests and quarterly accuracy assessments required under Appendix F, Procedure 1 of 40 CFR part 60, incorporated by reference in s. NR 440.17;

b. Measurements obtained by supplemental sampling required under sub. (6) (a) 13. and 40 CFR 60.106(k) for meeting minimum data requirements; and

c. The written procedures for the quality control program required by Appendix F, Procedure 1 of 40 CFR part 60, incorporated by reference in s. NR 440.17.

2. If complying with sub. (5) (b) 2., measurements obtained in the daily Method 8 testing, or those obtained by alternative measurement methods, if sub. (7) (i) 12. applies.

3. If complying with sub. (5) (b) 3., data obtained from the daily feed sulfur tests.

4. Each 7-day rolling average compliance determination.

(c) Each owner or operator subject to sub. (5) (b) shall submit a report except as provided by par. (d). The following information shall be contained in the report:

1. Any 7-day period during which:

a. The average percent reduction and average concentration of sulfur dioxide on a dry, O2-free basis in the gases discharged to the atmosphere from any fluid cracking unit catalyst regenerator for which the owner or operator seeks to comply with sub. (5) (b) 1. is below 90% and above 50 ppmv, as measured by the continuous monitoring system prescribed under sub. (6) (a) 8., or above 50 ppmv, as measured by the outlet continuous monitoring system prescribed under sub. (6) (a) 9. The average percent reduction and average sulfur dioxide concentration shall be determined using the procedures specified under sub. (7) (h);

b. The average emission rate of sulfur dioxide in the gases discharged to the atmosphere from any fluid catalytic cracking unit catalyst regenerator for which the owner or operator seeks to comply with sub. (5) (b) 2. exceeds 9.8 kg SOx per 1,000 kg coke burn-off, as measured by the daily testing prescribed under sub. (7) (i). The average emission rate shall be determined using the procedures specified under sub. (7) (i); and

c. The average sulfur content of the fresh feed for which the owner or operator seeks to comply with sub. (5) (b) 3. exceeds 0.30% by weight. The fresh feed sulfur content, a 7-day rolling average, shall be determined using the procedures specified under sub. (7) (j).

2. Any 30-day period in which the minimum data requirements specified in sub. (5) (d) are not obtained.

3. For each 7-day period during which an exceedance has occurred as defined in par. (c) 1. a. to c. and 2.:

a. The date that the exceedance occurred;

b. An explanation of the exceedance;

c. Whether the exceedance was concurrent with a startup, shutdown or malfunction of the fluid catalytic cracking unit or control system; and

d. A description of the corrective action taken, if any.

4. If subject to sub. (5) (b) 1.:

a. The dates for which and brief explanations as to why fewer than 18 valid hours of data were obtained for the inlet continuous monitoring system;

b. The dates for which and brief explanations as to why fewer than 18 valid hours of data were obtained for the outlet continuous monitoring system;

c. Identification of times when hourly averages have been obtained based on manual sampling methods;

d. Identification of the times when the pollutant concentration exceeded the full span of the continuous monitoring system;

e. Description of any modifications to the continuous monitoring system that 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; and

f. Results of daily 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.

5. If subject to sub. (5) (b) 2., for each day in which a Method 8 sample result required by sub. (7) (i) was not obtained, the date for which and brief explanation as to why a Method 8 sample result was not obtained, for approval by the department.

6. If subject to sub. (5) (b) 3., for each 8-hour period in which a feed sulfur measurement required by sub. (7) (j) was not obtained, the date for which and brief explanation as to why a feed sulfur measurement was not obtained, for approval by the department.

(d) For any periods for which sulfur dioxide or 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 which could affect the ability of the system to meet the applicable emission limit. Operations of the control system and affected facility during periods of data unavailability shall be compared with operation of the control system and affected facility before and following the period of data unavailability.

(e) The owner or operator of an affected facility shall submit the reports required under this subsection 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.

(f) The owner or operator of the affected facility shall submit a signed statement certifying the accuracy and completeness of the information contained in the report.

(9) PERFORMANCE TEST AND COMPLIANCE PROVISIONS.

(a) Section NR 440.08(4) shall apply to the initial performance test specified under par. (c), but not to the daily performance tests required thereafter as specified in par. (d). Section NR 440.08(6) does not apply when determining compliance with the standards specified under sub. (5) (d). Section NR 440.08(6) does not apply when determining compliance with the standards specified under sub. (5) (b). Performance tests conducted for the purpose of determining compliance under sub. (5) (b) shall be conducted according to the applicable procedures specified under sub. (7).

(b) Owners or operators who seek to comply with sub. (5) (b) 3. shall meet that standard at all times, including periods of startup, shutdown and malfunctions.

(c) The initial performance test shall consist of the initial 7-day average calculated for compliance with sub. (5) (b) 1., 2. or 3.

(d) After conducting the initial performance test prescribed under s. NR 440.08, the owner or operator of a fluid catalytic cracking unit catalyst regenerator subject to sub. (5) (b) shall conduct a performance test for each successive 24-hour period thereafter. The daily performance tests shall be conducted according to the appropriate procedures specified under sub. (7). In the event that a sample collected under sub. (7) (i) or (j) is accidentally lost or conditions occur in which one of the samples is discontinued because of forced shutdown, failure of an irreplaceable portion of the sample train, extreme meteorological conditions or other circumstances beyond the owner or operators' control, compliance may be determined using available data for the 7-day period.

(e) Each owner or operator subject to sub. (5) (b) who has demonstrated compliance with one of the provisions of sub. (5) (b) but at a later date seeks to comply with another of the provisions of sub. (5) (b) shall begin conducting daily performance tests as specified under par. (d) immediately upon electing to become subject to one of the other provisions of sub. (5) (b). The owner or operator shall furnish the department with a written notification of the change in the semiannual report required by sub. (8) (e).

Wis. Admin. Code Department of Natural Resources NR 440.26

Cr. Register, January, 1984, No. 337, eff. 2-1-84; am. (2) (intro.), (3) (a) 1., (6) (a) 2., (7) (a) 1. a. and 2., (d) (intro.) and 2., Register, September, 1990, No. 417, eff. 10-1-90; am. (1) (b), (6) (c) and (d), cr. (1) (c) to (e), (2) (c) to (f) and (q), (5) (b) to (d), (8) and (9), renum. (2) (c) to (L) to be (2) (g) to (p), r. and recr. (3) (a) (intro.), (4) to (6) (a), (e) and (7), Register, July, 1993, No. 451, eff. 8-1-93; am. (3) (a) (intro.), (4) (a), (5) (a) (intro.), December, 1995, No. 480, eff. 1-1-96; corrections in (6) and (8) made under s. 13.93(2m) (b) 7, Register, November, 1999, No. 527; CR 06-109: am. (3) (a) 1., (5) (b) 1. and 2., (6) (a) 3. a. and c., 4. c., 5. a. and b., 6. a. and b. and 7. a., (c) and (d), (7) (b) 2., 3. a. and b. and 4., (f) 1. and 3., (g) and (i) 2. a., b. and c., 10. and 11., (j) 2., (8) (a), (c) (intro.) and 5. and 6. and (9) (e), renum. (6) (a) 8., 9. and 12. and (7) (e) to be (6) (a) 8. (intro.), 9. (intro.) and 12. (intro.) and (7) (e) 1. (intro.) and am., cr. (6) (a) 8. a. and b., 9. a. and b. and 12. a. and b., (7) (e) 1. a., b. and c. and 2. and (8) (e), r. and recr. (7) (b) 1. and (b) 3. (intro.), (c) 1. and (i) 9., r. (8) (d), renum. (8) (e) to be (8) (d) Register May 2008 No. 629, eff. 6-1-08.