Tenn. Comp. R. & Regs. 1200-03-16-.09 - PETROLEUM REFINERIES

(1) Applicability.
(a) The provisions of this rule are applicable to the following affected facilities in petroleum refineries: fluid catalytic cracking unit catalyst regnerators, 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 subparagraph (a) of this paragraph which commences construction or modification after April 21, 1976 or any Claus sulfur recovery plant under subparagraph (a) of this paragraph which commences construction or modification after November 6, l988 is subject to the requirements of this rule.
(2) Definitions.
(a) "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.
(b) "Petroleum" means the crude oil removed from the earth and the oils derived from tar sands, shale, and coal.
(c) "Process gas" means any gas generated by a petroleum refinery process unit, except fuel gas and process upset gas as defined in this paragraph.
(d) "Fuel gas" means any gas which is generated by a petroleum refinery process unit and which is combusted, including any gaseous mixture of natural gas and fuel gas which is combusted.
(e) "Process upset gas" means any gas generated by a petroleum refinery process unit as a result of start-up, shut-down, upset or malfunction.
(f) "Refinery process unit" means any segment of the petroleum refinery in which a specific processing operation is conducted.
(g) "Fuel gas combustion device" means any equipment, such as process heaters, boilers and flares used to combust fuel gas, but does not include fluid coking unit and fluid catalytic cracking unit incinerator-waste heat boilers or facilities in which gases are combusted to produce sulfur or sulfuric acid.
(h) "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 a formula specified in 1200-3-16-.09(7)(a)(4).
(i) "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.
(j) "Oxidation control system" means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to sulfur dioxide.
(k) "Reduction control system" means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to hydrogen sulfide.
(l) "Reduced sulfur compounds" means hydrogen sulfide (H2S), carbonyl sulfide (COS) and carbon disulfide (CS2).
(m)

(Reserved)

(3) Standards for particulate matter and opacity:
(a) On and after the date on which the performance test required to be conducted by 1200-3-16-.01(5) is completed, no owner or operator subject to the provisions of this rule shall discharge or cause the discharge into the atmosphere from any fluid catalytic cracking unit catalyst regenerator or from any fluid catalytic cracking unit regenerator:
1. Particulate matter in excess of 1.0 kg/1000 kg (1.0 lb/1000 lb) of coke burn-off in the catalyst regenerator.
2. Gases exhibiting thirty (30) percent opacity or greater, except for six (6) minutes in any one (1) hour.
(b) Where gases discharged by the fluid catalytic cracking unit catalyst regenerator pass through an incinerator or waste heat boiler in which auxiliary liquid or solid fossil fuel is burned, particulate matter in excess of that permitted by part (a)1. of this paragraph may be emitted to the atmosphere, except that the incremental rate of particulate emissions shall not exceed 0.043 g/MJ (0.10 lb/million Btu) of heat input attributable to such liquid or solid fossil fuel.
(4) Standard for carbon monoxide. On and after the date on which the performance test required to be conducted by paragraph .01(5) of this chapter is completed, no owner or operator subject to the provisions of this rule shall discharge or cause the discharge into the atmosphere from the fluid catalytic cracking unit catalyst regenerator any gases which contain carbon monoxide in excess of 0.050 per cent by volume.
(5) Standard for sulfur dioxide.
(a) On and after the date on which the performance test required to be conducted by 1200-3-16-.01(5) is completed, no owner or operator subject to the provisions of this paragraph shall:
1. Burn in any fuel gas combustion device any fuel gas which contains hydrogen sulfide in excess of 230 mg/dscm (0.10 gr/dscf), except that the gases resulting from the combustion of fuel gas may be treated to control sulfur dioxide emissions provided the owner or operator demonstrates to the satisfaction of the Technical Secretary that this is as effective in preventing sulfur dioxide emissions to the atmosphere as restricting the H2S concentration in the fuel gas to 230 mg/dscm or less. The combustion in a flare of process upset gas, or fuel gas which is released to the flare as a result of relief valve leakage, is exempt from this subparagraph.
2. Discharge or cause the discharge of any gases into the atmosphere from any Claus sulfur recovery plant containing in excess of:
(i) 0.025 percent by volume of sulfur dioxide at zero percent oxygen on a dry basis if emissions are controlled by a oxidation control system, or a reduction control system followed by incineration, or
(ii) 0.030 percent by volume of reduced sulfur compounds and 0.0010 percent by volume of hydrogen sulfide calculated as sulfur dioxide at zero percent oxygen on a dry basis if emissions are controlled by a reduction control system not followed by incineration.
(b)

(Reserved)

(6) Emission monitoring:
(a) Continuous monitoring systems shall be installed, calibrated, maintained, and operated by the owner or operator as follows:
1. A continuous monitoring system for the measurement of the opacity of emissions discharged into the atmosphere from the fluid catalytic cracking unit catalyst regenerator. The continuous monitoring system shall be spanned at 60, 70, or 80 percent opacity.
2. An instrument for continuously monitoring and recording the concentration of carbon monoxide in gases discharged into the atmosphere from fluid catalytic cracking unit catalyst regenerators. The span value of this continuous monitoring system shall be 1,000 ppm. Installation of carbon monoxide (CO) continuous monitoring systems is not required if the owner or operator files a written request for exemption to the Technical Secretary and demonstrates, by the exemption performance test described below, that the average CO emissions are less than 10 percent of the applicable standard listed in paragraph (4) of this rule. The exemption performance test shall consist of continuously monitoring CO emissions for 30 days using an instrument that meets the requirements of Performance Specification 4 as specified in the Federal Register, Vol. 50, No. 150, August 5, 1985, pp. 31701-31702, except the span value shall be 100 ppm instead of 1,000 ppm, and if required, the relative accuracy limit shall be 10 percent or 5 ppm, whichever is greater.
3. A continuous monitoring system for the measurement of sulfur dioxide in the gases discharged into the atmosphere from the combustion of fuel gases (except where a continuous monitoring system for the measurement of hydrogen sulfide is installed as specified under part (a)4. of this paragraph). The pollutant gas used to prepare calibration gas mixtures under paragraph 2.1, Performance Specifications 2 and Appendix B, Federal Register, Vol. 40, No. 194, and for calibration checks under subparagraph .01(8)(d) of this chapter, shall be sulfur dioxide (SO2). The span shall be set at 100 ppm. For conducting monitoring system performance evaluations under subparagraph .01(8)(c) of this chapter, the method for sulfur dioxide specified in accordance with paragraph .01(5) of this chapter shall be used.
4. An instrument for continuously monitoring and recording concentrations of hydrogen sulfide in fuel gases burned in any fuel gas combustion device if compliance with part 1200-3-16-.09(5)(a) 1. is achieved by removing H2S from the fuel gas before it is burned; fuel gas combustion devices having a common source of fuel may be monitored at one location, if monitoring at this location accurately represents the concentration of H2S in the fuel gas burned. The span of this continuous monitoring system shall be 300 ppm.
5. An instrument for continuously monitoring and recording concentrations of SO2 in the gases discharged into the atmosphere from any Claus sulfur recovery plant if compliance with part 1200-3-16-.09(5)(a) 2. is achieved through the use of an oxidation control system or a reduction control system followed by incineration. The span of this continuous monitoring system shall be set at 500 ppm.
6. An instrument(s) for continuously monitoring and recording the concentration of H2S and reduced sulfur compounds in the gases discharged into the atmosphere from any Claus sulfur recovery plant if compliance with part 1200-3-16-.09(5)(a) 2. is achieved through the use of a reduction control system not followed by incineration. The span(s) of this continuous monitoring system(s) shall be set at 20 ppm for monitoring and recording the concentration of H2S and 600 ppm for monitoring and recording the concentration of reduced sulfur compounds.
(b)

(Reserved)

(c) The average coke burn-off rate (thousands of kilogram/hr) and hours of operation for any fluid catalytic cracking unit catalyst regenerator subject to paragraphs (3) and (4) of this rule shall be recorded daily.
(d) For any fluid catalytic cracking unit catalyst regenerator which is subject to paragraph (3) of this rule and which utilizes 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 (liters/hr or kilograms/hr) and the hours of operation during which liquid or solid fossil fuels are combusted in the incinerator-waste heat boiler.
(e) For the purpose of reports under subparagraph .01(7)(c) of this chapter periods of excess emissions that shall be reported are defined as follows:
1. Opacity. All one-hour periods which contain two or more six-minute periods during which the average opacity as measured by the continuous monitoring system exceeds 30 percent.
2. Carbon monoxide. All hourly periods during which the average carbon monoxide concentration in the gases discharged into the atmosphere from any fluid catalyltic cracking unit catalyst regenerator subject to paragraph 1200-3-16-.09(4) exceeds 0.050 percent by volume.
3. Sulfur dioxide.
(i) Any three-hour period during which the average concentration of H2S in any fuel gas combusted in any fuel gas combustion device subject to part 1200- 3-16-.09(5)(a)1. exceeds 230 mg/dscm (0.10 gr/dscf), if compliance is achieved by removing H2S from the fuel gas before it is burned; or any three-hour period during which the average concentration of SO2 in the gases discharged into the atmosphere from any fuel gas combustion device subject to part 1200-3-16-.09(5)(a) 1. exceeds the level specified in part 1200-3- 16-.09(5)(a) 1., if compliance is achieved by removing SO2 from the combusted fuel gases.
(ii) Any twelve-hour period during which the average concentration of SO2 in the gases discharged into the atmosphere from any Claus sulfur recovery plant subject to part 1200-3-16-.09(5)(a) 2. exceeds 250 ppm at zero percent oxygen on a dry basis if compliance with subparagraph 1200-3-16 - .09(5)(a)2 is achieved through the use of an oxidation control system or a reduction control system followed by incineration; or any twelve-hour period during which the average concentration of H2S, or reduced sulfur compounds in the gases discharged into the atmosphere of any Claus sulfur plant subject to part 1200-3-16 - .09(5)(a)2. exceeds 10 ppm or 300 ppm, respectively, at zero percent oxygen and on a dry basis if compliance is achieved through the use of a reduction control system not followed by incineration.
4. Any six-hour period during which the average emissions (arithmetic average of six contiguous one-hour periods) of sulfur dioxide as measured by a continuous monitoring system exceed the standard under 1200-3-16-.09(5).
(7) Test Methods and Procedures:
(a) For the purpose of determining compliance with 1200-3-16-.09(3)(a) 1, the following reference methods and calculation procedures shall be used:
1. For gases released to the atmosphere from the fluid catalytic cracking unit catalyst regenerator:
(i) Method 5B or 5F as specified in rule 1200-3-16.01(5)(g) is to be used to determine particulate matter emissions and associated moisture content from affected facilities without wet FGD systems; only Method 5B is to be used after wet FGD systems.
(ii) Method 1 for sample and velocity traverses, and
(iii) Method 2 for velocity and volumetric flow rate.
2. For Method 5B or 5F, the sampling time for each run shall be at least 60 minutes and the sampling rate shall be at least 0.015 dscm/min (0.53 dscf/min), except that shorter sampling times may be approved by the Technical Secretary when process variables or other factors preclude sampling for at least 60 minutes.
3. For exhaust gases from the fluid catalytic cracking unit catalyst regenerator prior to the emission control system: the integrated sample techniques of Methods 3. and 4. of subparagraph .01(5)(g) of this chapter for gas analysis and moisture content determination respectively; Method 1 for velocity traverses; and Method 2 for velocity and volumetric flow rate shall be used.
4. Coke burn-off rate shall be determined by the following formula:

Rc = 0.2982 Qre (%CO2+%CO) + 2.088 Qra-0.0994 Qre (%CO + %CO2+%O2) (Metric Units ) 2

or

Rc = 0.0186 Qre (%CO2 + %CO)+0.1303 Qra-0.0062 Qre (%CO + %CO2 + %O2)(English Units ) 2

where:

Rc = coke burn-off rate, kg/hr (English units: lb/hr).

0.2982 = metric units material balance factor divided by 100, kg-min/hr-m3.

.0.0186 = English units material balance factor divided by 100, lb-min/hr-ft3.

Qre = fluid catalytic cracking unit catalyst regenerator exhaust gas flow rate before entering the emission control system, as determined by Method 2., subparagraph .01(5)(g) of this chapter, dscm/min (English units: dscf/min).

%CO2 = percent carbon dioxide by volume, dry basis, as determinedby Method 3., subparagraph .01(5)(g) of this chapter.

%O2 = percent oxygen by volume dry basis, as determined by Method 3., subparagraph .01(5)(g) of this chapter.

2.088 = metric units material balance factor divided by 100, kg-min/hr-m3.

0.1303 = English units material balance factor divided by 100, lb-min/hr-ft3.

Qra = air rate to fluid catalytic cracking unit catalyst regenerator, as determined from fluid catalytic cracking unit control room instrumentation. dscm/min (English units:dscf/min).

0.0094 = metric units material balance factor divided by 100, kg-min/hr-m3.

0.0062 = English units material balance factor divided by 100, lb-min/hr-ft3.

%CO = Percent carbon monoxide by volume, dry basis, as determined by Method 3., subparagraph .01(5)(g) of thischapter.

5. Particulate emissions shall be determined by the following equation:

Re = (60 x 10-6) QrvCs (Metric Units ) or

Re = (8.57 x 10-3) QrvCs (English Units )

where:

Re = particulate emission rate, kg/hr (English units: lb/hr )

60 x 10-6 = Metric units conversion factor, min-kg/hr-mg

8.57 x 10-3 = English units conversion factor, min-lb/hr-gr

Qrv = volumetric flow rate of gases discharged into the atmosphere from the fluid catalytic cracking unit catalyst regenerator following the emission control system, as determined by Method 2, dscm/min. (English units: dscf/min).

Cs = particulate emission concentration discharged into the atmosphere, as determined by Method 5, mg/dscm (English units: gr/dscf).

6. For each run, emissions expressed in kg/1000 kg (English units: lb/1000 lb) of coke burn-off in the catalyst regenerator shall be determined by the following equation:

Rs = 1000 Re/Rc (Metric or English Units ) where:

Rs = Particulate emission rate, kg/1000 kg, (English units: lb/ 1000 lb) of coke burn-off in the fluid catalytic cracking unit catalyst regenerator.

1000 = conversion factor, kg to 1000 kg (English units: lb to 1000 lb).

Re = particulate emission rate, kg/hr. (English units: lb/hr).

Rc = coke burn-off rate, kg/hr (English units: lb/hr).

7. In those instances in which auxiliary liquid or solid fossil fuels are burned in an incinerator-waste heat boiler, the rate of particulate matter emission permitted under subparagraph (3)(b) of this rule must be determined. Auxiliary fuel heat input expressed in millions of cal/hr (English units: Millions of Btu/hr) shall be calculated for each run by fuel flow rate measurement and analysis of the liquid or solid fossil auxiliary fuels. For each run, the rate of particulate emissions permitted under subparagraph (3)(b) of this rule shall be calculated from the following equation:

Click to view Image

where:

Rs = allowable particulate emission rate, kg/1000 kg (English units: lb/1000 lb) of coke burn-off in the fluid catalytic cracking unit catalyst regenerator.

1.0 = emission standard, 1.0 kg/1000 kg (English units: 1.0 lb/1000 lb) of coke burn-off in the fluid catalytic cracking unit catalyst regenerator.

0.18 = metric units maximum allowable incremental rate of particulate emissions, g/million cal.

0.10 = English units maximum allowable incremental rate of particulate emissions, lb/million Btu.

H = heat input from solid or liquid fossil fuel, million cal/hr (English units: million Btu/hr).

Rc = coke burn-off rate, kg/hr (English units: lb/hr).

(b) For the purpose of determining compliance with paragraph (4) of this rule, the integrated sample technique of Method 10 as specified in 1200-3-16-.01(5)(g) 10. shall be used. The sample shall be extracted at a rate proportional to the gas velocity at a sampling point near the centroid of the duct. The sampling time shall not be less than sixty (60) minutes.
(c) For the purpose of determining compliance with part 1200-3-16-.09(5)(a) 1., Method 11 as specified in 1200-3-16-.01(5)(g) 11. shall be used to determine the concentration of H2S and Method 6 as specified in 1200-3-16-.01(5)(g) 6. shall be used to determine the concentration of SO2.
1. If Method 11 is used, the gases sampled shall be introduced into the sampling train at approximately atmospheric pressure. Where refinery fuel gas lines are operating at pressures substantially above atmosphere, this may be accomplished with a flow control valve. 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. The minimum sampling time shall be 10 minutes and the minimum sampling volume 0.01 dscm (0.35 dscf) for each sample. The arithmetic average of two samples of equal sampling time shall constitute one run. Samples shall be taken at approximately 1- hour intervals. For most fuel gases, sample times exceeding 20 minutes may result in depletion of the collecting solution, although fuel gases containing low concentrations of hydrogen sulfide may necessitate sampling for longer periods of time.
2. If Method 6 is used, Method 1 as specified in 1200-3-16-.01(5)(g) 1. shall be used for velocity traverses and Method 2 as specified in 1200-3-16-.01(5)(g) 2. for determining velocity and volumetric flow rate. The sampling site for determining SO2 concentration by Method 6 shall be the same as for determining volumetric flow rate by Method 2. The sampling point in the duct for determining SO2 concentration by Method 6 shall be at the centroid of the cross section if the cross sectional area is less than 5 m2 (54 ft2) or at a point no closer to the walls than 1 m (39 inches) if the cross sectional area is 5 m2 or more and the centroid is more than one meter from the wall. The sample shall be extracted at a rate proportional to the gas velocity at the sampling point. The minimum sampling time shall be 10 minutes and the minimum sampling volume 0.01 dscm (0.35 dscf) for each sample. The arithmetic average of two samples of equal sampling time shall constitute one run. Samples shall be taken at approximately 1- hour intervals.
(d) For the purpose of determining compliance with part 1200-3-16-.09(5)(a) 2, Method 6 shall be used to determine the concentration of SO2 and Method 15 as specified by 1200-3-16-.01(5)(g) 15 shall be used to determine the concentration of H2S and reduced sulfur compounds.

As an alternative, Method 15A as specified by 1200-3-16-.01(5)(g) 15 may be used for determining reduced sulfur compounds.

1. If Method 6 is used, the procedure outlined in subparagraph (c)(2) of this paragraph shall be followed except that each run shall span a minimum of four consecutive hours of continuous sampling. A number of separate samples may be taken for each run, provided the total sampling time of these samples adds up to a minimum of four consecutive hours. Where more than one sample is used, the average SO2 concentration for the run shall be calculated as the time weighted average of the SO2 concentration for each sample according to the formula:

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Where:

CR = SO2 concentration for the run.

N = Number of samples.

Csi = SO2 concentration for sample i.

tsi = Continuous time of sample i.

T = Total continuous sampling time of all N samples.

2. If Method 15 is used, each run shall consist of 16 samples taken over a minimum of 3 hours. If Method 15A is used, each run shall consist of one 3-hour sample or three 1-hour samples. The sampling point shall be at the centroid of the cross-section of the duct if the cross-sectional area is less than 5 m2 (54 ft2) or at a point no closer to the walls than 1 m (39 in.) if the cross-sectional area is 5 m2 or more and the centroid is more than 1 m from the wall. For Method 15, to ensure minimum residence time for the sample inside the sample lines, the sampling rate shall be at least 3 liters/min (0.1 ft3/min). The SO2 equivalent for each run shall be calculated as the arithmetic average of the SO2 equivalent of each sample during the run. Method 4 shall be used to determine the moisture content of the gases when using Method 15. The sampling point for Method 4 shall be adjacent to the sampling point for Method 15. The sample shall be extracted at a rate proportional to the gas velocity at the sampling point. Each run shall span a minimum of 4 consecutive hours of continuous sampling. A number of separate samples may be taken for each run provided the total sampling time of these samples adds up to a minimum of 4 consecutive hours. Where more than one sample is used, the average moisture content for the run shall be calculated as the time weighted average of the moisture content of each sample according to the formula:

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Where:

Bwo = Proportion by volume of water vapor in the gas stream for the run.

N = Number of samples.

Bsi = Proportion by volume of water vapor in the gas stream for the sample i.

tsi = Continuous sampling time for sample i.

T = Total continuous sampling time of all N samples.

Notes

Tenn. Comp. R. & Regs. 1200-03-16-.09
Original rule filed January 10, 1977; effective February 9, 1977. Amendment filed May 17, 1978; effective June 16, 1978. Amendment filed June 3, 1981; effective July 20, 1981. Amendment filed September 4, 1981; effective October 19, 1981. Amendment filed September 21, 1988; effective November 6, 1988.

Authority: T.C.A. ยงยง 68-25-105 and 4-5-202.

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