NR 440.24(5)(d)
(d) Alternatively, a source that processes elemental sulfur or an area that contains elemental sulfur and uses air to supply oxygen may use the following continuous emission monitoring approach and calculation procedures in determining SO
2 emission rates in terms of the standard. This procedure is not required but is an alternative that would alleviate problems encountered in the measurement of gas velocities or production rate. Continuous emission monitoring systems for measuring SO
2, O
2 and CO
2, if required, shall be installed, calibrated, maintained and operated by the owner or operator and subjected to the certification procedures in Performance Specifications 2 and 3 in Appendix B,
40 CFR part 60, incorporated by reference in
s. NR 440.17 (1). The calibration procedure and span value for the SO
2 monitor shall be as specified in
par. (b). The span value for CO
2, if required, shall be 10% and for O
2 shall be 20.9% (air). A conversion factor based on process rate data is not necessary. Calculate the SO
2 emission rate as follows: -
See PDF for diagram 
where:
Es is the SO2 emission rate in kg/metric ton (lb/ton) of 100% of H2SO4 produced
Cs is the concentration of SO2, kg/dscm (lb/dscf) (see the table in the note following this paragraph)
S is the acid production rate factor, 368 dscm/metric ton (11,800 dscf/ton) of 100% H2SO4 produced
%O2 is the oxygen concentration, percent dry basis
A is the auxiliary fuel factor,
= 0.00 for no fuel
= 0.0226 for methane
= 0.0217 for natural gas
= 0.0196 for propane
= 0.0172 for #2 oil
= 0.0161 for #6 oil
= 0.0148 for coal
= 0.0126 for coke
%CO2 is the carbon dioxide concentration, percent dry basis
NR 440.24 Note
Note:
It is necessary in some cases to convert measured concentration units to other units for these calculations. Use the following table for such conversions:
-
See PDF for table NR 440.24(5)(e)
(e) For the purpose of reports under
s. NR 440.07 (3), periods of excess emissions shall be all 3-hour periods (or the arithmetic average of 3 consecutive 1-hour periods) during which the integrated average sulfur dioxide emissions exceed the applicable standards under
sub. (3).
NR 440.24(6)(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). Acceptable alternative methods and procedures are given in
par. (c).
NR 440.24(6)(b)
(b) The owner or operator shall determine compliance with the SO
2 acid mist, and visible emission standards in
subs. (4) and
(5) as follows:
NR 440.24(6)(b)1.
1. The emission rate (E) of acid mist or SO
2 shall be computed for each run using the following equation:
E = (CQsd)/(PK)
where:
E is the emission rate of acid mist or SO2 kg/metric ton (lb/ton) of 100% H2SO4 produced
C is the concentration of acid mist or SO2, g/dscm (lb/dscf)
Qsd is the volumetric flow rate of the effluent gas, dscm/hr (dscf/hr)
P is the production rate of 100% H2SO4, metric ton/hr (ton/hr)
K is the conversion factor, 1000 g/kg (1.0 lb/lb)
NR 440.24(6)(b)2.
2. Method 8 shall be used to determine the acid mist and SO
2 concentrations (C's) and the volumetric flow rate (Q
sd) of the effluent gas. The moisture content may be considered to be zero. The sampling time and sample volume for each run shall be at least 60 minutes and 1.15 dscm (40.6 dscf).
NR 440.24(6)(b)3.
3. Suitable methods shall be used to determine the production rate (P) of 100% H
2SO
4 for each run. Material balance over the production system shall be used to confirm the production rate.
NR 440.24(6)(c)
(c) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this subsection:
NR 440.24(6)(c)1.
1. If a source processes elemental sulfur or an ore that contains elemental sulfur and uses air to supply oxygen, the following procedure may be used instead of determining the volumetric flow rate and production rate:
NR 440.24(6)(c)1.a.
a. The integrated technique of Method 3 is used to determine the O
2 concentration and, if required, CO
2 concentration.
NR 440.24(6)(c)1.b.
b. The SO
2 or acid mist emission rate is calculated as described in
sub. (5) (d), substituting the acid mist concentration for C
s as appropriate.
NR 440.24 History
History: 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 History
History: 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 (H
2S), carbonyl sulfide (COS) and carbon disulfide (CS
2).
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 (H
2S) 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:
