NR 440.207(2)(a)
(a) “Annual capacity factor" means the ratio between the actual heat input to a steam generating unit from an individual fuel or combination of fuels during a period of 12 consecutive calendar months and the potential heat input to the steam generating unit from all fuels had the steam generating unit been operated for 8,760 hours during that 12-month period at the maximum design heat input capacity. In the case of steam generating units that are rented or leased, the actual heat input shall be determined based on the combined heat input from all operations of the affected facility during a period of 12 consecutive calendar months.
NR 440.207(2)(b)
(b) “Coal" means all solid fuels classified as anthracite, bituminous, subbituminous or lignite by the American Society for Testing and Materials in ASTM D388-77, “Standard Specification for Classification of Coals by Rank", incorporated by reference in
s. NR 440.17; coal refuse; and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent-refined coal, gasified coal and coal-oil mixtures, are included in this definition for the purposes of this section.
NR 440.207(2)(c)
(c) “Coal refuse" means any by-product of coal mining or coal cleaning operations with an ash content greater than 50% (by weight) and a heating value less than 13,900 kilojoules per kilogram (k/kg) (6,000 Btu per pound (Btu/lb)) on a dry basis.
NR 440.207(2)(d)
(d) “Cogeneration steam generating unit" means a steam generating unit that simultaneously produces both electrical (or mechanical) and thermal energy from the same primary energy source.
NR 440.207(2)(e)
(e) “Combined cycle system" means a system in which a separate source, such as a stationary gas turbine, internal combustion engine or kiln, provides exhaust gas to a steam generating unit.
NR 440.207(2)(em)
(em) “Combustion research" means the experimental firing of any fuel or combination of fuels in a steam generating unit for the purpose of conducting research and development of more efficient combustion or more effective prevention or control of air pollutant emissions from combustion, provided that, during these periods of research and development, the heat generated is not used for any purpose other than preheating combustion air for use by that steam generating unit (that is, the heat generated is released to the atmosphere without being used for space heating, process heating, driving pumps, preheating combustion air for other units, generating electricity or any other purpose).
NR 440.207(2)(f)
(f) “Conventional technology" means wet flue gas desulfurization technology, dry flue gas desulfurization technology, atmospheric fluidized bed combustion technology and oil hydrodesulfurization technology.
NR 440.207(2)(g)
(g) “Distillate oil" means fuel oil that complies with the specifications for fuel oil number 1 or 2, as defined by the American Society for Testing and Materials in ASTM D396-98, Standard Specification for Fuel Oils, incorporated by reference in
s. NR 440.17 (2) (a) 13.
NR 440.207(2)(h)
(h) “Dry flue gas desulfurization technology" means a sulfur dioxide (SO
2) control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline reagents used in dry flue gas, desulfurization systems include, but are not limited to, lime and sodium compounds.
NR 440.207(2)(i)
(i) “Duct burner" means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary gas turbine, internal combustion engine, kiln, and other similar devices, to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a steam generating unit.
NR 440.207(2)(j)
(j) “Emerging technology" means any SO
2 control system that is not defined as a conventional technology under this subsection, and for which the owner or operator of the affected facility has received approval from the administrator to operate as an emerging technology under
sub. (9) (a) 4.
NR 440.207(2)(L)
(L) “Fluidized bed combustion technology" means a device wherein fuel is distributed onto a bed, or series of beds, of limestone aggregate, or other sorbent materials, for combustion; and these materials are forced upward in the device by the flow of combustion air and the gaseous products of combustion. Fluidized bed combustion technology includes, but is not limited to, bubbling bed units and circulating bed units.
NR 440.207(2)(m)
(m) “Fuel pretreatment" means a process that removes a portion of the sulfur in a fuel before combustion of the fuel in a steam generating unit.
NR 440.207(2)(n)
(n) “Heat input" means heat derived from combustion of fuel in a steam generating unit and does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust gases from other sources, such as stationary gas turbines, internal combustion engines and kilns.
NR 440.207(2)(o)
(o) “Heat transfer medium" means any material that is used to transfer heat from one point to another point.
NR 440.207(2)(p)
(p) “Maximum design heat input capacity" means the ability of a steam generating unit to combust a stated maximum amount of fuel, or combination of fuels, on a steady state basis as determined by the physical design and characteristics of the steam generating unit.
NR 440.207(2)(q)1.
1. A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane, or
NR 440.207(2)(q)2.
2. Liquified petroleum (LP) gas, as defined by the American Society for Testing and Materials in ASTM D1835-03a, Standard Specification for Liquified Petroleum Gases, incorporated by reference in
s. NR 440.17 (2) (a) 22.
NR 440.207(2)(r)
(r) “Noncontinental area" means the state of Hawaii, the Virgin Islands, Guam, American Samoa, the commonwealth of Puerto Rico or the Northern Mariana Islands.
NR 440.207(2)(s)
(s) “Oil" means crude oil or petroleum, or a liquid fuel derived from crude oil or petroleum, including distillate oil and residual oil.
NR 440.207(2)(t)
(t) “Potential sulfur dioxide emission rate" means the theoretical SO
2 emissions, nanograms per joule (ng/J) or pounds per million Btu (lb/million Btu) heat input, that would result from combusting fuel in an uncleansed state and without using emission control systems.
NR 440.207(2)(u)
(u) “Process heater" means a device that is primarily used to heat a material to initiate or promote a chemical reaction to which the material participates as a reactant or catalyst.
NR 440.207(2)(v)
(v) “Residual oil" means crude oil, fuel oil that does not comply with the specifications under the definition of distillate oil, and all fuel oil numbers 4, 5 and 6, as defined by the American Society for Testing and Materials in ASTM D396-98, Standard Specification for Fuel Oils, incorporated by reference in
s. NR 440.17 (2) (a) 13.
NR 440.207(2)(w)
(w) “Steam generating unit" means a device that combusts any fuel and produces steam or heats water or any other heat transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This term does not include process heaters as defined in this section.
NR 440.207(2)(x)
(x) “Steam generating unit operating day" means a 24-hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time in the steam generating unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period.
NR 440.207(2)(y)
(y) “Wet flue gas desulfurization technology" means an SO
2 control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition includes devices where the liquid material is subsequently converted to another form. Alkaline reagents used in wet flue gas desulfurization systems include, but are not limited to, lime, limestone and sodium compounds.
NR 440.207(2)(z)
(z) “Wet scrubber system" means any emission control device that mixes an aqueous stream or slurry with the exhaust gases from a steam generating unit to control emissions of particulate matter (PM) or SO
2.
NR 440.207(2)(zm)
(zm) “Wood" means wood, wood residue, bark or any derivative fuel or residue thereof, in any form, including but not limited to sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings and processed pellets made from wood or other forest residues.
NR 440.207(3)(a)(a) Except as provided in
pars. (b),
(c) and
(e), on and after the date on which the initial performance test is completed or required to be completed under
s. NR 440.08, whichever date comes first, the owner or operator of an affected facility that combusts only coal may neither:
NR 440.207(3)(a)1.
1. Cause to be discharged into the atmosphere from that affected facility any gases that contain SO
2 in excess of 10% (0.10) of the potential SO
2 emission rate, 90% reduction; nor
NR 440.207(3)(a)2.
2. Cause to be discharged into the atmosphere from that affected facility any gases that contain SO
2 in excess of 520 ng/J (1.2 lb/million Btu) heat input. If coal is combusted with other fuels, the affected facility is subject to the 90% SO
2 reduction requirement specified in this paragraph and the emission limit is determined pursuant to
par. (e) 2.
NR 440.207(3)(b)
(b) Except as provided in
pars. (c) and
(e), on and after the date on which the initial performance test is completed or required to be completed under
s. NR 440.08, whichever date comes first, the owner or operator of an affected facility that:
NR 440.207(3)(b)1.
1. Combusts coal refuse alone in a fluidized bed combustion steam generating unit may neither:
NR 440.207(3)(b)1.a.
a. Cause to be discharged into the atmosphere from that affected facility any gases that contain SO
2 in excess of 20% (0.20) of the potential SO
2 emission rate (80% reduction); nor
NR 440.207(3)(b)1.b.
b. Cause to be discharged into the atmosphere from that affected facility any gases that contain SO
2 in excess of 520 ng/J (1.2 lb/million Btu) heat input. If coal is fired with coal refuse, the affected facility is subject to
par. (a). If oil or any other fuel, except coal, is fired with coal refuse, the affected facility is subject to the 90% SO
2 reduction requirement specified in
par. (a) and the emission limit determined pursuant to
par. (e) 2.
NR 440.207(3)(b)2.
2. Combusts only coal and that uses an emerging technology for the control of SO
2 emissions may neither:
NR 440.207(3)(b)2.a.
a. Cause to be discharged into the atmosphere from that affected facility any gases that contain SO
2 in excess of 50% (0.50) of the potential SO
2 emission rate, 50% reduction; nor
NR 440.207(3)(b)2.b.
b. Cause to be discharged into the atmosphere from that affected facility any gases that contain SO
2 in excess of 260 ng/J (0.60 lb/million Btu) heat input. If coal is combusted with other fuels, the affected facility is subject to the 50% SO
2 reduction requirement specified in this paragraph and the emission limit determined pursuant to
par. (e) 2.
NR 440.207(3)(c)
(c) On and after the date on which the initial performance test is completed or required to be completed under
s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that combusts coal, alone or in combination with any other fuel, and is listed in
subd. 1.,
2.,
3. or
4. may cause to be discharged into the atmosphere from that affected facility any gases that contain SO
2 in excess of the emission limit determined pursuant to
par. (e) 2. Percent reduction requirements are not applicable to affected facilities under this paragraph.
NR 440.207(3)(c)1.
1. Affected facilities that have a heat input of 22 MW (75 million Btu/hr) or less.
NR 440.207(3)(c)2.
2. Affected facilities that have an annual capacity for coal of 55% (0.55) or less and are subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for coal of 55% (0.55) or less.
NR 440.207(3)(c)4.
4. Affected facilities that combust coal in a duct burner as part of a combined cycle system where 30% (0.30) or less of the heat entering the steam generating unit is from combustion of coal in the duct burner and 70% (0.70) or more of the heat entering the steam generating unit is from exhaust gases entering the duct burner.
NR 440.207(3)(d)
(d) On and after the date on which the initial performance test is completed or required to be completed under
s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that combusts oil may cause to be discharged into the atmosphere from that affected facility any gases that contain SO
2 in excess of 215 ng/J (0.50 lb/million Btu) heat input; or, as an alternative, no owner or operator of an affected facility that combusts oil shall combust oil in the affected facility that contains greater than 0.5 weight percent sulfur. The percent reduction requirements are not applicable to affected facilities under this paragraph.
NR 440.207(3)(e)
(e) On and after the date on which the initial performance test is completed or required to be completed under
s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that combusts coal, oil, or coal and oil with any other fuel may cause to be discharged into the atmosphere from that affected facility any gases that contain SO
2 in excess of the following:
NR 440.207(3)(e)1.
1. The percent of potential SO
2 emission rate required under
par. (a) or
(b) 2., as applicable, for any affected facility that:
NR 440.207(3)(e)2.
2. The emission limit determined according to the following formula for any affected facility that combusts coal, oil, or coal and oil with any other fuel:
Es = (KaHa + KbHb + KcH
c)/(Ha + Hb + Hc)
where:
Es is the SO2 emission limit, expressed in ng/J or lb/million Btu heat input
Ka is 520 ng/J (1.2 lb/million Btu)
Kb is 260 ng/J (0.60 lb/million Btu)
Kc is 215 ng/J (0.50 lb/million Btu)
Ha is the heat input from the combustion of coal, except coal combusted in an affected facility subject to par. (b) 2., in joules (J) (million Btu)
Hb is the heat input from the combustion of coal, in an affected facility subject to par. (b) 2., in J (million Btu)
Hc is the heat input from the combustion of oil, in J (million Btu)
NR 440.207(3)(f)
(f) Reduction in the potential SO
2 emission rate through fuel pretreatment is not credited toward the percent reduction requirement under
par. (b) 2. unless:
NR 440.207(3)(f)1.
1. Fuel pretreatment results in a 50% (0.50) or greater reduction in the potential SO
2 emission rate; and
NR 440.207(3)(f)2.
2. Emissions from the pretreated fuel, without either combustion or post-combustion SO
2 control, are equal to or less than the emission limits specified under
par. (b) 2.
NR 440.207(3)(g)
(g) Except as provided in
par. (h), compliance with the percent reduction requirements, fuel oil sulfur limits, and emission limits of this subsection shall be determined on a 30-day rolling average basis.
NR 440.207(3)(h)
(h) For affected facilities listed under
subd. 1.,
2. or
3., compliance with the emission limits or fuel oil sulfur limits under this subsection may be determined based on a certification from the fuel supplier, as described under
sub. (9) (f) 1.,
2. or
3., as applicable.
NR 440.207(3)(h)1.
1. Distillate oil-fired affected facilities with heat input capacities between 2.9 and 29 MW (10 and 100 million Btu/hr).
NR 440.207(3)(h)2.
2. Residual oil-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 million Btu/hr).
NR 440.207(3)(h)3.
3. Coal-fired facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 million Btu/hr).
NR 440.207(3)(i)
(i) The SO
2 emission limits, fuel oil sulfur limits and percent reduction requirements under this subsection apply at all times, including periods of startup, shutdown and malfunction.
NR 440.207(3)(j)
(j) Only the heat input supplied to the affected facility from the combustion of coal and oil is counted under this subsection. No credit is provided for the heat input to the affected facility from wood or other fuels or for heat derived from exhaust gases from other sources, such as stationary gas turbines, internal combustion engines and kilns.
NR 440.207(4)(a)(a) On and after the date on which the initial performance test is completed or required to be completed under
s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that combusts coal or combusts mixtures of coal with other fuels and has a heat input capacity of 8.7 MW (30 million Btu/hr) or greater, may cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits:
NR 440.207(4)(a)1.
1. 22 ng/J (0.051 lb/million Btu) heat input if the affected facility combusts only coal, or combusts coal with other fuels and has an annual capacity factor for the other fuels of 10% (0.10) or less.
NR 440.207(4)(a)2.
2. 43 ng/J (0.10 lb/million Btu) heat input if the affected facility combusts coal with other fuels, has an annual capacity factor for the other fuels greater than 10% (0.10), and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor greater than 10% (0.10) for fuels other than coal.
NR 440.207(4)(b)
(b) On and after the date on which the initial performance test is completed or required to be completed under
s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that combusts wood or combusts mixtures of wood with other fuels, except coal, and has a heat input capacity of 8.7 MW (30 million Btu/hr) or greater, may cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits:
NR 440.207(4)(b)1.
1. 43 ng/J (0.10 lb/million Btu) heat input if the affected facility has an annual capacity factor for wood greater than 30% (0.30); or
NR 440.207(4)(b)2.
2. 130 ng/J (0.30 lb/million Btu) heat input if the affected facility has an annual capacity factor for wood of 30% (0.30) or less and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for wood of 30% (0.30) or less.
NR 440.207(4)(c)
(c) On and after the date on which the initial performance test is completed or required to be completed under
s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that combusts coal, wood or oil and has a heat input capacity of 8.7 MW (30 million Btu/hr) or greater may cause to be discharged into the atmosphere from that affected facility any gases that exhibit greater than 20% opacity (6-minute average), except for one 6-minute period per hour of not more than 27% opacity.
NR 440.207(4)(d)
(d) The PM and opacity standards under this subsection apply at all times, except during periods of startup, shutdown or malfunction.
NR 440.207(5)
(5) Compliance and performance test methods and procedures for sulfur dioxide. NR 440.207(5)(a)(a) Except as provided in
pars. (g) and
(h) and in
s. NR 440.08 (2), performance tests required under
s. NR 440.08 shall be conducted following the procedures specified in
pars. (b) to
(f), as applicable. The cited methods and procedures are in Appendix A of
40 CFR part 60, incorporated by reference in
s. NR 440.17.
Section NR 440.08 (6) does not apply to this subsection. The 30-day notice required in
s. NR 440.08 (4) applies only to the initial performance test unless otherwise specified by the department.
NR 440.207(5)(b)
(b) The initial performance test required under
s. NR 440.08 shall be conducted over 30 consecutive operating days of the steam generating unit. Compliance with the percent reduction requirements and SO
2 emission limits under
sub. (3) shall be determined using a 30-day average. The first operating day included in the initial performance test shall be scheduled within 30 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after the initial startup of the facility. The steam generating unit load during the 30-day period does not have to be the maximum design heat input capacity, but shall be representative of future operating conditions.
NR 440.207(5)(c)
(c) After the initial performance test required under
par. (b) and
s. NR 440.08, compliance with the percent reduction requirements and SO
2 emission limits under
sub. (3) is based on the average percent reduction and the average SO
2 emission rates for 30 consecutive steam generating unit operating days. A separate performance test is completed at the end of each steam generating unit operating day, and a new 30-day average percent reduction and SO
2 emission rate are calculated to show compliance with the standard.
NR 440.207(5)(d)
(d) If only coal, only oil, or a mixture of coal and oil is combusted in an affected facility, the procedures in Method 19 are used to determine the hourly SO
2 emission rate (E
ho) and the 30-day average SO
2 emission rate (E
ao). The hourly averages are obtained from the continuous emission monitoring system (CEMS). Method 19 shall be used to calculate E
ao when using daily fuel sampling or Method 6B.
NR 440.207(5)(e)
(e) If coal, oil, or coal and oil are combusted with other fuels:
NR 440.207(5)(e)1.
1. An adjusted E
ho (E
hoo) is used in equation 19-19 of Method 19 to compute the adjusted E
ao (E
aoo). The E
hoo is computed using the following formula:
Ehoo = (Eho - Ew(1 - Xk))/Xk
where:
