NR 440.205(10)(k)7.
7. Identification of times when hourly averages have been obtained based on manual sampling methods.
NR 440.205(10)(k)8.
8. Identification of the times when the pollutant concentration exceeded full span of the CEMS.
NR 440.205(10)(k)9.
9. Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specification 2 or 3 of Appendix B,
40 CFR part 60, incorporated by reference in
s. NR 440.17.
NR 440.205(10)(L)
(L) For each affected facility subject to the compliance and performance testing requirements of
sub. (6) (d) and the reporting requirements of
par. (j), the following information shall be reported to the department:
NR 440.205(10)(L)1.
1. Calendar dates when the facility was in operation during the reporting period;
NR 440.205(10)(L)2.
2. The 24-hour average sulfur dioxide emission rate measured for each steam generating unit operating day during the reporting period that coal or oil was combusted, ending in the last 24-hour period in the quarter; reasons for noncompliance with the emission standards; and a description of corrective actions taken;
NR 440.205(10)(L)3.
3. Identification of the steam generating unit operating days that coal or oil was combusted for which sulfur dioxide or diluent (oxygen or carbon dioxide) data have not been obtained by an approved method for at lest 75% of the operating hours; justification for not obtaining sufficient data; and description of corrective action taken.
NR 440.205(10)(L)4.
4. Identification of the times when emissions data have been excluded from the calculation of average emission rates; justification of excluding data, and description of corrective action taken if data have been excluded for periods other than those during which coal or oil were not combusted in the steam generating unit.
NR 440.205(10)(L)5.
5. Identification of “F" factor used for calculations, method of determination and type of fuel combusted.
NR 440.205(10)(L)6.
6. Identification of times when hourly averages have been obtained based on manual sampling methods.
NR 440.205(10)(L)7.
7. Identification of the times when the pollutant concentration exceeded full span of the CEMS.
NR 440.205(10)(L)8.
8. Description of any modifications to the CEMS which could affect the ability of the CEMS to comply with Performance Specification 2 or 3 of Appendix B,
40 CFR part 60, incorporated by reference in
s. NR 440.17.
NR 440.205(10)(m)
(m) For each affected facility subject to the sulfur dioxide standards under
sub. (3) for which the minimum amount of data required under
sub. (8) (f) were not obtained during the reporting period, the following information is reported to the department in addition to that required under
par. (k).
NR 440.205(10)(m)1.
1. The number of hourly averages available for outlet emission rates and inlet emission rates.
NR 440.205(10)(m)2.
2. The standard deviation of hourly averages for outlet emission rates and inlet emission rates, as determined in Method 19, Section 7 of Appendix A,
40 CFR part 60, incorporated by reference in
s. NR 440.17.
NR 440.205(10)(m)3.
3. The lower confidence limit for the mean outlet emission rate and the upper confidence limit for the mean inlet emission rate, as calculated in Method 19, Section 7.
NR 440.205(10)(m)4.
4. The ratio of the lower confidence limit for the mean outlet emission rate and the allowable emission rate, as determined in Method 19, Section 7.
NR 440.205(10)(n)
(n) If a percent removal efficiency by fuel pretreatment (%R
f) is used to determine the overall percent reduction (%R
o) under
sub. (6), the owner or operator of the affected facility shall submit a signed statement with the report:
NR 440.205(10)(n)1.
1. Indicating what removal efficiency by fuel pretreatment (%R
f) was credited during the reporting period.
NR 440.205(10)(n)2.
2. Listing the quantity, heat content, and date each pretreated fuel shipment was received during the reporting period; the name and location of the fuel pretreatment facility; and the total quantity and total heat content of all fuels received at the affected facility during the reporting period;
NR 440.205(10)(n)3.
3. Documenting the transport of the fuel from the fuel pretreatment facility to the steam generating unit.
NR 440.205(10)(n)4.
4. Including a signed statement from the owner or operator of the fuel pretreatment facility certifying that the percent removal efficiency achieved by fuel pretreatment was determined in accordance with the provisions of Method 19 of Appendix A,
40 CFR part 60, incorporated by reference in
s. NR 440.17, and listing the heat content and sulfur content of each fuel before and after fuel pretreatment.
NR 440.205(10)(o)
(o) All records required under this subsection shall be maintained by the owner or operator of the affected facility for a period of 2 years following the date of the record.
NR 440.205(10)(p)
(p) The owner or operator of an affected facility described in
sub. (5) (j) or
(k) shall maintain records of the following information for each steam generating unit operating day:
NR 440.205(10)(q)
(q) The owner or operator of an affected facility described in
sub. (5) (j) or
(k) shall submit to the department a report containing all of the following:
NR 440.205(10)(q)2.
2. The average fuel nitrogen content during the reporting period, if residual oil was fired.
NR 440.205(10)(q)3.
3. If the affected facility meets the criteria described in
sub. (5) (j), the results of any nitrogen oxides emission tests required during the reporting period, the hours of operation during the reporting period and the hours of operation since the last nitrogen oxides emission test.
NR 440.205(10)(r)
(r) The owner or operator of an affected facility who elects to demonstrate that the affected facility combusts only very low sulfur oil under
sub. (3) (j) 2. shall obtain and maintain at the affected facility fuel receipts from the fuel supplier which certify that the oil meets the definition of distillate oil as defined in
sub. (2). For the purposes of this subsection, the oil need not meet the fuel nitrogen content specification in the definition of distillate oil. Reports shall be submitted to the department certifying that only very low sulfur oil meeting this definition was combusted in the affected facility during the reporting period.
NR 440.205(10)(s)
(s) The owner or operator of an affected facility may submit electronic quarterly reports for SO
2, NO
x and opacity in lieu of submitting the written reports required under
par. (h),
(i),
(j),
(k) or
(L). The format of each quarterly electronic report shall be coordinated with the department. The electronic report shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a certification statement from the owner or operator, indicating whether compliance with the applicable emission standards and minimum data requirement of this section was achieved during the reporting period. Before submitting reports in the electronic format, the owner or operator shall coordinate with the department to obtain agreement to submit reports in this alternative format.
NR 440.205(10)(t)
(t) The reporting period for the reports required under this section is each 6-month period. All reports shall be submitted to the department and shall be postmarked by the 30th day following the end of the reporting period.
NR 440.205 History
History: Cr.
Register, September, 1990, No. 417, eff. 10-1-90; am. (1) (c), (2) (c), (k), (L) and (zb), (3) (a), (c) to (e), (f) (intro.), 2. and (g), (4) (a) 1. (intro.), (b), (e) and (f), (5) (a), (b), (f) 1. (intro.), (g) and (h), (6) (b), (c) 2.a. and b., 3. a., 5. and (d) (intro.), (7) (c), (d) (intro.), 1.,6. a. and c. and (f), (8) (a) and (b) 2., (9) (b) and (f), (10) (a) 2. (b), (e), (g) (intro.), (m) 2. to 4. and (o), r. and recr. (2) (zj), cr. (3) (j), (5) (i) to (k), (6) (j), (7) (g), (h), (8) (f), (9) (i) and (10) (p) to (r),
Register, July, 1993, No. 451, eff. 8-1-93
; am. (2) (zj), (3) (d) (intro.), (4) (b), (f), (5) (g), (6) (d) 2., (7) (g), (h) 1., (10) (b),
Register, December, 1995, No. 480, eff. 1-1-96;
CR 06-109: cr. (1) (g) and (h), (2) (zdm), (5) (L), (7) (f) 1. and 2., (9) (b) 1. and 2., (10) (s) and (t), am. (2) (b), (d) (h), (t), (y) 2. and (zf), (4) (a) 1. (intro.) and (g), (5) (a) (intro.), (b), (c) and (e), (7) (d) 4., (9) (e) 2. and (h), (10) (d), (e), (h) (intro.), (i), (j), (k) 2. and 3., (m) (intro.), (n) (intro.), 1., 2. and 3., (q) (intro.), 2. and 3. and (r), renum. (7) (f) and (9) (b) to be (7) (f) (intro.) and (9) (b) (intro.) and am. Register May 2008 No. 629, eff. 6-1-08. NR 440.207
NR 440.207 Small industrial-commercial-institutional steam generating units. NR 440.207(1)(a)(a) Except as provided in
par. (d), the affected facility to which this section applies is each steam generating unit for which construction, modification or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100 million Btu per hour (Btu/hr)) or less, but greater than or equal to 2.9 MW (10 million Btu/hr).
NR 440.207(1)(c)
(c) Steam generating units which meet the applicability requirements in
par. (a) are not subject to the sulfur dioxide (SO
2) or particulate matter (PM) emission limits, performance testing requirement, or monitoring requirements under this section during periods of combustion research.
NR 440.207(1)(d)
(d) Any temporary change to an existing steam generating unit for the purpose of conducting combustion research is not considered a modification under
s. NR 440.14.
NR 440.207(2)
(2) Definitions. As used in this section, all terms not defined herein shall have the meaning given them in
s. NR 440.02.
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.
