Section NR 440.205 - Industrial - commercial - institutional steam generating units(1) APPLICABILITY. (a) The affected facility to which this section applies is each steam generating unit that commences construction, modification, or reconstruction after June 19, 1984, and that has a heat input capacity from fuels combusted in the steam generating unit of more than 29 MW (100 million Btu/hour).(b) Any affected facility meeting the applicability requirements under par. (a) and commencing construction, modification, or reconstruction after June 19, 1984, but on or before June 19, 1986, is subject to the following standards: 1. Coal-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 million Btu/hour), inclusive, are subject to the particulate matter and nitrogen oxides standards under this section.2. Coal-fired affected facilities having a heat input capacity greater than 73 MW (250 million Btu/hour) and meeting the applicability requirements under s. NR 440.19 (standards of performance for fossil fuel-fired steam generators) are subject to the particulate matter and nitrogen oxides standards under this section and to the sulfur dioxide standards in s. NR 440.19(4).3. Oil-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 million Btu/hour), inclusive, are subject to the nitrogen oxides standards in this section.4. Oil-fired affected facilities having a heat input capacity greater than 73 MW (250 million Btu/hour) and meeting the applicability requirements in s. NR 440.19 (standards of performance for fossil fuel-fired steam generators) are also subject to the nitrogen oxides standards in this section and the particulate matter and sulfur dioxide standards in s. NR 440.19(3) and (4).(c) Affected facilities which also meet the applicability requirements under s. NR 440.26 (standards of performance for petroleum refineries) are subject to the particulate matter and nitrogen oxides standards under this section and the sulfur dioxide standards under s. NR 440.26(5).(d) Affected facilities which also meet the applicability requirements in s. NR 440.21 (standards of performance for incinerators) are subject to the nitrogen oxides and particulate matter standards in this section.(e) Steam generating units meeting the applicability requirements in s. NR 440.20 (standards of performance for electric utility steam generating units) are not subject to this section.(f) Any change to an existing steam generating unit for the sole purpose of combusting gases containing TRS as defined in s. NR 440.45(2) is not considered a modification under s. NR 440.14 and the steam generating unit is not subject to this section.(g) Affected facilities which meet the applicability requirements under s. NR 440.216(1) are not subject to this section.(h) Unless and until s. NR 440.50 is revised to extend the applicability of s. NR 440.50 to steam generator units subject to this section, this section will continue to apply to combined cycle gas turbines that are capable of combusting more than 29 MW (100 million Btu/hour) heat input of fossil fuel in the steam generator. Only emissions resulting from combustion of fuels in the steam generating unit are subject to this section. (The gas turbine emissions are subject to s. NR 440.50.)(2) DEFINITIONS. As used in this section, terms not defined in this subsection have the meanings given in s. NR 440.02.(a) "Annual capacity factor" means the ratio between the actual heat input to a steam generating unit from the fuels listed in sub. (3) (a), (4) (a) or (5) (a), as applicable, during a calendar year and the potential heat input to the steam generating unit had it been operated for 8,760 hours at the maximum steady state 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 in a calendar year.(b) "Byproducts/waste" means any liquid or gaseous substance produced at chemical manufacturing plants, petroleum refineries or pulp and paper mills (except natural gas, distillate oil, or residual oil) and combusted in a steam generating unit for heat recovery or for disposal. Gaseous substances with carbon dioxide levels greater than 50% or carbon monoxide levels greater than 10% are not byproduct/waste for the purposes of this section.(c) "Chemical manufacturing plants" means industrial plants which are classified by the department of commerce under SIC code 28 in the Standard Industrial Classification Manual, incorporated by reference in s. NR 440.17.(d) "Coal" means all solid fuels classified as an anthracite, bituminous, subbituminous, or lignite by the American Society for Testing and Materials in ASTM D388-99 (reapproved 2004), Standard Specification for Classification of Coals by Rank, incorporated by reference in s. NR 440.17(2) (a) 12., coal refuse, and petroleum coke. Coal-derived synthetic fuels, including but not limited to solvent refined coal, gasified coal, coal-oil mixtures, and coal-water mixtures, are also included in this definition for the purposes of this section.(e) "Coal refuse" means any byproduct of coal mining or coal cleaning operations with an ash content greater than 50%, by weight, and a heating value less than 13,900 kJ/kg (6,000 Btu/lb) on a dry basis.(f) "Combined cycle system" means a system where a separate source, such as a gas turbine, internal combustion engine, kiln, etc., provides exhaust gas to a heat recovery steam generating unit.(g) "Conventional technology" means wet flue gas desulfurization (FGD) technology, dry FGD technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology.(h) "Distillate oil" means fuel oils which contai n 0.05 weight percent nitrogen or less and comply with the specifications for fuel oils number 1 and 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.(i) "Dry flue gas desulfurization technology" means a sulfur dioxide control system that is located downstream of the steam generating unit and 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 slurries or solutions used in dry flue gas desulfurization technology include but are not limited to lime and sodium.(j) "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, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit.(k) "Emerging technology" means any sulfur dioxide control system that is not defined as a conventional technology under this subsection, and for which the owner or operator of the facility has applied to the administrator and received approval to operate as an emerging technology under sub. (10) (a) 4.(m) "Fluidized bed combustion technology" means combustion of fuel in a bed or series of beds (including but not limited to bubbling bed units and circulating bed units) of limestone aggregate (or other sorbent materials) in which these materials are forced upward by the flow of combustion air and the gaseous products of combustion.(n) "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.(o) "Full capacity" means operation of the steam generating unit at 90% or more of the maximum steady-state design heat input capacity.(p) "Heat input" means heat derived from combustion of fuel in a steam generating unit and does not include the heat input from preheated combustion air, recirculated flue gases, or exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.(q) "Heat release rate" means the steam generating unit design heat input capacity (in MW or Btu/hour) divided by the furnace volume (in cubic meters or cubic feet); the furnace volume is that volume bounded by the front furnace wall where the burner is located, the furnace side waterwall, and extending to the level just below or in front of the first row of convection pass tubes.(r) "Heat transfer medium" means any material that is used to transfer heat from one point to another point.(s) "High heat release rate" means a heat release rate greater than 730,000 J/sec-m3 (70,000 Btu/hour-ft3).(t) "Lignite" means a type of coal classified as lignite A or lignite B by the American Society for Testing and Materials in ASTM D388-99 (reapproved 2004), Standard Specification for Classification of Coals by Rank, incorporated by reference in s. NR 440.17(2) (a) 12.(u) "Low heat release rate" means a heat release rate of 730,000 J/sec-m3 (70,000 Btu/hour-ft3) or less.(v) "Mass-feed stoker steam generating unit" means a steam generating unit where solid fuel is introduced directly into a retort or is fed directly onto a grate where it is combusted.(w) "Maximum heat input capacity" means the ability of a steam generating unit to combust a stated maximum amount of fuel on a steady state basis, as determined by the physical design and characteristics of the steam generating unit.(x) "Municipal-type solid waste" means refuse, more than 50% of which is waste consisting of a mixture of paper, wood, yard wastes, food wastes, plastics, leather, rubber, and other combustible materials, and noncombustible materials such as glass and rock.(y) "Natural gas" means: 1. A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal hydrocarbon constituent is methane; or2. Liquid petroleum gas, as defined by the American Society for Testing and Materials in ASTM D1835-03a, Standard Specification for Liquid Petroleum Gases, incorporated by reference in s. NR 440.17(2) (a) 22.(z) "Noncontinental area" means the state of Hawaii, the Virgin Islands, Guam, American Samoa, the commonwealth of Puerto Rico, or the Northern Mariana Islands.(za) "Oil" means crude oil or petroleum or a liquid fuel derived from crude oil or petroleum, including distillate and residual oil.(zb) "Petroleum refinery" means industrial plants as classified by the department of commerce under SIC code 29 in the Standard Industrial Classification Manual, incorporated by reference in s. NR 440.17.(zc) "Potential sulfur dioxide emission rate" means the theoretical sulfur dioxide emissions (ng/J, lb/million Btu heat input) that would result from combusting fuel in an uncleaned state and without using emission control systems.(zd) "Process heater" means a device that is primarily used to heat a material to initiate or promote a chemical reaction in which the material participates as a reactant or catalyst. (zdm) "Pulp and paper mills" means industrial plants which are classified under code 26 of the Standard Industrial Classification Manual, 1987 or under code 322 of the North American Industry Classification System, United States 2002, incorporated by reference in s. NR 440.17(2) (i) 1. and 3. respectively.(ze) "Pulverized coal-fired steam generating unit" means a steam generating unit in which pulverized coal is introduced into an air stream that carries the coal to the combustion chamber of the steam generating unit where it is fired in suspension. This includes both conventional pulverized coal-fired and micropulverized coal-fired steam generating units.(zf) "Residual oil" means crude oil, fuel oil numbers 1 and 2 that have a nitrogen content greater than 0.05 weight percent, and all fuel oil numbers 4, 5 and 6, as defined by the American Society for Testing and Materials in ASTM D396-98, Standard Specifications for Fuel Oils, incorporated by reference in s. NR 440.17(2) (a) 13.(zg) "Spreader stoker steam generating unit" means a steam generating unit in which solid fuel is introduced to the combustion zone by a mechanism that throws the fuel onto a grate from above and in which combustion takes place both in suspension and on the grate.(zh) "Steam generating unit" means a device that combusts any fuel or byproduct/waste to produce steam or to heat water or any other heat transfer medium. This term includes any municipal-type solid waste incinerator with a heat recovery steam generating unit or any steam generating unit that combusts fuel and is part of a cogeneration system or a combined cycle system. This term does not include process heaters as they are defined in this section.(zi) "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 anytime in the steam generating unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period.(zj) "Very low sulfur oil" means an oil that contains no more than 0.50 weight percent sulfur or that, when combusted without sulfur dioxide emission control, has a sulfur dioxide emission rate equal to or less than 215 ng/J (0.50 lb/million Btu) heat input.(zk) "Wet flue gas desulfurization technology" means a sulfur dioxide control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gas with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents used in wet flue gas desulfurization technology include, but are not limited to, lime, limestone, and sodium. (zL) "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 or sulfur dioxide.(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.(3) STANDARD FOR SULFUR DIOXIDE. (a) Except as provided in par. (b), (c), (d), or (j) on and after the date on which the 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 oil may cause to be discharged into the atmosphere any gases that contain sulfur dioxide in excess of 10% (0.10) of the potential sulfur dioxide emission rate (90% reduction) and that contain sulfur dioxide in excess of the emission limit determined according to the following formula: Es = (KaHa+ KbHb)/(Ha+ Hb)
where:
Es is the sulfur dioxide emission limit, in ng/J or lb/million Btu heat input
Ka is 520 ng/J (or 1.2 lb/million Btu)
Kb is 340 ng/J (or 0.80 lb/million Btu)
Ha is the heat input from the combustion of coal, in J (million Btu)
Hb is the heat input from the combustion of oil, in J (million Btu)
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 the combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat input to the affected facility from exhaust gases from another source, such as gas turbines, internal combustion engines, kilns, etc.
(b) On and after the date on which the performance test is completed or required to be completed under s. NR 440.08, whichever comes first, no owner or operator of an affected facility that combusts coal refuse alone in a fluidized bed combustion steam generating unit may cause to be discharged into the atmosphere any gases that contain sulfur dioxide in excess of 20% of the potential sulfur dioxide emission rate (80% reduction) and that contain sulfur dioxide in excess of 520 ng/J (1.2 lb/million Btu) heat input. If coal or oil is fired with coal refuse, the affected facility is subject to par. (a) or (d), as applicable. (c) On and after the date on which the performance test is completed or is required to be completed under s. NR 440.08, whichever comes first, no owner or operator of an affected facility that combusts coal or oil, either alone or in combination with any other fuel, and that uses an emerging technology for the control of sulfur dioxide emissions, may cause to be discharged into the atmosphere any gases that contain sulfur dioxide in excess of 50% of the potential sulfur dioxide emission rate (50% reduction) and that contain sulfur dioxide in excess of the emission limit determined according to the following formula: E=(KcHc + KdHd)/(Hc + Hd)
where:
Es is the sulfur dioxide emission limit, expressed in ng/J or lb/million Btu heat input
Kc is 260 ng/J (or 0.60 lb/million Btu)
Kd is 170 ng/J (or 0.40 lb/million Btu)
Hc is the heat input from the combustion of coal, in J (million Btu)
Hd is the heat input from the combustion of oil, in J (million Btu)
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 the combustion of natural gas, wood, municipal-type solid waste, or other fuels, or from the heat input to the affected facility from exhaust gases from another source, such as gas turbines, internal combustion engines, kilns, etc.
(d) On and after the date on which the performance test is completed or required to be completed under s. NR 440.08, whichever comes first, no owner or operator of an affected facility listed in subd. 1., 2. or 3. may cause to be discharged into the atmosphere any gases that contain sulfur dioxide in excess of 520 ng/J (1.2 lb/million Btu) heat input if the affected facility combusts coal, or 215 ng/J (0.50 lb/million Btu) heat input if the affected facility combusts oil other than very low sulfur oil. Percent reduction requirements are not applicable to affected facilities under this paragraph. 1. Affected facilities that have an annual capacity factor for coal and oil of 30% (0.30) or less and are subject to a federally enforceable permit limiting the operation of the affected facility to an annual capacity factor for coal and oil to 30% (0.30) or less;2. Affected facilities located in a noncontinental area; or3. Affected facilities combusting coal or oil, alone or in combination with any other fuel, in a duct burner as part of a combined cycle system where 30% (0.30) or less of the heat input to the steam generating unit is from combustion of coal and oil in the duct burner and 70% (0.70) or more of the heat input to the steam generating unit is from the exhaust gases entering the duct burner.(e) Except as provided in par. (f), compliance with the emission limits, fuel oil sulfur limits, and/or percent reduction requirements under this subsection are determined on a 30-day rolling average basis.(f) Except as provided for in par. (j) 2., compliance with the emission limits or fuel oil sulfur limits under this subsection is determined on a 24-hour average basis for affected facilities that:1. Have a federally enforceable permit limiting the annual capacity factor for oil to 10% or less;2. Combust only very low sulfur oil; and3. Do not combust any other fuel.(g) Except as provided in par. (i), the sulfur dioxide emission limits and percent reduction requirements under this subsection apply at all times, including periods of startup, shutdown, and malfunction. (h) Reductions in the potential sulfur dioxide emission rate through fuel pretreatment are not credited toward the percent reduction requirement under par. (c) unless: 1. Fuel pretreatment results in a 50% or greater reduction in potential sulfur dioxide emissions and2. Emissions from the pretreated fuel (without combustion or post combustion sulfur dioxide control) are equal to or less than the emission limits specified in par. (c).(i) An affected facility subject to par. (a), (b), or (c) may combust very low sulfur oil or natural gas when the sulfur dioxide control system is not being operated because of malfunction or maintenance of the sulfur dioxide control system. (j) Percent reduction requirements are not applicable to affected facilities combusting only very low sulfur oil. The owner or operator of an affected facility combusting very low sulfur oil shall demonstrate that the oil meets the definition of very low sulfur oil by: 1. Following the performance testing procedures as described in sub. (6) (c) or (d), and following the monitoring procedures as described in sub. (8) (a) or (b) to determine sulfur dioxide emission rate or fuel oil sulfur content; or2. Maintaining fuel receipts as described in sub. (10) (r).(4) STANDARD FOR PARTICULATE MATTER. (a) On and after the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever comes first, no owner or operator of an affected facility which combusts coal or combusts mixtures of coal with other fuels, may cause to be discharged into the atmosphere from that affected facility any gases which contain particulate matter in excess of the following emission limits: 1. 22 ng/J (0.051 lb/million Btu) heat input; a. If the affected facility combusts only coal, orb. If the affected facility combusts coal and other fuels and has an annual capacity factor for the other fuels of 10% (0.10) or less.2. 43 ng/J (0.10 lb/million Btu) heat input if the affected facility combusts coal and other fuels and 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.3. 86 ng/J (0.20 lb/million Btu) heat input if the affected facility combusts coal or coal and other fuels and: a. Has an annual capacity factor for coal or coal and other fuels of 30% (0.30) or less,b. Has a maximum heat input capacity of 73 MW (250 million Btu/hour) or less,c. Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor 30% (0.30) or less for coal or coal and other solid fuels, andd. Construction of the affected facility commenced after June 19, 1984 and before November 25, 1986.(b) On or after the date on which the 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, or mixtures of oil with other fuels, and uses a conventional or emerging technology to reduce sulfur dioxide emissions may discharge into the atmosphere from that affected facility any gases that contain particulate matter in excess of 43 ng/J (0.10 lb/million Btu) heat input.(c) On and after the date on which the initial performance test is completed or is 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 wood with other fuels, except coal, may cause to be discharged from that affected facility any gases that contain particulate matter in excess of the following emission limits: 1. 43 ng/J (0.10 lb/million Btu) heat input if the affected facility has an annual capacity factor greater than 30% (0.30) for wood.2. 86 ng/J (0.20 lb/million Btu) heat input if: a. The affected facility has an annual capacity factor of 30% (0.30) or less for wood,b. Is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor 30% (0.30) or less for wood, and:c. Has a maximum heat input capacity of 73 MW (250 million Btu/hour) or less.(d) On and after the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that combusts municipal-type solid waste or mixtures of municipal-type solid waste with other fuels, may cause to be discharged into the atmosphere from that affected facility any gases that contain particulate matter in excess of the following emission limits: 1. 43 ng/J (0.10 lb/million Btu) heat input if;a. The affected facility combusts only municipal-type solid waste, orb. The affected facility combusts municipal-type solid waste and other fuels and has an annual capacity factor for the other fuels of 10% (0.10) or less.2. 86 ng/J (0.20 lb/million Btu) heat input if the affected facility combusts municipal-type solid waste or municipal-type solid waste and other fuels; and a. Has an annual capacity factor for municipal-type solid waste and other fuels of 30% (0.30) or less,b. Has a maximum heat input capacity of 73 MW (250 million Btu/hour) or less,c. Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30% (0.30) for municipal-type solid waste, or municipal-type solid waste and other fuels, andd. Construction of the affected facility commenced after June 19, 1984, but before November 25, 1986.(e) For the purposes of this subsection, the annual capacity factor is determined by dividing the actual heat input to the steam generating unit during the calendar year from the combustion of coal, wood, or municipal- type solid waste, and other fuels, as applicable, by the potential heat input to the steam generating unit if the steam generating unit had been operated for 8,760 hours at the maximum design heat input capacity.(f) On and after the date on which the initial performance test is completed or is 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, wood or mixtures of these fuels with any other fuels may cause to be discharged into the atmosphere 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.(g) The particulate matter and opacity standards apply at all times, except during periods of startup, shutdown or malfunction.(5) STANDARD FOR NITROGEN OXIDES. (a) Except as provided under pars. (k) and (L), on and after the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that is subject to the provisions of this subsection and that combusts only coal, oil or natural gas may cause to be discharged into the atmosphere from that affected facility any gases that contain nitrogen oxides (expressed as NO2) in excess of the following emission limits: | Fuel/Steam Generating Unit Type | Nitrogen Oxide Emission Limits ng/J(lb/million Btu)(expressed as NO2) Heat Input |
| 1. | Natural gas and distillate oil, except 4.: |
| a. Low heat release rate | 43 (0.10) |
| b. High heat release rate | 86 (0.20) |
| 2. | Residual oil: |
| a. Low heat release rate | 130 (0.30) |
| b. High heat release rate | 170 (0.40) |
| 3. | Coal: |
| a. Mass-feed stoker | 210 (0.50) |
| b. Spreader stoker and fluidized bed combustion | 260 (0.60) |
| c. Pulverized coal | 300 (0.70) |
| d. Lignite, except e. | 260 (0.60) |
| e. Lignite mined in North Dakota, South Dakota, or Montana and combusted in a slag tap furnace | 340 (0.80) |
| f. Coal-derived synthetic fuels | 210 (0.50) |
| 4. | Duct burner used in a combined cycle | ystem: |
| a. Natural gas and distillate oil | 86 (0.20) |
| b. Residual oil | 170 (0.40) |
(b) Except as provided under pars. (k) and (L), on and after the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts mixtures of coal, oil or natural gas may cause to be discharged into the atmosphere from that affected facility any gases that contain nitrogen oxides in excess of a limit determined by use of the following formula: See PDF for diagram
where:
En is the nitrogen oxides emission limit (expressed as NO2), ng/J (lb/million Btu)
ELgo is the appropriate emission limit from the table in par. (a) for combustion of natural gas or distillate oil, ng/J (lb/million Btu)
Hgo is the heat input from combustion of natural gas or distillate oil, J (million Btu)
ELro is the appropriate emission limit from the table in par. (a) for combustion of residual oil
Hro is the heat input from combustion of residual oil, J (million Btu)
ELc is the appropriate emission limit from the table in par. (a) for combustion of coal
Hc is the heat input from combustion of coal, J (million Btu)
(c) Except as provided under par. (L), on and after the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever comes first, no owner or operator of an affected facility that simultaneously combusts coal or oil, or a mixture of these fuels with natural gas, and wood, municipal-type solid waste or any other fuel may cause to be discharged into the atmosphere any gases that contain nitrogen oxides in excess of the emission limit for the coal or oil, or mixture of these fuels with natural gas, combusted in the affected facility, as determined pursuant to par. (a) or (b), unless the affected facility has an annual capacity factor for coal or oil, or mixture of these fuels with natural gas of 10% (0.10) or less and is subject to a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10% (0.10) or less for coal, oil or a mixture of these fuels with natural gas. (d) On and after the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts natural gas with wood, municipal-type solid waste, or other solid fuel, except coal, may cause to be discharged into the atmosphere from that affected facility any gases that contain nitrogen oxides in excess of 130 ng/J (0.30 lb/million Btu) heat input unless the affected facility has an annual capacity factor for natural gas of 10% (0.10) or less and is subject to a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10% (0.10) or less for natural gas.(e) Except as provided under par. (L), on and after the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts coal, oil or natural gas with byproduct/waste may cause to be discharged into the atmosphere from that affected facility any gases that contain nitrogen oxides in excess of an emission limit determined by the following formula unless the affected facility has an annual capacity factor for coal, oil and natural gas of 10% (0.10) or less and is subject to a federally enforceable requirement which limits operation of the affected facility to an annual capacity factor of 10% (0.10) or less: - See PDF for diagram
where:
En is the nitrogen oxides emission limit (expressed as NO2), ng/J (lb/million Btu)
ELgo is the appropriate emission limit from the table in par. (a) for combustion of natural gas or distillate oil, ng/J (lb/million Btu)
Hgo is the heat input from combustion of natural gas, distillate oil and gaseous byproduct/waste, J (million Btu)
ELro is the appropriate emission limit from the table in par. (a) for combustion of residual oil, ng/J (lb/million Btu)
Hro is the heat input from combustion of residual oil or liquid byproduct/waste, J (million Btu)
ELc is the appropriate emission limit from the table in par. (a) for combustion of coal
Hc is the heat input from combustion of coal, J (million Btu)
(f) Any owner or operator of an affected facility that combusts byproduct/waste with either natural gas or oil may petition the administrator within 180 days of the initial startup of the affected facility to establish a nitrogen oxide emission limit which shall apply specifically to that affected facility when the byproduct/waste is combusted. The petition shall include sufficient and appropriate data, as determined by the administrator, such as nitrogen oxides emissions from the affected facility, waste composition (including nitrogen content), and combustion conditions to allow the administrator to confirm that the affected facility is unable to comply with the emission limits in par. (e) and to determine the appropriate emission limit for the affected facility. 1. Any owner or operator of an affected facility petitioning for a facility-specific nitrogen oxides emission limit under this subsection shall:a. Demonstrate compliance with the emission limits in the par. (a) table for natural gas and distillate oil or for residual oil as appropriate, by conducting a 30-day performance test as provided in sub. (7) (e). During the performance test only natural gas, distillate oil, or residual oil shall be combusted in the affected facility; and b. Demonstrate that the affected facility is unable to comply with the emission limits in the par. (a) table for natural gas and distillate oil or for residual oil as appropriate, when gaseous or liquid byproduct/waste is combusted in the affected facility under the same conditions and using the same technological system of emission reduction applied when demonstrating compliance under subd. 1. a. 2. The nitrogen oxides emission limits in the par. (a) table for natural gas or distillate oil or for residual oil, as appropriate, shall be applicable to the affected facility until and unless the petition is approved by the administrator. If the petition is approved by the administrator, a facility-specific nitrogen oxides emission limit will be established at the nitrogen oxides emission level achievable when the affected facility is combusting oil or natural gas and byproduct/waste in a manner which the administrator determines to be consistent with minimizing nitrogen oxides emissions.(g) Any owner or operator of an affected facility that combusts hazardous waste, as defined by 40 CFR part 261 or 40 CFR part 761, as in effect on July 1, 1994, with natural gas or oil may petition the administrator within 180 days of the initial startup of the affected facility for a waiver from compliance with the nitrogen oxides emission limit which applies specifically to that affected facility. The petition shall include sufficient and appropriate data, as determined by the administrator, on nitrogen oxides emissions from the affected facility, waste destruction efficiencies, waste composition (including nitrogen content), the quantity of specific wastes to be combusted and combustion conditions, to allow the administrator to determine if the affected facility is able to comply with the nitrogen oxides emission limits required by this subsection. The owner or operator of the affected facility shall demonstrate that when hazardous waste is combusted in the affected facility, thermal destruction efficiency requirements for hazardous waste specified in an applicable federally enforceable requirement preclude compliance with the nitrogen oxides emission limits of this subsection. The nitrogen oxides emission limits in the par. (a) table for natural gas or distillate oil or for residual oil, as appropriate, are applicable to the affected facility until and unless the petition is approved by the administrator. Note: See 40 CFR 761.70 for regulations applicable to the incineration of materials containing polychlorinated biphenyls (PCBs).
(h) For purposes of par. (i), the nitrogen oxide standards under this subsection apply at all times including periods of startup, shutdown or malfunction. (i) Except as provided under par. (j), compliance with the emission limits under this subsection is determined on a 30-day rolling average basis.(j) Compliance with the emission limits under this subsection is determined on a 24-hour average basis for the initial performance test and on a 3-hour average basis for subsequent performance tests for any affected facilities that: 1. Combust, alone or in combination, only natural gas, distillate oil or residual oil with a nitrogen content of 0.30 weight percent or less;2. Have a combined annual capacity factor of 10% or less for natural gas, distillate oil and residual oil with a nitrogen content of 0.30 weight percent or less, and3. Are subject to a federally enforceable requirement limiting operation of the affected facility to the firing of natural gas, distillate oil and/or residual oil with a nitrogen content of 0.30 weight percent or less and limiting operation of the affected facility to a combined annual capacity factor of 10% or less for natural gas, distillate oil and residual oil and a nitrogen content of 0.30 weight percent or less.(k) Affected facilities that meet the criteria described in par. (j) 1., 2., and 3., and that have a heat input capacity of 73 MW (250 million Btu/hour) or less, are not subject to the nitrogen oxides emission limits under this subsection. (L) On and after the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever date comes first, no owner or operator of an affected facility which commenced construction, modification or reconstruction after July 9, 1997 may cause to be discharged into the atmosphere from that affected facility any gases that contain nitrogen oxides (expressed as NO2) in excess of one of the following limits: 1. If the affected facility combusts coal, oil or natural gas, or a mixture of these fuels, or with any other fuels: a limit of 86 ng/J (0.20 lb/million Btu) heat input unless the affected facility has an annual capacity factor for coal, oil and natural gas of 10% (0.10) or less and is subject to a federally enforceable requirement that limits operation of the facility to an annual capacity factor of 10% (0.10) or less for coal, oil and natural gas.2. If the affected facility has a low heat release rate and combusts natural gas or distillate oil in excess of 30% of the heat input from the combustion of all fuels, a limit determined by use of the following formula: En = [(0.10 * Hgo) + (0.20 * Hr)]/(Hgo + Hr)
where:
En is the NOx emission limit, (lb/million Btu)
Hgo is the heat input from combustion of natural gas or distillate oil
Hr is the heat input from combustion of any other fuel
(6) COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES FOR SULFUR DIOXIDE. (a) The sulfur dioxide emission standards under sub. (3) apply at all times.(b) In conducting the performance tests required under s. NR 440.08, the owner or operator shall use the cited methods and procedures in Appendix A of 40 CFR part 60, incorporated by reference in s. NR 440.17, or the methods and procedures as specified in this subsection, except as provided in s. NR 440.08(2). 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.(c) The owner or operator of an affected facility shall conduct performance tests to determine compliance with the percent of potential sulfur dioxide emission rate (%Ps) and the sulfur dioxide emission rate (Es) pursuant to sub. (3) following the procedures listed below, except as provided under par. (d). 1. The initial performance test shall be conducted over the first 30 consecutive operating days of the steam generating unit. Compliance with the sulfur dioxide standards 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 initial startup of the facility.2. If only coal or only oil is combusted, the following procedures are used: a. The procedures in Method 19, Appendix A of 40 CFR part 60, incorporated by reference in s. NR 440.17, shall be used to determine the hourly sulfur dioxide emission rate (Eho) and the 30-day average emission rate (Eao). The hourly averages used to compute the 30-day averages are obtained from the continuous emission monitoring system of sub. (8) (a) or (b).b. The percent of potential sulfur dioxide emission rate (%Ps) emitted to the atmosphere is computed using the following formula: See PDF for diagram
where:
%Rg is the sulfur dioxide removal efficiency of the control device as determined by Method 19
%Rf is the sulfur dioxide removal efficiency of fuel pretreatment as determined by Method 19
3. If coal or oil is combusted with other fuels, the same procedures required in subd. 2. are used, except as provided in the following:a. An adjusted hourly sulfur dioxide emission rate (Ehoo) is used in equation 19-19 of Method 19 to compute an adjusted 30-day average emission rate (Eaoo). The Ehoo is computed using the following formula: See PDF for diagram
where:
Ehoo is the adjusted hourly sulfur dioxide emission rate, ng/J (lb/million Btu)
Eho is the hourly sulfur dioxide emission rate, ng/J (lb/million Btu)
Ew is the sulfur dioxide concentration in fuels other than coal and oil combusted in the affected facility, as determined by the fuel sampling and analysis procedures in Method 19, ng/J (lb/million Btu). The value Ew for each fuel lot is used for each hourly average during the time that the lot is being combusted.
Xk is the fraction of total heat input from fuel combustion derived from coal, oil, or coal and oil, as determined by applicable procedures in Method 19
b. To compute the percent of potential sulfur dioxide emission rate (%Ps), an adjusted %Rg (%Rgo) is computed from the adjusted Eaoo from subd. 3. a. and an adjusted average sulfur dioxide inlet rate (Eaio) using the following formula: See PDF for diagram
To compute Eai°, an adjusted hourly sulfur dioxide inlet rate (Ehi°) is used. The Ehi° is computed using the following formula:
See PDF for diagram
where:
Ehi° is the adjusted hourly sulfur dioxide inlet rate, ng/J (lb/million Btu)
Ehi is the hourly sulfur dioxide inlet rate, ng/J (lb/million Btu)
4. The owner or operator of an affected facility subject to subd. 3. does not have to measure parameters Ew or Xk if the owner or operator elects to assume that Xk = 1.0. Owners or operators of affected facilities who assume Xk = 1.0 shall determine %Ps, following the procedures in subd. 2., and sulfur dioxide emissions (Es) shall be considered to be in compliance with sulfur dioxide emission limits under sub. (3).5. The owner or operator of an affected facility that qualifies under the provisions of sub. (3) (d) does not have to measure parameters Ew or Xk under subd. 3. if the owner or operator of the affected facility elects to measure sulfur dioxide emission rates of the coal or oil following the fuel sampling and analysis procedures under Method 19.(d) Except as provided in par. (j), the owner or operator of an affected facility that combusts only very low sulfur oil, has an annual capacity factor for oil of 10% (0.10) or less, and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for oil of 10% (0.10) or less shall:1. Conduct the initial performance test over 24 consecutive steam generating unit operating hours at full load;2. Determine compliance with the standards after the initial performance test based on the arithmetic average of the hourly emissions data during each steam generating unit operating day if a continuous emission monitoring system (CEMS) is used, or based on a daily average if Method 6B, Appendix A of 40 CFR part 60, incorporated by reference in s. NR 440.17, or fuel sampling and analysis procedures under Method 19, Appendix A of 40 CFR part 60, incorporated by reference in s. NR 440.17, are used.(e) The owner or operator of an affected facility subject to sub. (3) (d) 1., shall demonstrate the maximum design capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. This demonstration will be made during the initial performance test and a subsequent demonstration may be requested at any other time. If the 24-hour average firing rate for the affected facility is less than the maximum design capacity provided by the manufacturer of the affected facility, the 24-hour average firing rate shall be used to determine the capacity utilization rate for the affected facility, otherwise the maximum design capacity provided by the manufacturer shall be used.(f) For the initial performance test required under s. NR 440.08, compliance with the sulfur dioxide emission limits and percent reduction requirements under sub. (3) is based on the average emission rates and the average percent reduction for sulfur dioxide for the first 30 consecutive steam generating unit operating days, except as provided under par. (d). The initial performance test is the only test for which at least 30 days prior notice is required unless otherwise specified by the department. The initial performance test is to be scheduled so that the first steam generating unit operating day of the 30 successive steam generating unit operating days is completed within 30 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility. The boiler load during the 30-day period does not have to be the maximum design load, but shall be representative of future operating conditions and include at least one 24-hour period at full load.(g) After the initial performance test required under s. NR 440.08, compliance with the sulfur dioxide emission limits and percent reduction requirements under sub. (3) is based on the average emission rates and the average percent reduction for sulfur dioxide for 30 successive steam generating unit operating days, except as provided under par. (d). A separate performance test shall be completed at the end of each steam generating unit operating day after the initial performance test, and a new 30-day average emission rate and percent reduction for sulfur dioxide shall be calculated to show compliance with the standard.(h) Except as provided under par. (i), the owner or operator of an affected facility shall use all valid sulfur dioxide emissions data in calculating %Ps and Eho under par. (c), whether or not the minimum emissions data requirements under sub. (7) are achieved. All valid emissions data, including valid sulfur dioxides emission data collected during periods of startup, shutdown and malfunctions, shall be used in calculating %Ps and Eho pursuant to par. (c). (i) During periods of malfunction or maintenance of the sulfur dioxide control systems when oil is combusted as provided under sub. (3) (i), emission data are not used to calculate %Ps or Es under sub. (3) (a), (b) or (c). However, the emissions data are used to determine compliance with the emission limit under sub. (3) (i).(j) The owner or operator of an affected facility that combusts very low sulfur oil is not subject to the compliance and performance testing requirements of this subsection if the owner or operator obtains fuel receipts as described in sub. (10) (r).(7) COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES FOR PARTICULATE MATTER AND NITROGEN OXIDES. (a) The particulate matter emission standards and opacity limits under sub. (4) apply at all times except during periods of startup, shutdown, or malfunction. The nitrogen oxides emission standards under sub. (5) apply at all times.(b) Compliance with the particulate matter emission standards under sub. (4) shall be determined through performance testing as described in par. (d).(c) Compliance with the nitrogen oxides emission standards under sub. (5) shall be determined through performance testing under par. (e) or (f), or under pars. (g) and (h), as applicable.(d) To determine compliance with the standards for particulate matter emission limits and opacity limits under sub. (4), the owner or operator of an affected facility shall conduct an initial performance test as required under s. NR 440.08 using the following procedures and reference methods. These reference methods and procedures are in 40 CFR part 60, Appendix A, which is incorporated by reference in s. NR 440.17. 1. Method 3B is used for gas analysis when applying Method 5 or Method 17.2. Method 5, Method 5B, or Method 17 shall be used to measure the concentration of particulate matter as follows: a. Method 5 shall be used at affected facilities without wet flue gas desulfurization (FGD) systems; andb. Method 17 may be used at facilities with or without wet scrubber systems provided the stack gas temperature does not exceed a temperature of 160°C (320°F). The procedures of ss. 2.1 and 2.3 of Method 5B may be used in Method 17 only if it is used after a wet FGD system. Do not use Method 17 after wet FGD systems if the effluent is saturated or laden with water droplets.c. Method 5B is to be used only after wet FGD systems.3. Method 1 is used to select the sampling site and the number of traverse sampling points. The sampling time for each run shall be at least 120 minutes and the minimum sampling volume is 1.7 dscm (60 dscf) except that smaller sampling times or volumes may be approved by the department when necessitated by process variables or other factors.4. For Method 5, the temperature of the sample gas in the probe and filter holder is monitored and is maintained at 160 ± 14°C (320 ± 25°F).5. For determination of particulate emissions, the oxygen or carbon dioxide sample is obtained simultaneously with each run of Method 5, Method 5B or Method 17 by traversing the duct at the sampling location.6. For each run using Method 5, Method 5B or Method 17, the emission rate expressed in nanograms per joule heat input is determined using: a. The oxygen or carbon dioxide measurements and particulate matter measurements obtained under this subsection,b. The dry basis F factor, andc. The dry basis emission rate calculation procedure contained in Method 19.7. Method 9 is used for determining the opacity of stack emissions.(e) To determine compliance with the emission limits for nitrogen oxides required under sub. (5), the owner or operator of an affected facility shall conduct the performance test as required under s. NR 440.08 using the continuous system for monitoring nitrogen oxides under sub. (9). 1. For the initial compliance test, nitrogen oxides from the steam generating unit shall be monitored for 30 successive steam generating unit operating days and the 30-day average emission rate is used to determine compliance with the nitrogen oxides emission standards under sub. (5). The 30-day average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 30-day test period.2. Following the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever date comes first, the owner or operator of an affected facility which combusts coal or which combusts residual oil having a nitrogen content greater than 0.30 weight % shall determine compliance with the nitrogen oxides emission standards under sub. (5) on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly nitrogen oxides emission data for the preceding 30 steam generating unit operating days.3. Following the date on which the initial performance test is completed or is required to be completed under s. NR 440.08, whichever date comes first, the owner or operator of an affected facility which has a heat input capacity greater than 73 MW (250 million Btu/hour) and which combusts natural gas, distillate oil, or residual oil having a nitrogen content of 0.30 weight % or less shall determine compliance with the nitrogen oxides standards under sub. (5) on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly nitrogen oxides emission data for the preceding 30 steam generating unit operating days.4. Following 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 which has a heat input capacity of 73 MW (250 million Btu/hour) or less and which combusts natural gas, distillate oil, or residual oil having a nitrogen content of 0.30 weight % or less shall, upon request, determine compliance with the nitrogen oxides standards under sub. (5) through the use of a 30-day performance test. During periods when performance tests are not requested, nitrogen oxides emissions data collected pursuant to sub. (9) (g) 1. or 2. are used to calculate a 30-day rolling average emission rate on a daily basis and used to prepare excess emission reports, but will not be used to determine compliance with the nitrogen oxides emission standards. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly nitrogen oxides emission data for the preceding 30 steam generating unit operating days.5. If the owner or operator of an affected facility which combusts residual oil does not sample and analyze the residual oil for nitrogen content, as specified in sub. (10) (e), the requirements of subd. 2. apply and the provisions of subd. 4. are inapplicable.(f) To determine compliance with the emission limit for NOx required by sub. (5) (a) 4. or (L) for duct burners used in combined cycle systems, either of the procedures described in subd. 1. or 2. may be used: 1. The owner or operator of an affected facility shall conduct the performance test required under s. NR 440.08 as follows:a. The emissions rate (E) of NOx shall be computed using Equation 1 of this section: E = Esg + (Hg/Hb)(E sg - Eg) Equation 1
where:
E is the emissions rate of NOx from the duct burner, ng/J (lb/million Btu) heat input
Esg is the combined effluent emissions rate, in ng/J (lb/million Btu) heat input using appropriate F-Factor as described in Method 19
Hg is the heat input rate to the combustion turbine, in Joules/hour (million Btu/hour)
Hb is the heat input rate to the duct burner, in Joules/hour (million Btu/hour)
Eg is the emissions rate from the combustion turbine, in ng/J (lb/million Btu) heat input calculated using appropriate F-Factor as described in Method 19
b. Method 7E shall be used to determine the NOx concentrations. Method 3A or 3B shall be used to determine oxygen concentration.c. The owner or operator shall identify and demonstrate to the department's satisfaction suitable methods to determine the average hourly heat input rate to the combustion turbine and the average hourly heat input rate to the affected duct burner.d. Compliance with the emissions limits under sub. (5) (a) 4. or (L) shall be determined by the 3-run average (nominal 1-hour runs) for the initial and subsequent performance tests.2. The owner or operator of an affected facility may elect to determine compliance on a 30-day rolling average basis by using the continuous emission monitoring system specified under sub. (9) for measuring NOx and oxygen and meet the requirements of sub. (9). The sampling site shall be located at the outlet from the steam generating unit. The NOx emissions rate at the outlet from the steam generating unit shall constitute the NOx emissions rate from the duct burner of the combined cycle system.(g) The owner or operator of an affected facility described in sub. (5) (j) or (k) shall demonstrate the maximum heat input capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. The owner or operator of an affected facility shall determine the maximum heat input capacity using the heat loss method described in Sections 5 and 7.3 of the ASME Power Test Codes 4.1, incorporated by reference in s. NR 440.17. This demonstration of maximum heat input capacity shall be made during the initial performance test for affected facilities that meet the criteria of sub. (5) (j). It shall be made within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of each facility, for affected facilities meeting the criteria of sub. (5) (k). Subsequent demonstrations may be required by the department at any other time. If this demonstration indicates that the maximum heat input capacity of the affected facility is less than that stated by the manufacturer of the affected facility, the maximum heat input capacity determined during this demonstration shall be used to determine the capacity utilization rate for the affected facility. Otherwise, the maximum heat input capacity provided by the manufacturer is used.(h) The owner or operator of an affected facility described in sub. (5) (j) that has a heat input capacity greater than 73 MW (250 million Btu/hour) shall: 1. Conduct an initial performance test as required under s. NR 440.08 over a minimum of 24 consecutive steam generating unit operating hours at maximum heat input capacity to demonstrate compliance with the nitrogen oxides emission standards under sub. (5) using Method 7, 7A or 7E of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17, or other approved reference methods; and2. Conduct subsequent performance tests once per calendar year or every 400 hours or operation (whichever comes first) to demonstrate compliance with the nitrogen oxides emission standards under sub. (5) over a minimum of 3 consecutive steam generating unit operating hours at maximum heat input capacity using Method 7, 7A, 7E or other approved reference methods.(8) EMISSION MONITORING FOR SULFUR DIOXIDE. (a) Except as provided in pars. (b) and (f), the owner or operator of an affected facility subject to the sulfur dioxide standards under sub. (3) shall install, calibrate, maintain, and operate continuous emission monitoring systems (CEMS) for measuring sulfur dioxide concentrations and either oxygen (O2) or carbon dioxide (CO2) concentrations and shall record the output of the systems. The sulfur dioxide and either oxygen or carbon dioxide concentrations shall both be monitored at the inlet and outlet of the sulfur dioxide control device.(b) As an alternative to operating CEMS as required under par. (a), an owner or operator may elect to determine the average sulfur dioxide emissions and percent reduction by: 1. Collecting coal or oil samples in an as-fired condition at the inlet to the steam generating unit and analyzing them for sulfur and heat content according to Method 19 of Appendix A, 40 CFR part 60, incorporated by reference in s. NR 440.17. Method 19 provides procedures for converting these measurements into the format to be used in calculating the average sulfur dioxide input rate, or2. Measuring sulfur dioxide according to Method 6B of Appendix A, 40 CFR part 60, incorporated by reference in s. NR 440.17, at the inlet or outlet to the sulfur dioxide control system. An initial stratification test is required to verify the adequacy of the Method 6B sampling location. The stratification test shall consist of 3 paired runs of a suitable sulfur dioxide and carbon dioxide measurement train operated at the candidate location and a second similar train operated according to the procedures in Sectio n 3.2 and the applicable procedures in Section 7 of Performance Specification 2 of Appendix B, 40 CFR part 60, incorporated by reference in s. NR 440.17. Method 6B, Method 6A, or a combination of Methods 6 and 3 or 3B or Methods 6C and 3A, all in Appendix A of 40 CFR part 60, incorporated by reference in s. NR 440.17, are suitable measurement techniques. If Method 6B is used for the second train, sampling time and timer operation may be adjusted for the stratification test as long as an adequate sample volume is collected; however, both sampling trains are to be operated similarly. For the location to be adequate for Method 6B 24-hour tests, the mean of the absolute difference between the 3 paired runs shall be less than 10%.3. A daily sulfur dioxide emission rate, ED, shall be determined using the procedure described in Method 6A, Sectio n 7.6.2 (equation 6A-8) and stated in ng/J (lb/million Btu) heat input.4. The mean 30-day emission rate is calculated using the daily measured values in ng/J (lb/million Btu) for 30 successive steam generating unit operating days using equation 19-20 of Method 19.(c) The owner or operator of an affected facility shall obtain emission data for at least 75% of the operating hours in at least 22 out of 30 successive boiler operating days. If this minimum data requirement is not met with a single monitoring system, the owner or operator of the affected facility shall supplement the emission data with data collected with other monitoring systems as approved by the department or the reference methods and procedures as described in par. (b).(d) The 1-hour average sulfur dioxide emission rates measured by the CEMS required by par. (a) and required under s. NR 440.13(8) shall be expressed in ng/J or lb/million Btu heat input and shall be used to calculate the average emission rates under sub. (3). Each 1-hour average sulfur dioxide emission rate shall be based on more than 30 minutes of steam generating unit operation and include at least 2 data points with each representing a 15-minute period. Hourly sulfur dioxide emission rates are not calculated if the affected facility is operated less than 30 minutes in a 1-hour period and are not counted toward determination of a steam generating unit operating day. (e) The procedures in s. NR 440.13 shall be followed for installation, evaluation, and operation of the CEMS. 1. All CEMS shall be operated in accordance with the applicable procedures under Performance Specifications 1, 2, and 3, Appendix B, 40 CFR part 60, incorporated by reference in s. NR 440.17.2. Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 1 of Appendix F, 40 CFR part 60, incorporated by reference in s. NR 440.17.3. For affected facilities combusting coal or oil, alone or in combination with other fuels, the span value of the sulfur dioxide CEMS at the inlet to the sulfur dioxide control device shall be 125% of the maximum estimated hourly potential sulfur dioxide emissions of the fuel combusted, and the span value of the CEMS at the outlet to the sulfur dioxide control device shall be 50% of the maximum estimated hourly potential sulfur dioxide emissions of the fuel combusted.(f) The owner or operator of an affected facility that combusts very low sulfur oil is not subject to the emission monitoring requirements of this subsection if the owner or operator obtains fuel receipts as described in sub. (10) (r).(9) EMISSION MONITORING FOR PARTICULATE MATTER AND NITROGEN OXIDES.(a) The owner or operator of an affected facility subject to the opacity standard under sub. (4) shall install, calibrate, maintain, and operate a continuous monitoring system for measuring the opacity of emissions discharged to the atmosphere and record the output of the system.(b) Except as provided under pars. (g), (h) and (i), the owner or operator of an affected facility shall comply with one of the following: 1. Install, calibrate, maintain and operate a continuous monitoring system, and record the output of the system, for measuring nitrogen oxides emissions discharged to the atmosphere.2. If the owner or operator has installed a nitrogen oxides emission rate continuous emission monitoring system (CEMS) to meet the requirements of 40 CFR part 75 and is continuing to meet the ongoing requirements of 40 CFR part 75, that CEMS may be used to meet the requirements of this subsection, except that the owner or operator shall also meet the requirements of sub. (10). Data reported to meet the requirements of sub. (10) may not include data substituted using the missing data procedures in 40 CFR part 75, subpart D, nor shall the data have been bias adjusted according to the procedures of 40 CFR part 75.(c) The continuous monitoring systems required under par. (b) shall be operated and data recorded during all periods of operation of the affected facility except for continuous monitoring system breakdowns and repairs. Data shall be recorded during calibration checks, and zero and span adjustments.(d) The 1-hour average nitrogen oxides emission rates measured by the continuous nitrogen oxides monitor required by par. (b) and required under s. NR 440.13 shall be expressed in ng/J or lb/million Btu heat input and shall be used to calculate the average emission rates under sub. (5). The 1-hour averages shall be calculated using the data points required under s. NR 440.13(2). At least 2 data points shall be used to calculate each 1-hour average.(e) The procedures under s. NR 440.13 shall be followed for installation, evaluation, and operation of the continuous monitoring systems. 1. For affected facilities combusting coal, wood or municipal-type solid waste, the span value for a continuous monitoring system for measuring opacity shall be between 60 and 80%.2. For affected facilities combusting coal, oil, or natural gas, the span value for nitrogen oxides is determined as follows: | Fuel | Span values for nitrogen oxides (ppm) |
| a. | Natural gas | 500 |
| b. | Oil | 500 |
| c. | Coal | 1,000 |
| d. | Combination | 500 (x + y) + 1,000z |
where:
x is the fraction of total heat input derived from natural gas
y is the fraction of total heat input derived from oil
z is the fraction of total heat input derived from coal
3. All span values computed under subd. 2. for combusting mixtures of regulated fuels shall be rounded to the nearest 500 PPM.(f) When nitrogen oxides 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 standby monitoring systems, Method 7 or 7A of Appendix A, 40 CFR part 60, incorporated by reference in s. NR 440.17, or other approved reference methods to provide emission data for a minimum of 75% of the operating hours in each steam generating unit operating day, in at least 22 out of 30 successive steam generating unit operating days.(g) The owner or operator of an affected facility that has a heat input capacity of 73 MW (250 million Btu/hour) or less, and which has an annual capacity factor for residual oil having a nitrogen content of 0.30 weight % or less, natural gas, distillate oil, or any mixture of these fuels, greater than 10% (0.10) shall: 1. Comply with the provisions of pars. (b), (c), (d), (e) 2., (e) 3., and (f), or2. Monitor steam generating unit operating conditions and predict nitrogen oxides emission rates as specified in a plan submitted pursuant to sub. (10) (c).(h) The owner or operator of a duct burner, as described in sub. (2) (j), which is subject to the NOx standards of sub. (5) (a) 4. or (L), is not required to install or operate a continuous emissions monitoring system to measure NOx emissions.(i) The owner or operator of an affected facility described under sub. (5) (j) or (k) is not required to install or operate a continuous monitoring system for measuring nitrogen oxide emissions.(10) REPORTING AND RECORDKEEPING REQUIREMENTS.(a) The owner or operator of each affected facility shall submit notification of the date of initial startup, as provided by s. NR 440.07. This notification shall include: 1. The design heat input capacity of the affected facility and identification of the fuels to be combusted in the affected facility,2. If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or mixture of fuels under subs. (3) (d) 1., (4) (a) 2., 3. c., (c) 2. b., (d) 2. c., (5) (c), (d), (e), (i), (j) or (k), (6) (d), (7) (g) or (h), or (9) (i),3. The annual capacity factor at which the owner or operator anticipates operating the facility based on all fuels fired and based on each individual fuel fired, and4. Notification that an emerging technology will be used for controlling emissions of sulfur dioxide. The administrator will examine the description of the emerging technology and will determine whether the technology qualifies as an emerging technology. In making this determination, the administrator may require the owner or operator of the affected facility to submit additional information concerning the control device. The affected facility is subject to the provisions of sub. (3) (a) unless and until this determination is made by the administrator.(b) The owner or operator of each affected facility subject to the sulfur dioxide, particulate matter, or nitrogen oxides emission limits under subs. (3), (4), and (5) shall submit to the department the performance test data from the initial performance test and the performance evaluation of the CEMS using the applicable performance specifications in Appendix B, 40 CFR part 60, incorporated by reference in s. NR 440.17. The owner or operator of each affected facility described in sub. (5) (j) or (k) shall submit to the department the maximum heat input capacity data from the demonstration of the maximum heat input capacity of the affected facility.(c) The owner or operator of each affected facility subject to the nitrogen oxides standard of sub. (5) who seeks to demonstrate compliance with those standards through the monitoring of steam generating unit operating conditions under the provisions of sub. (9) (g) 2. shall submit to the department for approval a plan that identifies the operating conditions to be monitored under sub. (9) (g) 2. and the records to be maintained under par. (j). This plan shall be submitted to the department for approval within 360 days of the initial startup of the affected facility. The plan shall:1. Identify the specific operating conditions to be monitored and the relationship between these operating conditions and nitrogen oxides emission rates (i.e., ng/J or lbs/million Btu heat input). Steam generating unit operating conditions include, but are not limited to, the degree of staged combustion (i.e., the ratio of primary air to secondary and/or tertiary air) and the level of excess air (i.e., flue gas oxygen level);2. Include the data and information that the owner or operator used to identify the relationship between nitrogen oxides emission rates and these operating conditions;3. Identify how these operating conditions, including steam generating unit load, will be monitored under sub. (9) (g) on an hourly basis by the owner or operator during the period of operation of the affected facility; the quality assurance procedures or practices that will be employed to ensure that the data generated by monitoring these operating conditions will be representative and accurate; and the type and format of the records of these operating conditions, including steam generating unit load, that will be maintained by the owner or operator under par. (j). If the plan is approved, the owner or operator shall maintain records of predicted nitrogen oxide emission rates and the monitored operating conditions, including steam generating unit load, identified in the plan.(d) The owner or operator of an affected facility shall record and maintain records of the amounts of each fuel combusted during each day and calculate the annual capacity factor individually for coal, distillate oil, residual oil, natural gas, wood, and municipal-type solid waste for the reporting period. The annual capacity factor is determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end of each calendar month.(e) For an affected facility that combusts residual oil and meets the criteria under sub. (5) (j) or (k) or (7) (e) 4., the owner or operator shall maintain records of the nitrogen content of the residual oil combusted in the affected facility and calculate the average fuel nitrogen content for the reporting period. The nitrogen content shall be determined using ASTM method D3431-80 (reapproved 1987), Test Method for Trace Nitrogen in Liquid Petroleum Hydrocarbons, incorporated by reference in s. NR 440.17(2) (a) 48., or fuel specification data obtained from fuel suppliers. If residual oil blends are being combusted, fuel nitrogen specifications may be prorated based on the ratio of residual oils of different nitrogen content in the fuel blend.(f) For facilities subject to the opacity standard under sub. (4), the owner or operator shall maintain records of opacity.(g) Except as provided under par. (p), the owner or operator of an affected facility subject to nitrogen oxides standards under sub. (5) shall maintain records of the following information for each steam generating unit operating day: 2. The average hourly nitrogen oxides emission rates (expressed as NO2) (ng/J or lb/million Btu heat input) measured or predicted.3. The 30-day average nitrogen oxides emission rates (ng/J or lb/million Btu heat input) calculated at the end of each steam generating unit operating day from the measured or predicted hourly nitrogen oxide emission rates for the preceding 30 steam generating unit operating days.4. Identification of the steam generating unit operating days when the calculated 30-day average nitrogen oxides emission rates are in excess of the nitrogen oxides emissions standards under sub. (5), with the reasons for such excess emissions as well as a description of corrective actions taken.5. Identification of the steam generating unit operating days for which pollutant data have not been obtained, including reasons for not obtaining sufficient data and a description of corrective actions taken.6. Identification of the times when emission data have been excluded from the calculation of average emission rates and the reasons for excluding data.7. Identification of "F" factor used for calculations, method of determination, and type of fuel combusted.8. Identification of the times when the pollutant concentration exceeded full span of the continuous monitoring system.9. 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 Appendix B, 40 CFR part 60, incorporated by reference in s. NR 440.17.10. Results of daily CEMS drift tests and quarterly accuracy assessments as required under 40 CFR part 60, Appendix F, Procedure 1, incorporated by reference in s. NR 440.17.(h) The owner or operator of any affected facility in any category listed in subd. 1. or 2. is required to submit excess emission reports to the department for any excess emissions which occurred during the reporting period. 1. Any affected facility subject to the opacity standards under sub. (4) (f) or to the operating parameter monitoring requirements under s. NR 440.13(9) (a).2. Any affected facility which is subject to the nitrogen oxides standard of sub. (5), and that: a. Combusts natural gas, distillate oil, or residual oil with a nitrogen content of 0.3 weight % or less, orb. Has a heat input capacity of 73 MW (250 million Btu/hour) or less and is required to monitor nitrogen oxides emissions on a continuous basis under sub. (9) (g) 1. or steam generating unit operating conditions under sub. (9) (g) 2.3. For the purpose of sub. (4), excess emissions are defined as all 6-minute periods during which the average opacity exceeds the opacity standards under sub. (4) (f).4. For purposes of sub. (9) (g) 1., excess emissions are defined as any calculated 30-day rolling average nitrogen oxides emission rate, as determined under sub. (7) (e), which exceeds the applicable emission limits in sub. (5).(i) The owner or operator of any affected facility subject to the continuous monitoring requirements for nitrogen oxides under sub. (9) shall submit reports to the department containing the information recorded under par. (g).(j) The owner or operator of any affected facility subject to the sulfur dioxide standards under sub. (3) shall submit reports to the department.(k) For each affected facility subject to the compliance and performance testing requirements of sub. (6) and the reporting requirement in par. (j) the following information shall be reported to the department: 1. Calendar dates covered in the reporting period.2. Each 30-day average sulfur dioxide emission rate (ng/J or lb/million Btu heat input) measured during the reporting period, ending with the last 30-day period; reasons for noncompliance with the emission standards; and a description of corrective actions taken.3. Each 30-day average percent reduction in sulfur dioxide emissions calculated during the reporting period, ending with the last 30-day period; reasons for noncompliance with the emission standards; and a description of corrective actions taken.4. Identification of the steam generating unit operating days that coal or oil was combusted and for which sulfur dioxide or diluent (oxygen or carbon dioxide) data have not been obtained by an approved method for at least 75% of the operating hours in the steam generating unit operating day; justification for not obtaining sufficient data; and description of corrective action taken.5. Identification of the times when emissions data have been excluded from the calculation of average emission rates; justification for 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.6. Identification of "F" factor used for calculations, method of determination, and type of fuel combusted.7. Identification of times when hourly averages have been obtained based on manual sampling methods.8. Identification of the times when the pollutant concentration exceeded full span of the CEMS.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 440.17.10. Results of daily CEMS drift tests and quarterly accuracy assessments as required under 40 CFR part 60, Appendix F, Procedure 1, incorporated by reference in s. NR 440.17.11. The annual capacity factor of each fuel fired as provided under par. (d). (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:1. Calendar dates when the facility was in operation during the reporting period;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;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.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.5. Identification of "F" factor used for calculations, method of determination and type of fuel combusted.6. Identification of times when hourly averages have been obtained based on manual sampling methods.7. Identification of the times when the pollutant concentration exceeded full span of the CEMS.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 440.17.9. Results of daily CEMS drift tests and quarterly accuracy assessments as required under 40 CFR part 60, Appendix F, Procedure 1, incorporated by reference in s. NR 440.17.(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). 1. The number of hourly averages available for outlet emission rates and inlet emission rates.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 440.17.3. 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 7.4. 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.(n) If a percent removal efficiency by fuel pretreatment (%Rf) is used to determine the overall percent reduction (%Ro) under sub. (6), the owner or operator of the affected facility shall submit a signed statement with the report:1. Indicating what removal efficiency by fuel pretreatment (%Rf) was credited during the reporting period.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;3. Documenting the transport of the fuel from the fuel pretreatment facility to the steam generating unit.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.(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.(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: 2. The number of hours of operation, and3. A record of the hourly steam load.(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: 1. The annual capacity factor over the previous 12 months,2. The average fuel nitrogen content during the reporting period, if residual oil was fired.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.(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.(s) The owner or operator of an affected facility may submit electronic quarterly reports for SO2, NOx 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.(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.Wis. Admin. Code Department of Natural Resources NR 440.205
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.