Section NR 440.20 - Electric steam generating units for which construction is commenced after September 18, 1978(1) APPLICABILITY AND DESIGNATION OF AFFECTED FACILITY.(a) The affected facility to which this section applies is each electric utility steam generating unit: 1. That is capable of combusting more than 73 megawatts (250 million Btu/hour) heat input of fossil fuel, either alone or in combination with any other fuel; and2. For which construction or modification is commenced after September 18, 1978.(b) Unless and until s. NR 440.50 extends the applicability of s. NR 440.50 to electric utility steam generators, this section applies to electric utility combined cycle gas turbines that are capable of combusting more than 73 megawatts (250 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. Note: The gas turbine emissions are subject to s. NR 440.50.
(c) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels, will not bring that unit under the applicability of this section.(d) Any change to an existing steam generating unit originally designed to fire gaseous or liquid fossil fuels, to accommodate the use of any other fuel (fossil or nonfossil) will not bring that unit under the applicability of this section.(2) DEFINITIONS. As used in this section, terms not defined in this subsection have the meanings given in s. NR 440.02. (a) "24-hour period" means the period of time between 12:01 a.m. and 12:00 midnight.(b) "Anthracite" means coal that is classified as anthracite according to the ASTM Standard Specification for Classification of Coals by Rank, D388-99 (reapproved 2004), incorporated by reference in s. NR 440.17(2) (a) 12.(c) "Available purchase power" means the lesser of the following: 1. The sum of available system capacity in all neighboring companies.2. The sum of the rated capacities of the power interconnection devices between the principal company and all neighboring companies, minus the sum of the electric power load on these interconnections.3. The rated capacity of the power transmission lines between the power interconnection devices and the electric generating units (the unit in the principal company that has the malfunctioning flue gas desulfurization system and the unit or units in the neighboring company supplying replacement electrical power) less the electric power load on these transmission lines.(d) "Available system capacity" means the capacity determined by subtracting the system load and the system emergency reserves from the net system capacity.(e) "Boiler operating day" means a 24-hour period during which fossil fuel is combusted in a steam generating unit for the entire 24 hours.(f) "Coal refuse" means waste products of coal mining, physical coal cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.(g) "Combined cycle gas turbine" means a stationary turbine combustion system where heat from the turbine exhaust gases is recovered by a steam generating unit. (gr) "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 or kiln, to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit.(h) "Electric utility combined cycle gas turbine" means any combined cycle gas turbine used for electric generation that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. Any steam distribution system that is constructed for the purpose of providing steam to a steam-electric generator that would produce electrical power for sale is also considered in determining the electrical energy output capacity of the affected facility.(i) "Electric utility company" means the largest interconnected organization, business or governmental entity that generates electric power for sale (e.g., a holding company with operating subsidiary companies).(j) "Electric utility steam generating unit" means any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. Any steam supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is also considered in determining the electrical energy output capacity of the affected facility.(k) "Emergency condition" means that period of time when:1. The electric generation output of an affected facility with a malfunctioning flue gas desulfurization system cannot be reduced or electrical output must be increased because: a. All available system capacity in the principal company interconnected with the affected facility is being operated, andb. All available purchase power interconnected with the affected facility is being obtained, or2. The electric generation demand is being shifted as quickly as possible from an affected facility with a malfunctioning flue gas desulfurization system to one or more electrical generating units held in reserve by the principal company or by a neighboring company, or3. An affected facility with a malfunctioning flue gas desulfurization system becomes the only available unit to maintain a part or all of the principal company's system emergency reserves and the unit is operated in spinning reserve at the lowest practical electric generation load consistent with not causing significant physical damage to the unit. If the unit is operated at a higher load to meet load demand, an emergency condition would not exist unless the conditions under subd. 1. apply. (L) "Fossil fuel" means natural gas, petroleum, coal, and any form of solid, liquid or gaseous fuel derived from such material for the purpose of creating useful heat. (Lm) "Gross output" means the gross useful work performed by the steam generated. For units generating only electricity, the gross useful work performed is the gross electrical output from the turbine or generator set. For cogeneration units, the gross useful work performed is the gross electrical output plus one half the useful thermal output (that is, steam delivered to an industrial process).(m) "Interconnected" means that 2 or more electric generating units are electrically tied together by a network of power transmission lines, and other power transmission equipment.(n) "Lignite" means coal that is classified as lignite A or B according to the ASTM Standard Specification for Classification of Coals by Rank, D388-99 (reapproved 2004), incorporated by reference in s. NR 440.17(2) (a) 12.(o) "Neighboring company" means any one of those electric utility companies with one or more electric power interconnections to the principal company and which have geographically adjoining service areas.(p) "Net system capacity" means the sum of the net electric generating capability (not necessarily equal to rated capacity) of all electric generating equipment owned by an electric utility company (including steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and all other electric generating equipment) plus firm contractual purchases that are interconnected to the affected facility that has the malfunctioning flue gas desulfurization system. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement.(q) "Potential combustion concentration" means the theoretical emissions (ng/J, lb/million Btu heat input) that would result from combustion of a fuel in an uncleaned state without emission control systems) and: 1. For particulate matter is: a. 3,000 ng/J (7.0 lb/million Btu) heat input for solid fuel; andb. 73 ng/J (0.17 lb/million Btu) heat input for liquid fuels.2. For sulfur dioxide is determined under sub. (9) (b).3. For nitrogen oxides is: a. 290 ng/J (0.67 lb/million Btu) heat input for gaseous fuels;b. 310 ng/J (0.72 lb/million Btu) heat input for liquid fuels; andc. 990 ng/J (2.30 lb/million Btu) heat input for solid fuels.(r) "Potential electrical output capacity" means 33% of the maximum design heat input capacity of the system generating unit (e.g., a steam generating unit with a 100-MW (340 million Btu/hr) fossil-fuel heat input capacity would have a 33-MW potential electrical output capacity). For electric utility combined cycle gas turbines the potential electrical output capacity is determined on the basis of the fossil-fuel firing capacity of the steam generator exclusive of the heat input and electrical power contribution by the gas turbine.(s) "Principal company" means the electric utility company which owns the affected facility.(t) "Resource recovery unit" means a facility that combusts more than 75% nonfossil fuel on a quarterly (calendar) heat input basis.(u) "Solid-derived fuel" means any solid, liquid or gaseous fuel derived from solid fuel for the purpose of creating useful heat and includes, but is not limited to, solvent refined coal, liquified coal and gasified coal.(v) "Spare flue gas desulfurization system module" means a separate system of sulfur dioxide emission control equipment capable of treating an amount of flue gas equal to the total amount of flue gas generated by an affected facility when operated at maximum capacity divided by the total number of nonspare flue gas desulfurization modules in the system.(w) "Spinning reserve" means the sum of the unutilized net generating capability of all units of the electric utility company that are synchronized to the power distribution system and that are capable of immediately accepting additional load. The electric generating capability of equipment under multiple ownership shall be prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement.(x) "Steam generating unit" means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam including fossil-fuel-fired steam generators associated with combined cycle gas turbines but nuclear steam generators are not included.(y) "Subbituminous coal" means coal that is classified as subbituminous A, B or C according to the ASTM Standard Specification for Classification of Coals by Rank, D388-99 (reapproved 2004), incorporated by reference in s. NR 440.17(2) (a) 12.(z) "System emergency reserves" means an amount of electric generating capacity equivalent to the rated capacity of the single largest electric generating unit in the electric utility company (including steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units and all other electric generating equipment) which is interconnected with the affected facility that has the malfunctioning flue gas desulfurization system. The electric generating capability of equipment under multiple ownership shall be prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement. (zm) "System load" means the entire electric demand of an electric utility company's service area interconnected with the affected facility that has the malfunctioning flue gas desulfurization system plus firm contractual sales to other electric utility companies. Sales to other electric utility companies (e.g., emergency power) not on a firm contractual basis may also be included in the system load when no available system capacity exists in the electric utility company to which the power is supplied for sale.(3) STANDARD FOR PARTICULATE MATTER. (a) On and after the date on which the performance test required to be conducted under s. NR 440.08 is completed, no owner or operator subject to the provisions of this section may cause to be discharged into the atmosphere from any affected facility any gases which contain particulate matter in excess of: 1. 13 ng/J (0.03 lb/million Btu) heat input derived from the combustion of solid, liquid or gaseous fuel;2. One percent of the potential combustion concentration (99% reduction) when combusting solid fuel; and3. 30% of potential combustion concentration (70% reduction) when combusting liquid fuel.(b) On and after the date the particulate matter performance test required to be conducted under s. NR 440.08 is completed, no owner or operator subject to the provisions of this section may cause to be discharged into the atmosphere from any affected facility any gases which exhibit greater than 20% opacity (6-minute average), except for one 6-minute period per hour of not more than 27% opacity.(4) STANDARD FOR SULFUR DIOXIDE. (a) On and after the date on which the initial performance test required to be conducted under s. NR 440.08 is completed, no owner or operator subject to the provisions of this section may cause to be discharged into the atmosphere from any affected facility which combusts solid fuel or solid-derived fuel, except as provided under par. (c), (d), (f) or (h), any gases which contain sulfur dioxide in excess of: 1. 520 ng/J (1.20 lb/million Btu) heat input and 10% of the potential combustion concentration (90% reduction), or2. 30% of the potential combustion concentration (70% reduction), when emissions are less than 260 ng/J (0.60 lb/million Btu) heat input.(b) On and after the date on which the initial performance test required to be conducted under s. NR 440.08 is completed, no owner or operator subject to the provisions of this section may cause to be discharged into the atmosphere from any affected facility which combusts liquid or gaseous fuels (except for liquid or gaseous fuels derived from solid fuels and as provided under par. (h)), any gases which contain sulfur dioxide in excess of: 1. 340 ng/J (0.80 lb/million Btu) heat input and 10% of the potential combustion concentration (90% reduction), or2. 100% of the potential combustion concentration (zero percent reduction) when emissions are less than 86 ng/J (0.20 lb/million Btu) heat input.(c) On and after the date on which the initial performance test required to be conducted under s. NR 440.08 is complete, no owner or operator subject to the provisions of this section may cause to be discharged into the atmosphere from any affected facility which combusts solid solvent refined coal (SRC-I) any gases which contain sulfur dioxide in excess of 520 ng/J (1.20 lb/million Btu) heat input and 15% of the potential combustion concentration (85% reduction) except as provided under par. (f); compliance with the emission limitation is determined on a 30-day rolling average basis and compliance with the percent reduction requirement is determined on a 24-hour basis.(d) Sulfur dioxide emissions shall be limited to no more than 520 ng/J (1.20 lb/million Btu) heat input from any affected facility which: 1. Combusts 100% anthracite, or2. Is classified as a resource recovery unit.(f) The emission reduction requirements under this subsection do not apply to any affected facility that is operated under an SO2 commercial demonstration permit issued by the administrator in accordance with the provisions of 40 CFR 60.47Da.(g) Compliance with the emission limitation and percent reduction requirements under this subsection are both determined on a 30-day rolling average basis except as provided under par. (c).(h) When different fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:1. If emissions of sulfur dioxide to the atmosphere are greater than 260 ng/J (0.60 lb/million Btu) heat input: Es = [340 x + 520 y]/100
and
%Ps = 10
2. If emissions of sulfur dioxide to the atmosphere are equal to or less than 260 ng/J (0.60 lb/million Btu) heat input: Es = [340 x + 520 y]/100
and
%Ps = [10 x + 30 y]/100
where:
Es is the prorated sulfur dioxide emission limit (ng/J heat input)
%Ps is the percentage of potential sulfur dioxide emission allowed
x is the percentage of total heat input derived from the combustion of liquid or gaseous fuels, excluding solid-derived fuels
y is the percentage of total heat input derived from the combustion of solid fuel, including solid-derived fuels
(5) STANDARD FOR NITROGEN OXIDES.(a) On and after the date on which the initial performance test required to be conducted under s. NR 440.08 is completed, no owner or operator subject to the provisions of this section may cause to be discharged into the atmosphere from any affected facility, except as provided under pars. (b) and (d), any gases which contain nitrogen oxides, expressed as NO2, in excess of the following emission limits, based on a 30-day rolling average, except as provided under sub. (6) (j) 1.: 1. NOx emission limits. | Emission limit for heat input |
| Fuel type | ng/J | (lb/million Btu) |
| a. | Gaseous fuels: |
| Coal-derived fuels . | 210 | 0.50 |
| All other fuels . . . . | 86 | 0.20 |
| b. | Liquid fuels: |
| Coal-derived fuels . | 210 | 0.50 |
| Shale oil ......... | 210 | 0.50 |
| All other fuels . . . . | 130 | 0.30 |
| Coal-derived fuels . | 210 | 0.50 |
| Any fuel containing more than 25%, by weight, coal refuse ........ | (1) | (1) |
| c. | Solid fuels: |
| Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace2 ...... | 340 | 0.80 |
| Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat input emission limit2 ......... | 260 | 0.60 |
| Subbituminous coal .......... | 210 | 0.50 |
| Bituminous coal . . . | 260 | 0.60 |
| Anthracite coal . . . . | 260 | 0.60 |
| All other fuels . . . . | 260 | 0.60 |
1 Exempt from NOx standards and NOx monitoring requirements.
2 Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel.
2. NOx reduction requirements. | Percent reduction of |
| potential combustion |
| Fuel type | concentration |
| a. | Gaseous fuels ........... | 25 |
| b. | Liquid fuels ............. | 30 |
| c. | Solid fuels .............. | 65 |
(b) The emission limitations under par. (a) do not apply to any affected facility which is combusting coal-derived liquid fuel and is operating under a commercial demonstration permit issued by the administrator in accordance with the provisions of 40 CFR 60.47Da. (c) Except as provided under par. (d), when 2 or more fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula: En = [86 w + 130 x + 210 y + 260 z + 340 v] /100
where:
En is the applicable standard for nitrogen oxides when multiple fuels are combusted simultaneously (ng/J heat input)
w is the percentage of total heat input derived from the combustion of fuels subject to the 86 ng/J heat input standard
x is the percentage of total heat input derived from the combustion of fuels subject to the 130 ng/J heat input standard
y is the percentage of total heat input derived from the combustion of fuels subject to the 210 ng/J heat input standard
z is the percentage of total heat input derived from the combustion of fuels subject to the 260 ng/J heat input standard
v is the percentage of total heat input delivered from the combustion of fuels subject to the 340 ng/J heat input standard
(d)1. On and after the date on which the initial performance test required to be conducted under s. NR 440.08 is completed, no new source owner or operator subject to the provisions of this section may cause to be discharged into the atmosphere from any affected facility for which construction commenced after July 9, 1997 any gases which contain nitrogen oxides, expressed as NO2, in excess of 200 nanograms per joule (1.6 pounds per megawatt-hour) gross energy output, based on a 30-day rolling average, except as provided under sub. (6) (k) 1.2. On and after the date on which the initial performance test required to be conducted under s. NR 440.08 is completed, no existing source owner or operator subject to the provisions of this section may cause to be discharged into the atmosphere from any affected facility for which construction commenced after July 9, 1997 any gases which contain nitrogen oxides, expressed as NO2, in excess of 65 nanograms per joule (0.15 pounds per million Btu) heat input, based on a 30-day rolling average.(6) COMPLIANCE PROVISIONS. (a)Percent reduction requirement for particulate matter. Compliance with the particulate matter emission limitation under sub. (3) (a) 1. constitutes compliance with the percent reduction requirements for particulate matter under sub. (3) (a) 2. and 3.(b)Percent reduction requirement for NOx. Compliance with the nitrogen oxides emission limitation under sub. (5) (a) 1. constitutes compliance with the percent reduction requirements under sub. (5) (a) 2.(c)Compliance exception. The particulate matter emissions standards under sub. (3) and the nitrogen oxides emission standards under sub. (5) apply at all times except during periods of startup, shutdown or malfunction. The sulfur dioxide emission standards under sub. (4) apply at all times except during periods of startup, shutdown or when both emergency conditions exist and the procedures under par. (d) are implemented.(d)Operation with malfunctioning flue gas desulfurization. During emergency conditions in the principal company, an affected facility with a malfunctioning flue gas desulfurization system may be operated if sulfur dioxide emissions are minimized by:1. Operating all operable flue gas desulfurization system modules, and bringing back into operation any malfunctioned module as soon as repairs are completed.2. Bypassing flue gases around only those flue gas desulfurization system modules that have been taken out of operation because they were incapable of any sulfur dioxide emission reduction or which would have suffered significant physical damage if they had remained in operation, and3. Designing, constructing and operating a spare flue gas desulfurization system module for an affected facility larger than 365 MW (1,250 million Btu/hr) heat input (approximately 125 MW electrical output capacity). The department may at its discretion require the owner or operator within 60 days of notification to demonstrate spare module capability. To demonstrate this capability, the owner or operator shall demonstrate compliance with the appropriate requirements under sub. (4) (a), (b), (d) and (h) for any period of operation lasting from 24 hours to 30 days when: a. Any one flue gas desulfurization module is not operated.b. The affected facility is operating at the maximum heat input rate,c. The fuel fired during the 24-hour to 30-day period is representative of the type and average sulfur content of fuel used over a typical 30-day period, andd. The owner or operator has given the department at least 30 days notice of the date and period of time over which the demonstration will be performed.(e)Compliance after the initial performance test. After the initial performance test required under s. NR 440.08, compliance with the sulfur dioxide emission limitations and percentage reduction requirements under sub. (4) and the nitrogen oxides emission limitations under sub. (5) shall be based on the average emission rate for 30 successive boiler operating days. A separate performance test is completed at the end of each boiler operating day after the initial performance test, and a new 30-day average emission rate for both sulfur dioxide and nitrogen oxides and a new percent reduction of sulfur dioxide are calculated to show compliance with the standards.(f)Initial performance test. For the initial performance test required under s. NR 440.08, compliance with the sulfur dioxide emission limitations and percent reduction requirements under sub. (4) and the nitrogen oxides emission limitation under sub. (5) shall be based on the average emission rates for sulfur dioxide, nitrogen oxides, and percent reduction for sulfur dioxide for the first 30 successive boiler operating days. The initial performance test is the only test in which at least 30 days prior notice is required unless otherwise specified by the department. The initial performance test shall be scheduled so that the first boiler operating day of the 30 successive boiler operating days is completed 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 the facility.(g)Compliance calculations for SO2 and NOx. Compliance shall be determined by calculating the arithmetic average of all hourly emission rates for SO2 and NOx for the 30 successive boiler operating days, except for data obtained during startup, shutdown, malfunction (NOx only) or emergency conditions (SO2 only). Compliance with the percentage reduction requirement for SO2 shall be determined based on the average inlet and average outlet SO2 emission rates for the 30 successive boiler operating days.(h)Quantity of emission data below minimum. If an owner or operator has not obtained the minimum quantity of emission data as required under sub. (7), compliance of the affected facility with the emission requirements under subs. (4) and (5) for the day on which the 30-day period ends may be determined by the department by following the applicable procedures in section 7.0 of Method 19, 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17.(i)Compliance provisions for sources subject to sub. (5) (d) 1. The owner or operator of an affected facility subject to sub. (5) (d) 1. (new source constructed after July 7, 1997) shall calculate NOx emissions by multiplying the average hourly NOx output concentration measured according to the provisions of sub. (7) (c) by the average hourly flow rate measured according to the provisions of sub. (7) (L) and divided by the average hourly gross energy output measured according to the provisions of sub. (7) (k).(j)Compliance provisions for duct burners subject to sub. (5) (a) 1. To determine compliance with the emissions limits for NOx required by sub. (5) (a) for duct burners used in combined cycle systems, the owner or operator of an affected duct burner shall use one of the following procedures: 1. Conduct the performance test required under s. NR 440.08 using the appropriate methods in 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1). Compliance with the emissions limits under sub. (5) (a) 1. shall be determined on the average of 3 (nominal 1-hour) runs for the initial and subsequent performance tests. During the performance test, one sampling site shall be located in the exhaust of the turbine prior to the duct burner. A second sampling site shall be located at the outlet from the heat recovery steam generating unit. Measurements shall be taken at both sampling sites during the performance test.2. Use the continuous emission monitoring system specified under sub. (7) for measuring NOx and oxygen and meet the requirements of sub. (7). Data from a CEMS certified or recertified according to the provisions of 40 CFR 75.20, meeting the QA and QC requirements of 40 CFR 75.21, and validated according to 40 CFR 75.23, may be used. The sampling site shall be located at the outlet from the steam generating unit. The NOx emission rate at the outlet from the steam generating unit shall constitute the NOx emission rate from the duct burner of the combined cycle system.(k)Compliance provisions for duct burners subject to sub. (5) (d) 1. To determine compliance with the emissions limits for NOx required by sub. (5) (d) 1. for duct burners used in combined cycle systems, either of the procedures described in subd. 1. or 2. shall be used.1.a. Compute the emission rate (E) of NOx using the following equation: See PDF for diagram
where
E is the emission rate of NOx from the duct burner, ng/J (lb/Mwh) gross output
Csg is the average hourly concentration of NOx exiting the steam generating unit, ng/dscm (lb/dscf)
Cte is the average hourly concentration of NOx in the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf)
Qsg is the average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr (dscf/hr)
Qte is the average hourly volumetric flow rate of exhaust gas from combustion turbine, dscm/hr (dscf/hr)
Osg is the average hourly gross energy output from steam generating unit, J (Mwh)
h is the average hourly fraction of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner
b. Use Method 7E in 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), to determine the NOx concentrations (Csg and Cte). Use Method 2, 2F or 2G in 40 CFR part 60, Appendix A, as appropriate, to determine the volumetric flow rates (Qsg and Qte) of the exhaust gases. The volumetric flow rate measurements shall be taken at the same time as the concentration measurements.c. Develop, demonstrate and provide information satisfactory to the department to determine the average hourly gross energy output from the steam generating unit, and the average hourly percentage of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner.d. Determine compliance with the emissions limits under sub. (5) (d) 1. by the 3-run average (nominal 1-hour runs) for the initial and subsequent performance tests.2. Use a 30-day rolling average basis by doing all of the following: a. Compute the emission rate (E) of NOx using the following equation: See PDF for diagram
where:
E is the emission rate of NOx from the duct burner, ng/J (lb/Mwh) gross output
Csg is the average hourly concentration of NOx exiting the steam generating unit, ng/dscm (lb/dscf)
Qsg is the average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr (dscf/hr)
Occ is the average hourly gross energy output from entire combined cycle unit, J (Mwh)
b. Use the continuous emissions monitoring system specified under sub. (7) for measuring NOx and oxygen to determine the average hourly NOx concentrations (Csg). The continuous flow monitoring system specified in sub. (7) (L) shall be used to determine the volumetric flow rate (Qsg) of the exhaust gas. The sampling site shall be located at the outlet from the steam generating unit. Data from a continuous flow monitoring system certified or recertified following procedures specified in 40 CFR 75.20, meeting the quality assurance and quality control requirements of 40 CFR 75.21 and validated according to 40 CFR 75.23 may be used.c. Use the continuous monitoring system specified under sub. (7) (k) for measuring and determining gross energy output to determine the average hourly gross energy output from the entire combined cycle unit (Occ), which is the combined output from the combustion turbine and the steam generating unit.d. The owner or operator may, in lieu of installing, operating and recording data from the continuous flow monitoring system specified in sub. (7) (L), determine the mass rate (lb/hr) of NOx emissions by installing, operating and maintaining continuous fuel flow meters following the appropriate measurements procedures specified in 40 CFR part 75, Appendix D, incorporated by reference in s. NR 440.17(1). If this compliance option is selected, the emission rate (E) of NOx shall be computed using the following equation: See PDF for diagram
where:
E is the emission rate of NOx from the duct burner, ng/J (lb/Mwh) gross output
ERsg is the average hourly emission rate of NOx exiting the steam generating unit heat input calculated using appropriate F-factor as described in Method 19 in 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1), ng/J (lb/million Btu)
Hcc is the average hourly heqt input rate of entire combined cycle unit, J/hr (million Btu/hr)
Occ is the average hourly gross energy output from entire combined cycle unit, J(Mwh)
3. When an affected duct burner steam generating unit utilizes a common steam turbine with one or more affected duct burner steam generating units, the owner or operator shall do one of the following:a. Determine compliance with the applicable NOx emissions limits by measuring the emissions combined with the emissions from the other units utilizing the common steam turbine.b. Develop, demonstrate and provide information satisfactory to the department on methods for apportioning the combined gross energy output from the steam turbine for each of the affected duct burners. The department may approve a demonstrated substitute method for apportioning the combined gross energy output measured at the steam turbine whenever the demonstration ensures accurate estimation of emissions regulated under this section.(7) EMISSION MONITORING. (a) The owner or operator of an affected facility shall install, calibrate, maintain and operate a continuous monitoring system, and record the output of the system, for measuring the opacity of emissions discharged to the atmosphere, except where gaseous fuel is the only fuel combusted. If opacity interference due to water droplets exists in the stack (for example, from the use of a flue gas desulfurization (FGD) system), the opacity shall be monitored upstream of the interference (at the inlet to the FGD system). If opacity interference is experienced at all locations (both at the inlet and outlet of the sulfur dioxide control system), alternate parameters indicative of the particulate matter control system's performance shall be monitored (subject to the approval of the department).(b) The owner or operator of an affected facility shall install, calibrate, maintain and operate a continuous monitoring system, and record the output of the system, for measuring sulfur dioxide emissions, except where natural gas is the only fuel combusted, as follows: 1. Sulfur dioxide emissions shall be monitored at both the inlet and outlet of the sulfur dioxide control device.2. For a facility which qualifies under the provisions of sub. (4) (d), sulfur dioxide emissions shall only be monitored as discharged to the atmosphere.3. An "as fired" fuel monitoring system (upstream of coal pulverizers) meeting the requirements of Method 19, 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17, may be used to determine potential sulfur dioxide emissions in place of a continuous sulfur dioxide emission monitor at the inlet to the sulfur dioxide control device as required under subd. 1.(c)1. The owner or operator of an affected facility shall 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, except as provided in subd. 2.2. 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 requirement of this paragraph, except that the owner or operator shall also meet the requirements of sub. (9). Data reported to meet the requirements of sub. (9) 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.(d) The owner or operator of an affected facility shall install, calibrate, maintain and operate a continuous monitoring system, and record the output of the system, for measuring the oxygen or carbon dioxide content of the flue gases at each location where sulfur dioxide or nitrogen oxides emissions are monitored.(e) The continuous monitoring systems under pars. (b), (c) and (d) shall be operated and data recorded during all periods of operation of the affected facility including periods of startup, shutdown, malfunction or emergency conditions, except for continuous monitoring system breakdowns, repairs, calibration checks and zero and span adjustments.(f) The owner or operator shall obtain emission data for at least 18 hours in at least 22 out of 30 successive boiler operating days. If this minimum data requirement cannot be met with a continuous monitoring system, the owner or operator shall supplement emission data with other monitoring systems approved by the department or the reference methods and procedures as described in par. (h).(g) The one-hour averages required under s. NR 440.13(8) shall be expressed in ng/J (lbs/million Btu) heat input and used to calculate the average emission rates under sub. (6). The one-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 the one-hour averages.(h) When it becomes necessary to supplement continuous monitoring system data to meet the minimum data requirements in par. (f), the owner or operator shall use the reference methods and procedures as specified in this paragraph. Acceptable alternative methods and procedures are given in par. (j).1. Method 6 shall be used to determine the SO2 concentration at the same location as the SO2 monitor. Samples shall be taken at 60 minute intervals. The sampling time and sample volume for each sample shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Each sample represents a 1-hour average.2. Method 7 shall be used to determine the NOx concentration at the same location as the NOx monitor. Samples shall be taken at 30-minute intervals. The arithmetic average of 2 consecutive samples represent a 1-hour average.3. The emission rate correction factor, integrated bag sampling and analysis procedure of Method 3B shall be used to determine the O2 or CO2 concentration at the same location as the O2 or CO2 monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample represents a 1-hour average.4. The procedures in Method 19 shall be used to compute each 1-hour average concentration in ng/J (lb/million Btu) heat input.(i) The owner or operator shall use methods and procedures in this paragraph to conduct monitoring system performance evaluations under s. NR 440.13(3) and calibration checks under s. NR 440.13(4). Acceptable alternative methods and procedures are given in par. (j). 1. Methods 3B, 6 and 7 shall be used to determine O2, SO2 and NOx concentrations, respectively.2. SO2 or NOx (NO), as applicable, shall be used for preparing the calibration gas mixtures (in N2, as applicable) under Performance Specification 2 of Appendix B of 40 CFR part 60, incorporated by reference in s. NR 440.17.3. For affected facilities burning only fossil fuel, the span value for a continuous monitoring system for measuring opacity shall be between 60 and 80% and for a continuous monitoring system measuring nitrogen oxides shall be determined as follows: | Fossil fuel | Span value for nitrogen oxides (ppm) |
| a. | Gas .................. | 500 |
| b. | Liquid ................ | 500 |
| c. | Solid ................. | 1,000 |
| d. | Combination ........... | 500(x+ y)+ 1,000z |
where:
x is the fraction of total heat input derived from gaseous fossil fuel
y is the fraction of total heat input derived from liquid fossil fuel
z is the fraction of total heat input derived from solid fossil fuel
4. All span values computed under par. (b) 3. for burning combinations of fossil fuels shall be rounded to the nearest 500 ppm.5. For affected facilities burning fossil fuel, alone or in combination with nonfossil fuel, the span value of the sulfur dioxide continuous monitoring system at the inlet to the sulfur dioxide control device shall be 125% of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the sulfur dioxide control device shall be 50% of maximum estimated hourly potential emissions of the fuel fired.(j) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this subsection. All test methods are in Appendix A of 40 CFR part 60, incorporated by reference in s. NR 440.17.1. For Method 6, Method 6A or 6B (whenever Methods 6 and 3 or 3B data are used) or 6C may be used. Each Method 6B sample obtained over 24 hours represents 24 1-hour averages. If Method 6A or 6B is used under par. (i), the conditions under s. NR 440.19(7) (d) 1. apply; these conditions do not apply under par. (h). 2. For Method 7, Method 7A, 7C, 7D or 7E may be used. If Method 7C, 7D or 7E is used, the sampling time for each run shall be 1 hour.3. For Method 3, Method 3A may be used if the sampling time is 1 hour.4. For Method 3B, Method 3A may be used.(k) The procedures specified in subds. 1. to 3. shall be used to determine gross output for sources demonstrating compliance with the output-based standard under sub. (5) (d) 1. 1. The owner or operator of an affected facility with electricity generation shall install, calibrate, maintain and operate a wattmeter; measure gross electrical output in megawatt-hours on a continuous basis and record the output of the monitor.2. The owner or operator of an affected facility with process steam generation shall install, calibrate, maintain and operate meters for steam flow, temperature and pressure; measure gross process steam output in joules per hour (Btu per hour) on a continuous basis and record the output of the monitor.3. For affected facilities generating process steam in combination with electrical generation, the gross energy output is determined from the gross electrical output measured in accordance with subd. 1. plus 50% of the gross thermal output of the process steam measured in accordance with subd. 2. (L) The owner or operator of an affected facility demonstrating compliance with the output-based standard under sub. (5) (d) 1. shall do one of the following: 1. Install, certify, operate and maintain a continuous flow monitoring system meeting the requirements of Performance Specification 6 in 40 CFR part 60, Appendix B, and Procedure 1 in 40 CFR part 60, Appendix F, both incorporated by reference in s. NR 440.17(1), and record the output of the system for measuring the flow of exhaust gases discharged to the atmosphere.2. Use data from a continuous flow monitoring system certified according to the requirements of 40 CFR 75.20, meeting the applicable quality control and quality assurance requirement of 40 CFR 75.21 and validated according to 40 CFR 75.23.(m) The owner or operator of an affected unit that qualifies as a gas-fired or oil-fired unit, as defined in 40 CFR 72.2, may use, as an alternative to the requirements specified in either par. (L) 1. or 2., a fuel flow monitoring system certified and operated according to the requirements of 40 CFR part 75, Appendix D, incorporated by reference in s. NR 440.17(1).(n) The owner or operator of a duct burner which is subject to the NOx standards of sub. (5) (a) 1. or (d) 1. is not required to install or operate a continuous emissions monitoring system to measure NOx emissions; a wattmeter to measure gross electrical output; meters to measure steam flow, temperature and pressure; and a continuous flow monitoring system to measure the flow of exhaust gases discharged to the atmosphere.(8) COMPLIANCE DETERMINATION PROCEDURES AND METHODS. (a) In conducting the performance tests required in s. NR 440.08, the owner or operator shall use as reference methods and procedures the methods 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 for SO2 and NOx. Acceptable alternative methods are given in par. (e).(b) The owner or operator shall determine compliance with the particulate matter standards in sub. (3) as follows: 1. The dry basis F factor (O2) procedures in Method 19 shall be used to compute the emission rate of particulate matter.2. For the particulate matter concentration, Method 5 shall be used at affected facilities without wet FGD systems and Method 5B shall be used after wet FGD systems. a. The sampling time and sample volume for each run shall be at least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder heating system in the sampling train may be set to provide an average gas temperature of no greater than 160"14°C (320"25°F).b. For each particulate run, the emission rate correction factor, integrated or grab sampling and analysis procedures of Method 3B shall be used to determine the O2 concentration. The O2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate run. If the particulate run has more than 12 traverse points, the O2 simultaneous traverse points may be reduced to 12 provided that Method 1 is used to locate the 12 O2 traverse points. If the grab sampling procedure is used, the O2 concentration for the run shall be the arithmetic mean of the sample O2 concentrations at all traverse points.3. Method 9 and the procedures in s. NR 440.11 shall be used to determine opacity.(c) The owner or operator shall determine compliance with the SO2 standards in sub. (4) as follows: 1. The percent of potential SO2 emissions (% Ps) to the atmosphere shall be computed using the following equation: % Ps = [(100 - %Rf) (100 - %R g)]/100
where:
%Ps is the percent of potential SO2 emissions, percent
%Rf is the percent reduction from fuel pretreatment, percent
%Rg is the percent reduction by SO2 control system, percent
2. The procedures in Method 19 may be used to determine percent reduction (%Rf) of sulfur by such processes as fuel pretreatment (physical coal cleaning, hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom and flyash interactions. This determination is optional.3. The procedures in Method 19 shall be used to determine the percent SO2 reduction (%Rg) of any SO2 control system. Alternatively, a combination of an`as fired' fuel monitor and emission rates measured after the control system, following the procedures in Method 19, may be used if the percent reduction is calculated using the average emission rate from the SO2 control device and the average SO2 input rate from the `as fired' fuel analysis for 30 successive boiler operating days.4. The appropriate procedures in Method 19 shall be used to determine the emission rate.5. The continuous monitoring system in sub. (7) (b) and (d) shall be used to determine the concentrations of SO2 and CO2 or O2.(d) The owner or operator shall determine compliance with the NOx standard in sub. (5) as follows: 1. The appropriate procedures in Method 19 shall be used to determine the emission rate of NOx.2. The continuous monitoring system in sub. (7) (c) and (d) shall be used to determine the concentrations of NOx and CO2 or O2.(e) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this subsection:1. For Method 5 or 5B, Method 17 may be used at facilities with or without wet FGD systems if the stack temperature at the sampling location does not exceed an average temperature of 160°C (320 °F). The procedures of sections 2.1 and 2.3 of Method 5B may be used in Method 17 only if it is used after wet FGD systems. Method 17 may not be used after wet FGD systems if the effluent is saturated or laden with water droplets.2. The Fc factor (CO2) procedures in Method 19 may be used to compute the emission rate of particulate matter under the stipulations of s. NR 440.19(7) (d) 1. The CO2 shall be determined in the same manner as the O2 concentration.(f) Electric utility combined cycle gas turbines are performance tested for particulate matter, sulfur dioxide and nitrogen oxides using the procedures of Method 19 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17(1). The sulfur dioxide and nitrogen oxides emission rates from the gas turbine used in Method 19 calculations are determined when the gas turbine is performance tested under s. NR 440.50. The potential uncontrolled particulate matter emission rate from a gas turbine is defined as 17 ng/J (0.04 lb/million Btu) heat input.(9) REPORTING REQUIREMENTS. (a) For sulfur dioxide, nitrogen oxides and particulate matter emissions, the performance test data from the initial performance test and from the performance evaluation of the continuous monitors (including the transmissometer) shall be submitted to the department.(b) For sulfur dioxide and nitrogen oxides the following information shall be reported to the department for each 24-hour period.2. The average sulfur dioxide and nitrogen oxide emission rates (ng/J or lb/million Btu) for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for noncompliance with the emission standards; and description of corrective actions taken.3. Percent reduction of the potential combustion concentration of sulfur dioxide for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for noncompliance with the standard; and description of corrective actions taken.4. Identification of the boiler operating days for which pollutant or diluent data have not been obtained by an approved method for at least 18 hours of operation of the facility; justification for not obtaining sufficient data; and description of corrective actions taken.5. Identification of the times when emissions data have been excluded from the calculation of average emission rates because of startup, shutdown, malfunction (NOx only), emergency conditions (SO2 only) or other reasons, and justification for excluding data for reasons other than startup, shutdown, malfunction or emergency conditions.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 continuous monitoring system.9. Description of any modifications to the continuous monitoring system which could affect the ability of the continuous monitoring system to comply with Performance Specification 2 or 3 of 40 CFR part 60, Appendix B, incorporated by reference in s. NR 440.17.(c) If the minimum quantity of emission data as required by sub. (7) is not obtained for any 30 successive boiler operating days, the following information obtained under the requirements of sub. (6) (h) shall be reported to the department for that 30-day period: 1. The number of hourly averages available for outlet emissions rates (no) and inlet emission rates (ni), as applicable.2. The standard deviation of hourly averages for outlet emission rates (So) and inlet emission rates (Si), as applicable.3. The lower confidence limit for the mean outlet emission rate (Eo*) and the upper confidence limit for the mean inlet emission rate (Eo*), as applicable.4. The applicable potential combustion concentration.5. The ratio of the upper confidence limit for the mean outlet emission rate (Eo*) and the allowable emission rate (Estd), as applicable.(d) If any standards under sub. (4) are exceeded during emergency conditions because of control system malfunction, the owner or operator of the affected facility shall submit a signed statement: 1. Indicating if emergency conditions existed and requirements under sub. (6) (d) were met during each period, and2. Listing the following information: a. Time periods the emergency condition existed;b. Electrical output and demand on the owner or operator's electric utility system and the affected facility;c. Amount of power purchased from interconnected neighboring utility companies during the emergency period;d. Percent reduction in emissions achieved;e. Atmospheric emission rate (ng/J) of the pollutant discharged; andf. Actions taken to correct control system malfunction.(e) If fuel pretreatment credit toward the sulfur dioxide emission standard under sub. (4) is claimed, the owner or operator of the affected facility shall submit a signed statement: 1. Indicating what percentage cleaning credit was taken for the calendar quarter, and whether the credit was determined in accordance with the provisions of sub. (8) and Method 19 of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17; and2. Listing the quantity, heat content, and date each pretreated fuel shipment was received during the previous quarter; 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 previous quarter.(f) For any periods for which opacity, sulfur dioxide or nitrogen oxides emissions data are not available, the owner or operator of the affected facility shall submit a signed statement indicating if any changes were made in operation of the emission control system during the period of data unavailability. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before and following the period of data unavailability.(g) The owner or operator of the affected facility shall submit a signed statement indicating whether: 1. The required continuous monitoring system calibration, span, and drift checks or other periodic audits have or have not been performed as specified.2. The data used to show compliance was or was not obtained in accordance with approved methods and procedures of this chapter and is representative of plant performance.3. The minimum data requirements have or have not been met; or, the minimum data requirements have not been met for errors that were unavoidable.4. Compliance with the standards has or has not been achieved during the reporting period.(h) For the purposes of the reports required under s. NR 440.07, periods of excess emissions are defined as all 6-minute periods during which the average opacity exceeds the applicable opacity standards under sub. (3) (b). Opacity levels in excess of the applicable opacity standard and the date of such excesses shall be submitted to the department each calendar quarter.(i) The owner or operator of an affected facility shall submit the written reports required under this subsection and ss. NR 440.01 to 440.15 to the department semiannually for each 6-month period. All semiannual reports shall be postmarked by the 30th day following the end of each 6-month period.(j) 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 pars. (b) and (h). 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 requirements 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.Wis. Admin. Code Department of Natural Resources NR 440.20
Cr. Register, January, 1984, No. 337, eff. 2-1-84; am. (7) (h) 1., 3., 4., (L) 1. and (8) (a) 1., Register, September, 1986, No. 369, eff. 10-1-86; am. (2) (intro.), (7) (h) 1. to 3., (i) 1., (8) (a) 1. to 6., r. (8) (a) 7., Register, September, 1990, No. 417, eff. 10-1-90; am. (4) (h) 1. and 2., (5) (a) 1., (c), (6) (d) 3. (intro.) and (h), r. and recr. (7) (f), (h), (i) (intro.) to 2. and (8), cr. (7) (j), Register, July, 1993, No. 451, eff. 8-1-93; am. (2) (n), (y), (5) (a) 1., (7) (h) 2., (8) (b) 2., Register, December, 1995, No. 480, eff. 1-1-96; correction in (4) (b) (intro.) made under s. 13.93(2m) (b) 7, Stats., Register, November, 1999, No. 527; CR 06-109: am. (1) (b), (2) (b), (n), (q) 1. b. and (y), (4) (d) 2., (f), (5) (a) (intro.), 1. and 2., (b) and (c), (7) (e) and (i) 1. and 3., (8) (title) and (b) 2. b. and (9) (i), cr. (2) (gr) and (Lm), (5) (d), (6) (a) (title), (b) (title), (c) (title), (d) (title), (e) (title), (f) (title), (g) (title) and (h) (title), (i) to (k), (7) (c) 2. and (k) to (n), (8) (f) and (9) (j), renum. (7) (c) to be (7) (c) 1. Register May 2008 No. 629, eff. 6-1-08.