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)
NR 440.20(6)(k)2.b.
b. Use the continuous emissions monitoring system specified under
sub. (7) for measuring NO
x and oxygen to determine the average hourly NO
x 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.
NR 440.20(6)(k)2.c.
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.
NR 440.20(6)(k)2.d.
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 NO
x 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 NO
x shall be computed using the following equation:
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 NO
x 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)
NR 440.20(6)(k)3.
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:
NR 440.20(6)(k)3.a.
a. Determine compliance with the applicable NO
x emissions limits by measuring the emissions combined with the emissions from the other units utilizing the common steam turbine.
NR 440.20(6)(k)3.b.
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.
NR 440.20(7)(a)(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).
NR 440.20(7)(b)
(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:
NR 440.20(7)(b)1.
1. Sulfur dioxide emissions shall be monitored at both the inlet and outlet of the sulfur dioxide control device.
NR 440.20(7)(b)2.
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.
NR 440.20(7)(b)3.
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.
NR 440.20(7)(c)1.1. 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.
NR 440.20(7)(c)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.
NR 440.20(7)(d)
(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.
NR 440.20(7)(e)
(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.
NR 440.20(7)(f)
(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).
NR 440.20(7)(g)
(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.
NR 440.20(7)(h)
(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).
NR 440.20(7)(h)1.
1. Method 6 shall be used to determine the SO
2 concentration at the same location as the SO
2 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.
NR 440.20(7)(h)2.
2. Method 7 shall be used to determine the NO
x concentration at the same location as the NO
x monitor. Samples shall be taken at 30-minute intervals. The arithmetic average of 2 consecutive samples represent a 1-hour average.
NR 440.20(7)(h)3.
3. The emission rate correction factor, integrated bag sampling and analysis procedure of Method 3B shall be used to determine the O
2 or CO
2 concentration at the same location as the O
2 or CO
2 monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample represents a 1-hour average.
NR 440.20(7)(h)4.
4. The procedures in Method 19 shall be used to compute each 1-hour average concentration in ng/J (lb/million Btu) heat input.
NR 440.20(7)(i)
(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).
NR 440.20(7)(i)1.
1. Methods 3B, 6 and 7 shall be used to determine O
2, SO
2 and NO
x concentrations, respectively.
NR 440.20(7)(i)2.
2. SO
2 or NO
x (NO), as applicable, shall be used for preparing the calibration gas mixtures (in N
2, as applicable) under Performance Specification 2 of Appendix B of
40 CFR part 60, incorporated by reference in
s. NR 440.17.
NR 440.20(7)(i)3.
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:
-
See PDF for table 
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
NR 440.20(7)(i)4.
4. All span values computed under
par. (b) 3. for burning combinations of fossil fuels shall be rounded to the nearest 500 ppm.
NR 440.20(7)(i)5.
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.
NR 440.20(7)(j)
(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.
NR 440.20(7)(j)1.
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).
NR 440.20(7)(j)2.
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.
NR 440.20(7)(j)3.
3. For Method 3, Method 3A may be used if the sampling time is 1 hour.
NR 440.20(7)(k)
(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.
NR 440.20(7)(k)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.
NR 440.20(7)(k)2.
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.
NR 440.20(7)(k)3.
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.
NR 440.20(7)(L)
(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:
NR 440.20(7)(L)1.
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.
NR 440.20(7)(m)
(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).
NR 440.20(7)(n)
(n) The owner or operator of a duct burner which is subject to the NO
x standards of
sub. (5) (a) 1. or
(d) 1. is not required to install or operate a continuous emissions monitoring system to measure NO
x 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.
NR 440.20(8)
(8) Compliance determination procedures and methods. NR 440.20(8)(a)(a) In conducting the performance tests required in
s. NR 440.08, the owner or operator shall use as reference methods and procedures the 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 SO
2 and NO
x. Acceptable alternative methods are given in
par. (e).
NR 440.20(8)(b)
(b) The owner or operator shall determine compliance with the particulate matter standards in
sub. (3) as follows:
NR 440.20(8)(b)1.
1. The dry basis F factor (O
2) procedures in Method 19 shall be used to compute the emission rate of particulate matter.
NR 440.20(8)(b)2.
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.
NR 440.20(8)(b)2.a.
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).
NR 440.20(8)(b)2.b.
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 O
2 concentration. The O
2 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 O
2 simultaneous traverse points may be reduced to 12 provided that Method 1 is used to locate the 12 O
2 traverse points. If the grab sampling procedure is used, the O
2 concentration for the run shall be the arithmetic mean of the sample O
2 concentrations at all traverse points.
NR 440.20(8)(c)
(c) The owner or operator shall determine compliance with the SO
2 standards in
sub. (4) as follows:
NR 440.20(8)(c)1.
1. The percent of potential SO
2 emissions (% P
s) to the atmosphere shall be computed using the following equation:
% Ps = [(100 - %Rf) (100 - %Rg)]/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
NR 440.20(8)(c)2.
2. The procedures in Method 19 may be used to determine percent reduction (%R
f) 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.
NR 440.20(8)(c)3.
3. The procedures in Method 19 shall be used to determine the percent SO
2 reduction (%R
g) of any SO
2 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 SO
2 control device and the average SO
2 input rate from the `as fired' fuel analysis for 30 successive boiler operating days.
NR 440.20(8)(c)4.
4. The appropriate procedures in Method 19 shall be used to determine the emission rate.
NR 440.20(8)(c)5.
5. The continuous monitoring system in
sub. (7) (b) and
(d) shall be used to determine the concentrations of SO
2 and CO
2 or O
2.
NR 440.20(8)(d)
(d) The owner or operator shall determine compliance with the NO
x standard in
sub. (5) as follows:
NR 440.20(8)(d)1.
1. The appropriate procedures in Method 19 shall be used to determine the emission rate of NO
x.
NR 440.20(8)(d)2.
2. The continuous monitoring system in
sub. (7) (c) and
(d) shall be used to determine the concentrations of NO
x and CO
2 or O
2.
NR 440.20(8)(e)
(e) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this subsection:
NR 440.20(8)(e)1.
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.
NR 440.20(8)(e)2.
2. The F
c factor (CO
2 ) 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 CO
2 shall be determined in the same manner as the O
2 concentration.
NR 440.20(8)(f)
(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.
NR 440.20(9)(a)(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.
NR 440.20(9)(b)
(b) For sulfur dioxide and nitrogen oxides the following information shall be reported to the department for each 24-hour period.
