Wis. Admin. Code Department of Natural Resources NR 440.19

Current through November 25, 2024

Section NR 440.19 - Fossil-fuel-fired steam generators for which construction is commenced after August 17, 1971

(1) APPLICABILITY AND DESIGNATION OF AFFECTED FACILITY.

(a) The affected facilities to which the provisions of this section apply are:

1. Each fossil-fuel-fired steam generating unit of more than 73 megawatts heat input rate (250 million Btu per hour).

2. Each fossil-fuel and wood-residue-fired steam generating unit capable of firing fossil fuel at a heat input rate of more than 73 megawatts (250 million Btu per hour).

(b) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials other than fossil fuels as defined in this section does not bring that unit under the applicability of this section.

(c) Except as provided in par. (d), any facility under par. (a) that commenced construction or modification after August 17, 1971, is subject to the requirements of this section.

(d) The requirements of subs. (5) (a) 4. and 5., (b) and (d), and (6) (f) 4. f. are applicable to lignite-fired steam generating units that commenced construction or modification after December 22, 1976.

(e) Any facility covered under s. NR 440.20 is not covered under 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) "Coal" means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by ASTM D388-99 (reapproved 2004), incorporated by reference in s. NR 440.17(2) (a) 12.

(b) "Coal refuse" means waste-products of coal mining, cleaning and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay and other organic and inorganic material.

(c) "Fossil fuel" means natural gas, petroleum, coal and any form of solid, liquid or gaseous fuel derived from such materials for the purpose of creating useful heat.

(d) "Fossil-fuel and wood-residue-fired steam generating unit" means a furnace or boiler used in the process of burning fossil fuel and wood residue for the purpose of producing steam by heat transfer.

(e) "Fossil-fuel-fired steam generating unit" means a furnace or boiler used in the process of burning fossil fuel for the purpose of producing steam by heat transfer.

(f) "Wood residue" means bark, sawdust, slabs, chips, shavings, mill trim and other wood products derived from wood processing and forest management operations.

(3) STANDARD FOR PARTICULATE MATTER.

(a) On and after the date on which the performance test required to be conducted by 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:

1. Contain particulate matter in excess of 43 nanograms per joule heat input (0.10 lb per million Btu) derived from fossil fuel or fossil fuel and wood residue.

2. Exhibit greater than 20% opacity except for one 6-minute period per hour of not more than 27% opacity.

(4) STANDARD FOR SULFUR DIOXIDE.

1. 340 nanograms per joule heat input (0.80 lb per million Btu) derived from liquid fossil fuel or liquid fossil fuel and wood residue.

2. 520 nanograms per joule heat input (1.2 lb per million Btu) derived from solid fossil fuel or solid fossil fuel and wood residue.

(b) When different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) shall be determined by proration using the following formula:

See PDF for diagram

in which:

PS_Nox

is the prorated standard for sulfur dioxide when burning different fuels simultaneously, in nanograms per joule heat input derived from all fossil fuels fired or from all fossil fuels and wood residue fired

y is the percentage of total heat input derived from liquid fossil fuel

z is the percentage of total heat input derived from solid fossil fuel

(c) Compliance shall be based on the total heat input from all fossil fuels burned, including gaseous fuels.

(5) STANDARD FOR NITROGEN OXIDES.

1. 86 nanograms per joule heat input (0.20 lb per million Btu) derived from gaseous fossil fuel.

2. 129 nanograms per joule heat input (0.30 lb per million Btu) derived from liquid fossil fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and wood residue.

3. 300 nanograms per joule heat input (0.70 lb per million Btu) derived from solid fossil fuel or solid fossil fuel and wood residue (except lignite or a solid fuel containing 25%, by weight, or more of coal refuse).

4. 260 nanograms per joule heat input (0.60 lb per million Btu) derived from lignite or lignite and wood residue, except as provided under subd. 5.

5. 340 nanograms per joule heat input (0.80 lb per million Btu) derived from lignite which is mined in North Dakota, South Dakota or Montana and which is burned in a cyclone-fired unit.

(b) Except as provided under pars. (c) and (d), when different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) is determined by proration using the following formula:

See PDF for diagram

in which:

PS_NOx

is the prorated standard for nitrogen oxides when burning different fuels simultaneously, in nanograms per joule heat input derived from all fossil fuels fired or from all fossil fuels and wood residue fired

w is the percentage of total heat input derived from lignite

x is the percentage of total heat input derived from gaseous fossil fuel

y is the percentage of total heat input derived from liquid fossil fuel

z is the percentage of total heat input derived from solid fossil fuel (except lignite)

(c) When a fossil fuel containing at least 25%, by weight, of coal refuse is burned in combination with gaseous, liquid or other solid fossil fuel or wood residue, the standard for nitrogen oxides does not apply.

(d) Cyclone-fired units which burn fuels containing at least 25% of lignite that is mined in North Dakota, South Dakota or Montana remain subject to par. (a) 5. regardless of the types of fuel combusted in combination with that lignite.

(6) EMISSION AND FUEL MONITORING.

(a) Each owner or operator shall install, calibrate, maintain and operate continuous monitoring systems for measuring the opacity of emissions, sulfur dioxide emissions, nitrogen oxides emissions, and either oxygen or carbon dioxide except as provided in par. (b).

(b) Certain of the continuous monitoring system requirements under par. (a) do not apply to owners or operators under the following conditions:

1. For a fossil-fuel-fired steam generator that burns only gaseous fossil fuel, continuous monitoring systems for measuring the opacity of emissions and sulfur dioxide emissions are not required.

2. For a fossil-fuel-fired steam generator that does not use a flue gas desulfurization device, a continuous monitoring system for measuring sulfur dioxide emissions is not required if the owner or operator monitors sulfur dioxide emissions by fuel sampling and analysis.

3. Notwithstanding s. NR 440.13(2), installation of a continuous monitoring system for nitrogen oxides may be delayed until after the initial performance tests under s. NR 440.08 have been conducted. If the owner or operator demonstrates during the performance test that emissions of nitrogen oxides are less than 70% of the applicable standards in sub. (5), a continuous monitoring system for measuring nitrogen oxides emissions is not required. If the initial performance test results show that nitrogen oxide emissions are greater than 70% of the applicable standard, the owner or operator shall install a continuous monitoring system for nitrogen oxides within one year after the date of the initial performance tests under s. NR 440.08 and comply with all other applicable monitoring requirements under this chapter.

4. If an owner or operator does not install any continuous monitoring systems for sulfur oxides and nitrogen oxides, as provided under subds. 1. and 3. or subds. 2. and 3., a continuous monitoring system for measuring either oxygen or carbon dioxide is not required.

(c) For performance evaluations under s. NR 440.13(3) and calibration checks under s. NR 440.13(4), the following procedures shall be used:

1. Methods 6, 7 and 3B of 40 CFR part 60, Appendix A, incorporated by reference in s. NR 440.17, as applicable, shall be used for the performance evaluations of sulfur dioxide and nitrogen oxides continuous monitoring systems. Acceptable alternative methods for Methods 6, 7 and 3B are given in sub. (7) (d).

2. Sulfur dioxide or nitric oxide, as applicable, shall be used for preparing calibration gas mixtures under Performance Specification 2 of 40 CFR part 60, Appendix B, incorporated by reference in s. NR 440.17.

3. For affected facilities burning fossil fuel, the span value for a continuous monitoring system measuring the opacity of emissions shall be 80, 90 or 100% and for a continuous monitoring system measuring sulfur oxides or nitrogen oxides the span value shall be determined as follows:

[In parts per million]

Fossil fuel	Span value for sulfur dioxide	Span value for nitrogen oxides
a.	Gas............	not applicable	500
b.	Liquid ..........	1,000	500
c.	Solid ...........	1,500	1000
d.	Combinations............	1,000y + 1,500z	500 (x+ y) + 1,000z

in which:

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 subd. 3. for burning combinations of fossil fuels shall be rounded to the nearest 500 ppm.

5. For a fossil-fuel-fired steam generator that simultaneously burns fossil fuel and nonfossil fuel, the span value of all continuous monitoring systems shall be subject to the department's approval.

(e) For any continuous monitoring system installed under par. (a), the conversion procedures of this paragraph shall be used to convert the continuous monitoring data into units of the applicable standards (ng/J, lb/million Btu).

1. When a continuous monitoring system for measuring oxygen is selected, the measurement of the pollutant concentration and oxygen concentration shall each be on a consistent basis (wet or dry). Alternative procedures approved by the department shall be used when measurements are on a wet basis. When measurements are on a dry basis, the following conversion procedures shall be used:

E = CF [20.9/(20.9 - percent O₂)]

where E, C, F, and percent O₂ are determined under par. (f).

2. When a continuous monitoring system for measuring carbon dioxide is selected, the measurement of the pollutant concentration and carbon dioxide concentration shall each be on a consistent basis (wet or dry) and the following conversion procedure shall be used:

E = CF_c [100/percent CO₂]

where E, C, Fc and percent CO₂ are determined under par. (f).

(f) The values used in the equations under par. (e) 1. and 2. are derived as specified in this paragraph.

1. E is the pollutant emissions, ng/J (lb/million Btu).

2. C is the pollutant concentration, ng/dscm (lb/dscf), determined by multiplying the average concentration (ppm) for each one-hour period by 4.15 10⁴ M ng/dscm per ppm (2.59 10^-9 M lb/dscf per ppm) where M is the pollutant molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for sulfur dioxide and 46.01 for nitrogen oxides.

3. %O₂ or %CO₂ is the oxygen or carbon dioxide volume expressed as percent, determined with equipment specified under par. (a).

4. F, F_c are a factor representing a ratio of the volume of dry flue gases generated to the calorific value of the fuel combusted (F), and a factor representing a ratio of the volume of carbon dioxide generated to the calorific value of the fuel combusted (F_c), respectively. Values of F_c and F are:

a. For anthracite coal as classified according to ASTM D388-99 (reapproved 2004), incorporated by reference in s. NR 440.17(2) (a) 12., F = 2.723 x 10^-7 dscm/J (10,140 dscf/million Btu) and F_c = 0.532 x 10^-7 scm CO₂ /J (1,980 scf CO₂/million Btu).

b. For subbituminous and bituminous coal as classified according to ASTM D388-99 (reapproved 2004), incorporated by reference in s. NR 440.17(2) (a) 12., F = 2.637 10-7 dscm/J (9,820 dscf/million Btu) and F_c = 0.486 10^-7 scm CO₂/J (1,810 scf CO₂/million Btu).

c. For liquid fossil fuels including crude, residual and distillate oils, F = 2.476 10^-7 dscm/J (9,220 dscf/million Btu) and F_c = 0.384 10^-7 scm CO₂/J (1,430 scf CO₂/million Btu).

d. For gaseous fossil fuels, F = 2.347 10^-7 dscm/J (8,740 dscf/million Btu). For natural gas, propane and butane fuels, F_c = 0.279 10^-7 scm CO₂/J (1,040 scf CO₂/million Btu) for natural gas, 0.322 10^-7 scm CO₂/J (1,200 scf CO₂/million Btu) for propane, and 0.338 10^-7 scm CO2/J (1,260 scf CO₂/million Btu) for butane.

e. For bark, F = 2.589 10^-7 dscm/J (9,640 dscf/million Btu) and Fc = 0.500 10^-7 scm CO2/J (1,840 scf CO₂/million Btu). For wood residue other than bark, F = 2.492 10^-7 dscm/J (9,280 dscf/million Btu) and Fc = 0.494 10^-7 scm CO₂/J (1,860 scf CO₂/million Btu).

f. For lignite coal as classified according to ASTM D388-99 (reapproved 2004), incorporated by reference in s. NR 440.17(2) (a) 12., F = 2.659 10-7 dscm/J (9900 dscf/million Btu) and F_c = 0.516 10^-7 scm CO₂/J (1,920 scf CO₂/million Btu).

5. The owner or operator may use the following equation to determine an F factor (dscm/J or dscf/million Btu) on a dry basis (if it is desired to calculate F on a wet basis, consult the department) or F_c factor (scm CO₂/J, or scf CO₂/million Btu) on either basis in lieu of the F or F_c factors specified in subd. 4.:

See PDF for diagram

a. H, C, S, N and O are content by weight of hydrogen, carbon, sulfur, nitrogen and oxygen (expressed as percent), respectively, as determined on the same basis as GCV by ultimate analysis of the fuel fired, using ASTM method D3178-89 or D3176-89 (solid fuels), or computed from results using ASTM method D1137-75, D1945-96 or D1946-90 (reapproved 1994) (gaseous fuels) as applicable. These 5 ASTM methods are incorporated by reference in s. NR 440.17(2) (a) 43., 41., 16., 23. and 24., respectively.

b. GCV is the gross calorific value (kJ/kg, Btu/lb) of the fuel combusted, determined by the ASTM test methods D2015-96 or D5865-98 for solid fuels and D1826-94 for gaseous fuels as applicable. These 2 ASTM methods are incorporated by reference in s. NR 440.17(2) (a) 26. and 21., respectively.

c. For affected facilities which fire both fossil fuels and nonfossil fuels, the F or F_c value shall be subject to the department's approval.

6. For affected facilities firing combinations of fossil fuels or fossil fuels and wood residue, the F or F_c factors determined by subd. 4. or 5. shall be prorated in accordance with the applicable formulas as follows:

See PDF for diagram

X_i is the fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood residue, etc.)

F_i or (F_c)i is the applicable F or F_c factor for each fuel type determined in accordance with subd. 4. or 5.

n is the number of fuels being burned in combination

(g) Excess emission and monitoring system performance reports shall be submitted to the department semiannually for each 6-month period in the calendar year. All semiannual reports shall be postmarked by the 30th day following the end of each 6-month period. Each excess emission and monitoring system performance report shall include the information required in s. NR 440.07(3). Periods of excess emissions and monitoring systems downtime that shall be reported are defined as follows:

1. Opacity. Excess emissions are defined as any 6-minute period during which the average opacity of emissions exceeds 20% opacity, except that one 6-minute average per hour of up to 27% opacity need not be reported.

2. Sulfur dioxide. Excess emissions for affected facilities are defined as:

a. Any 3-hour period during which the average emissions (arithmetic average of 3 contiguous one-hour periods) of sulfur dioxide as measured by a continuous monitoring system exceed the applicable standard under sub. (4).

3. Nitrogen oxides. Excess emissions for affected facilities using a continuous monitoring system for measuring nitrogen oxides are defined as any 3-hour period during which the average emissions (arithmetic average of 3 contiguous one-hour periods) exceed the applicable standards under sub. (5).

(7) TEST METHODS AND PROCEDURES.

(a) In conducting the performance tests required in s. NR 440.08, the owner or operator shall use as reference methods and procedures the test methods in Appendix A of 40 CFR part 60, incorporated by reference in s. NR 440.17, or other methods and procedures as specified in this subsection, except as provided in s. NR 440.08(2). Acceptable alternative methods and procedures are given in par. (d).

(b) The owner or operator shall determine compliance with the particulate matter, SO₂ and NO_x standards in subs. (3), (4) and (5) as follows:

1. The emission rate (E) of particulate matter, SO₂ or NO_x shall be computed for each run using the following equation:

E = CFd (20.9)/(20.9 - %0₂)

where:

E is the emission rate of pollutant, ng/J (lb/million Btu)

C is the concentration of pollutant, ng/dscm (lb/dscf)

%O₂ is the oxygen concentration, percent dry basis

F_d is the factor as determined from Method 19

2. Method 5 shall be used to determine the particulate matter concentration (C) at affected facilities without wet flue-gas-desulfurization (FGD) systems and Method 5B shall be used to determine the particulate matter concentration (C) after FGD systems.

a. The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder heating systems in the sampling train shall be set to provide an average gas temperature of 160"14°C (320"25°F).

b. The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 3B shall be used to determine the O₂ concentration (%O₂). The O₂ sample shall be obtained simultaneously with, and at the same traverse points as, the particulate sample. 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.

c. If the particulate run has more than 12 traverse points, the O₂ traverse points may be reduced to 12 provided that Method 1 is used to locate the 12 O₂ traverse points.

3. Method 9 and the procedures in s. NR 440.11 shall be used to determine opacity.

4. Method 6 shall be used to determine the SO₂ concentration.

a. The sampling site shall be the same as that selected for the particulate sample. The sampling location in the duct shall be at the centroid of the cross section or at a point no closer to the walls than 1 m (3.28 ft). The sampling time and sample volume for each sample run shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples shall be taken during a 1-hour period, with each sample taken within a 30-minute interval.

b. The emission rate correction factor, integrated sampling and analysis procedure of Method 3B shall be used to determine the O₂ concentration (%O₂). The O₂ sample shall be taken simultaneously with, and at the same point as, the SO₂ sample. The SO₂ emission rate shall be computed for each pair of SO₂ and O₂ samples. The SO₂ emission rate (E) for each run shall be the arithmetic mean of the results of the 2 pairs of samples.

5. Method 7 shall be used to determine NO_x concentration.

a. The sampling site and location shall be the same as for the SO₂ sample. Each run shall consist of 4 grab samples, with each sample taken at about 15-minute intervals.

b. For each NO_x sample, the emission rate correction factor, grab sampling and analysis procedure of Method 3B shall be used to determine the O₂ concentration (%O₂). The sample shall be taken simultaneously with, and at the same point as, the NO_x sample.

c. The NO_x emission rate shall be computed for each pair of NO_x and O₂ samples. The NO_x emission rate (E) for each run shall be the arithmetic mean of the results of the 4 pairs of samples.

(c) When combinations of fossil fuels or fossil fuel and wood residue are fired, the owner or operator, in order to compute the prorated standard as shown in subs. (4) (b) and (5) (b), shall determine the percentage (w, x, y, or z) of the total heat input derived from each type of fuel as follows:

1. The heat input rate of each fuel shall be determined by multiplying the gross calorific value of each fuel fired by the rate of each fuel burned.

2. ASTM method D2015-96 or D5865-98 (solid fuels), D240-92 (liquid fuels) or D1826-94 (gaseous fuels), incorporated by reference in s. NR 440.17(2) (a) 26., 66., 9. and 21., respectively, shall be used to determine the gross calorific values of the fuels. The method used to determine the calorific value of wood residue shall be approved by the department.

3. Suitable methods shall be used to determine the rate of each fuel burned during each test period, and a material balance over the steam generating system shall be used to confirm the rate.

(d) The owner or operator may use the following as alternatives to the reference methods and procedures in this subsection or in other subsections as specified:

1. The emission rate (E) of particulate matter, SO₂ and NO_x may be determined by using the F_c factor, provided that the following procedure is used:

a. The emission rate (E) shall be computed using the following equation:

E = CF_c (100/%CO₂)

where:

E is the emission rate of pollutant, ng/J (lb/million Btu)

C is the concentration of pollutant, ng/dscm (lb/dscf)

%CO₂ is the carbon dioxide concentration, percent dry basis

F_c is the factor as determined in appropriate sections of Method 19

b. If and only if the average F_c factor in Method 19 is used to calculate E and either E is from 0.97 to 1.00 of the emission standard or the relative accuracy of a continuous emission monitoring system is from 17 to 20%, then 3 runs of Method 3 shall be used to determine the O₂ and CO₂ concentration according to the procedures in sub. (7) (b) 2. b., 4. b. or 5. b. Then if Fo (average of 3 runs), as calculated from the equation in Method 3B, is more than "3% than the average Fo value, as determined from the average values of F_d and F_c in Method 19, that is, F_oa = 0.209 (Fda/Fca), then the following procedure shall be followed:

1) When F_o is less than 0.97 F_oa, then E shall be increased by that proportion under 0.97 F_oa. For example, if F_o is 0.95 F_oa, E shall be increased by 2%. This recalculated value shall be used to determine compliance with the emission standard.

2) When F_o is less than 0.97 F_oa and when the average difference (d) between the continuous monitor minus the reference methods is negative, then E shall be increased by that proportion under 0.97 F_oa. For example, if F_o is 0.95 F_oa, E shall be increased by 2%. This recalculated value shall be used to determine compliance with the relative accuracy specification.

3) When F_o is greater than 1.03 F_oa and when the average difference d is positive, then E shall be decreased by that proportion over 1.03 F_oa. For example, if F_o is 1.05 F_oa, E shall be decreased by 2%. This recalculated value shall be used to determine compliance with the relative accuracy specification.

2. For Method 5 or 5B, Method 17 may be used at facilities with or without wet FGD systems if the stack gas 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 with Method 17 only if it is used after wet FGD systems. Method 17 may not be used after wet FGD systems if the effluent gas is saturated or laden with water droplets.

3. Particulate matter and SO₂ may be determined simultaneously with the Method 5 train provided that the following changes are made:

a. The filter and impinger apparatus in sections 2.1.5 and 2.1.6 of Method 8 is used in place of the condenser (sectio n 2.1.7) of Method 5.

b. All applicable procedures in Method 8 for the determination of SO₂, including moisture, are used.

4. For Method 6, Method 6C may be used. Method 6A may also be used whenever Methods 6 and 3B data are specified to determine the SO₂ emission rate, under the conditions in par. (d) 1.

5. 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 at least 1 hour and the integrated sampling approach shall be used to determine the O₂ concentration (%O₂) for the emission rate correction factor.

6. For Method 3, Method 3A or 3B may be used.

7. For Method 3B, Method 3A may be used.

Wis. Admin. Code Department of Natural Resources NR 440.19

Cr. Register, January, 1984, No. 337, eff. 2-1-84; am. (6) (c) 1., (7) (a) 2., 4. and 5., (7) (c), (e), (f) 2., 3. (intro.) and a., Register, September, 1986, No. 369, eff. 10-1-86; am. (1) (b), (2) (intro.), (5) (a) 1. and 2., (6) (c) 1. and (f) 5. a., (7) (a) 1. to 5., (b); (c) and (f) 3., Register, September, 1990, No. 417, eff. 10-1-90; r. and recr. (6) (c) 1., (g) (intro.) and (7), am. (6) (c) 3., (f) 1. to 3., 4. a. and 5. (intro.), Register, July, 1993, No. 451, eff. 8-1-93; am. (6) (f) 5. (intro.), a., (7) (b) 2. (intro.), Register, December, 1995, No. 480, eff. 1-1-96; CR 06-109: am. (2) (a), (6) (b) 2., (c) 3. a. to d., (f) 4. a., b. and f., 5. a. and b., (g) (intro.), (7) (b) 2. a. and b. and (c) 2. Register May 2008 No. 629, eff. 6-1-08.