KERN COUNTY AIR POLLUTION CONTROL DISTRICT
RULE 425.2 - BOILERS, STEAM GENERATORS & PROCESS HEATERS (NOx)
(Adopted 10/13/94, Amended 4/6/95, 7/10/97)
The purpose of this Rule is to limit oxides of nitrogen (NOx) emissions from boilers, steam generators, and process heaters to levels consistent with Reasonably Available Control Technology (RACT) to satisfy California Health and Safety Code Section 40918(b) and 1990 Federal Clean Air Act Amendments, Section 182(f). Carbon monoxide emissions are also limited to insure efficient combustion at reduced NOx levels.
This Rule shall apply, as specified, to any boiler, steam generator or process heater with rated heat input of 5 million Btu per hour or more and fired with gaseous and/or liquid fuels.
A. Annual Heat Input - total heat released (therms) by fuel(s) burned in a unit during a calendar year as determined from higher heating value and cumulative annual fuel(s) usage.
B. Boiler or Steam Generator - any external combustion unit fired with liquid and/or gaseous fuel used to produce hot water or steam, but not including gas turbine engine exhaust gas heat recovery systems.
C. British Thermal Unit (Btu) - amount of heat required to raise the temperature of one pound of water from 59°F to 60°F at one atmosphere.
D. Gaseous Fuel - any fuel existing as gas at standard conditions.
E. Heat Input - total heat released (Btu's) by fuel(s) burned in a unit as determined from higher heating value, not including sensible heat of incoming combustion air and fuel(s).
F. Higher Heating Value (HHV) - total heat released per mass of fuel burned (Btu's per pound), when fuel and dry air at standard conditions undergo complete combustion and all resulting products are brought to standard conditions.
G. Liquid Fuel - any fuel, including distillate and residual oil, existing as liquid at standard conditions.
H. Natural gas curtailment - loss of natural gas supply due to action of PUC-regulated supplier. For Section V curtailment limit to apply, curtailment must not exceed 168 cumulative hours of operation per calendar year, excluding equipment testing not to exceed 48 hours per calendar year.
I. Oxides of Nitrogen (NOx) - total nitrogen oxides (expressed as NO2).
J. Process Heater - any external combustion unit fired with liquid and/or gaseous fuel used to transfer heat from combustion gases to liquid process streams.
K. Reasonably Available Control Technology (RACT) - lowest emission limitation a particular source is capable of meeting by application of control technology reasonably available considering technological and economic feasibility.
L. Rated Heat Input - heat input capacity (Btu's/hr) specified on nameplate of unit or by manufacturer for that model number, or as limited by District permit.
M. Standard Conditions - as defined in Rule 102, Subsection DD.
N. Therm - 100,000 British thermal units (Btu's).
O. Unit - any boiler, steam generator or process heater as defined in this Rule.
This Rule shall not apply to any unit with rated heat input less than 5 million Btu's per hour.
A. An owner/operator of any unit subject to this Rule with annual heat input of 90,000 therms or more during one or more of the three preceding years of operation shall comply with following applicable NOx emission limit(s):
70 ppmv, or
115 ppmv, or
150 ppmv, or
For units subject to this Subsection, carbon monoxide (CO) emissions shall not exceed 400 ppmv.
NOx emission limit for any unit fired simultaneously with gaseous and liquid fuels shall be heat input-weighted average of applicable limits. Calculations shall be performed as prescribed in Section VIII.
NOx and CO emission limits in ppmv are referenced at dry stack gas conditions, adjusted to 3.00 percent by volume stack gas oxygen in accordance with Section VIII., and averaged over 15 consecutive minutes from no less than 5 data sets, recorded from sampling of no more than 3 minutes.
B. An owner/operator of any unit subject to this Rule with annual heat input rate of 90,000 therms or more shall comply, until November 30, 1997, and any unit with annual heat input rate of less than 90,000 therms shall comply with one of the following NOx minimization procedures:
C. Monitoring Requirements
D. Compliance Demonstration
VI. Administrative Requirements
A. Recordkeeping and Reporting
B. Test Methods
a. ASTM D 240-87 or D 2382-88 for liquid fuels; and
b. ASTM D 1826-88 or D 1945-81 in conjunction with ASTM D 3588-89 for gaseous fuels.
C. Compliance Testing
D. Emission Control Plan
An owner/operator of any unit subject to this Rule shall submit to Control Officer an Emission Control Plan including:
VII. Compliance Schedule
A. An owner/operator of any unit subject to Section V. shall comply with following schedule:
B. An owner/operator of any unit becoming subject to requirements of Subsection V.A. by exceeding the annual heat input exemption threshold shall comply with following increments of progress:
A. All ppmv emission limits specified in Section V.A. are referenced at dry stack gas conditions and 3.00 percent by volume stack gas oxygen. Emission concentrations shall be corrected to 3.00 percent oxygen as follows:
B. All lb/MMBtu NOx emission rates shall be calculated as pounds of nitrogen dioxide per million Btu's of heat input (HHV).
C. Heat input-weighted average NOx emission limit for combination of natural gas and liquid fuel shall be calculated as follows:
X = heat input from gaseous fuel and Y = heat input from liquid fuel.
IX. NOx Minimization Tuning Procedures
The purpose of these procedures is to provide a reasonable, cost-effective method to minimize NOx emissions from smaller, or low-fire/low use-rate combustion units subject to this Rule. These procedures not only minimize NOx emissions, but also result in reduced operating costs.
B. Equipment Tuning Procedure1 for Mechanical Draft Boilers, Steam Generators, and Process Heaters
Nothing in this Tuning Procedure shall be construed to require any act or omission that would result in unsafe conditions or would be in violation of any regulation or requirement established by Factory Mutual, Industrial Risk Insurers, National Fire Prevention Association, California Department of Industrial Relations (Occupational Safety and Health Division), Federal Occupational Safety and Health Administration, or other relevant regulations and requirements.
Increase combustion air flow to unit until stack gas oxygen levels increase by one to two percent over level
measured in Step 2. As in Step 2, record stack gas temperature, CO concentration (for gaseous fuels) or smoke spot
number (for liquid fuels), and observe flame conditions for these higher oxygen levels after unit operation stabilizes.
2. The smoke-spot number can be determined with ASTM Test Method D-2156 or with the Bacharach method.
3. Typical minimum oxygen levels for boilers at high firing rates are: For natural gas: 0.5% to 3% and For liquid fuels: 2% to 4%.
a. Unacceptable flame conditions- such as flame impingement on furnace walls or burner parts, excessive flame
carryover, or flame instability,
b. Stack gas CO concentrations greater than 400 ppm,
c. Smoking at the stack, or
d. Equipment-related limitations such as low windbox/furnace pressure differential, built in air-flow limits, etc.
|Gaseous||CO Emissions||400 ppm|
|#1 and #2 Oils||smoke-spot number||number 1|
|#4 Oil||smoke-spot number||number 2|
|#5 Oil||smoke-spot number||number 3|
|Other Oils||smoke-spot number||number 4|
Above conditions are referred to as CO or smoke thresholds, or as minimum excess oxygen levels.
Compare this minimum value of excess oxygen to expected value provided by combustion unit manufacturer. If minimum level found is substantially higher than value provided by combustion unit manufacturer, burner adjustments can probably be made to improve fuel and air mix, thereby allowing operations with less air.
C. Equipment Tuning Procedure1 for Natural and Induced-Draft Boilers, Steam Generators, and Process Heaters
Nothing in this Tuning Procedure shall be construed to require any act or omission that would result in unsafe conditions or would be in violation of any regulation or requirement established by Factory Mutual, Industrial Risk Insurers, National Fire Prevention Association, the California Department of Industrial Relations (Occupational Safety and Health Division), the Federal Occupational Safety and Health Administration, or other relevant regulations and requirements.
a. Check operating pressure or temperature. Operate unit at lowest acceptable pressure or temperature that will satisfy load demand. Determine pressure or temperature that will be used as basis for comparative combustion analysis before and after tuneup.
b. Check operating hours. Plan workload so that unit operates only the minimum hours and days necessary to perform work required.
This tuning procedure is based on a tune-up procedure developed by Parker Boiler for South Coast AQMD.
c. Check air supply. Area of air supply openings must be in compliance with applicable codes and regulations. Air openings must be kept wide open when burner is firing and clean from restriction to flow.
d. Check vent. Check to be sure vent is in good condition, sized properly and with no obstructions.
e. Perform combustion analysis. Perform an "as is" flue gas analysis (O2, CO, CO2, etc.) at high and low fire, if possible. In addition to data obtained from combustion analysis, also record following:
With above conditions recorded, make following checks and corrective actions as necessary.
a. Check burner condition. Clean burners and burner orifices thoroughly. To clean burners effectively all burners must be removed, blown out with high pressure air and checked for obstructions. All accumulated sediment, dirt, and carbon must be removed. Check for smooth lighting and even flame. Also, ensure that fuel filters and moisture traps are in place, clean, and operating properly, to prevent plugging of gas orifices. Confirm proper location and orientation of burner diffuser spuds, gas canes, etc. Look for any burned-off or missing burner parts, and replace as needed.
b. Check for clean boiler, steam generator, or process heater tubes and heat transfer surfaces. Clean tube surfaces, remove scale and soot, assure proper fluid flow, and flue gas flow.
c. Check water treatment and blowdown program. Employ timely flushing and periodic blowdown to eliminate sediment and scale build-up in heat exchange tubes.
d. Check for steam hot water or process fluid leaks. Repair all leaks immediately. Be sure there are no leaks through the blow-off drains, safety valve, by-pass lines or at the feed pump, if used.
a. Test primary and secondary low water level controls.
b. Check operating and limit pressure and temperature controls.
c. Check safety valve pressure and capacity to meet boiler, steam generator, or process heater requirements.
d. Check limit safety control and spill switch.