COLUSA COUNTY AIR POLLUTION CONTROL DISTRICT

REGULATION II - PROHIBITIONS

RULE 2.39 - INDUSTRIAL, INSTITUTIONAL, AND COMMERCIAL BOILERS, STEAM GENERATORS, AND PROCESS HEATERS OXIDES OF NITROGEN CONTROL MEASURE
(Adopted 1/23/96)

a. PURPOSE

To reduce Oxides of Nitrogen emissions during the operations of Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters to levels consistent with reasonably available control technology (RACT).

b. APPLICABILITY

This rule applies to all boilers, steam generators, and process heaters used in industrial, institutional, and commercial operations that exist within the boundaries of the Colusa County Air Pollution Control District on the date of adoption of this Rule.

c. EXEMPTIONS

The requirements of Section e. shall not apply to the following:

  1. Units with a rated heat input capacity less than one (1) million Btu per hour.
  2. Units which are willing to accept a permit condition that restricts operation to an annual capacity factor of 15% or less and requires compliance with one (1) of the options specified in Sections e.2.a., b., or c. of this rule

    a. To continue to qualify for the exemption provided in Section c.2. the owner or operator of any applicable unit(s) shall submit to the Air Pollution Control Officer annual fuel use data that demonstrates that the unit(s) operated at or below the allowable 15% annual capacity factor(s). For the purposes of this Section, the annual capacity factor for multiple units may be calculated based on the total fuel input to multiple like units.

    b. Following adoption of this rule, an exemption granted for any unit will become null and void if that unit operates for more than 1 calendar year at an annual capacity factor greater than 15%.

  3. The use of an emergency standby unit during equipment breakdowns and during routine maintenance of the primary unit. Operation of the emergency standby unit shall not exceed a maximum of 30 days of operation per year.
  4. Units for which the APCO has determined it is not technically or economically feasible to comply with the RACT emission limitations.

d. DEFINITIONS

For the purposes of this Section, the following definitions shall apply.

  1. ANNUAL CAPACITY FACTOR

    The ratio of the amount of fuel burned by a boiler in a calendar year to the amount of fuel it could have burned if it had operated at the rated heat input capacity for 100 percent of the time during the calendar year.

  2. BOILER OR STEAM GENERATOR

    An individual piece of combustion equipment fired with liquid, gaseous, or solid fuel with the primary purpose of producing steam. Boiler or steam generator does not include water heaters, any waste heat recovery boiler that is used to recover sensible heat from the exhaust of a combustion turbine, nor does it include equipment associated with a chemical recovery cycle.

  3. BRITISH THERMAL UNIT (BTU)

    The amount of heat required to raise the temperature of one pound of water from 590F to 600F at one atmosphere.

  4. GAS-FIRED

    Using natural gas, propane, or any other gaseous fuel for firing the boiler or steam generator.

  5. HEAT INPUT

    The chemical heat released due to fuel combustion in a boiler, using the higher heating value of the fuel. This does not include the sensible heat of incoming combustion air.

  6. HIGHER HEATING VALUE (HHV)

    The heat liberated per mass of fuel burned (Btu) per pound, when fuel and dry air at standard conditions (68 degrees F and one atmosphere pressure) undergo complete combustion and all resultant products are brought to their standard states at standard conditions. Higher heating value shall be determined using Subsection g.1.E.

  7. INDUCED DRAFT UNIT

    A unit similar to a natural draft unit having a stack, which by itself is not of sufficient size to create the necessary draft for proper combustion, and therefore utilizes a mechanically driven blower in the stack to supplement the draft requirements of the unit.

  8. NATURAL DRAFT UNIT

    A unit that uses no mechanical means to cause air to flow through a combustion chamber, flue, chimney, or space.

  9. OXIDES OF NITROGEN EMISSIONS

    The sum of nitric oxide (NO) and nitrogen dioxide (NO2) in the flue gas, collectively expressed as nitrogen dioxide.

  10. PARTS PER MILLION BY VOLUME (PPMV)

    The ratio of the number of gas molecules of a given species, or group of species, to the number of millions of total gas molecules.

  11. PROCESS HEATER

    Any combustion equipment fired with liquid, gaseous, or solid fuel and which transfers heat from combustion gases to water or process streams. A process heater does not include any kiln, furnace, recovery furnace, or oven used for drying, baking, heat treating, cooking, calcining, vitrifying or chemical reduction.

  12. RATED INPUT CAPACITY

    The heat input capacity specified on the nameplate of the combustion unit. If the unit has been permanently altered or modified such that the maximum heat input is different than the input capacity specified on the nameplate and this alteration or modification has been approved in writing by the Air Pollution Control Officer (APCO), then the new maximum heat input shall be considered as the rated heat input capacity.

  13. REASONABLY AVAILABLE CONTROL TECHNOLOGY (RACT)

    The lowest emission limitation that a particular source is capable of meeting by the application of control technology that is reasonably available considering technological and economic feasibility.

  14. UNIT

    Any boiler, steam generator or process heater as defined in this definition section.

e. REQUIREMENTS

  1. No later than one year following District adoption of this Rule, all existing units with a rated heat input capacity greater than or equal to 5 million BTU per hour shall demonstrate final compliance with the following Reasonably Available Control Technology (RACT) emission limitations dependent upon the specific fuel fired in the unit and based upon a three-hour averaging period. All new units shall comply with the requirements of District Rule 3.6 - Standards for Authority to Construct (New Source Review).

    EMISSION LIMITS FOR OXIDES OF NITROGEN (AS NO2)

    Gaseous only fuel firing: 0.084 lbs/MMBtu of heat input or 70 ppmv
    Gaseous & Non-gaseous fuel co-firing: Heat input weighted average of gaseous and non-gaseous fuel limits as calculated per Section e.1.a. below
    Liquid or Solid fuel firing: 0.15 lbs/MMBtu of heat input or 115 ppmv

f. COMPLIANCE DETERMINATION

  1. An owner or operator of any unit(s) shall have the option of complying with either the pounds-per-million-Btu emission rates or parts-per-million-by-volume emission limits specified in Section e.1. of this Rule. All units covered under Sections e.1. and e.2. shall be tested for compliance not less than once every 12 months, except that units complying with Section e.2.C. shall be tuned not less than once every 12 months.
  2. All emission determinations shall be conducted at the maximum firing rate allowed by the district permit. No compliance determination shall be established within two hours after a continuous period in which fuel flow to the unit is zero, or shut off, for 15 minutes or longer.

a. All ppmv emission limits for gaseous, liquid, or gaseous/liquid fuel firing specified in Section e. of this rule are referenced at dry stack-gas conditions and corrected to 3% by volume stack gas oxygen.

    Emission concentrations shall be corrected to 3% oxygen as follows:

b. All ppmv emission limits for solid fuel firing specified in Section e. of this rule are referenced at dry stack-gas conditions and corrected to 12% by volume stack gas CO2.

Emission concentrations shall be corrected to 12% CO2 as follows:

  1. All emission concentrations and emission rates shall be calculated or obtained from continuous emission monitoring data obtained by utilizing the test methods specified in Section g. of this Rule or by using a portable emissions analyzer pursuant to Section g.

g. TEST METHODS

  1. Compliance with the emission requirements in Section e. shall be determined using the following test methods:

    A. Oxides of Nitrogen (ppmv) - EPA Method 7E or ARB Method 100

    B. Carbon Monoxide (ppmv) - EPA Method 10 or ARB Method 100

    C. Stack Gas Oxygen - EPA Method 3A or ARB Method 100

    D. NOX Emission Rate (Heat Input Basis) - EPA Method 19

    E. Higher heating value shall be certified by a third party fuel supplier or determined by one of the following test methods: (1) ASTM D 2015-85 for solid fuels; (2) ASTM D 240-87 or ASTM D 2382-88 for liquid hydrocarbon fuels; or (3) ASTM D 1826-88, or ASTM D 1945-81 in conjunction with ASTM D 3588-89 for gaseous fuels.

  2. A portable emissions analyzer may be used to determine emissions provided approval has been granted from the Air Pollution Control Officer.
  3. For determination of the NH3 concentrations in stack gases, Bay Area Air Quality Management District (BAAQMD) Source Test Procedure ST-1B, "Ammonia, Integrated Sampling" shall be utilized for stack sampling and EPA Method 350.3, "Ion Specific Electrode," shall be utilized as the analysis method. (Reference EPA 600/4-79-020.)

    Alternate methods may be used with prior approval from the Air Pollution Control Officer.

h. RECORD KEEPING REQUIREMENTS

  1. Any persons subject to the provisions of Subsection e.1 of this rule shall install, no later than one year following District adoption of this rule, a non-resettable totalizing volumetric or mass-flow fuel meter in each fuel line for each applicable unit that fires gaseous and/or liquid fuel. Meters shall be accurate to ± one (1) percent, as certified by the manufacturer in writing. The meter shall be used to demonstrate that each unit operates at or below the applicable emission limitation.

    Meter readings and the higher heating value for each fuel shall be recorded at the end of each operating day in units of either cubic feet per day or gallons per day. At the end of each quarter, daily records shall be compiled into a quarterly report. Both quarterly reports and daily records shall be maintained for a period of four (4) years and shall be made available for inspection by the Air Pollution Control Officer upon request.

  2. Any person subject to the provisions of Subsection e.1 of this rule who fires a solid fuel in an applicable unit shall provide a means of calculating or verifying fuel input to the unit in lbs/hr that is acceptable to the Air Pollution Control Officer for purposes of documenting compliance with the specified emission limit.


Attachment 1

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 that 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 different tuning procedure may be used if it produces equivalent results. Should a different tuning procedure be used, a copy of this procedure should be kept with the unit records for two years and made available to the District on request.

  1. Operate the unit at the firing rate most typical of normal operation. If the unit experiences significant load variations during normal operation, operate it at its average firing rate.
  2. At this firing rate, record stack gas temperature, oxygen concentration, and CO concentration (for gaseous fuels) or smoke-spot number2 (for liquid fuels), and observe flame conditions after unit operation stabilizes at the firing rate selected. If the excess oxygen in the stack gas is at the lower end of the range of typical minimum values3, and if CO emissions are low and there is no smoke, the unit is probably operating at near optimum efficiency -- at this particular firing rate. However, complete the remaining portion of this procedure to determine whether still lower oxygen levels are practical.
  3. Increase combustion air flow to the unit until stack gas oxygen levels increase by one to two percent over the level measured in Step 2. As in Step 2, record the 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 boiler operation stabilizes.
  4. Decrease combustion air flow until the stack gas oxygen concentration is at the level measured in Step 2. From this level gradually reduce the combustion air flow, in small increments. After each increment, record the stack gas temperature, oxygen concentration, CO concentration (for gaseous fuels) and smoke-spot number (for liquid fuels). Also, observe the flame and record any changes in its condition.
  5. Continue to reduce combustion air flow stepwise, until one of these limits is reached:

    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. Smoke at the stack.

    D. Equipment-related limitations -- such as low windbox/unit pressure differential, built in air-flow limits, etc.

  6. Develop an O2/CO curve (for gaseous fuels) or O2/smoke curve (for liquid fuels) similar to those shown in Figures 1 and 2 using the excess oxygen and CO or smoke-spot number data obtained at each combustion air flow setting.
  7. From the curves prepared in Step 6, find the stack gas oxygen levels where the CO emissions or smoke-spot number equal the following values:

    FUEL MEASUREMENT VALUE
    Gaseous Co emisions 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

    The above conditions are referred to as the CO or smoke thresholds, or as the minimum excess oxygen levels.

    Compare this minimum value of excess oxygen to the expected value provided by the combustion unit manufacturer. If the minimum level found is substantially higher than the value provided by the combustion unit manufacturer, burner adjustments can probably be made to improve fuel and air mix, thereby allowing operations with less air.

  8. Add 0.5 to 2.0 percent to the minimum excess oxygen level found in Step 7 and reset burner controls to operate automatically at this higher stack gas oxygen level. This margin above the minimum oxygen level accounts for fuel variations, variations in atmospheric conditions, load changes, and nonrepeatability or play in automatic controls.
  9. If the load of the combustion unit varies significantly during normal operation, repeat Steps 1-8 for firing rates that represent the upper and lower limits of the range of the load. Because control adjustments at one firing rate may affect conditions at other firing rates, it may not be possible to establish the optimum excess oxygen level at all firing rates. If this is the case, choose the burner control settings that give best performance over the range of firing rates. If one firing rate predominates, settings should optimize conditions at that rate.
  10. Verify that the new settings can accommodate the sudden changes that may occur in daily operation without adverse effects. Do this by increasing and decreasing load rapidly while observing the flame and stack. If any of the conditions in Step 5 result, reset the combustion controls to provide a slightly higher level of excess oxygen at the affect firing rates. Next, verify these new settings in a similar fashion. Then make sure that the final control settings are recorded at steady-state operating conditions for future reference.

(Refer to Figure 1 and Figure 2)


Attachment 2

Equipment Tuning Procedure for Natural and Induced Draft-Boilers,

Steam Generators, and Process Heaters

Nothing in this Equipment 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 Insurors, 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 different tuning procedure may be used if it produces equivalent results. Should a different tuning procedure be used, a copy of this procedure should be kept with the unit records for two years and made available to the District on request.

  1. Preliminary Analysis

    a. Verify that the boiler, steam generator, or process heater (unit) is operating at the lowest pressure or temperature that will satisfy load demand. This pressure or temperature will be used as a basis for comparative combustion analysis before and after tuneup.

    b. Verify that the unit operates for the minimum number of hours and days necessary to perform the work required.

    c. Verify that the size of air supply openings is in compliance with applicable codes and regulations. Air supply openings must be fully open when the burner is firing and air flow must be unrestricted.

    d. Verify that the vent is in good condition, properly sized, and free from obstruction.

    e. Perform a combustion analysis (CO, O2, etc.) With a warmed up boiler, steam generator, or heater at both high and low fire, if possible. Record all data, as well as the following:

    1. Inlet fuel pressure at burner at high and low firing rates.
    2. Pressure above draft hood or barometric damper at high, medium, and low firing rates.
    3. Steam pressure, water temperature, or process fluid pressure or temperature entering and leaving the unit.
    4. Inlet fuel use rate if meter is available.

    f. Check thermal insulation. Check condition of, or absence of, appropriate insulation on all steam, hot water or process pipes, return tank, heat exchangers, storage tanks, etc. Lack of adequate thermal insulation will significantly increase fuel usage.

  2. Checks and Corrections

    a. Clean all dirty burners or burner orifices. Verify that fuel filters and moisture traps are in place, clean, and operating properly. confirm proper location and orientation of burner diffuser spuds, gas canes, etc. Replace or repair damaged or missing burner parts.

    b. Remove external and internal sediment and scale from heating surfaces.

    c. Verify that the necessary water or process fluid treatment is being used. Confirm flushing and/or blow-down schedule.

d. Repair all leaks. In addition to the high-pressure lines, check the blow-off drain, safety valve, bypass lines and, if used, the feed pump.

  1. Safety Checks

    a. Test primary and secondary low water level controls.

    b. Check operating and limit pressure and temperature controls.

    c. Check pilot safety shut-off operation.

    d. Check safety valve pressure and capacity setting and verify that the setting and capacity are consistent with unit load requirements.

    e. Check limit safety control and spill switch.

  2. Adjustments

    Perform the following checks and adjustments on a warm unit at high fire:

    a. Adjust unit to fire at the maximum inlet fuel use rate; record fuel manifold pressure

    b. Adjust draft and/or fuel pressure to obtain acceptable, clean combustion at both high, medium, and low firing rates. The carbon monoxide (CO) value should not exceed 400 parts per million (PPM) at 3 percent O2.

    Verify that unit light-offs are smooth and safe. Perform a reduced fuel pressure test at both high and low firing rates in accordance with the manufacturers instructions.

    c. Check and adjust the modulation controller. Verify proper, efficient, and clean combustion through the range of firing rates.

    When optimum performance has been achieved, record all data.

  3. Final Test

    Perform a final combustion analysis on the warm unit at high, medium, and low firing rates, if possible. Record data obtained from combustion analysis, as well as the following:

    a. Inlet fuel pressure at burner at high and low firing rates.

    b. Pressure above draft hood or barometric damper at high, medium, and low firing rates.

    c. Steam pressure, water temperature, or process fluid pressure or temperature entering and leaving the unit.

    d. Inlet fuel use rate if meter is available.