07/15 RULE 74.15.1: 1

VENTURA COUNTY AIR POLLUTION CONTROL DISTRICT

RULE 74.15.1 - BOILERS, STEAM GENERATORS, AND PROCESS HEATERS

(Adopted 5/11/93, Revised 6/13/95, 6/13/00, 9/11/12, 6/23/15)

A. Applicability

The provisions of this rule apply to any gaseous fuel or liquid fuel fired boiler, steam 

generator, or process heater with a rated heat input capacity equal to or greater than 1

million BTU per hour and less than 5 million BTU per hour. Both stationary and portable 

process heaters are subject to this rule. Applicable gaseous fuels include natural gas, 

landfill gas, biogas, liquefied petroleum gas (LPG), and produced oilfield gas.

B. Requirements

1. No person shall allow the discharge into the atmosphere, from any boiler, steam 

generator, or process heater with an annual heat input rate of equal to or greater 

than 1.8 x 109 BTU, oxides of nitrogen (NOx) emissions in excess of 30 parts per 

million volume (ppmv). Carbon monoxide (CO) emissions from units subject to 

this rule shall not exceed 400 ppmv.

2. Emission Limits for New and Replacement Boilers and Steam Generators

and Process Heaters:

a. No person shall allow the discharge into the atmosphere, from any new or 

replacement natural gas-fired boiler, steam generator, or process heater 

with a rated heat input capacity of equal to or greater than 1 million

BTU/hr and less than or equal to 2 million BTU/hr, oxides of nitrogen 

emissions in excess of 20 ppmv or 0.025 lbs/MMBTU heat input. Carbon 

monoxide emissions shall not exceed 400 ppmv. In addition prior to 

installation, each device shall be certified by the South Coast Air Quality 

Management District in accordance with the requirements of SCAQMD 

Rule 1146.2, adopted May 5, 2006. 

b. After January 1, 2016, no person shall allow the discharge into the 

atmosphere, from any new or replacement boiler, steam generator, or 

process heater fired with a rated heat input capacity of greater than 2

million BTU/hr and less than 5 million BTU/hr oxides of nitrogen 

emissions in excess of the following limits:

CATEGORY LIMITS

Units fired on Natural Gas- Atmospheric 12 ppm or 0.015 lbs/MMBTU heat input 

Units fired on Natural Gas- Pressurized 9 ppm or 0.011 lbs/MMBTU heat input

Units fired on Landfill Gas 25 ppm or 0.031 lbs/MMBTU heat input

Units fired on Biogas 15 ppm or 0.019 lbs/MMBTU heat input

Units fired on Liquefied Petroleum Gas 20 ppm or 0.025 lbs/MMBTU heat input

Units fired on Produced Oilfield Gas - Atmospheric 15 ppm or 0.019 lbs/MMBTU heat input

Units fired on Produced Oilfield Gas – Pressurized 12 ppm or 0.015 lbs/MMBTU heat input
07/15 RULE 74.15.1: 2

Carbon monoxide emissions shall not exceed 400 ppmv or 0.30 

lbs/MMBTU.

3. Any boiler, steam generator, or process heater with an annual heat input rate of 

equal to or greater than 0.3 x 109 BTU and less than 1.8 x 109 BTU (less than 2.8 

x 109 BTU for portable oil well dewaxing process heaters) shall comply with one 

of the following requirements:

a. The unit shall be tuned every 6 months or after 750 hours of operation 

since the previous tune-up, whichever occurs last, but in no case less than

once per calendar year. The unit shall be tuned in accordance with the 

procedure described in Attachment 1 for forced draft-fired equipment or 

Attachment 2 for natural draft-fired equipment; or

b. The unit shall comply with the emission and testing requirements of 

Subsection B.4.

4. Test Requirements

a. Units with a rated heat input capacity greater than 2 million BTU/hr, and 

subject to the provisions of Subsection B.1, shall test for compliance upon 

initial installation and then not less than once every 24 months.

b. Units with a rated heat input capacity of greater than 2 million BTU/hr, 

and subject to the provisions of Subsection B.2.b shall test for compliance 

upon initial installation and then not less than once every 48 months. 

c. Units with a rated heat input capacity of less than or equal to 2 million 

BTU/hr, and subject to the provisions of Subsection B.1 or B.2.a, shall test 

for compliance upon initial installation and then not less than once every 

48 months. The first source test on this test schedule shall be 48 months 

after the last source test conducted prior to September 11, 2012.

d. All units subject to emission limits shall perform an annual screening 

analysis of NOx and CO emissions unless a source test specified in either 

Subsection B.4.a, B.4.b, or B.4.c is required that year. The deadline for 

performing this annual screening is no later than the yearly anniversary 

date of the last source test. The operator shall notify the APCD by 

telephone, fax, or email, 24 hours prior to any screening analysis.

C. Exemptions

1. The provisions of Section B of this rule shall not apply to any unit operated on 

alternate fuel under the following conditions:
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a. Alternate fuel use is required due to the curtailment of natural gas service 

to the individual unit by the natural gas supplier. Alternate fuel use in this 

case shall not exceed the period of natural gas curtailment.

b. Alternate fuel use is required to maintain the alternate fuel system. 

Alternate fuel use in this case shall not exceed 50 hours per year.

2. The emission limits in Subsection B.1 shall not apply to any portable oil well 

dewaxing process heater if the annual heat input rate is less than 2.8 x 109 BTU. 

D. Recordkeeping Requirements

1. Any person owning and/or operating a boiler, steam generator, or process heater 

with an annual heat input rate of less than 2.8 x 109 BTU and not subject to the 

requirements of Subsection B.1 shall install a totalizing fuel meter for each 

applicable unit and for each fuel. Meters shall be accurate to ± one (1) percent, as 

certified by the manufacturer in writing. Fuel consumption for each unit shall be 

compiled monthly into a rolling twelve (12) calendar month report.

2. Any person subject to the provisions of Subsection B.3.a shall submit a report to 

the Air Pollution Control Officer (APCO) within forty-five (45) days after 

achieving first compliance with Subsection B.3.a. Reports shall continue to be 

submitted every twelve (12) months. The report shall verify that each tune-up has 

been performed and the results were satisfactory. The report shall contain all 

information and or documentation that the APCO may determine, in writing, to be 

necessary.

3. Any person subject to the provisions of Subsection B.4.d shall submit a report to 

the APCO within forty-five (45) days after first achieving compliance with the 

subsection. Reports shall continue to be submitted every twelve (12) months. 

The report shall contain all information and or documentation that the APCO may 

determine, in writing, to be necessary. Any person subject to the provisions of 

Subsection B.4.d, shall record the results of all screenings in an annual test log,

and this log shall be made available to APCD personnel upon request. This log

shall indicate the date of the screening, the NOx and CO emissions measured at 

3% Oxygen (calculated as NO2), the applicable NOx and CO limits for the unit, 

and any action taken, if applicable.

4. Any person utilizing alternate fuel, pursuant to the provisions of Subsection C.1 of 

this rule, shall maintain daily records of each occurrence. Each record shall 

include the type of fuel, the quantity of fuel, and the duration of the occurrence.

5. All records required by Subsection D shall be maintained for a period of four (4) 

years and shall be available for inspection by the APCO upon request.
07/15 RULE 74.15.1: 4

E. Test Methods

1. Compliance with the emission requirements in Section B shall be determined 

using ARB Method 100 for Oxides of Nitrogen, Carbon Monoxide, and Stack Gas 

Oxygen. An alternative procedure for determining emission compliance in units 

of lb/MMBTU heat input shall be determined using the South Coast AQMD 

“Compliance Protocol for the Measurement of Nitrogen Dioxide, Carbon 

Monoxide, and Oxygen From Sources Subject to SCAQMD Rules 1146 and 

1146.1” dated March 10, 2009.

2. Emission tests resulting in compliance determinations for the requirements of 

Subsection B.1 or B.2 shall be conducted on units in "As-found" operating 

condition.

3. The NOx parts per million emission limitation specified in Subsection B.1 and 

B.2 is expressed as nitrogen dioxide. The limitations for both NOx and CO are 

referenced at three (3) percent volume stack gas oxygen on a dry basis averaged 

over 15 consecutive minutes.

4. Screening analyses required pursuant to Subsection B.4.d shall be performed 

using a portable analyzer calibrated, maintained, and operated in accordance with 

the manufacturer’s specifications or as approved in writing by the APCO. 

Portable analyzer operators shall undergo training, on the operation and 

maintenance of the analyzer.

F. Violations

1. Failure to comply with any provision of this rule shall constitute a violation of this 

rule.

2. Any unit subject to the provisions of Subsection B.3 shall comply with the 

provisions of Subsection B.1 if the unit operates during any rolling twelve (12) 

month period at a total annual heat input rate greater than the applicable annual 

heat input rate specified in Subsection B.3.

3. Any unit previously operating at an annual heat input rate of less than 0.3 x 109

BTU shall comply with the applicable provisions of Subsection B.1 or Subsection 

B.3 if the unit operates during any rolling twelve (12) month period at a total 

annual heat input rate greater than 0.3 x 109 BTU.

4. An applicable unit shall be in violation if, according to a screening analysis, it is 

operated out-of-compliance with the requirements of either Subsection B.1 or B.2

as follows. All out-of-compliance screening analyses shall be reported to the 

District within seven (7) calendar days. The unit shall be corrected and a second 

screening analysis or source test shall be performed within fourteen (14) calendar 
07/15 RULE 74.15.1: 5

days of the initial screening analysis. The results of the second analysis shall be 

reported to the District within seven (7) days. If the unit remains out-ofcompliance, a violation has occurred.

G. Definitions

1. "Alternate Fuel": Any fuel that is permitted to be used due to natural gas 

curtailment by the natural gas supplier because of limited availability.

2. “Atmospheric Unit”: Any natural gas or produced oilfield gas fired unit with a 

non-sealed combustion chamber in which natural draft is used to exhaust 

combustion gases.

3 "Annual Heat Input": The actual amount of heat released by fuels burned in a unit 

during a twelve (12) calendar month rolling period, based on the fuel's higher 

heating value. The annual heat input shall be calculated as the sum of the 

previous 12 monthly fuel use rates multiplied by the fuel's higher heating value.

4. “Biogas”: A gaseous mixture of methane and carbon dioxide produced by the 

bacterial decomposition of organic waste and used as a fuel, including, but not 

limited to, digester gas.

5 "Boiler or Steam Generator": Any external combustion equipment fired with 

liquid and/or gaseous fuel and used to produce steam or to heat water. Boiler or 

Steam Generator does not include any unfired waste heat recovery boiler that is 

used to recover sensible heat from the exhaust of any combustion equipment.

6. “Landfill Gas”: Any gas derived through any biological process from the 

decomposition of waste buried within a waste disposal site.

7. “Liquefied Petroleum Gas (LPG)”: An organic compound having a vapor 

pressure not exceeding that allowed for commercial propane that is composed 

predominantly of the following hydrocarbons, either by themselves or as 

mixtures: propane, propylene, butane, and to a lesser extent butylenes, and that is 

stored and transported under pressure in a liquid state.

8. “Natural Gas”: Any mixture of gaseous hydrocarbons containing at least 80 

percent methane by volume, as determined using Standard Method ASTM D1945-

03(2010) or later revision.

9. "New or Replacement Boiler, Steam Generator, or Process Heater": Any 

applicable unit sold, offered for sale, or installed after January 1, 2013, pursuant to

Subsection B.2.a or after January 1, 2016, pursuant to Subsection B.2.b. 

10. “Open Heated Tank”: Any non-pressurized self-heated tank that may include a 

cover or doors that can be opened or detached to put in or remove parts, 
07/15 RULE 74.15.1: 6

components or other material for processing in the tank. Tanks heated solely by 

an electric heater, boiler, thermal fluid heater, or heat recovered from another 

process using heat exchangers are excluded from this definition.

11. “Portable Oil Well Dewaxing Process Heater”: Any portable process heater 

mounted on a truck or trailer that is used to heat and circulate fluid (usually crude 

oil) around oil well production tubing or oil flow lines to remove paraffin wax (a 

natural occurring constituent of crude oil) to prevent loss of oil production caused 

by wax plugging of the unit. 

12. “Pressurized Unit”: Any unit that does not meet the criteria needed to qualify as 

an atmospheric unit.

13. "Process Heater": Any external combustion equipment fired with liquid and/or 

gaseous fuel and which transfers heat from combustion gases to water or process 

streams. For the purpose of rule applicability, process heater does not include any 

of the following combustion sources:

a. Kiln, oven, open heated tank, dehydrator, dryer, crematory, incinerator, 

calciner, cooker, roaster, or furnace.,

b. Unfired waste heat recovery heater that is used to recover sensible heat 

from the exhaust of any combustion equipment, 

c. Fuel-fired degreasing or metal finishing equipment including parts 

washers and metal heat treating or metal furnaces,

d. Afterburner, vapor incinerator, or thermal or catalytic oxidizers used as an 

emission control device.

e. Glass melting furnace,

f. Tenter frame, fabric or carpet dryer.

14. “Produced Oilfield Gas”: Any mixture of gaseous hydrocarbons produced in the 

oil field containing less than 80 percent methane by volume, as determined using 

Standard Method ASTM D1945-03(2010) or later revision.

15. "Rated Heat Input Capacity": The heat input capacity specified on the nameplate 

of the combustion unit. If the combustion unit has been altered or modified such 

that its maximum heat input is different than the heat input capacity specified on 

the nameplate, the new maximum heat input shall be considered as the rated heat 

input capacity. This alteration or modification can be through either burner 

alteration or modification or installation of a fixed orifice. The new maximum 

heat input must be certified, in writing, by the manufacturer or installer and 

engineering calculations supporting the new maximum heat input rating must be 

submitted to the APCO.

16. “Tenter Frame Dryer”: Any cloth dryer that hold the edges of the material as it is 

dried in order to control shrinkage.
07/15 RULE 74.15.1: 7

17. "Therm": 100,000 BTU.

18. "Unit": Any boiler, steam generator, or process heater as defined in Subsections 

G.5, G.9, and G.13 of this rule.
7/95 ATTACHMENT 1 RULE 74.15.1: 8

ATTACHMENT 1

Equipment Tuning Procedure

for Forced Draft-fired Equipment1

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 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.

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 

the CO emissions are low and there is not 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 furnace 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 

 

1

. This tuning procedure is based on a tune-up procedure developed by KVB, Inc. for the 

EPA.

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:

1. For natural gas: 0.5% - 3%

2. For liquid fuels: 2% - 4%
7/95 ATTACHMENT 1 RULE 74.15.1: 9

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 in 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. Smoking at the stack.

d. Equipment-related limitations - such as low windbox/furnace pressure differential, 

built in air-flow limits, etc.

6. Develop an 02/CO curve (for gaseous fuels) or 02/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 Emissions 400 ppm

#1 & #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 CO or smoke threshold, or as the minimum excess 

oxygen level.

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 mixing, thereby allowing operation 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 
7/95 ATTACHMENT 1 RULE 74.15.1: 10

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.
7/95 ATTACHMENT 1 RULE 74.15.1: 11

Figure 1

Oxygen/CO Characteristic Curve

Figure 2

Oxygen/Smoke Characteristic Curve
7/95 ATTACHMENT 2 RULE 74.15.1: 12

ATTACHMENT 2

Equipment Tuning Procedure

for Natural Draft-Fired Equipment

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 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. Steps in the Procedure not applicable to specific units may be omitted.

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 tune-up.

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.) 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.

2. Checks & 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 
7/95 ATTACHMENT 2 RULE 74.15.1: 13

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 blowdown 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.

3. 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 setting and verify that the setting is consistent with 

unit load requirements.

e. Check limit safety control and spill switch.

4. 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% 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.

5. Final Test
7/95 ATTACHMENT 2 RULE 74.15.1: 14

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.