SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

(Adopted September 9, 1988)(Amended January 6, 1989)

(Amended May 13, 1994)(Amended June 16, 2000)

(Amended November 17, 2000)(Amended September 5, 2008)

(Amended November 1, 2013)

RULE 1146 EMISSIONS OF OXIDES OF NITROGEN FROM 

INDUSTRIAL, INSTITUTIONAL, AND COMMERCIAL 

BOILERS, STEAM GENERATORS, AND PROCESS 

HEATERS

(a) Applicability

This rule applies to boilers, steam generators, and process heaters of equal to or 

greater than 5 million Btu per hour rated heat input capacity used in all industrial, 

institutional, and commercial operations with the exception of:

(1) boilers used by electric utilities to generate electricity; and

(2) boilers and process heaters with a rated heat input capacity greater than 40 

million Btu per hour that are used in petroleum refineries; and

(3) sulfur plant reaction boilers.

(4) RECLAIM facilities (NOx emissions only)

(b) Definitions

(1) ADSORPTION CHILLER UNIT means any natural gas fired unit that 

captures and uses waste heat to provide cold water for air conditioning and 

other process requirements.

(2) ANNUAL CAPACITY FACTOR means the ratio of the amount of fuel 

burned by a unit 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.

(3) ANNUAL HEAT INPUT means the actual amount of heat released by 

fuels burned in a unit during a calendar year.

(4) ATMOSPHERIC UNIT means any natural gas fired unit with a heat input 

less than or equal to 10 million Btu per hour with a non-sealed combustion 

chamber in which natural draft is used to exhaust combustion gases.

(5) BOILER or STEAM GENERATOR means any combustion equipment 

fired with liquid and/or gaseous (including landfill and digester gas)

and/or solid fossil fuel and used to produce steam or to heat water and that 

is not used exclusively to produce electricity for sale. Boiler or Steam 

1146-1
Rule 1146 (Cont.) (Amended November 1, 2013)

Generator does not include any open heated tank, adsorption chiller unit, 

or waste heat recovery boiler that is used to recover sensible heat from the 

exhaust of a combustion turbine or any unfired waste heat recovery boiler 

that is used to recover sensible heat from the exhaust of any combustion 

equipment.

(6) BTU means British thermal unit.

(7) COMMERCIAL OPERATION means any office building, lodging place, 

or similar location designed for tenancy by one or more business entities 

or residential occupants.

(8) GROUP I UNIT means any unit burning natural gas with a rated heat 

input greater than or equal to 75 million Btu per hour, excluding thermal 

fluid heaters.

(9) GROUP II UNIT means any unit burning gaseous fuels, excluding 

digester and landfill gases, with a rated heat input less than 75 million Btu 

per hour down to and including 20 million Btu per hour, excluding 

thermal fluid heaters.

(10) GROUP III UNIT means any unit burning gaseous fuels, excluding

digester and landfill gases, and thermal fluid heaters with a rated heat 

input less than 20 million Btu per hour down to and including 5 million 

Btu per hour, and all units operated at schools and universities greater than 

or equal to 5 million Btu per hour.

(11) HEALTH FACILITY has the same meaning as defined in Section 1250 of 

the California Health and Safety Code.

(12) HEAT INPUT means the chemical heat released due to fuel combustion in 

a unit, using the higher heating value of the fuel. This does not include the 

sensible heat of incoming combustion air.

(13) INDUSTRIAL OPERATION means any entity engaged in the production 

and/or provision of chemicals, foods, textiles, fabricated metal products, 

real estate, personal services or other kindred or allied products or 

services.

(14) INSTITUTIONAL OPERATION means any public or private 

establishment constituted to provide medical, educational, governmental, 

or other similar services to promote safety, order, and welfare.

(15) NOx EMISSIONS means the sum of nitric oxide and nitrogen dioxide in 

the flue gas, collectively expressed as nitrogen dioxide.

1146-2
Rule 1146 (Cont.) (Amended November 1, 2013)

(16) OPEN HEATED TANK means a non-pressurized self-heated tank that 

may include a cover or doors that can be opened or detached to put in or 

remove parts, 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.

(17) PROCESS HEATER means any combustion equipment fired with liquid 

and/or gaseous (including landfill and digester gas) and/or solid fossil fuel 

and which transfers heat from combustion gases to water or process 

streams. Process Heater does not include any kiln or oven used for drying, 

curing, baking, cooking, calcining, or vitrifying; or any unfired waste heat 

recovery heater that is used to recover sensible heat from the exhaust of 

any combustion equipment.

(18) RATED HEAT INPUT CAPACITY means 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.

(19) SCHOOL means any public or private school, including juvenile detention 

facilities with classrooms, used for purposes of the education of more than 

12 children at the school, including in kindergarten and grades 1 to 12, 

inclusive, but does not include any private school in which education is 

primarily conducted in private homes. The term includes any building or 

structure, playground, athletic field, or other area of school property, but 

does not include unimproved school property. 

(20) STANDBY BOILER is a boiler which operates as a temporary 

replacement for primary steam or hot water while the primary steam or hot 

water supply unit is out-of-service.

(21) THERM means 100,000 Btu.

(22) THERMAL FLUID HEATER means a PROCESS HEATER in which a 

process is heated indirectly by a heated fluid other than water.

(23) UNIT means any boiler, steam generator, or process heater as defined in 

paragraph (b)(5) or (b)(17) of this subdivision.

1146-3
Rule 1146 (Cont.) (Amended November 1, 2013)

(c) Requirements

(1) The owner or operator shall subject all of the units within the facility to 

the NOx emission limits and schedules specified in Table 1146-1:

Table 1146-1 – Standard Compliance Limits and Schedule

(2) In lieu of complying with the NOx emission limits and schedules specified 

in paragraph (c)(1), the owner or operator may elect to subject all of the 

units within the facility to the requirements specified in Table 1146-2. 

The owner or operator that fails to submit a Compliance Plan or 

Application for Permit to Construct pursuant to the schedule specified in 

Table 1146-1 for any of the Group II units shall be subject to the NOx 

limits and schedule specified in Table 1146-2.

Rule 

Reference Category Limit Submit Compliance

Plan on or 

before

Submit Application 

for Permit to

Construct on or 

before

Unit Shall be in 

Full Compliance

on or before

(c)(1)(A) All Units Fired on 

Gaseous Fuels

30 ppm or

for natural gas fired 

units 0.036 lbs/106 Btu 

- - September 5, 2008

(c)(1)(B) Any Units Fired on 

Non-gaseous Fuels

40 ppm - - September 5, 2008

(c)(1)(C) Any Units Fired on 

Landfill Gas

25 ppm - - January 1, 2015

(c)(1)(D) Any Units Fired on 

Digester Gas

15 ppm - - January 1, 2015

(c)(1)(E) Atmospheric Units 12 ppm or

0.015 lbs/106 Btu

January 1, 2010 January 1, 2013 January 1, 2014

(c)(1)(F) Group I Units 5 ppm or

0.0062 lbs/106 Btu

- January 1, 2012 January 1, 2013

(c)(1)(G) Group II Units

75% or more of 

units (by heat 

input)

January 1, 2010 January 1, 2011 January 1, 2012

(c)(1)(H) Group II Units

100% of units (by 

heat input) 9 ppm or

January 1, 2010 January 1, 2013 January 1, 2014

(c)(1)(I) Group III Units

75% or more of 

units (by heat 

input)

0.011 lbs/106 Btu January 1, 2011 January 1, 2012 January 1, 2013

(c)(1)(J) Group III Units

100% of units (by 

heat input)

January 1, 2011 January 1, 2014 January 1, 2015

1146-4
Rule 1146 (Cont.) (Amended November 1, 2013)

Table 1146-2 – Enhanced Compliance Limits and Schedule

Rule 

Reference Category Limit Submit Compliance

Plan on or before

Submit Application 

for Permit to

Construct on or 

before

Unit Shall be 

in Full 

Compliance

on or before

(c)(2)(A) Group II Units

75% or more of units 

(by heat input) 5 ppm or 0.0062 

lbs/106 Btu

January 1, 2011 January 1, 2013 January 1, 

2014

(c)(2)(B) Group II Units

100% of units (by 

heat input)

January 1, 2011 January 1, 2015 January 1, 

2016

 

(3) For dual fuel co-fired combustion a weighted average limit calculated by 

Equation 1146-1 may be used provided a totalizing fuel flow meter is 

installed pursuant to paragraph (c)(8), for units burning a combination of 

both fuels. 

(CLA x QA) + (CLB x QB)

Weighted Limit = ______________________ Equation 1146-1

QA + QB

Where:

CLA = compliance limit for fuel A

CLB = compliance limit for fuel B

QA = heat input from fuel A

QB = heat input from fuel B

 

(4) The owner or operator of any unit(s) with a heat input capacity greater 

than or equal to 5 million Btu per hour shall not discharge into the 

atmosphere carbon monoxide (CO) emissions in excess of 400 ppm or for 

natural gas fired units 0.30 lbs/106 Btu.

(5) In lieu of complying with the applicable emission limits specified in 

paragraphs (c)(1), (c)(2), (c)(3), and (c)(4), the owner or operator of any 

unit(s) in operation prior to September 5, 2008 with an annual heat input 

less than or equal to 9.0 x 109 Btu (90,000 therms) per year, shall: 

1146-5
Rule 1146 (Cont.) (Amended November 1, 2013)

(A) operate the unit(s) in a manner that maintains stack gas oxygen 

concentrations at less than or equal to 3 percent on a dry basis for 

any 15-consecutive-minute averaging period; or

(B) tune the unit(s) at least twice per year, (at intervals from 4 to 8 

months apart) in accordance with the procedure described in 

Attachment 1 or the unit manufacturer's specified tune-up 

procedure. If a different tune-up procedure from that described in 

Attachment 1 is used then a copy of this procedure shall be kept on 

site. The operator of any unit(s) selecting the tune-up option shall 

maintain records for a rolling twenty four month period verifying 

that the required tune-ups have been performed. If the unit does 

not operate throughout a continuous six-month period within a 

twelve month period, only one tuneup is required for the twelve 

month period that includes the entire period of non-operation. For 

this case, the tune-up shall be conducted within thirty (30) days of 

start-up. No tune-up is required during a rolling twelve month 

period for any unit that is not operated during that rolling twelve 

month period; this unit may be test fired to verify availability of 

the unit for its intended use but once the test firing is completed the 

unit shall be shutdown. Records of test firings shall be maintained 

for a rolling twenty four month period, and shall be made 

accessible to an authorized District representative upon request.

(6) Any unit(s) with a rated heat input capacity greater than or equal to 40 

million Btu per hour and an annual heat input greater than 200 x 109 Btu 

per year shall have a continuous in-stack nitrogen oxides monitor or 

equivalent verification system in compliance with 40 CFR part 60 

Appendix B Specification 2. Maintenance and emission records shall be 

maintained and made accessible for a period of two years to the Executive 

Officer.

(7) An owner or operator that has installed or modified a Group III natural gas 

fired unit prior to September 5, 2008 complying with the applicable BACT

emission limit of 12 ppm or less of NOx may defer compliance with 

subparagraphs (c)(1)(I) or (c)(1)(J) until the unit’s burner(s) replacement.

(8) Any owner or operator who chooses the pound per million Btu compliance 

option specified in paragraph(s) (c)(1) (c)(2), or (c)(4) or chooses the 

weighted average emission limit using Equation 1146-1 under paragraph 

1146-6
Rule 1146 (Cont.) (Amended November 1, 2013)

(c)(3) shall install a non-resettable totalizing fuel meter to measure the 

total of each fuel used by each individual unit, as approved by the 

Executive Officer.

(9) The owner or operator of Group II or III units shall submit for the 

approval of the Executive Officer a compliance plan in accordance with 

the requirements of Rule 221 – Plans and Rule 306 – Plan Fees by the 

applicable date specified in Tables 1146-1 or 1146-2. The compliance 

plan shall include the following information:

(A) Owner/operator contact information (company name, AQMD 

facility identification number, contact name, phone number, 

address, e-mail address).

(B) Number and size (mmbtu/hr) of Group II and III units located at 

the facility.

(C) Selection of the Standard (Table 1146-1) or Enhanced (Table 

1146-2) compliance schedule by Group II and III units.

(D) The owner or operator of more than one unit located within the 

same facility that have opted to divide the units by heat input for 

the purpose of separate compliance dates according to Tables 

1146-1 or 1146-2 shall indicate which units are categorized 75 

percent or more of the heat input and which units make up the 

remaining 100 percent of the heat input.

(10) On or after January 1, 2015, an owner operator of any landfill or digester 

gas (biogas) unit co-fired with natural gas shall not operate the unit in a 

manner that exceeds the emission concentration limits specified in 

subparagraphs (c)(1)(C) or (c)(1)(D), provided that the facility monthly 

average biogas usage by the biogas units is 90% or more, based on the 

higher heating value of the fuels used.

(A) The Executive Officer may approve the burning of more than 

10% up to:

(i) 25% natural gas in a biogas fired unit at the 15 ppm 

(digester gas) or 25 ppm (landfill gas) NOx level, when it 

is necessary, if the only alternative to limiting natural gas 

to 10% would be shutting down the unit and flaring more 

biogas.

(ii) 50% natural gas in a digester gas-fired unit at the 15 ppm 

NOx level, when it is necessary as specified in clause (c) 

1146-7
Rule 1146 (Cont.) (Amended November 1, 2013)

(10)(A)(i) and for units installed on or after September 5, 

2008 provided the unit has demonstrated compliance with 

the NOx limits in paragraph (c)(1) applicable to units 

fired exclusively on natural gas.

For units subject to this subparagraph, the percent natural gas 

usage shall be based on the facility monthly average biogas 

usage by the biogas units and the higher heating value of the 

fuels used.

(B) Any biogas-fired unit burning more than the approved percent 

natural gas as determined under subparagraph (c)(10)(A) shall 

comply with the weighted average NOx limit specified in 

paragraph (c)(3).

(d) Compliance Determination

(1) An owner or operator of any unit(s) shall have the option of complying 

with either the pound per million Btu or parts per million emission limits 

specified in paragraphs (c)(1), (c)(2), (c)(3), and (c)(4).

(2) All emission determinations shall be made in the as-found operating 

condition, except no compliance determination shall be established during 

start-up, shutdown, or under breakdown conditions. Compliance 

determination as specified in paragraph (d)(6) shall be conducted at least 

250 operating hours, or at least thirty days subsequent to the tuning or 

servicing of any unit, unless it is an unscheduled repair. 

(3) All parts per million emission limits specified in subdivision (c) are 

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

over a period of 15 consecutive minutes.

(4) Compliance with the NOx and CO emission requirements of paragraphs 

(c)(1), (c)(2), (c)(3), and (c)(4) and the stack-gas oxygen concentration 

requirement of subparagraph (c)(5)(A) shall be determined using a District 

approved contractor under the Laboratory Approval Program according to 

the following procedures:

(A) District Source Test Method 100.1 - Instrumental Analyzer 

Procedures for Continuous Gaseous Emission Sampling (March 

1989), or

(B) District Source Test Method 7.1 - Determination of Nitrogen 

Oxide Emissions from Stationary Sources (March 1989) and 

1146-8
Rule 1146 (Cont.) (Amended November 1, 2013)

District Source Test Method 10.1 - Carbon Monoxide and Carbon 

Dioxide by Gas Chromatograph/Non-Dispersive Infrared Detector 

(GC/NDIR) - Oxygen by Gas Chromatograph-Thermal 

Conductivity (GC/TCD) (March 1989); or

(C) United States Environmental Protection Agency Conditional Test 

Method CTM-030, Determination of Nitrogen Oxides, Carbon 

Monoxide, and Oxygen Emissions from Natural Gas-Fired 

Engines, Boilers and Process Heaters Using Portable Analyzers; or 

(D) ASTM D6522-00(2005) Standard Test Method for Determination 

of Nitrogen Oxides, Carbon Monoxide, and Oxygen 

Concentrations in Emissions from Natural Gas-Fired Reciprocating 

Engines, Combustion Turbines, Boilers, and Process Heaters Using 

Portable Analyzers

(E) any other test method determined to be alternative and approved 

before the test in writing by the Executive Officers of the District 

and the California Air Resources Board and the Regional 

Administrator of the United States Environmental Protection 

Agency, Region IX; or 

(F) a continuous in-stack nitrogen oxide monitor or equivalent 

verification system as specified in paragraph (c)(6).

Records of all source tests shall be made available to District personnel 

upon request. Emissions determined to exceed any limits established by 

this rule through the use of any of the above-referenced test methods shall 

constitute a violation of this rule.

(5) For any operator who chooses the pound per million Btu of heat input 

compliance option of paragraph (c)(1), (c)(2), (c)(3), or (c)(4), NOx

emissions in pounds per million Btu of heat input shall be calculated using 

procedures in 40 CFR Part 60, Appendix A, Method 19, Sections 2 and 3

and CO emissions in pounds per million Btu of heat input shall be 

calculated according to the Protocol for the Periodic Monitoring of 

Nitrogen Oxides, Carbon Monoxide, and Oxygen from Units Subject to 

South Coast Air Quality Management District Rules 1146 and 1146.1.

1146-9
Rule 1146 (Cont.) (Amended November 1, 2013)

(6) Compliance determination with the NOx emission requirements in 

paragraph (d)(4) shall be conducted once:

(A) every three years for units with a rated heat input greater than or 

equal to 10 million Btu per hour, except for units subject to 

paragraph (c)(6).

(B) every five years for units with a rated heat input less than 10 

million Btu per hour down to and including 5 million Btu per hour.

(7) Provided the emissions test is conducted within the same calendar year as 

the test required in paragraph (d)(6), an owner or operator may use the 

following emissions tests to comply with paragraph (d)(6):

(A) Periodic monitoring or testing of a unit as required in a Title V 

permit pursuant to Regulation XXX, or 

(B) Relative accuracy testing for continuous emissions monitoring 

verification pursuant to Rule 218.1 or 40 CFR part 60 Appendix B 

Specification 2.

(8) Any owner or operator of units subject to this rule shall perform diagnostic 

emission checks of NOx emissions with a portable NOx, CO and oxygen 

analyzer according to the Protocol for the Periodic Monitoring of Nitrogen 

Oxides, Carbon Monoxide, and Oxygen from Units Subject to South Coast 

Air Quality Management District Rules 1146 and 1146.1 according to the 

following schedule:

(A) On or after July 1, 2009, the owner or operator of units subject to 

paragraphs (c)(1), (c)(2), (c)(3), and (c)(4) shall check NOx

emissions at least monthly or every 750 unit operating hours, 

whichever occurs later. If a unit is in compliance for three 

consecutive diagnostic emission checks, without any adjustments 

to the oxygen sensor set points, then the unit may be checked 

quarterly or every 2,000 unit operating hours, whichever occurs 

later, until the resulting diagnostic emission check exceeds the 

applicable limit specified in paragraphs (c)(1), (c)(2), or (c)(3).

(B) On or after January 1, 2015 or during burner replacement, 

whichever occurs later, the owner or operator of units subject to 

paragraph (c)(5) shall check NOx emissions according to the tuneup schedule specified in subparagraph (c)(5)(B).

(C) Records of all monitoring data required under subparagraphs 

(d)(8)(A) and (d)(8)(B) shall be maintained for a rolling twelve 

1146-10
Rule 1146 (Cont.) (Amended November 1, 2013)

month period of two years (5 years for Title V facilities) and shall 

be made available to District personnel upon request.

(D) The portable analyzer diagnostic emission checks required under 

subparagraph (d)(8)(A) and (d)(8)(B) shall only be conducted by a 

person who has completed an appropriate District-approved 

training program in the operation of portable analyzers and has 

received a certification issued by the District.

(9) An owner or operator shall comply with the requirements as applied to CO 

emissions specified in paragraph (d)(8) and subparagraph:

(A) (d)(6)(A) for units greater than or equal to 10 mmbtu/hr, or

(B) (d)(6)(B) for units less than 10 mmbtu/hr.

(10) A diagnostic emission check conducted under the requirements specified 

in paragraph (d)(8) that finds emissions in excess of those allowed by this 

rule or a permit condition shall not constitute a violation of this rule if the 

owner or operator corrects the problem and demonstrate compliance with 

another emission check within 72 hours from the time the owner or 

operator knew of excess emissions, or reasonably should have known, or 

shut down the unit by the end of an operating cycle, whichever is sooner.

(11) Notwithstanding the requirements specified in paragraph (d)(10) any 

diagnostic emission check conducted by District staff that finds emissions 

in excess of those allowed by this rule or a permit condition is a violation.

(12) An owner or operator may opt to lower the unit’s rated heat input capacity. 

The lowered rated heat input capacity shall not be less than or equal to 2 

million Btu per hour and shall be based on manufacturer’s identification or 

rating plate or permit condition.

1146-11
Rule 1146 (Cont.) (Amended November 1, 2013)

(e) Compliance Schedule

(1) An owner or operator of units subject to paragraph (c)(1) shall comply 

with the schedule specified in Table 1146-1.

(2) An owner or operator of units subject to paragraph (c)(2) shall comply 

with the schedule specified in Table 1146-2.

(3) On or after January 1, 2015 or during burner replacement, whichever 

occurs later, no person shall operate in the District any unit subject to

paragraph (c)(5) which does not meet the emissions limits specified in

subparagraph (c)(1)(A) of Table 1146-1.

(4) Any unit subject to the requirements specified in paragraph (c)(5) that 

exceeds 90,000 therms of heat input from all fuels used in any twelve 

month period, the operators shall:

(A) within 4 months after exceeding 90,000 therms of heat input in any 

twelve month period, submit required applications for permits to 

construct and operate; and 

(B) within 18 months after exceeding 90,000 therms of heat input in 

any twelve month period, demonstrate and maintain compliance 

with all applicable requirements of paragraphs (c)(1), (c)(2), (c)(3), 

and (c)(6) for the life of the unit.

(5) The Executive Officer shall grant a time extension to the full compliance 

date with the applicable NOx compliance limits specified in 

subparagraphs (c)(1)(E) through (c)(1)(J) and paragraph (c)(2) for any 

health facility as defined in Section 1250 of the California Health and 

Safety Code that can demonstrate that the Office of Statewide Health 

Planning and Development has approved an extension of time to comply 

with seismic safety requirements pursuant to Health and Safety Code 

Sections 130060 and 130061.5. The extension of time granted by the 

Executive Officer shall be consistent with the time extension granted 

pursuant to Health and Safety Code Section 130060 but not to exceed 

January 1, 2015 and shall be consistent with the time extension granted 

pursuant to Health and Safety Code Section 130061.5 but not to exceed 

January 1, 2020. Those health facilities granted a time extension shall 

submit a compliance plan to the Executive Officer on or before January 1, 

2010.

1146-12
Rule 1146 (Cont.) (Amended November 1, 2013)

ATTACHMENT 1

A. Equipment Tuning Procedure1 for Forced-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 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.

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 personnel 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 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 

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

States EPA.

2 The smoke-spot number can be determined with ASTM Test Method D-2156 or with the 

Bacharach method. ASTM Test Method D-2156 is included in a tuneup kit that can be 

purchased from the Bacharach Company.

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%

1146-13

 
Rule 1146 (Cont.) (Amended November 1, 2013)

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. Smoking at the stack.

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

1146-14
Rule 1146 (Cont.) (Amended November 1, 2013)

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 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 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 O2 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.

1146-15
Rule 1146 (Cont.) (Amended November 1, 2013)

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 load 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 affected 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.

11. When the above checks and adjustments have been made, record data and attach 

combustion analysis data to boiler, steam generator, or heater records indicating 

name and signature of person, title, and date the tuneup was performed.

B. Equipment Tuning Procedure for Natural Draft-Fired 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 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 codes, regulations, and equipment manufacturers specifications and 

operating manuals.

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 personnel on request.

1. PRELIMINARY ANALYSIS

a. CHECK THE OPERATING PRESSURE OR TEMPERATURE.

Operate the boiler, steam generator, or heater at the lowest acceptable 

pressure or temperature that will satisfy the load demand. This will 

minimize heat and radiation losses. Determine the pressure or temperature 

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Rule 1146 (Cont.) (Amended November 1, 2013)

that will be used as a basis for comparative combustion analysis before 

and after tuneup.

b. CHECK OPERATING HOURS.

Plan the workload so that the boiler, steam generator, or process heater 

operates only the minimum hours and days necessary to perform the work 

required. Fewer operating hours will reduce fuel use and emissions. For 

units requiring a tuneup to comply with the rule, a totalizing non-resettable 

fuel meter will be required for each fuel used and for each boiler, steam 

generator, and heater to prove fuel consumption is less than the heat input 

limit in therms per year specified in the rule.

c. CHECK AIR SUPPLY.

Sufficient fresh air supply is essential to ensure optimum combustion and 

the area of air supply openings must be in compliance with applicable 

codes and regulations. Air openings must be kept wide open when the 

burner is firing and clear from restriction to flow.

d. CHECK VENT.

Proper venting is essential to assure efficient combustion. Insufficient 

draft or overdraft promotes hazards and inefficient burning. Check to be 

sure that vent is in good condition, sized properly and with no 

obstructions.

e. COMBUSTION ANALYSIS.

Perform an "as is" combustion analysis (CO, O2, etc.) with a warmed up 

unit at high and low fire, if possible. In addition to data obtained from 

combustion analysis, also record the following:

i. Inlet fuel pressure at burner (at high & low fire)

ii. Draft at inlet to draft hood or barometric damper

1) Draft hood: high, medium, and low

2) Barometric Damper: high, medium, and low

iii. Steam pressure, water temperature, or process fluid pressure or 

temperature entering and leaving the boiler, steam generator, or 

process heater.

iv. Unit rate if meter is available.

With above conditions recorded, make the following checks and corrective 

actions as necessary: 

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Rule 1146 (Cont.) (Amended November 1, 2013)

2. CHECKS & CORRECTIONS

a. CHECK BURNER CONDITION.

Dirty burners or burner orifices will cause boiler, steam generator, or 

process heater output rate and thermal efficiency to decrease. Clean 

burners and burner orifices thoroughly. 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 & HEAT TRANSFER SURFACES.

External and internal build-up of sediment and scale on the heating 

surfaces creates an insulating effect that quickly reduces unit efficiency. 

Excessive fuel cost will result if the unit is not kept clean. Clean tube 

surfaces, remove scale and soot, assure proper process fluid flow and flue 

gas flow.

c. CHECK WATER TREATMENT & BLOWDOWN PROGRAM.

Soft water and the proper water or process fluid treatment must be 

uniformly used to minimize scale and corrosion. Timely flushing and 

periodic blowdown must be employed to eliminate sediment and scale 

build-up on a boiler, steam generator or process heater.

d. CHECK FOR STEAM, HOT WATER OR PROCESS FLUID LEAKS.

Repair all leaks immediately since even small high-pressure leaks quickly 

lead to considerable fuel, water and steam losses. Be sure there are no 

leaks through the blow-off, drains, safety valve, by-pass lines or at the 

feed pump, if used.

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 and capacity to meet boiler, steam generator 

or process heater requirements.

e. Check limit safety control and spill switch.

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Rule 1146 (Cont.) (Amended November 1, 2013)

4. ADJUSTMENTS

While taking combustion readings with a warmed up boiler, steam generator, or 

process heater at high fire perform checks and adjustments as follows:

a. Adjust unit to fire at rate; record fuel manifold pressure.

b. Adjust draft and/or fuel pressure to obtain acceptable, clean combustion at 

both high, medium and low fire. Carbon Monoxide (CO) value should 

always be below 400 parts per million (PPM) at 3% 02. If CO is high 

make necessary adjustments.

Check to ensure boiler, steam generator, or process heater light offs are 

smooth and safe. A reduced fuel pressure test at both high and low fire 

should be conducted in accordance with the manufacturers instructions 

and maintenance manuals.

c. Check and adjust operation of modulation controller. Ensure proper, 

efficient and clean combustion through range of firing rates.

When above adjustments and corrections have been made, record all data.

5. FINAL TEST

Perform a final combustion analysis with a warmed up boiler, steam generator, or 

process heater at high, medium and low fire, whenever possible. In addition to 

data from combustion analysis, also check and record:

a. Fuel pressure at burner (High, Medium, and Low).

b. Draft above draft hood or barometric damper (High, Medium and Low).

c. Steam pressure or water temperature entering and leaving boiler, steam 

generator, or process heater.

d. Unit rate if meter is available.

When the above checks and adjustments have been made, record data and attach 

combustion analysis data to boiler, steam generator, or process heater records 

indicating name and signature of person, title, company name, company address 

and date the tuneup was performed.

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