Rule 3.21 INDUSTRIAL, INSTITUTIONAL, AND COMMERCIAL BOILERS, STEAM 

GENERATORS, AND PROCESS HEATERS (Adopted: 6/05/2006) 

A. APPLICABILITY 

This rule applies to boilers, steam generators, and process 

heaters having the heat input capacities greater than or 

equal to 1 million BTU per hour (MMBTU/hr), used in all 

industrial, institutional, and commercial operations. 

B. EXEMPTIONS 

 

B.1 The requirements of Section D of this Rule shall not 

apply to the units with a rated heat input greater than 

or equal to 1 MMBtu/hr but less than 5 MMBtu/hr which 

are willing to accept permit conditions that restricts 

operation to less than 90,000 therms of annual heat 

inputs. 

a. To continue to qualify for the exemption provided 

in Section B.1, the owner or operator of any 

applicable unit(s) shall submit to the Air 

Pollution Control Officer (APCO) annual fuel use 

data and/or annual hours of operation that will 

demonstrate the unit(s) to have an annual heat 

inputs of less than 90,000 therms. 

b. Following the adoption of this rule, an exemption 

granted for any unit will become null and void, 

and in violation of this rule if the unit have an 

annual heat inputs more than or equal to 90,000 

therms. 

C. DEFINITIONS

C.1 Annual Heat Input: The total heat input of fuels burned 

by a unit in a calendar, as determined from the fuel’s 

HHV and cumulative annual usage of each fuel or 

cumulative hours of operation. 

C.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 any unit 

that is used exclusively to produce electricity for 

sale, any waste heat recovery boiler that is used to 

recover sensible heat from exhaust of combustion or a 

combustion turbine, nor does it include equipment 

associated with a chemical recovery cycle. 

 

C.3 British Thermal Unit (BTU): The amount of heat required 

to raise the temperature of one pound of water from 

59o

F to 60oF at one atmosphere. 

C.4 Commercial/Institutional Boiler: A boiler used to 

provide steam and/or hot water which is used in 
commercial or institutional establishments including 

but not limited to hospitals, research centers, 

educational facilities, hotels, dormitories, or 

laundries. 

C.5 Gaseous Fuel: Any fuel which is a gas at standard 

conditions. 

C.6 Gas-Fired: Using natural gas, propane, or any other 

gaseous fuel for firing the boiler or steam generator. 

 

C.7 Heat Input: 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. 

C.8 Higher Heating Value (HHV): The total heat liberated 

per mass of fuel burned (BTU per pound), when fuel and 

dry air at standard conditions undergo complete 

combustion and all resultant products are brought to 

their standard states at standard conditions. 

C.9 Industrial Boilers: A boiler used in manufacturing, 

processing, mining, refining and any other industries, 

where it provides steam, and/or hot water. 

C.10 Modification: Any physical change or operational change 

to an exiting emission unit, including a change in 

hours of operation or production rate which would 

necessitate a change in permit conditions. (Also 

defined in Rule 10.1) 

C.11 North FRAQMD: The area of the Feather River Air Quality 

Management District which is north of a line connecting 

the northern border of Yolo County to the Southwestern 

tip of Yuba County, and continuing along the Southern 

Yuba County border to Placer County. (Also defined in 

Rule 10.1) 

C.12 NOx Emissions: The sum of nitric oxides (NO) and 

nitrogen dioxide (NO2) in the flue gas. 

C.13 Nongaseous Fuel: Any fuel which is not a gas at 

standard conditions. 

C.14 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. 

C.15 Process Heater: Any combustion equipment fired with any 

fuel, and which transfers heat from combustion gases to 

heat water or process streams. This definition does not 

include any dryers in which the material being dried is 

in direct contact with the products of combustion, 

cement or lime kilns, glass melting furnaces, and 

smelters. 
C.16 Rated Heat Input Capacity: The heat input capacity, in 

million BTU per hour (MMBTU/hr), 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 maximum heat input 

shall be considered as the rated heat input. 

C.17 Sacramento Federal Non-attainment Area (SFNA)for Ozone: 

The area defined in 40CFR Section 81.305 for the 

Sacramento Metro Area. (Also defined in Rule 10.1) 

C.18 Standard Conditions: 68o

F and one atmosphere. 

C.19 Therm: One hundred thousand (100,000) BTU. 

C.20 Unit: Any boiler, steam generator or process heater as 

defined in Sections C.2 and C.15 of this rule. 

D. REQUIREMENTS 

D.1 No later than one (1) year following District adoption 

of this Rule, the owner or operator of any unit(s) 

under his/her control with a rated heat input capacity 

less than 5 MMBTU/hr but greater than or equal to 1 

MMBTU/hr and an annual heat input greater than or equal 

to 90,000 therms shall submit an application and a list 

of all operating units to the District. The owner or 

operator of the unit also shall select one of the 

following four options to be added as a permit 

condition to the Permit to Operate for each unit, in 

order to achieve compliance with this Rule. All new or 

modified units shall also comply with the requirements 

of District Rule 10.1, New Source Review. The options 

are: 

 

a. Operate in a manner that maintains stack gas 

oxygen concentrations at less than or equal to 3% 

by volume on dry basis for at a minimum of fifteen 

(15) consecutive minute averaging period. The 

averages shall be calculated from no less than 

five data set, recorded from a samplings on 

interval of no greater than three minutes; or 

b. Operate with a stack gas oxygen trim system set at 

3% by volume oxygen. The operational tolerance of 

the setting shall be within the range of 2.85% to 

3.15%; or 

c. Tune the unit at least once per year by a 

qualified technician to perform a tune-up in 

accordance with the procedure described in 

Attachment 1. The owner/operator of any unit(s) 

is required to submit an annual report verifying 

that the tune-up has been performed with 

satisfactory results in accordance to procedures 
described in Attachment 1. The report shall 

contain any other information or documentation 

that the APCO determines to be necessary; or 

d. Operate in compliance with the emission limits 

specified in Table 1 of this Rule. 

D.2 No later than one (1) year following District adoption 

of this Rule, all units with a rated heat input 

capacity greater than or equal to 5 MMBTU/hr and an 

annual heat inputs less than 90,000 therms shall select 

one of the following four options in sections D.1.aD.1.d to be added as a permit condition to the Permit 

to Operate for each unit, in order to achieve 

compliance with this Rule. All new or modified units 

shall also comply with the requirements of District 

Rule 10.1, New Source Review. 

D.3 No later than one (1) year following District adoption 

of this Rule, all units with a rated heat input 

capacity greater than or equal to 5 MMBTU/hr and annual 

heat inputs greater than or equal to 90,000 therms 

shall demonstrate compliance with the following 

emission limits dependent upon the area of nonattainment and specific fuel fired in the unit as shown 

in Table 1. All new or modified units shall meet the 

emission limits shown in Table 1 and comply with the 

requirements of District Rule 10.1, New Source Review. 

Table 1. EMISSION LIMITATIONS FOR NOx 

Type of Fuel Used

Only Gaseous Fuel 

Firing Units 

Gaseous & Non-Gaseous 

Fuel Co-Firing Units 

Non-Gaseous 

Firing Units 

North 

Portion of 

FRAQMD 

Emission 

Limits 

0.08 lbs/MMBTU 

or 

70 ppmv @ 3% O2

*Heat Input Weighted 

Average Fuel Limits 

0.15 lbs/MMBTU 

or 

115 ppmv @ 3% O2

SFNA 

Portion of 

FRAQMD 

Emission 

Limits 

0.036 lbs/MMBTU 

or 

30 ppmv @ 3% O2

*Heat Input Weighted 

Average Fuel Limits 

0.052 lbs/MMBTU 

or 

40 ppmv @ 3% O2

*The weighted average shall be calculated as follows: 

Emission = ( ) ( )

( ) YX

YyXx

+

+ **

Where x = emission limit for gaseous fuel 

 y = emission limit for non-gaseous fuel 

 X = heat input of the gaseous fuel 
 Y = heat input of the non-gaseous fuel. 

 

D.3 Emissions from units subject to D.2 shall not exceed a 

carbon monoxide (CO) concentration of 400 ppm corrected 

to 3% oxygen (O2) by volume when using only a gaseous or 

a combination of gaseous and liquid fuels. Solid fuelfired units shall not exceed CO limits expressed in the 

Permit to Operate. 

D.4 No person shall allow the discharge of ammonia 

(NH3)emissions in excess of 20 ppmv at dry stack 

conditions adjusted to 3% oxygen into the atmosphere 

from any emission control devices. 

E. EQUIPMENT REQUIREMENT 

 

E.1 Any persons subject to the provisions of Section B and 

Section D of this Rule shall install one of the 

following no later than one (1) year following District 

adoption of this Rule: 

a. A totalizing fuel meter. Fuel meters shall be 

installed to cumulatively record the total fuel 

used. Fuel meters shall be accurate to ±1% as 

certified in writing by the manufacturer and the 

fuel consumption for each unit shall be compiled 

monthly into a rolling twelve calendar month 

report , or; 

b. A non-resettable hour meter. Hour meter shall be 

installed with 9,999 non-resettable display 

capacity and the hours of operation shall be 

compiled monthly into a rolling twelve calendar 

month. 

A meter shall be installed for each applicable unit 

that fires gaseous and/or liquid fuel and shall be used 

to demonstrate compliance of the Permit to Operate, 

validate the exemption, and/or track annual emissions. 

E.2 Any person who operates a unit rated less 5 MMBtu/hr 

but greater than or equal to 1 MMBtu/hr or a unit rated 

at or greater than 5 MMBtu/hr with annual heat inputs 

of less than 90,000 therms who selects the option D.1.b 

shall install an Oxygen Trim System. The Oxygen Trim 

System shall be set accordingly to the requirements in 

section D.1.b and all related conditions on the Permit 

to Operate. 

F. COMPLIANCE DETERMINATION 

 

F.1 Initial Compliance: All existing, modified, or new units 

subject to meet requirements of Table 1 or section 

D.1.a of this rule shall demonstrate initial 

compliance. Initial compliance can be achieved by 

conducting a source test on a unit. All units shall be 

tested using the appropriate test method specified in 

Section G. 
F.2 Compliance Demonstration: All owners or operators of any 

unit subject to meet the emission limits listed in 

Table 1 or section D.1.a shall demonstrate compliance 

once every 8,760 hours of operation, or once every two 

calendar years; whichever occurs more frequently. All 

units shall be tested using the appropriate test method 

specified in Section G. 

F.3 Emission Determination: All emission determinations 

shall be made in the as-found operating conditions, 

except that emission determinations shall include, at a 

minimum, one source test conducted at the maximum 

firing rate allowed by the District permit, and no 

compliance determination shall be established within 

two (2) hours after a continuous period in which fuel 

flow to the unit is zero, or shut off for thirty (30) 

minutes or longer. 

F.4 Emission Concentration: All ppmv emission limits 

specified in Table 1 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 (O2) as follows: 

20.95% - 3.00% 

[ppm] corrected = 

20.95% - [%O2] measured 

*[ppm] measured 

F.5 Emission Averaging: All emission concentrations and 

emission rates shall be based on 15-consecutive-minute 

averaging periods. The averages shall be calculated 

from no less than five data sets, recorded from 

samplings on intervals of no greater than three 

minutes. 

F.6 Continuous Emission Monitoring: All units using 

continuous emission monitoring system to obtain data 

such as emission concentrations and emission rates 

shall utilize the test methods specified in Section G, 

Test Methods. 

G. TEST METHODS 

G.1 Compliance with the emission requirements in Table 1 

shall be determined using the following test methods: 

a. Oxides of Nitrogen – EPA Method 7E or CARB Method 

100 

b. Carbon Monoxide – EPA Method 10 or CARB Method 100 

c. Stack Gas Oxygen – EPA Method 3A or CARB Method 

100 

d. NOx Emission Rate (Heat Input Basis) – EPA Method 

19 

e. If certification of the higher heating value of 

the fuel is not provided by a third party fuel 

supplier, it shall be determined by EPA Method 19. 
G.2 For determination of the NH3 concentrations in stack 

gases, Bay Area Air Quality Management District 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.) 

H. RECORDKEEPING REQUIREMENTS

H.1 To assure compliance with this rule, the facility shall 

maintain records for a period of three (3) years and 

shall be made available for inspection by any 

authorized personnel upon request. The facility shall 

maintain the following information: 

a. The monthly hours of operation or quantity of fuel 

consumed for each unit, and; 

b. At the end of each calendar year, the facility 

shall compile a month-to-month report of the 

unit’s total operation i.e. fuel usage or hours of 

operation, and; 

c. A maintenance or testing log which includes but 

not limited to tune-up verification and source 

test results to verify compliance. 

 

H.2 The APCO may include additional recordkeeping 

requirements to assure compliance of this rule for each 

unit. 

H.3 Any person subject to the provisions of Section D.3 

and D.4 who fires 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 

APCO for purposes of documenting compliance with the 

specified emission limits. 
ATTACHMENT 1 

Tuning Procedure

General: Nothing in the tuning procedures** 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. 

** This tuning procedure is based on a tune-up procedure 

developed by KVB, Ind. for the EPA. 

A. Procedures for tuning mechanical draft boilers, steam 

generators, and process heaters: 

1) Operate the unit at the firing rate most typical of 

normal operation. If the unit experiences significant 

load variations during normal operations, operate the 

unit at its average firing rate. 

2) At the firing rate established in Section A.1, record 

stack-gas temperatures, oxygen concentration, and CO 

concentration (for gaseous fuels) or smoke-spot 

number(for liquid fuels), and observe flame conditions 

after unit operation stabilizes at the selected firing 

rate. If the excess oxygen in the stack-gas is at the 

lower end of the range of typical minimum values, 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. 

a) The smoke-spot number can be determined with ASTM 

test method D-2156 or with the Bacharach method. This 

Bacharach method is included in a tune-up kit that 

can be purchased from the Bacharach Company. 

b) Typical minimum oxygen levels for units at high 

firing rates are: 

1) For natural gas: 0.5 - 3% 

2) For liquid fuels: 2 - 4% 

3) Increase combustion air flow until the stack-gas oxygen 

levels increase by one or two percent over the level 

measured in Section A.2. As in Section A.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 unit operation stabilizes. 
4) Decrease combustion air flow until the stack-gas oxygen 

is at the level measured in Section A.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 the following 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 stack; 

d) equipment-related limitations - such as low 

windbox/furnace pressure differential, built-in airflow 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 smokespot number data obtained at each combustion air flow 

setting. 

 
7) From the curves prepared in Section A.6, find the stackgas 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 the CO or smokespot 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 

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 Section A.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 non-repeatability or play 

in automatic controls 

9) If the load of the combustion unit varies significantly 

during normal operation, repeat Sections A.1-A.8 for the 

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 the 

best performance over the range of the firing rates. If 

one firing rate predominates, the setting should 

optimize the 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 Section A.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. 

B. Procedures for tuning natural and induced draft boilers, 

steam generators, and process heaters. 

1) Preliminary Analysis 

a) Check the Operating Pressure or Temperature. Operate 

the boiler, steam generator, or process 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 that will be used as a basis for 

comparative combustion analysis before and after 

tune-up. 

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. 

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) 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. 
f) Combustion Analysis. Perform an "as is" flue gas 

analysis (O2, CO, CO2, etc.) with a warmed up boiler 

steam generator, or heater at high and low fire. In 

addition to data obtained from combustion analysis, 

also record the following: 

1) Inlet fuel pressure at burner (at high and low 

fire) 

2) Draft above draft hood or barometric damper 

a. Draft hood: high, medium, and low 

b. Barometric damper: high, medium, and low 

c. Steam pressure, water temperature, or process 

fluid pressure or temperature entering and 

leaving the boiler, steam generator, or process 

heater. 

d. Unit rate if meter is available. 

With above conditions recorded, make the following 

checks and corrective actions as necessary: 

2) Checks and 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 burnedoff or missing burner parts, and replace as needed. 

b) Check for Clean Boiler, Steam Generator, or Process 

Heater Tubes and Heat transfer Surfaces. External and 

internal build-up of sediment and scale of the 

heating surfaces creates an insulating effect that 

quickly reduces unit efficiency. Excessive fuel cost 

will result if units are not kept clean. Clean tube 

surfaces, remove scale and soot, and assure proper 

fluid 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 safety valve pressure and capacity to meet 

boiler, steam generator, or process heater 

requirements. 

d) Check limit safety control and spill switch. 

e) Check pilot safety shut-off operation. 

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 rated capacity, record fuel 

manifold pressure. 

b) Adjust draft and/or fuel pressure to obtain 

acceptable, clean combustion at high, medium and low 

fire. Carbon monoxide value should always be below 

400 ppm at 3% O2. 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 

manufacturer’s instructions and maintenance manuals. 

c) Check and adjust operation of modulation controller. 

Ensure proper, efficient, and clean combustion 

through the 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. 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 tune-up was 

performed.