State of California 

AIR RESOURCES BOARD 

DETERMINATION OF REASONABLY AVAILABLE CONTROL TECHNOLOGY 

AND BEST AVAILABLE RETROFIT CONTROL TECHNOLOGY 

FOR 

INDUSTRIAL, INSTITUTIONAI. AND COMMERCIAL BOILERS, 

STEAM GENERATORS, AND PROCESS HEATERS 

Prepared by 

Criteria Pollutants Branch 

Stationary Source Division 

Approved by 

the Technical Review Group 

of the 

California Air Pollution Control Officers' Association 

July 18, 1991 
This determination was prepared by the Air Resources Board staff in 

cooperation with the Combustion Committee of the California Air Pollution 

Control Officers' Association's Technical Review Group. We would like to 

particularly thank: 

rt •.. ERfi1iT~Tii 

Jim Guthrie 

Marline Hicks 

Theresa Dade 

Don Price 

Craig Ullery 

Brigette Tolistrup 

Dan Speer 

Jim Guthrie 

Gary Quinn 

Ventura County APCD 

Bay Area AQMD 

Sacramento Metropolitan AQMD 

San Diego County APCD 

ARB 

South Coast Air Quality 

Management District 

Peter D. Venturini, Chief, Stationary Source Division 

Ronald A. Friesen, Assistant Chief, Stationary Source Division 

Dean C. Simeroth, Chief, Criteria Pollutants Branch 

Robert D. Fletcher, Manager, Fuels Section 
Contents LIU 

INTRODUCTION .........................................................

1 

I. RACT/BARCT RECOMMENDATION .......................................1 

A. RACT Discussion .............................................1 

B. BARCT Discussion ........ ...................................4 

II. CONTROL TECHNOLOGY ..............................................6 

A. Low-NOx Burners .............................................7 

B. Flue Gas Recirculation . ....................................8 

C. Selective NoncatAlytic Reduction ............................8 

D. Se3ertive Catalyt7c Redl1S ion ...............................8 

III. COST-EFFECTIVENESS ..............................................9 

IV. IMPACTS .........................................................10 

A. Economic ....................................................10 

B. Air Oualitv .................................................10 

C. Hazards .....................................................10 

D. Enrav .................................................. .11 

V. REFERENCES ......................................................12 

APPENDICES 

A. RACT/BARCT DETERMINATION 

B. SCAQMD RULE 1146.1 - Emissions of Oxides of Nitrogen From Small 

Industrial, Institutional, and Commercial Boilers, Steam 

Generators, and Process Heaters. 

C. SCAQMD RULE 1146 - Emissions of Oxides of Nitrogen From Industrial, 

Institutional, and Commercial Boilers, Steam Generators, and 

Process Veaters 

D. SCAQMD RULE 1109 - Emissions of Oxides of Nitrogen From Boilers and 

Process Heaters in Petroleum Refineries 

E. VCAPCD RULE 74.15 - Boilers, Steam Generators and Process Heaters 

F. SIGNIFICANT COMMENTS AND RESPONSES 
INTRODUCTION 

This report presents the proposed determinations of reasonably 

available control technology (RACT) and best available retrofit control 

technology (BARCT) for industrial, institutional, and commercial boilers, 

steam generators, and process heaters. The RACT/BARCT Determination is 

presented in Appendix A of this document. The determinations follow the 

"California Clean Air Act Guidance for the Deterrnination of Reasonably 

Available Control Technology and Best Available Retrofit Control 

Technology," approved by the California Air Resources Board (ARB) on 

April 13, 1990. The determinations have been reviewed and approved by the 

Technical Review Group (TRG) of the California Air ?ollution Control 

Officers' Association (CAPCOA). 

In developing the proposed RACT and BARCT determinations, the staff 

reviewed a statewide suggested control measure (SCM) and several district 

rules. Tables 1 and 2 present summaries of the SCM and the district rules 

that the staff reviewed. The Technical Support Document (TSD) for the SCM 

is available upon request. The complete texts of the applicable district 

rules are contained in Appendices B-E. 

I. RACT/BARCT RECOMMENDATION 

On Aprii 29, 1987, the TRG approved a suggested control measure for the 

control of emissions of oxides of nitrogen (NOx) from industrial, 

institutional, and commercial boilers, steam generators and process heaters. 

This SCM was subsequently approved by the ARB on September 10, 1987. The 

SCM applies to units with rated heat inputs of 10 million British thermal 

units per hour (MMBtu/hr) and up, except units with rated heat inputs of 

greater than 40 MMBtu/hr that are based in petroleum refineries. 

The lowest ernission limits contained in the SCM apply to units with 

rated heat inputs of greater than or equal to 20 million Btu per hour and 

less than or equal to 150 million Btu per hour, operating with annual 

capacity factors of greater than 10 percent. The limits for these units are 

70 parts per million by volume (ppmv) NOx for gaseous fuel operations and 

115 ppmv NOx for.number 1 or number 2 grade fuel oil. 

For the RACT determination, we have extended the application of these 

limits to all units with rated heat inputs of greater than or equal to 

5 million Btu per hour, operating with annual heat inputs of greater than or 

equal to 90,000 therms. We have also applied the limit for operating on 

number 1 or number 2 grade fuel oil to operation with all types of 

nongaseous fuels. Units which normally burn only gas are allowed a 150 ppmv 

NOx emission limit for burning nongaseous fuel for not more than 168 hours 

per year, if gas is unavailable for purchase. 

1 
Table 1 

Emission Limits Contained in the Suggested Control Measure 

Approved by the Air Resou -ces Board on September 10, 1987 

RatedIL Annual NOxhL 

Heat Capacity Fuel Emission 

I flDSdt FactoL Jy= Limits 

120 and <150 MMBtu/hr >10.0X Gas 70 ppmv NO xor 

0.08 lbs NO 2 /MMBtu 

Fuel Oi1 #1 or #2 115 ppm NO xor 

0.15 lbs NO 2 /MMBtu 

Other Fuel Oil 150 ppmv NO xor 

0.20 lbs NO 2 /MMBtu 

>150 MMBtu/hr >5.0% Gas 85 ppmv NOxor 

0.10 lbs NO 2 /MMBtu 

Fuel Oil #1 or #2 135 ppmv NO x or 

0.18 ibs NO2 /MMBtu 

Other Fuel Oil 165 ppmv NOxor 

0.22 lbs NO2 /MMBtu 

AL Units with rated heat inputs of greater than or equal to 10 MMBtu/hr, and 

less than 20 MMBtu/hr, and with annual capacity factors of greater than 

10.0%, are subject to other requirements. 

hL Corrected to 3.00 percent by volume 0 2 , dry, and averaged over 15 

consecutive minutes. 

2 
Table 2 

Sunrnary District Rules Reviewed for NOx Emissions 

from Non-Utility Boilers and Process Heaters 

Rated Annual NOxf.L C0rl 

Heat Neat Input or Emission Emission 

Input Ca ap city Factor Limits Limits 

-------SCAQMD's Rule 1146.1, Boilers and Process Heaters (10/5/90)---- 

12 and <5 MMBtu/hr >18,000 thermsIL 30 ppmv or 400 ppmv 

0.037 lbs NO 2 /MMBtu 

-------SCAQMD's Rule 1146, Boilers and Process Heaters (9/9/88, 1/6/89)----- 

>_5 MMBtu/hr < 90,000 thermshL 40 ppmv or 400 ppmv 

0.05 lbs NO 2 /MMBtu 

>_40 MMBtu/hr >25x 30 pprnv 400 ppmv 

-------SCAQMD's Rule 1109, Boilers and Process Heaters - Petroieum----------- 

Refineries, (11/1/85, 8/5188) 

>40 MMBtu/hr >lOx 0.03 lbs NO /MMBtu 

@ maximum rited 

capacity 

-------YCAPCD's Rule 74.15, Boiiers and Process Heaters, (3/28/89)---------- 

>5 MMBtu/hr 290,000 therms hL 40 ppmv 400 ppmv 

~ Units with annual heat inputs of less than 18,000 therms are subject to 

other requirements. 

kL Units with annual heat inputs of less than 90,000 therms are subject to 

other requirements. 

r.L Corrected to 3.00 percent by volume 0 2 , dry, and averaged over 15 

consecutive minutes. 

3 
A summary of the RACT determination is presented in Tabie 3. 

F.P05i11:i4>• ~ • ~ 

As shown in Table 2, both the South Coast Air Quality Management 

District (SCAQMD) and the Ventura County Air Pollution Control District 

(VCAPCD) have adopted source specific rules for NOx emission control on nonelectric-generating boilers, steam generators, and process heaters. SCAQMD 

Rule 1109, adopted November 1, 1985, and amended August 5, 1988, applies to 

units with rated heat inputs of greater than 40 MMBtu/hr located at 

petroleum refineries. SCAQMD Rule 1146, adopted September 9, 1988, and 

amended January 6, 1989, applies to units with rated heat inputs of 5 

MMBtu/hr and up not located at petroleum refineries. SCAQMD Rule 1146.1, 

adopted October 5, 1990, applies to units with rated heat inputs from 2 

MMBtu/hr to less than 5 MMBtu/hr. VCAPCD Rule 74.15, adopted March 28, 

1989, applies to units with rated heat inputs of 5 MMBtu/hr and up, except 

water heaters. 

The emission limits contained in district rules are 30 ppmv NOx for 

units with rated heat inputs of greater than or equal to 2 million Btu per 

hour and less than 5 miilion Btu per hour, having annual heat inputs of 

greater than 18,000 therms; 40 ppmv Nbx for units with rated heat inputs of 

greater than or equal to 5 million Btu per hour, having annual heat inputs 

of greater than 90,000 therms; 30 ppmv NOx for units with rated heat inputs 

of greater than or equal to 40 million Btu per hour, operating at annual 

capacity factors of greater than 25 percent; and 0.03 pounds NO 2per miliion 

Btu of heat input for units operating at maxirnum rated capacity with rated 

heat inputs of greater than 40 million Btu per hour, sited at petroleum 

refineries and operating at annual capacity factors of greater than or equal 

to 10 percent. 

For the BARCT determination, we have applied the 30 ppmv NOx emission 

limit to all units burning gas, having rated heat inputs of greater than or 

equal to 5 million Btu per hour and operating with annual heat inputs of 

greater than or equal to 90,000 therms. For units burning nongaseous fuels, 

we have applied the 40 ppmv NOx emission limit to all units having rated 

heat inputs of greater than or equal to 5 million Btu per hour, operating 

with annual heat inputs of greater than or equal to 90,000 therms. Units 

which normally burn only gas are allowed a 150 ppmv NOx emission limit for 

burning nongaseous fuel for not more than 168 hours per year, if gas is 

unavailable for purchase. 
Table 3 

RACT/BARCT Summary for Industrial, Institutional 

and Commercial Boilers, Steam Generators, and Process Heaters 

Standards 

---------- RACT ----------- 

Rated Annual"~ 

Heat Heat Fuel 

Inpsl.t. Ingut~ 7.= 

> 5 MMBtu/hr > 90,000 therms Gas 

Other 

ExemptionaL 

NOxbL 

Emission 

70 ppmvf.L 

115 ppmv~ 

150 ppmv 

C0 L 

Emission 

Limits 

400 ppmv 

400 ppmv 

400 ppmv 

NOx bl 

Fuel Emission 

1= Li mits 

Gas 30 ppmv&L 

Other 40 ppmvfL 

150 ppmvbl- ExemptiongL 

C 0kL 

Emission 

Limits 

400 ppmv 

400 ppmv 

400 ppmv 

---------- BARCT ---------- 

Rated Annual AL 

Heat Heat 

IADJIt I D RSIt — 

> 5 MMBtu/hr > 90,000 therms 

AL Units with annual heat inputs of iess than 90,000 therms are subject to 

other requirements. 

~ Corrected to 3.00 percent by volume O z , dry, and averaged over 15 

consecutive minutes. 

~ 0.084 pounds NO 2per MMBtu of heat input. 

~ 0.150 pounds NO 2 per MMBtu of heat input. 

'L 0.036 pounds NO2per MMBtu of heat input. 

" 0.052 pounds NO 2per MMBtu of heat input. 

9L For not more than 168 hours per calendar year, only when gas is not 

available for purchase. 

hL 0.215 pounds NOx per MMBtu of heat input. 

~~ 
We chose 30 ppmv as the uniforrn BARCT NOx emission limit for gas firing 

of all industrial, institutional, and commercial boilers, steam generators, 

and process heaters. This uniform emission limit reflects improvements in 

technology which have occurred in the last few years. We believe that most 

units can meet this limit by installing new burners with flue gas 

recirculation. Some units may need to add selective noncatalytic reduction or 

other emission control technology instead of flue gas recirculation due to 

particular unit design problems. We believe that 30 ppmv is the appropriate 

BARCT NOx emission limit due to the many units currently operating within this 

limit without the use of flue gas emission controls. New units- of the near 

future may achieve emission limits below 15 ppmv NOx without the use of flue 

gas emission controls. However, for districts which have recently adopted 

rules which allow higher emissions, the incremental cost-effectiveness of 

requiring 30 ppmv may be high for some affected units. Therefore, districts 

which have adopted rules covering the applicability of this determination, 

within three years prior to the date of approval of this determination, are 

deemed to comply with this determination. 

In the SCAQMD, specially blended low-NOx fuel oil, which has low sulfur, 

nitrogen, and aromatic hydrocarbon contents, is being used to meet the 40 ppmv 

limit of Rule 1146. Since the low-NOx fuel oil is blended in small 

quantities, it is much more expensive than number 2 fuel oil. Therefore, this 

low-NOx fuel oil is being used primarily for dual fuel firing capability at 

this time. Methanoi is also being used in the SCAQMD to meet the 40 ppmv 

limit with dual fuel firing capability. We believe that, in the future, 

liquid fuel firing at 40 ppmv NOx may be economically competitive with gas 

firing at 30 ppmv NOx. 

A summary of the BARCT determination is also presented in Table 3. 

II. CONTROL TECHNOLOGY 

Nitric oxide (NO) forms in process equipment such as boilers and heaters, 

which operate on the combustion of fuel and air. The NO may then be emitted 

to the atmosphere along with other products of combustion in the flue gas. 

Smaller amounts of nitrogen dioxide (NO 2 ) form in the combustion process, and 

some NO oxidizes to NO 2 in the stack. 

We refer to NO and NO cumulatively as oxides of nitrogen (NO ), and we 

quantify NO emissions as ~ arts per million (ppm) by volume, relative to dry 

stack gases x at 3'percent 0. Alternately, we may quantify NO emissions as 

pounds of NO per million iritish thermal unit (MMBtu) of fuel input to the 

process, basid on the higher heating value (HHY) and flow rate of the fuel. 

The formation of NO by combustion processes is governed primarily by (1) 

the chemically-bound nitrogen content of the fuel, (2) the oxygen 

concentration of the flame, (3) the temperature of the flame, and {4} the 

length of time for which the combustion gases are held at the flame 

temperature. 
Chemically-bound nitrogen of 1000 ppm by weight in fuel oi1 could result 

in NO formation of up to 83 ppm by volume, relative to dry stack gases at 3 

percent 0. This estimate is based on 65 percent conversion of fuel-nitrogen 

to N0. Fgr higher fuel-nitrogen contents the percent conversion is iower. 

For lower fuel-nitrogen contents, the percent conversion is higher. Residual 

fuel oils may have nitrogen contents of between 1000 ppm and 8000 ppm by 

weight. In California, distillate fuel oils with nitrogen contents between 

200 and 600 ppm by weight are typically available. Sy 1994, distillate fuel 

oils with nitrogen contents beiow 10 ppm by weight may be available as a 

result of statewide regulations limiting the sulfur content of motor vehicle 

diesel fuel. Chemically-bound nitrogen of 10 ppm in fuel oil could not 

convert to more than 1 ppm of N0. Oue partly to chemically-bound nitrogen in 

fuel oils, the combustion of fuel oils produces more NO than the combustion of 

natural gas at the same conditions. 

Generally, premixed flames, such as in natural gas combustion, wili 

produce less NO than diffusion flames, such as in oil droplet combustion, with 

the same amount of excess air. This is because the peak temperatures in 

diffusion flames occur at surfaces of theoreticaliy correct air-to-fuel 

ratios, while the peak temperatures for premixed flames are lower due to 

excess-air dilution. 

For most applications reducing NOx emissions from industrial, 

institutional, and commercial boilers, steam generators, and process heaters 

can be broken down into four methods. These are (1) retrofitting of 1ow-NOxemitting burners, (2) retrofitting of flue-gas-recirculation systems (3) 

installation of ammonia injection systems for selective noncatalytic 

reduction, and (4) installation of ammonia injection systems along with 

catalytic reactors for selective catalytic reduction. These methods are 

discussed below. 

Low-NOx burners employ low excess air combustion, air staging, fuel 

staging, or combustion product recirculation to lower NOx formation in the 

flame. Low excess air combustion and combustion product recirculation 

decrease the oxygen available for NOx formation. Combustion product 

recirculation also lowers the bulk flame temperature, and consequently lowers 

the NOx formation rate and equilibrium concentration. Staged-air burners 

lower available oxygen at points in the combustion chamber where the 

temperature is h.igh. Staged-fuel burners lower the temperature at points in 

the combustion chamber where available oxygen is high. Retrofitting of lowNOx burners may require derating of equipment, because flame lengths may be 

significantly increased. 

Low-NOx burners are applicable to most gas-fired and oil-fired units. 

For gas-fired units, the control effectiveness ranges from 10 to 55 percent. 

For units fired with low-nitrogen oil, the control effectiveness is expected 

to be within the same range. 
~MUMMMMWM • { 

Flue gas recirculation (FGR) for NOx control consists of extracting a 

portion of the flue gas from the economizer outlet and returning it to the 

furnace, admitting the flue gas through the furnace windbox. Flue gas 

recirculation lowers the bulk furnace gas temperature and reduces oxygen 

concentration in the combustion zone. 

A retrofit installation of FGR consists of adding a fan, ductwork, 

dampers, and controls as well as possibly having to increase existing fan 

horsepower due to increased draft loss. 

FGR is an effective control technique for both gas-fired and distillate 

oil-fired units. FGR is not effective at reducing NOx formation originating 

from fuel-bound nitrogen. The control effectiveness of flue gas recirculation 

ranges from 60 to 70 percent for gas-fired units. The control effectiveness 

of FGR for units firing low-nitrogen oil is expected to be within the same 

range. 

- ► • ~ . ;nLq~: -~:M ~ { 

Exxon Research and Engineering Company has developed, patented, and is 

offering for license, a noncatalytic process called Thermal DeNOx for removing 

oxides of nitrogen from flue gas in stationary combustion sources. Thermal 

DeNOx is based on the gas phase homogeneous reaction between NOx in flue gas 

and ammonia (NH 3 ), which produces nitrogen and water. 

In general, NH is injected into the hot flue gas by means of either air 

or steam carrier ga ~ at a point in the flue specifically selected to provide 

optiTum reacti8n temperature and residence time. In the temperature range of 

1600 F to 2200 F, the reaction occurs through the injection of NHalone. 

Hydrogen (H ) can also be injected alongowith NH3 to extend the e?fectiveness 

range of thi deNOx reaction down to 1300 F. 

NOx reductions of up to 90 percent have been demonstrated on an oil field 

steam generators where favorable process conditions exist. DeNOx performance 

using earlier technology ranges from 50 to 70 percent reduction for most oilfired and gas-fired process heaters and steam boilers. 

MMMMUMMM19MMIXr. • ~ 

Selective catalytic reduction (SCR) refers to a process that chemically 

reduces NOx with NH over a heterogeneous catalyst in the presence of oxygen 

(0 ) The process ~ s termed setective because the reducing agent NH 

priferentially attacks NOx rather than 0. However, the 0 enhances 3 the 

reaction and is a necessary part of the ~ eaction scheme. ~ hus, SCR is 

potentially applicable to flue gas under oxidizing conditions, greater than 

one percent 0 2 . 

In theory a 1:1 stoichiometric molar ratio of NH to NO is sufficient to 

reduce NOx to molecular nitrogen (N ) and water vapor 3 (H 0). In practice a 

NH 3 :N0 ratio of 1:1 has typically riduced NOx emissions gy 80 to 90 percent 

8 
with a residual NH concentration of less than 20 pBmv. The o optimum 

temperature range ?or the catalytic reaction is 570 F to 845 F. 

SCR retrofitting requires a reactor, which contains the catalytic 

material, and an ammonia storage and injection system. Due to the increased 

pressure drop across the reactor, some increase in boiler fan horsepower, or 

possibly a new fan, may be necessary. 

SCR has been extensively employed in Japan on gas-fired and oil-fired 

industrial and utility boilers. 

III. COST-EFFECTIVENESS 

Flue-gas recirculation and ammonia injection are probably the most 

universally applicable methods for reducing NOx emissions from industrial, 

institutional, and commercial boilers, and process heaters. The unit cost of 

NOx emission reduction with FGR ranges from E1600 to $7800 per ton at 

50 percent capacity factors. The unit cost of NOx emission reduction with 

ammonia injection ranges from $1500 to $6000 per ton at 50 percent capacity 

factors. Low-NOx burners are generally less expensive, and SCR is generally 

more expensive, than these methods. The ranges are reflective that unit costs 

generally increase with decreasing equipment size. Furthermore, unit costs 

increase rapidly with decreasing capacity factors below 25 percent. Table 4 

presents a summary of cost-effectiveness ranges for the different 

technologies. 

Table 4 

Cost-Effectiveness of Selected NOx Emission Control Technologies 

Annual Unit Size NOx Emission Reduction 

Capacity Range Cost-Effectiveness Range 

Factor (MMBtu/hr) (1986E thousand/ton NOx) 

Low-N x Burners 10% 2.3 to 27 

50% 3.5 to 150 0.5 to 6.4 

90% 0.3 to 4.0 

Elue Gas Recirculation 10% 6.8 to 29 

50% 3.5 to 350 1.6 to 6.8 

90% 1.0 to 3.7 

Selective Noncatalytic 10% 2.3 to 20 

Reduction 50% 50 to 375 1.5 to 6.0 

90% 1.3 to 3.8 

Selectiye Catalytic 10% 24 to 66 

Reduction 50% 50 to 350 6.0 to 14 

90% 4.0 to 9.0 

9 
Reasonably available control technology (RACT) requirements can be met 

with either FGR or ammonia injection. However, for oil-firing, switching to a 

lower nitrogen-content fuel may be required. FGR is ineffective at reducing 

NOx formation originating from fuel nitrogen, and the absolute amount of NOx 

passing through ammonia injection systems increases directly with the amount 

entering. Where applicable, low-NOx burners may be more effective at reducing 

emissions when firing with high-nitrogen fuel. 

Best avaiiable retrofit control technology (BARCT) requirements for gasfiring may be met by installing new burners with either FGR or ammonia 

injection. However, both methods, or SCR, may be necessary for up to twice 

the cost. 

IV. IMPACTS 

•i•o 

The potential economic impacts of this determination are the capital cost 

of emission control equipment and the increased operating cost associated with 

emission control equipment. If combustion equipment is operated with lower 

excess air after, or instead of, retrofitting control equipment; there will be 

a cost benefit due to increased thermal efficiency. 

B. Air Oualitv 

The most significant impact of this determination is the decrease in NOx 

emissions and resultant decrease in atmospheric ozone and PM10 formation. 

Other potential impacts inciude ammonia slip from SNCR and SCR systems and 

ammonia leakage from storage and handling systems, which will result in 

emissions of ammonia to the atmosphere. Ammonia emissions will increase the 

formation of PM10 in the atmosphere. 

C. Hazards 

Ammonia is a toxic, highly reactive compound and its use, storage, and 

transport can be hazardous, especially in the case of worker exposure to 

highly concentrated ammonia vapor or contact with liquid ammonia. 

Occupational Safety and Health Administration (OSHA) regulations specify the 

rnethods for the use, storage, and transport of ammonia. These regulations 

were developed to reduce the hazards that could occur when handling ammonia. 

The spent catalyst materials from the use of SCR commonly contain small 

amounts of hazardous materials, including vanadium pentoxide. This compound 

is toxic if inhaled. A majority of catalysts used in California are now 

reclaimed and recycled by the manufacturer, so that their disposal should pose 

no significant environmental impacts. For those facilities that do not 

recycle their catalysts, the spent material wouid have to be deposited in a 

Class I landfill. The only operational Class I disposal site in California is 

located in Kings County. 

10 
D.Energv 

Additional fan energy will be required to operate FGR, SNCR, and SCR 

systems. Ali of the systems require additional mass flows and gas velocities, 

which will increase flow losses through the furnaces and downstream passages. 

The FGR ducting and SCR reactor are additional flow impedances. 

11 
REFERENCES 

(1) Calvert, S., and Englund, H.M. Nandbook of Air Pollution Technology, 

John Wiley and Sons, Inc., New York, 1984. Chapter 5, "Gaseous 

Pollutant Characteristics," Chapter 9, "Control of Gases by Chemical 

Reaction," and Chapter 35, "Atmospheric Chemistry." 

(2) DeLacy, J.M. Introduction to Coen Low NOx Burner Techniques, Revision 

A, Coen Company, Inc., Burlingame, California, November 1986. 

(3) Energy Section, Stationary Source Division. Technical Support Document 

for A Suggested Control Measure for the Control of Emissions of Oxides 

of Nitrogen from Industrial, Institutional, and Commerical Boilers, 

Steam Generators and Process Heaters, California Air Resources Board, 

Sacramento, April 1987. Chapter X, "Cost and Cost-Effectiveness of NOx 

Controis," and Appendix C, "Cost Calculation Methodology." 

(4) Exxon Research and Engineering Company. "Improved ER&E Thermal DeNOx 

Process," Exxon Technology, Florham Park, New Jersey, July 1987. 

(5) Glassman, I. Combustion, Academic Press, Inc., New York, 1977. 

Chapter 8, "Environmental Combustion Considerations." 

(6) Goff, T., Kern County. Telephone conversation, June 1991. 

(7) Howard, G., Neggo, R., and Wallerstein, B., Rule Development Division. 

Staff Report, Proposed Arrrended Rule 1109, Emissions of Oxides of 

Nitrogen from Boilers and Process Neaters in Petroleum Refineries, 

South Coast Air Quality Management District, E1 Monte, California, 

October, 1987. Section VII, "Other Environmentai Impacts," and 

"Attachment A." 

(8) Karaba, J.M., Pyronics, Inc. Cornbustion Nandbook, Industrial Heating 

Equipment Association, Inc., Washington D.C., 1970. Session I. 

"Fundamentals of Combustion." 

(9) Keenan, J.H., and Kaye, J. Gas Tables, John Wiley and Sons, Inc., New 

York, 1948. Table 1, "Air at Low Pressures (for One Pound)." 

(10) Keenan, J.H., Keyes, F.G., Hill, P.G., and Moore, J.G. Steam Tables, 

John Wiley and Sons, Inc., New York, 1969. Table 3, p. 14, "Water Vapor 

at Low Pressures." 

(11) KVB, Inc. 6oiler Efficiency Improvement Training Seminar, KVB, Inc., 

Tustin, California. United States Department of Energy Contract No. CR04-70190, November 1977. Unit 1.0, "Boiler Energy Overview," Unit 3.0, 

"Boiler Efficiency and Controlling Factors," and Unit 4.0, "Efficiency 

Calculation." 

12 
(12) Lim, K.J., Milligan, R.J., Lips, H.I., Castaldini, C., Merrill, R.S., 

and Mason, H.B. Technology Assessment Report for Industrial Boiler 

Applications: NOx Combustion Modification, U.S. Environmental 

Protection Agency, Washington, D.C., December 1979. EPA-600/7-79-178f. 

Section 2, "Emission ControT Techniques." 

(13) Office of Research and Development. Guidelines for Industrial Boiler 

Performance Improvement, EPA-600/8-77-003a, United States Environmental 

Protection Agency, Research Triangle Park, North Carolina, January 1977. 

Section 2.0, "Fundamentals of Combustion," and Section 3.0, "Preparation 

for Boiler Tests." 

(14) 0'Rourke, D. Petro America, Inc. Facsimile transmission and telephone 

conversation, July 1991. 

(15) Robertson, W.S. Boiler ffficiency and Safety, ESSO Petroleuro Company, 

Limited, The MacMillan Press, Ltd., London, 1981. P. 29, et seq., 

"Calculation of Combustion Efficiency." 

(16) Shields, C.D. Boilers, F.W. Dodge Corporation, New York, 1961. 

Chapter 1, "Boiler Types," Chapter 2, "Steel Firetube Boilers," Chapter 

3, "Steel Watertube Boilers," and Chapter 30, "Boiler Performance." 

(17) Votlucka, P., Rule Development Division. Staff Report, Proposed 

Amended Rule 1146 - Emissions of Oxides of Nitrogen from Irtdustrial, 

Institutional, and Commercial Boilers, Steam Generators, and Process 

Neaters, South Coast Air Quality Management District, E1 Monte, 

California, December 1988. Appendix B. "Cost-Effectiveness 

Calculations." 

(18) Votlucka, P., Smith, S., and Johnson, S.L., Office of Planning and 

Rules. Staff Report for: Proposed Rule 1146.1: Emissions of Oxides 

of Nitrogen from Small Industrial, Institutional, and Comnercial 

Boilers, Steam Generators, and Process Neaters, South Coast Air Quality 

Management District, E1 Monte, California, September 1990. Appendix A, 

"Cost-Effectiveness Calculations." 

(19) Yang, S., Pohl, J.H., Bortz, S.J., Yang, R.J., and Chang, W. 

"Development of Low NOx Gas Burners," EPRI/EPA 1991 Joint Symposium on 

Stationary Combustion NOx Control, Electric Power Research Institute, 

Palo Alto,.California, March 1991. 

13 
APPENDIX A 

RACT/BARCT Determination 

A.1 
DETERMINATION OF REASONABLY AVAILABLE CONTROL TECHNOLOGY AND 

BEST AVAILABLE RETROFIT CONTROL TECHNOLOGY 

FOR INDUSTRIAL. INSTITUTIONAL, AND COMMERCIAL BOIIERS, STEAM GENERATORS. 

AND PROCESS HEATERS 

I. Applicability 

This determination applies to boilers, steam generators, and process 

heaters with rated heat inputs of greater than or equal to 5 million Btu per 

hour, used in all industrial, institutional, and commercial operations. 

This determination does not apply to boilers used by electric utilities to 

generate electricity, waste heat recovery boilers that are used to recover 

sensible heat from the exhaust of combustion turbines, dryers in which the 

material being dried is iri direct contact with the products of combustion, 

cement and lime kilns, glass melting furnaces, and smelters. 

II. Definitions 

A. ANNUAL HEAT INPUT means the total heat input of fuels burned by a 

unit in a calendar year, as determined from the HHV and cumulative 

annual usage of each fuel. 

B. BARCT means "best available retrofit control technology," defined 

in section 40406 of the California Health and Safety Code as "an 

emission limitation that is based on the maximum degree of 

reduction achievable, taking into account environmental, energy, 

and economic impacts by each class or category of source." 

C. BOILER OR STEAM GENERATOR means any combustion equipment fired 

with any fuel and used to produce steam that is not used 

exclusively to produce electricity for sale. BOILER or STEAM 

GENERATOR does not include any waste heat recovery boiler that is 

used to recover sensible heat from the exhaust of a combustion 

turbine. 

D. BRITISH TNERMAL UNIT (Btu) means the amount of heat requireg to 

raise the temperature of one pound of water from 59 °F to 60 F at 

one atmosphere. 

E. NEAT 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. 

F. 6AS means any fuel which is a gas at standard conditions. 

G. HIGNER HEATING VALUE (HHV) means the totaT heat liberated per 

mass of fuel burned (8tu 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. HHV shall be determined by one of the following test 

methods: (1) ASTM D 2015-85 for solid fuels; (2) ASTM D 240-87 or 

A.2 
ASTM D 2382-88 for liquid hydrocarbon fuels; or (3) ASTM D 1826-88, 

or ASTM 0 1945-81 in conjunction with ASTM Q 3588-89 for gaseous 

fuels. 

H. NOx EMISSIONS (NOx) means the sum of nitric oxides and nitrogen 

dioxide in the flue gas. 

I. NON6ASEOUS FUEL means any fuel which is not a gas at standard 

conditions. 

J. PARTS PER MILLION (BY VOLUME) (ppmv) means the ratio of the number 

of gas molecules of a given species, or group, to the number of 

millions of total gas molecules. 

K. PROCESS HEATER means any combustion equipment fired with any 

fuel, and which transfers heat from combustion gases to water or 

process streams. PROCESS HEATER 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, or smelters. 

L. RACT means "reasonably available control technology." 

M. RATED HEAT INPUT (million Btu per hour) 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 maximum heat input shall be 

considered as the rated heat input. 

N. STANDARD CONDITIONS means 68 0

F and one atmosphere. 

0. THERM means one hundred thousand (100,000) Btu. 

P. THREE PREVIOUS CALENDAR YEARS means the three corssecutive years 

irtmediately preceding the year in which final compliance is 

required by this determination, or the three consecutive years 

imnediately preceding each calendar year of compliance thereafter. 

Q. UNIT means any boiler, steam generator or process heater as 

defined in Sections C and K, above. 

A.3 
III. Standards 

(FOR RACT) 

A. For units with rated heat inputs of greater than or equal to 

5 million Btu per hour and annual heat inputs of greater thart or 

equal to 90,000 therms for any of the three previous calendar 

years, NOx emissions shall not exceed the following levels: 

1) 70 parts per million by volume, or 0.084 pound per million Btu 

of heat input, when operated on gas, or 

2) 115 parts per million by volume, or 0.150 pound per million 

Btu of heat input, when operated on nongaseous fuel, or 

3) the heat-input weighted average of the limits specified in 1) 

and 2), above, when operated on combinations of gas and 

nongaseous fuel. 

Emissions from units subject to this subsection shall not exceed a 

carbon monoxide concentration of 400 parts per million by volume. 

B. Units with rated heat inputs of greater than or equal to 5 million 

Btu per hour and annual heat inputs of less than 90,000 therms 

for each of the three previous calendar years shall: 

1) be operated in a manner that maintains stack-gas oxygen (0 ) 

concentrations at less than or equal to 3.00 percent by voiume 

on a dry basis; or 

2) be operated with a stack-gas oxygen trim system set at 

3.00 percent by volume oxygen (0 ). The tolerance of the 

setting shall be plus or minus five (± 5.0) percent; or 

3) be tuned at ieast once per year by a technician that is 

qualified, to the satisfaction of the Executive Officer/Air 

Poilution Control Officer, to perform a tune-up in accordance 

with the procedure described in Attachment 1; or 

4) be operated in compliance with the applicable emission levels 

specified in Subsection III A. 

(FOR BARCT) 

A. For units with rated heat inputs of greater than or equal to 5 

miilion Btu per hour and annual heat inputs of greater than or 

equal to 90,000 therms for any of the three previous calendar 

years, NOx emissions shall not exceed the following levels: 

1) 30 parts per million by volume, or 0.036 pound per million Btu 

of heat input, when operated on gas, or 

A.4 
2) 40 parts per million by volume, or 0.052 pound per million Btu 

of heat input, when operated on nongaseous fuel, or 

3) the heat-input weighted average of the limits specified in 1) 

and 2), above, when operated on combinations of gas and 

nongaseous fuel. 

Emissions from units subject to this subsection shall not exceed a 

carbon monoxide concentration of 400 parts per million by volume. 

B. Units with rated heat inputs of greater than or equal to 5 million 

Btu per hour and annual heat inputs of less than 90,000 therms for 

each of the three previous calendar years shall: 

1) be operated in a manner that maintains stack-gas oxygen 

concentrations at less than or equal to 3.00 percent by volurne 

on a dry basis; or 

2) be operated with a stack-gas oxygen trim system set at 

3.00 percent by volume oxygen. The tolerance of the setting 

shall be plus or minus five (± 5.0) percent; or 

3) be tuned at least once per year by a technician that is 

qualified, to the satisfaction of the Executive Officer/Air 

Poilution Control Officer, to perform a tune-up in accordance 

with the procedure described in Attachment i; or 

4) be operated in compiiance with the applicable emission ievels 

specified in Subsection III A. 

IY. Exemptions 

A. Units subject to the requirements of Subsection III A which 

normally burn only gas shall comply with a 150 ppmv, or 0.215 

pound per million Btu of heat input, NOx emission limit when 

burning nongaseous fuel, if gas is unavailable for purchase. This 

exemption is good for not more than 168 hours of operation per 

calendar year, excluding equipment and emission testing time not 

exceeding 48 hours per calendar year. 

Y. Compliance Requirements 

A. Comoliance Schedule 

The owner or operator of units subject to this determination shall 

fulfill the following increments of progress: 

1) Submit, within two years from the date of adoption of this 

determination, a plan containing the foliowing: 

A.5 
(a) A list of all units with their rated heat inputs and 

anticipated annual heat inputs. 

(b) For owners or operators of units subject to Subsection 

III A, for each unit listed, the selected method of 

achieving the applicable standard or standards of 

Subsection III A. 

(c) For owners or operators of units to Subsection III B, for 

each unit listed, a selection of one of the four options 

specified in Subsection III B to achieve compliance with 

this determination. 

2) 4lithin four years from the date of adoption of this 

determination, demonstrate final compliance with all 

applicable standards and requirements of the determination. 

.iIN I I- ii ~ • • ~ 

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

complying with either the pounds-per-million-Btu emission 

rates or parts-per-million-by-volume emission limits specified 

in Subsection III A. 

2) A11 emission determinations shall be made in the as-found 

operating condition, 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 sha11 be established within two hours after a 

continuous period in which fuel flow to the unit is zero, or 

shut off, for 30 minutes or longer. 

3) A11 ppmv emiss{on limits specified in Subsections III A and IV 

A are referenced at dry stack-gas conditions and 3.00 percent 

by volume stack-gas oxygen. Emission concentrations shall be 

corrected to 3.00 percent oxygen as follows: 

[ppm NOx] = 20.95% - 3.00% x(ppm NOx] corrected 20,95% - [% 0 ] measured 

2 measured 

= 20.95% - 3.00% ,~ 

[ppm CO]corrected 20.95% - [% 0 ] [ppm CO]measured 

2 measured 

4) A11 pounds-per-million-Btu emission rates shall be caiculated 

as pounds of nitrogen dioxide per million Btu of heat input. 

A.b 
5) Ali emission concentrations and emission rates shall be based 

on 15-consecutive-minute averages. The averages shall be 

calculated from no less than five data sets, recorded from 

samplings on intervals of no greater than three minutes. 

6) Compliance with the NOx emission requirements and the stackgas carbon monoxide and oxygen requirements of Section III 

shall be determined using the following test methods. 

(a) Oxides of Nitrogen - ARB Method 100 

(b) Carbon Monoxide - ARB Method 100 

(c) Stack Gas Oxygen - ARB Method 100 

(d) NOx Emission Rate (Heat Input Basis) - EPA Method 19 

(7) Integrated sampling methods for ozides of nitrogen, stack-gas 

oxygen, and stack-gas carbon dioxide, as approved by the 

Executive Officer/Air Pollution Control Officer, may be 

acceptable for determination of compliance with NOx emission 

concentration or rate limits. 

(8) Ail units covered under Subsections III A and III B shall be 

tested for compliance not less than once every 12 months, 

except that units complying with Subsection III B(3) shall 

be tuned not less than once every 12 months. 

(9) A violation of the plan required under Subsection V A(1) 

shall constitute a violation of this determination. 

(10) The cumulative annual usage of each fuel shall be monitored 

from utility service meters, purchase or tank fill records, 

or by any other acceptable methods, as approved by the 

Executive Officer/Air Pollution Control Officer. 

C. Administra ive Requirements 

1) The owners or operators of units subject to Section III of 

this determination shail monitor and record for each unit the 

NHU and cumulative annual usage of each fuel. The owners and 

operators of units exempt from Subsection III A in accordance 

with Subsection IV A shall monitor and record for each unit 

the cumulative annual hours of operation on each nongaseous 

fuel. This data shall be updated weekly and made available to 

district or state auditors upon their request. Nistorical 

annual data for the three previous calendar years shall be 

kept and made available by the owners and operators. 

2) The owners or operators of units subject to Section III of 

this determination shall submit compliance test reports on 

each unit for each fuel burned, including any fuels which may 

A.7 
be burned in accordance with Subsection IV A, not less than 

once every 12 months; except that tune-up verification reports 

shall be submitted not less than once every 12 months for each 

unit cornplying with Subsection III B(3) for each fuel burned. 

Test reports shall include the operational characteristics of 

all flue-gas NOx reduction equipment. The first test or tuneup report, for each unit subject to Section III of this 

determination, shall be submitted within four years from the 

date of adoption of this determination. 

D. F.quipment Req irements 

1) Owners or operators of units which simultaneously fire 

combinations of different fuels, and are subject to the 

requirements of Subsection III A, shall install mass flow rate 

meters in each fuel line. Alternatively, volumetric flow rate 

meters may be installed in conjunction with temperature and 

pressure probes in each fuel line. 

2) Owners or operators of units which employ flue-gas NOx 

reduction technology, and are subject to the requirements of 

Subsection III A, shall install meters as applicable to ailow 

instantaneous monitoring of the operational characteristics of 

the NOx reduction equipment. 

A.8 
Attachment 1 

Tuning Procedure IL 

Nothing in this Tuning Procedure shall be construed to require any act 

or omission that would result in unsafe conditions or would be in violation 

of any regulation or requirement established by Factory Mutual, Industrial 

Risk 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 reievant 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 con ~gntration, 

and CO concentration (for gaseous fuels) or smoke-spot number (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 values ~/ , 

and if CO ernissions 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 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 ftow, in srnall 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. 

1/ This tuning procedure is based on a tune-up procedure developed by KVS, 

Inc. for the EPA. This procedure is included as Attachment 2 to this 

determination. 

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 as 

Attachment 3 to this determination. The Bacharach method is included in 

a tune-up kit that can be purchased from the Bacharach Company. 

2/ Typical minimum oxygen levels for boilers at high firing rates are: 

1. For natural gas: 0.5 - 3% 

2. For liquid fuels: 2- 4% 

A.9 
5. Continue to reduce combustion air flow stepwise, until one of these 

limits is reached: 

a. Unacceptabie 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 0/CO curve (for gaseous fuels) or 0/smoke curve (for liquid 

fuels) similir to those shown in Figures 1 and i 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: 

Eut1 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 levels. 

Compare this minimum value of excess oxygen to the expected value 

provided by the combustion unit manufacturer. If the minimum level 

found is substantialiy 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. 

A.10 
! I 

'e 

a 

n a 

v 

c_ 

m 

~ 

o ~ 

0 

E 

~ 

Figure 1 

Ozygen/CO Characteristic Curve 

Sreso C0/07 

crraracrrnanc 

Graaual CO/Oz 

cnaratrerrsnc 

Approartate oaerarrng 

margrn trom mtnrmum Oz 

r Automabc ControlS 

CO limrr aoiustea ro rnia 

t400 aaml O? iever 

Mtnrmum OZ ~~ 

1 

O■ygen in hue gas. 

Figure 2 

Oxygen/Smoke Characteristic Curve 

Sreso smoas/OZ 

crtaracrerrsrrc 

l 

m d 

E 

c 

c 

~ 

Y 

E 

N 

Graeuar ~ 

Smoka/07 

OnaracrerlSllC 

\ Aoproanare oaeraung 

j margtn rrom mrnomum 01 

~ Automauc poder 

Smoxe rrmrt conrrors aausrea ~ to rrus O? rever 

Minrmum OZ ~I i 

Oxygen in nue gas, °o l—0— 

4/89 ATTACFMENT 1 Rule 74. 15 : 8 

APAEkDIX F 

Siqnificant Conments and Responses 

F.2 
Kern Oil b Refining Company (5/31/91) 

"The proposed BAR[CT] limits of 30 ppm NOx on gas fuel and 40 ppm NOx 

on liquid fuel are substantially lower than the limits contained in 

ARB's 1987 Suggested Control Measure ('SCM')..." 

Response: 

We agree with this statement. The SCM was approved by the California 

Air Pollution Control Officer's Association's (CAPCOA's) Technical 

Review Group (TRG) on April 20, 1987, and approved by the Air Resources 

Board (ARB) on September 10, 1987. The SCM was developed to guide the 

air pollution control and air quality management districts in their 

consideration and development of rules and regulations. The SCM is 

based on reducing oxides of nitrogen (NOx) emissions from industrial, 

institutional, and commercial boilers, steam generators, and process 

heaters by approximately 40 to 45 percent with an average costeffectiveness of about $1.00 to $3.00 per pound of NOx removed. Since 

the approval of the SCM, four district rules have been adopted or 

amended, which have more stringent standards than the SCM. These rules 

have taken advantage of improvements in NOx emission control technology 

in the last few years. The proposed RACT/BARCT determination also 

reflects these improvements. 

Furthermore, on September 30, 1988, the California Legislature enacted 

the California Clean Air Act (CCAA), which requires each district with 

serious or severe air pollution to include in its attainment plan a 

requirement for the application of best available retrofit control 

technology (BARCT) to existing stationary sources. "Best Available 

Retrofit Control Technology" means an emission limitation that is based 

on the maximum degree of reduction achievable, taking into account 

environmentai, energy, and economic impacts by each class or category 

of source. 

"The proposed BARCT limits go beyond the technology that is available 

for retrofitting existing equipment... We estimate that a 94 percent 

reduction would be required to meet the proposed 40 ppm limit... In any 

event, the cost of providing SCR on our existing heaters and boilers 

would probably exceed the cost of new heaters and boilers... We suggest 

that the BARCT for NOx emissions from boilers and process heaters 

either exempt devices that are permitted to burn residual fuel oil, or 

include a NOx limit for those devices that is achievable by combustion 

modifications such as low NOx burners and flue gas recirculation." 

Resp2nse• 

We know of no technological reason why selective catalytic reduction 

(SCR) cannot achieve 94 percent reduction to meet 40 ppm NOx; however, 

we believe that the commentor should also consider the cost of 

F.2 
retrofitting low-NOx ernitting burners plus a lesser degree of SCR. A 

NOx reduction of 0.78 pounds per million Btu is likely to be relatively 

cost-effective. The cost-effectiveness estimates contained in the 

technical support document (TSD) for the SCM are based on NOx 

reductions of 0.05 to 0.35 pounds per million Btu. The difference 

between the cost of retrofitting an existing unit to meet the BARCT 

standard and the cost of installing a new unit with best available 

control technology (BACT) is dependent on the size of the unit, the 

type of emission control equipment required to meet standards, and 

other site-specific factors. 

For a large unit burning residual fuel oil, retrofitting to meet BARCT 

is probably much less expensive than installing a new unit with BACT. 

This is due to the facts that the cost of a unit increases with its 

size, and that flue gas emission controls would be required in either 

case. On the other hand, if a small gas-fired unit requires flue gas 

emission controls to meet the BARCT standard, and a new unit without 

flue gas emission controls complies with BACT, then the cost difference 

between the two choices may be negligible, or the new unit may cost 

less than the retrofit. In deciding whether to retrofit or replace a 

unit, the age of the unit at the final compliance date should also be 

considered. An exemption for units burning residual fuel oil does not 

encompass the scope of the CCAA requirement of BARCT for existing 

stationary sources, nor does a standard based solely on combustion 

modifications. Flue gas recirculation is not effective at reducing NOx 

emissions originating from fuel-bound nitrogen. 

"South Coast Air Quality Management District ('SCAQMD') Rule 1109, 

Section (b)(1)(A)(ii) requires devices operated or liquid fuel to meet 

a NOx limit of 0.308 pounds per million [B]tu." 

Resoonse: 

SCAQMD Rule 1109 was amended on August 5, 1988. For 36 percent of the 

refinery-wide heat input to applicable units by December 31, 1992, and 

for 100 percent of the refinery-wide heat input to applicable units by 

December 31, 1995, the rule will require that NOx emissions from each 

applicable unit not exceed 0.03 pound per million Btu of heat input 

when firing at the maximum rated capacity. This limit is approximately 

equal to 21•parts per miliion by volume (ppmv), corrected to 3 percent 

oxygen (0 2 ), relative to dry stack gases, when firing residual fuel 

oil. 

F.3 
California Manufacturers Association (7/11/91) 

The proposed limits contained in the determination would make the use 

of residual fuel oil unaffordable and thus adversely impact the ability 

to obtain competitive natural gas rates, and operate during periods of 

natural gas curtailment. 

Res on nse: 

In our drafting of the proposed determination, we included a provision 

which allows the use of residual fuel oil for up to 168 hours during a 

calendar year in the event that natural gas is curtailed, subject to an 

oxides of nitrogen emission limit of 115 ppm. Based on this comment 

and our subsequent review of emission limits, we have increased the 

oxides of nitrogen emission limit to 150 ppm. We believe that the use 

of low-NOx burners designed to meet the emission limit for natural gas 

can readily achieve the 150 ppm limit when using residual oil. 

F.4 
Ventura County Air Pollution Control District (7110/91) 

"ARB states on Page 3[of the 7/5/91 revision] of the determination 

report (report) that 'most units can meet [the 30 ppm] limit by 

installing new burners with flue gas recirculation.' No evidence in 

support of this belief is presented in the report. The paragraph goes 

on to say that '30 ppm is the appropriate BARCT NOx emission limit due 

to the many units currently operating within this limit without the use 

of flue gas emission controls.' Again, not one case is sited to 

support this claim. If these units exist, we need to know the 

circumstances under which they operate. It is also unclear how any 

unit, new or retrofitted, can meet a 30 ppm NOx limit 'without the use 

of flue gas emission controls."' 

ges onse : 

We do not have a list of units which are meeting the 30 ppm limit. We 

believe the most convincing evidence for the appropriateness of a 30 

ppm BARCT limit is the SCAQMD's recent adoption of Rule 1146.1 for 

units 2 to 5 million BTU per hour in size. The 30 ppm standard for 

these small units is based solely on combustion modifications. The 

same or similar control technologies as which are the bases of the 

standard for the small units have been, and will be, applied to larger 

units. Burner manufacturers have not challenged the technical 

feasibility of the 30 ppm standard for larger units, though they have 

indicated to us that not a11 units can be economically retrofitted to 

meet the standard solely with combustion modifications. For some units 

selective noncatalytic reduction or selective catalytic reduction may 

be the preferred method of NOx emission control. Economic and other 

considerations have caused, and will cause, operators of units less 

than 50 million Btu per hour in size to favor combustion modifications 

over flue-gas emission controls in their selection of retrofit emission 

control equipment. 

"Even though the report states that 'consideration should be given to 

the incremental cost-effectiveness of achieving the lower 30 ppm,' both 

[the SCAQMD•and Ventura County] districts wi11 be forced to spend a 

substantial amount of time proving that the incremental costeffectiveness of achieving the lower 30 ppm limit is too high." 

F.5 
Bespon;g : 

The determination has been modified to state that districts which have 

adopted rules between July 18, 1988 and July 18, 1991, covering the 

applicability of this determination, are considered to be in compliance 

with this determination. 

"This lack of factual support [for the 30 ppm limit] is made worse by 

ARB's position that BARCT should be 'technology forcing' when Health 

and Safety Code Section 40406 states that BARCT means `the maximum 

degree of reduction achievable.' This means that any technology that 

cannot yet be achieved goes beyond the definition of BARCT. Any 

technology that has not been proven successful is inappropriate." 

Resp9.a 5e : 

This RACT/BARCT determination is not "technology forcing." All of the 

technologies described in the report, and which may be necessary for 

cornpliance with the BARCT determination, are proven, available, and inuse in California. 

"Selective Non-catalytic Reduction (SNCR) is discussed on Page 7. 

Table 2 implies that the applicable range for this technology is 50 

MMBTU/hr or more. It is not clear if units in this size range have 

flue gas temperatures in the 1600 to 2200 degree F range. Stack gas 

temperatures for the two large units in our report are 591 degrees F 

(Arcturus) and 760 degree[s] F(Rocketdyne). SNCR is offered as a 

viable possibility on Page 3, but, in fact, it may work on only a small 

percentage of units. On what units will SNCR work? 

RespQJIsg = 

SNCR injection is not normally retrofitted to the stack or flue gas 

ducting. A flue gas temperature of 1600 to 2200 degrees F indicates an 

extremely low combustion efficiency. Normally an SNCR injection grid 

is retrofitted within a unit at the downstream end of the furnace. 

SNCR will work on all units which wili allow adequate residence time 

within the reaction temperature window. 

"There is no basis for the 40 ppm lirnit for units burning non-gaseous 

fuel (Page 3). No information is provided on the source of this limit 

or how it wi11 be met. Under what circumstances is this limit 

applicable?" 

ResoonseInformation has been added to the report regarding the use of inethanol 

and specially blended oil to meet a 40 ppm limit for units burning nongaseous fuel. 

F.fi 
"Limiting total use of non-gaseous back-up fuel to 168 hours per year 

is unreasonable. Back-up fuel is typically used during natural gas 

curtailments; we cannot assume (without vast statistical support) that 

... curtailments will always last less than 168 hours (seven days) per 

year. Back-up fuel equipment must be tested periodically; a 168 to 200 

hour per year limit on testing would be reasonable." 

ResQonse• 

A 168-hour allowance for burning back-up fuel will enable unit 

operators to qualify for a noncore (lower) rate for purchasing gas. If 

the higher NOx emission concentration of 150 ppm were not subject to a 

time limitation, it could not be allowed under the RACT/BARCT 

determination. Operators must be prepared to either (1) pay a higher 

rate for gas, (2) have a back-up gas supply, (3) meet RACT/BARCT 

standards for nongaseous fuel firing, or (4) shut down, when gas is 

unavailable for purchase for more than 168 hours per year. We have 

added an allowance of 48 hours per year for equipment and emission 

testing with back-up fuel burning. 

"Selective Catalytic Reduction (SCR) needs additional discussion (Page 

8). As noted above for SNCR, stack gas temperatures in the 570 to 845 

degree F range occur only in very large units (over 100 MMBTU/hr). 

Does this mean that flue gas preheaters will be required? On.Page 9, 

the cost effectiveness of SCR is all but ignored. This technology is 

extremely expensive, which is exactly why it was not considered to be a 

reasonable emission control technology for industrial boilers in 

Ventura." 

ReiponseLow-pressure heating boilers operate at saturated steam temperatures 

not exceeding 250 degrees F. They may have flue gas temperatures as 

low as 400 degrees F. For most units, a flue-gas temperature below 

570 degrees F is difficult to achieve without an economizer and an air 

preheater. An SCR reactor should be appropriately located in the flue 

gas ducting to optimize the catalytic reaction. It is unlikely that 

SCR technology will be necessary to control NOx emissions from lowpressure heating boilers. However, if it is necessary, a boiler may 

have to be modified to operate at a higher flue gas temperature and 

lower combustion efficiency. The cost-effectiveness of SCR technology 

will be high for small boilers firing gas. However, there are other 

technologies available for use in complying with the BARCT standard. 

'On Page 11 [of the 7/15/91 version], under Hazards, it is misleading 

to say that 'a majority of catalysts used in California are now 

reclaimed and recycled by the manufacturer.' We believe that most of 

the catalyst material in the state is in Ventura County (by virtue of 

F.7 
the IC engine rule) and, while some manufacturers may provide this 

service, we know of no organized recycling system. We are optimistic 

that increased use of catalyst material will lead to such a system." 

Res op nse: 

We do not believe that the report is misleading. 

"The RACT limit for 'other' fuels (III.A.2) should be increased to 150 

ppm, similar to the 'exemption' limit in the BARCT section (IY.A). For 

RACT, 'other' fuels means fuel oil, and fuel oil is what the 150 ppm 

limit in the BARCT section is intended to regulate." 

Response• 

We disagree; the "exemption" limit is for units which normally burn 

only gas and applies only when gas is unavailable for purchase. Units 

with emission control equipment designed for gas-firing are allowed a 

150 ppm limit for burning "back-up" fuel. We have extended the 

applicability of this exernption to the RACT standard, also. 

F.8 
Kings County Air Pollution Control District (7/30/91) 

"Section IV. of the draft determination BARCT rule (Appendix A) 

provides that boilers shall meet 150 ppmv or 0.215 lb NOx/MMBtu for no 

more than a total of 216 hours per year, including testing time, when 

natural gas is unavailable for purchase. Our experience with dual 

fired boilers indicates, that for at least boilers operating 24 hours 

per day, such a limited firing period is highly unrealistic. Pursuant 

to the above requirement, will the District require the temporary 

shutdown of a boiler if beyond the control of the owner operator 

gaseous fuel cannot be burned?" 

Res,Ronse: 

The boiler operator may either (1) comply with the BARCT standard for 

nongaseous fuel firing, (2) obtain a back-up gas supply, (3) pay a 

higher (core-customer) rate for natural gas, or (4) shutdown the 

boiler. 

"Gas supply curtailments are more likely to occur during the winter 

months due to increased public demand. In areas that are not likely to 

exceed ozone standards during the winter, restrictions on the use of 

fuel oil during these months may have little effect on ozone levels, 

yet may be difficult to comply with because of the increased likelihood 

of curtaiiment." 

Res op nse_ 

A precedent has been set by Ventura County APCD's Rule 59, "Electrical 

Power Generating Equipment - Oxides of Nitrogen Emissions," to allow 

winter-month flexibility for fuel oil burning on days for which ambient 

ozone is predicted to not exceed 0.07 ppm. Districts should be careful 

in considering this approach. Emissions from fuel oil burning 

contribute directly and indirectly to ambient PM10. In Ventura County 

there is a strong daily correlation between no~ exceeding the 0.07 ppm 

1-hour ambient ozone and not exceeding 50 μg/m 24-hour PM10. 

"Is the intent of 150 ppmv for firing on nongaseous fuel not to allow 

the burning of No. 6 oil with standard nitrogen content? For No. 6 

fuel, compliance with this limit would require controls beyond flue gas 

recirculation and burner replacement." 

Res o~nse: 

The intent of the exemption of 150 ppmv NOx for firing a nongaseous 

back-up fuel is to aliow the use of residual fuel oil for back-up 

situations without necessitating additional emission control equipment 

beyond that required for gas firing. There is no standard for nitrogen 

F.9 
content of residual fuel oiT; however, the range is 1000 to 8000 pprn by 

weight. 0.150 1bs/MMBtu (104 ppmv) NOx with Kern County residual fuel 

firing has been met with staged combustion without flue gas 

recirculation. 

"If a significant amount of boilers in California are fired primarily 

on fuel oil, is the present supply of "specially blended" low nitrogen 

fuel oil sufficient to meet state wide needs? If not, than do the 

retrofit cost figures include installation of natural gas supply 

equipment?" 

Res o~nse_ 

The BARCT standard for oil firing is cost-effective with fiue gas 

emission controls. Some boiler operators may determine that switching 

to gas firing with combustion modifications to meet a lower limit is 

less costly and therefore more cost-effective. The cost-effectiveness 

of using methanol or "specially blended" oil with combustion 

modifications to meet the BARCT standard will depend on the future 

demands and prices of inethanol or "specially blended" oil. 

"Buyers have the option of lower gas costs if the supplier does not 

guarantee supply at all or most times. Do these cost figures include 

natural gas cost increases from the supplier which would result because 

the buyer (source) would not have the option of random curtailments." 

Reaponse: 

The exemption for back-up fuel burning when gas is unavailable for 

purchase wiil enable the buyer to qualify for a noncore gas rate. 

"The use of natural gas will increase with the various clean fuels 

programs for both stationary and mobile sources. Has the availability 

of future natural gas supplies been studied adequately to warrant the 

virtual elimination of fuel oil?" 

Response• 

The economical choice of fuel and emission control equipment is left to 

the market interaction between the fuel suppliers, the control 

equipment suppliers, and the unit operators. Oil firing with flue-gas 

emission controls is considered to be available and cost-effective. 

The fuel supply and cost-effectiveness resulting from market 

interaction can only be better. 

F.10 
"The NOx retrofit of a boiler may cause an increase in CO emissions. 

In some circumstances an increase to 400 ppm could cause an emissions 

change greater than 550 lbs/day. Although many low NOx burner 

manufacturers are reluctant to guarantee less than 400 ppm CO 3 in 

fresno County 100 ppm has been both required and achieved after FGR and 

burner replacement (135 MMBtu/hr boiler)." 

Res op ~se_ 

In most districts, any CO increase from permitted levels will activate 

the new source review process. By necessity, operators will have to 

maintain CO emissions at levels which will not activate the new source 

review process. Therefore, operators should consider CO emissions as a 

factor in their selection of NOx emission control equipment. 

F.il 
m O 

O 7 

C 

0 

~ ~ 

oc 0 

E 

0 

n m U 

~ 

0 

a 

E ~ 

c 

~ 

~ 

: 

Y 

s: 

u7 

Figure 1 

Oxygen/CO Characteristic Curve 

~ 

E 

a 

Graduar COr 02 

Ularactensrrc 

$tNp Co/o? 

cnaractoretrc 

Appropnate o0eratrng 

margrn from mrnrmum O? 

AulomalrC Controfs 

CO ~imrt adlUSred to tnls 

N00 a1pml Op ferel 

\ 

M+nrmum O? 

O■ ygen in flue gas. % --r 

Figure 2 

Oxygen/Smoke Characteristic Curve 

St••p amok.102 

characterearlc 

Graduar 

smokeiO~ 

~haratlsrrshc 

Approprrafs opsfafrrtg 

~ margrn trom m+nrmum OZ 

Automatrc Doder 

smoke trmrt controts adfusted 

` to rArs O? rerel 

Mrnrmum 02 

Oxygan rn flua pas. X --r— 

Source: KVB Inc, 

A.lz 
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 ozygen 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, setting should optimize conditions at the 

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. 

A.12 
~'UNING iN©US i RIAL 3C1LER~-- ~ 1 

Attachment 2 

Establish excess-air levels 

Use the test program outiined befow to tdentify the minimum amount of excess oxygen 

reauireo for combustion of gaseous. liquid, and sotid fuels in industrial boilers 

8y D E Sitore and M W McElroy, KV6 Inc 

Once ~ our boiler Is in good workine 

r,rder I<ce Fart I oi this series. Aprii 

1977l. the next ma;or step in tmprovtng 

.:fticienct. ind tn reductnc emtssions, ts 

:.o cstaoitsh the iuwest level oi excess 

iwgen at which thc untt can operate 

::aiclv 3na still mett the clean-air laws. 

aincc :^ost industrtal boiicrs operatc 

over a reasonabiv broad load range. tests 

rnust be run at several firina rates to 

ietermine the mtnlmum excess-otivgen 

cvei ior each. Univ then can the 

combustion-control svstem bc tuned for 

obtimum fuel economv. 

At each tirin¢ rate investi2ated, excess 

oxygen In thc ftue gas shouid be varted 

from 1-Y:7c above the normal operating 

point. down to where the boiler just 

starts to smoke (Fig 4), or to where CO 

cmissions cxceed 400 ppm. This lattcr 

condition is referred to as the smoke or 

CO thresnoid. or slmpiy as the nnrtrrrtunt- 

,j.rt•Qen pornt. The smoke threshoid generk apnnes to coak and oil tiring. because 

.moktne usuaih occurs bcturc CO emisstons reach sleniticant lcvels. The CO 

threshold pertalns to easeous fuels. 

The smoke threshoid for solld and 

liquid fuels recresrnts the iowest posstble 

excess-oxygen ;ecei at Ahtch acceptabie 

stack conaittons snll can be maintained. 

In terms of the 8acharactt smoke-spot 

number ISSNl scale, the maxtmum 

desirable smokc number for coai is 4 

imeasured doμnstream or' the dust 

coliectort. For ~ o o irestduall oii. it 

aiso is 4: No. ? and low-suifur resl(i. a 

SSN of 3: tio. 4. a SSN of 2: and No. 2. 

a SSN of less than I. 

A proven mcthod for determining the 

minimum amount of excess oxygen 

requircd for combustion invoives developing so-called oxygeniCO and oxygen/smoke characteristic curves, like 

those shown in Figs i and 6. Based on 

test measurements. thesc curves show 

how boiler sm:)ke and CO ievels change 

as cxeess oxN ecn is varied. 

Each of the fieures depicts two 

distinct cunts. rllustratlne the extrcmes 

in smoke and CO behavior that mav be 

encountered. One curve exhibits a verv 

eradual increasc in CO or smoke as thc 

minimum excess-osv¢en conditton rs 

rcached. The other has a gradual slope at 

reiatively high oxvecn icvcis. and a steep 

slope near the minimum-oxygen potnt. 

For cases rcprescntcd by this second 

curve, unpredictably high leveis of smoke 

or CO, or potenttall} unstable conditions, can occur wtth small chan2es tn atr 

flow. 

Thus, caution is required on your part 

when reducing atr dow near the smoke 

or CO threshold—that is, carcPullv 

monitor instrumenu and controls, flame 

appt:arance. and stack conditions simultaneousty. Decrease the level of excess 

oxygen in very small increments until 

there are enough data to show whether 

the boiler exhibits a gradual or stceo 

characteristic curtie. \ote. too, that trur 

boiier may exhibit a¢raduai charactcristic at one firing rate and a steep onc at 

another. 

:adjusting boiler controls for tow-excess oxygen—a step-bystep procedure 

:. Establieh the desired firing rate and switch comiwstton 

controfs h'om automatiC to menual operatton. Make sure ali salety 

;nrarrocxs are stifl luncrroning. 

Z. Recora boiler and stack data tpressures, temoeretures. etcl. 

ana ooserve flame conbitiorrs after boder operatton stabil¢es at 

'.^.e Rarticu;ar f:rina rate selecteo. If you tind that the amount ot 

cxcess oxygen in the flue gas ts at the lower ena of the range of 

'

.

.olcal m,nrmum vatves tsee textf, and it CO arta smoke are at 

.ccec[acle revels. the boder orooably rs already operattng at near 

=D1rmuT 9rticlencv—ar r/1ts particLlar Jiring rate. It may stlll be 

-estracie. now3ver, t; comDlete the rematning portton :t tMs 

=roceQure, to aetermrne whether slill lower levets are practic8t. A 

.vora o' zautlon: rJo not assume tnat excess-oxvgen sett,ngs at 

- ;ner rr-, nc rates also are close to the optinturrt. 

_. tncrsase atr flow to the turnace untll reaorngs ot e ~ cess 

wrterr, at tne stacK rrcrease ov 1-2%a. Agatn. oe sure tc taKe 

:aorrlas arter boller operauon staollizes. ano note any cr,ances rn 

 3me conaltlons. 

=. Return air ftow to the normal leval ano begln srow!v to 

- 'ouce t1 further. In srllat! increments. Watcn the stacK for anv 

.-ar+s c • SmoKe. ano constantiv observe trle flame. Recora stacK 

~ ce5s-oYvoen reatllno, ZmoKe-soot nt}mber, lne eoncentratr7n Of 

'. :r n;;e oas. ane stacK temoerature tollowtng eacn chanoe. 

7

._r^Qmper not tC reaUce arT t:ow oy tnrottllno the curner atr 

reglstera# because this altera the tuel and air mvring charactenstics and compllcates the testa. Itlso. It you nm teate at low firing 

rates. which is not generally recotnmended (see step 9), keeo a 

uose walctl on the wrndboxifurnaee preswre difterentiet. II it 

crops too low, a fuel trip wdl be initiated by tne ourner sateguaras 

system. 

S. t:ontinue to reduee atr flow stepwne untll you reach one of 

hese hmits: 

e Unacceotable flame contlitions—sucrt as riame Imptngement 

on turnace waI1S or ourner p3rts, excesstve ttame carryover, or 

S.ame rnstaDNlty. 

• Hrgh level of CO irl the flue gas. 

* SmoKlna at tne staek. ao not c9ntUse smoKe wrth waler 

.aoor. suifur. or dust plume3, whch usuanv are wfvte or oray rn 

,scoearance. ano remember to obsarve ucar arr-ooiuunon crarcances. 

0 IncomDlete burntng ot solid fuets. n-:coenrze tnts bv nrgn 

caroon carrvover t7 aust collectors or rncreasea 0uantltles 0t 

Comoust,btes In tne asn. 

a Equtpment-related limitations—sucn as iow wtnaboxiturnace 

~ res5ure dttterentlal. Duitt-in asr-ffow Itmlts. etc. 

s. Develop O,/ srnoke or O,/CO charaetertslic curves, s mrtar 

, o tr,ose snown tn Figs 4 and S. using tne excess oxygen ana CO 

:r smoKe-soot number aata obtained at eacn alr-flow setting. 

=••wa.r.~ av ratc 

A.13 
A irgb oiaistNw-ezygra reatiatg may 

indicate a burner malfunction or other 

fuel- or eq ui pment- related probiems. But 

realize that difTerent burner designs and 

fuels gtncrally have difrerent minimumoxygen requirements. ln addition, many 

burners exhibit a higher minimumoxygcn level at low firing rates than they 

do at high firing rates. For these reasons. 

it is difficult to spccify a range of 

minimum levels that would be considcrcd normal for all boilcrs. 

Rcsults of tests at many industrial 

power plant.s arc provided, howevcr, to 

help you judge whether the minimumoxygen levels you mtasure are typical 

values. The data: For natural gas, the 

typical range of minimum excess oxygen 

at high firing rates is 0.5-3 °.b; for liquid 

fuels, 2-4%: for pulverized coal, 3-690; 

and for stokcr-fircd coal, 4-8%. 

Boilcr startup records showing initial 

cxcess-oxygcn conditions provide a valuabic refcrence point for your tuneup 

program. If current minimum-oxygen 

levels arc higher than expected, any 

necessary maintenance or repairs should 

be completed beforc making final adjustments to the combustion-control system. 

Once the minimum-oxygen setting is 

established, the next stcp is to determine 

the appropriate operating margin above 

minimum oxygen where the boiler can be 

operated routinely. This lowest practical 

oxygen level for the boiler ofTers the 

optimum setting for high ef&ciency and, 

in most cascs. the lowest NO, emissions. 

The exccss-oxygen margin above the 

minimum-oxygen point accommodates: 

■ Rapid boiler modulation, which 

could cause smoking or a high concentration of eombustibkes in the flue gas. 

• Nonrepeatability or play in automatie controls I Ecccssive piay should be 

eorrectcd.) 

■ Normal vanations in atmospheric 

conditions, which also can change the 

level of exccss ocygen on units not 

equipped with temperaturc- and pressure-compensated combustion-air 

systcros. This ts an important factor, 

which often is nealected. Extreme variations in ambicni conditions can easily 

produce changes in excess oxygen of 1% 

or more. 

■ Changes in fuel properties, which 

may require varving amounts of excess 

air at the burner. 

Typical margins above minimum oxygen may range from 0.5% to 2`9c, 

depending on the characteristics of thc 

partieular boiler-control system and the 

fuel being burned. if you think it necessary, the boiler manufacturer or a 

combustion consultant probably can 

establish a narrower range for your unit. 

Another point: (f the boiler is to be 

operated at a oortstant firing rate for 

extended periods, the smallcat possible 

margin should be sefected. 

Recognizing excessive play. A simple 

test can help you determine if there is 

cxcessive play (poor repeatability) in 

your combustion-control system. All you 

havc to do is to repeat a firing-rate 

eondition, allowing fuel and air oontrols 

to function in a normal manner. 

Approach thc selected firing rate from 

both higher and lower firing rates, and 

eompare stack excess-oxygen Ievels rccorded after each run. Make - sure boiler 

operation stabilizes before taking reada. lfMqefntmn Ntart oMen a quldc way 

to determtne If boller anissiorts mest 

codes. Badtarach ecaie, moro aCCUrate, is 

better tor burrter adlustments 

ings. Excess-oxygen data shoaid repeat 

to within a few tenths of a percent; a 

greater difference indicates excessive 

wear or toicrance problems in air dampcrs, controi shafts, valve cams, eontrollers, etc (Fig 7). 

Atmospheric rariatiom. Changes in air 

density at the forced-draft-fan inlet 

cannot be corrected like control-system 

play. Rtcognize that. while the f-d fan 

deiivers a certain volume of air to the 

burncr, as the air density ehanges. the 

numbcr of pounds of air supplied to thc 

7. FMd tlw rnktYaultt axoaes-oxypat fwM for your boiler from 

the asras praparod Irt step 6, but do not ad)ust ttro burner 

controls to this value. Thougtt this may be trie point of maxinwm 

efflclertcy, as weN as minlmal NO, embaions, it uaually is Impraatical to operate the bofler at this setting, beeauae of the tendency 

to smoke, or to increase CO to dangerousty high levels. as load 

changes. 

Compare this minimum value of exeess oxygen to the expected 

value provfded by the boMer manufacturer. It the r.tlnimum IevN 

you found Is substanthdly higher than the vendor's, bumer adiustments probably can Improve fuel and air mixing, thereby allowing 

operatEon with iess alr. 

S. Establish tMa margin. In excess oxygen above ihe minimum 

value, required for tuel variations, load changes, and atmospheric 

conditions. Add thls to the rninimum value and reset burner 

controls to operate automatically at the higher levei—the lowest 

practical setting at the particular firing rate. For most boilers. NO, 

emissions typica7ry wul be lower at the new setting than they were 

originalty, tt they are higher, hovrever, try to reduce them by 

adjusting tne burner. 

9. Rapat stapa ta for each fkring rate to be t>•sted. Bear in 

mind that. for some control systema. It Is not posslble to establish 

the optimum exoass-0xygen level at each firing rate. Reason: 

Control adjustments at one firing rate also may affect conditions 

at other firing rates. In such cases, choose the Settings that give 

best performance over a range of firing rates. A triat-and-error 

approach, one InvoMrq rpeated tests, rrtay be rteoawary. 9ut tf 

one flring ra3e predominatee, settlnga aftotaid opUrt oortdltlons 

at that t•ate. 

Many experts agree that 1t ger arally ts beat not to make any 

ad)ustments to your control system whNe the boiier Is operating at 

low loads. Air-flow requirements at low-Ilre conditlons usuatty are 

dictated by flame Ignition characterlstics and stability (and they 

can be critical and dMflcult to evaluate) rattter than by eRidency. lf 

p ocees requiremsnts foreae your boiler to operate at low loads 

much of the tlme, check wltb tfte boiler manufacttxse's servke 

group or a qualified combuetion consultanl before estabgshing 

excess-oxygen levels. 

10. Yertfy tftat your nevm aettings can aeeommodata the 

sudden load changes that may occur in deily operation without 

adverse affects. Oo this by Incressing and decreasing load rapidly 

while observing the flame and stack. If you deteet undesirable 

conditlons, reset the combustion controls to provide a slightly 

higher level of exeess oxygen at the affeeted flring rates. Next, 

vetify these new saftings In a slmilar fashion. Then make sure that 

the finat control settings are recorded at steady-state operating 

conditions for tuture reference. 

One flnal note: When an aitemative hiel is burnatl, perform 

these same tests and adjustments for the second fuel. Sinee it is 

not ahvays possibie to achleve optimum excess-oxygen levels tor 

both fuels at all firing rates, you must establish fhe besl eonditions 

at normel firing rates. 

Powar.uaY •.-- S7EAMGENERA710tt 77 

A.14 
.~ prr!c".+rE 7CC•, ~ ..^" 

-:r ~ Cr^ rrnT m,n,•nr ~.~n , . 

- i 

~ iJUr1: 

 —,J•Orn frp..t mn „n~~ m C.' ~ 

~I 

f ~ tM 4 ,rorriar,c !er 

_ '^pNPlrmi• 

~ 

Vrnrmum G- _01 

I 

Oxt-e^ , + , ueaas.'' —~— 

. '•^+umG? --*I 

Oxvaen in +rue oas '- —11 - 

5,6. Oxygsn/CO and otrygen/smoke characteristie ourves identity the mrnrmum amount of excess oxygen required for combustton 

burner varies. influencing the amount of 

excess oxvgen. When combustion air is 

supplied from thc boiier room. maintaining a constant boiler-room temperature mtnimizes the oroblem. but atmospheric-pressure etTccts are unavoidable. 

Evsluati!ng new settings 

After the boiler has been tuncd and 

returned to normal automatic firing, pay 

close attention to the unit for a few 

weeks, until conhdence is gained in the 

new operating mode. Watch for any 

signs of unusual tube fouling or flame 

patterns, which might be corrccted by 

further burner adjustmcnts. Also, look 

for any cquipment or operating changes 

that may aIter the minimum-oxygen 

levei—such as variations in fuel properties. inadvertent chan¢es in burner 

~ettings, new boiler•controi sctpoints. 

air-control-damper dcterioratton, and 

air-preheater piuggage. Assure continuous high efficiency and low NO, emissions on a continuous basis by plottinK 

periodic stack measurements (cxcess 

oxygen, CO, smokc. temperature) on 

¢raph paper, and comparing thesc trends 

to the baseiine data obtainea durintt the 

boiler-test program. 

Burner adjustments 

~\s noted earlier. adiustments to the 

,:ontrol svstem alone sometimes cannot 

improve cf6ciency andior reduce pollutant emissions to desirable levels. In such 

cases. you should carcfully inspect combustion equipment for proper operation. 

Often, you can achieve your operating 

goals by making changcs in: 

■ Burner air-register settings (on 

swirl- or circular-type burners). 

• Oil-burner tip position with respect 

to the burner throat. 

+ Oil-gun difTuser position with respect to the burner tip snd• burner 

throat. 

• Fuel-oil temperature 

• Fuel-oil atomizing pressure. 

• Coal-spreader position. 

• Cual size. 

The effccu of such adiustmertts on 

NIO, formation and on mtnrmum excessoxygen Ievels vary from unit to unit. and 

are difficult to preoict. Therefore, you 

should use a trial-and-error procedure 

when making ehanges. But be sure vour 

program is sufficientiv organized to 

assure adeauate stack and flame monitoring. Observe thc gcneral precauttons 

gtven for the excess-oxygen adiustments 

(see boxl. Sueh modiPtcattons to the 

firin¢ svstem are best factoreo tnto the 

excess-oxvgen adjustment tests (step 7 in 

box). This insures that changes arc 

completed before the final controlsystcm adjustments are made. 

Aiso. after adjusting the burner, make 

a complete set of stack measurements to 

determine whether the change is producing the desired effects. F'inally. makc all 

burner adjustments slowiy, to allow 

adeauate time to evaluate esch move. 

Look for any other changes rn burner 

settings or fuel properties that mtght also 

atTect the flow of air or fuel to the boiler 

and produce uncontrolled shifts in the 

cxccss-oxvgen level. 

The range of adjustment possible for 

the parameters listed above depends on 

the design of the burner or stoi:er and its 

particular operating charactertstres. Example: It may be possible to van the airregister settings on one boiler from :Or'e 

to 80% of full open. while or enother 

unit fittle or no adjustment i ~ c-lcttcal. 

For the fatter. further openrnp Dr !he atr 

register Ireducing air swirll -:a} cause 

flame tnstabilitv. while bv ciosrns ofi the 

atr rcgtsier tmore swtrit vou rr_ ~ wrdert 

the tlame. causing flame imc:necment 

on the burner throat or furn_,e sidewalls. Rcad thc boiler operat:ng manuai 

for informatton on %our hr:r.g tquipment. 

1n important ilctor in o_tarnrng 

complete combustion ol fuel e:; at low 

cxcess-oxvgen Icveis is ,o mairtarn thc 

proper atomizing temperature. This is 

dictated b ~ the fucE ~ tscostt ~ recommended bv the burner manutacturer. 

Typical viscostty ranges for various 

liquid fuels and burner types arc gtven in 

Fig ts. For stoker firing, coal sizc I Fig 9) 

is imnortant. i4G8 

°c •e• Msy 19•' 

T. E:usttire play 

,n posrtronrng 

combustion 

controts can be 

rclentrfted by 

marKrng lrnkage 

posrtion for a 

panrcular firing 

rate and then 

aDproacnrn(j that 

rate from Doth 

hrgher ano lower 

firing rates. 

Linkage posnion 

tor tne two test 

runs snoutd match 

the origrnai setting 

A.15 
Attachment 3 

I~ DesFpnatlon: D 2736 — 80 

Standard Test Method for 

SMOKE DENSITY IN FLUE GASES FROM BURNING 

DESTILLATE FUELS' 

Thts sun.Urd ts tuued under the I11ed devgnaluon 021'0. the numher immedulcl% lollow•tnp Ihe ucsRnanon ,ndtcotes the ytu, 

unpnal a000uon or. In lhe case ul revsldn. the vur of last nR•rsuon \ numhet rn parcntheses indicates tht rpr PI ISI ropprpp ` 

A sunrrrnoa e)'}{tlon tr 1 indtcatcs dn cditunal chanEe stnce UNC iut re%ts+nn nr reappro%Ji. 

1. Scope 

1,1 This method Co.crS the evaluatton of 

smoke densnv tn the Ilue eases from burntne 

dtstillate fuels. It is intended primarilv for use 

wtth home heating equtpment burntnc kerosino 

or heattne otls. It mav be used in the laboratorv 

or tn the tield to compare fuels 1•or clean burnlne ur t. :ampare heattn_ eyutpment 

Z- Applicable Document 

2.1 .4ST.if Standard: 

E 97Test Method for 45-'. 0-' Directtonal 

Retltctancc Factor of Opaquc Spcctmcns h} 

Broad Band Filtcr RefJcctumctrv= 

3. Summtrv of vlethod 

3.1 A test smoke spot is obtained by pulline 

a futed volume of flue gas through a ftxed area 

of standard filter paper. The coior (or shade) 

of the spot thus produced ts vuually matched 

with a standard scale, and the smoke denstty ts 

expressed as a"Smoke Spot Number." 

A. Significance 

J I This method provtdes a means of controlJtne smoke productton tn home heatine 

equtpment to an acccptable level. EzcesstNe 

smoke densitv adverselv affects effictencv b% 

heat-e><chaneer foultne4.2 The range ofsmoke densines covered by 

thts method ts that whtch has been found particularh perttnent to hnme-heattng applicatton. 

)t ta more sensittve tn .mall amtronts of smoke 

tfian aeteral othcr ,moke test, ,t, ln.11c•at:d tn 

the folluwlne compartson: 

Smake spot Icham. percent Rtngetman 

`umber Transmtulon Smnke Numbet 

F IB J 

lo c 

t. Description of Termti 

5.1 The test result is reporrted as the "Smoire 

Spot Number." which is the number of the spot 

on the standard scale most closety matchin6 tbe 

color (or shade) of the test spot. 

6. Apparatus 

b.l SamphnR De+-ue—A wttable devtce provldtng a totai flue eati samplc volume of 36 900 

~ 1650 cm` at Ih °C. I atm (2250 = 100 in.' at 

600 F. I atm) for each b.45 cm` ( I in.') efiective 

surface area of filter paper shall be employed 

The sampling devtce and connecttons shall be 

of such constructton that the total travel of ttue 

gas sampie from flue to ftlter paper shall not 

exceed 410 mm 116 tn.). The devtce shall proa 

vtde for cooltng the sample below the charrinE 

temperature for the filter paper but not belor' 

the deA point of the sample. Suitable labaratory and ponable field servtce equipment ts 

tllustrated tn Fie>. I and 2. 

t+ - Smr!!<e S<u!r—The smoke.cale requtred 

r hn mr!hud n undcr ihclunaltctuun M>ti I\1 C,rmmttiR 

IY: on Prtrokum Pr'tlurt4 und t.uhncam. 

t urtont cdltuon u{+pr—td \ur _ 4 IVkfr PuMmnrd OC10e' 

,•~ ~ tnrr,Jn ~ punh.hru ~ . n t I 1 

tn ~ a,., b••. . i ~ I t! u ~nu~•~. t.t ta u:. 

A.16 
Ch o 2156 

conststs of ten spots numbered consecuttvelv 

from t) to 9. ranetne m eyual photometnc steps 

from white throueh neutral shades uf gray to 

black. tmpnnted or otherktse processed on 

whtte paper or plasttc itock ha , tng a surface 

retlectance of betNeen S_ ` snd •4' S%45`. 0° 

davlteht lumtnous dtrecaonai rcilectance m accordance with Method E 9' The smoke scale 

spot number is defined a> the reductton (due to 

smoke) tn reflected tnctdent li¢_ht divided bv 

10. Thus. the first :pot. wht.h ts the color of 

the untmprinted scale. will he No. ll. stnce in 

the case of this spot there util be no reductton 

tn reflected incident hght dtrected thereon. The 

last spot. however. ts tierc dark. reflecnne onlv 

IU `', of the inctdent lisht dtrected therenn: thus 

tn this case the reduction tn rttlected trtctdent 

litht is 90 1-,, ahich eues w this darkest ,pot 

thc'`10 v lnterrnedt,tte ^imher.. arc +tmtlarly establishcd. Limn> of permtsstble retlectance vanatton of anv smoke scale spot shall 

not exceed t3 r rclatnc retlectance (Notes I 

and 2). 

Nuir I- Such .mnt,e scalc, are suffictenth accurate for field use and fur manv laburatorv smoke 

testm6 applicattons. However, specsallv cittbrated 

snles {known as certrfied smoke scates) wdl someumea be required. A certtfied smoke scate is obuined 

bv tndividuallv calibtattnE each smoke spot of a 

narmal ,moke ceale 

Nort :- Wherc thc mnke .4 1e n protected w'ith 

a plaauc nr transparem cr.erthc ronxtrucuon empic+ved sh,iVl bc .aucn thji w her. the ,,moke ,pa+t +n the 

filter paper Iti vlQwed fur mat.htnz with the numher 

spots on the smnke scatc. tx+th shall be vtstble through 

the same thtcknesc and number of sheets oi transparent protecuve cover 

7. Haterrals 

7.1 Tesr fiher Paper, made from white filter 

paper stsxk having a.urface rellectance of R2.5 

to N7.5'45°. 0' davlteht lumtnous dtrecttonal 

re(lectance, in accordance wtth the Method 

E 97. When cJcan atr aI standard cnndittons ts 

drawn throueh clean lilter paper at a rate ol 

47.6 cm'/s-cm' I 11_5 tn , mtn-tn't eflectt%e 

surface area ol filter paper. the prc.%sure drvp 

acrosn the filtcr paper ~ hould fill betKecn itmrt, 

of 13 and 64 mm 10.5 and 2.5 tn.t He. 

S. Procedure 

8] The sampline prcxrdurc used is .nucal 

Therefore, the procedure recommended hv the 

equipment manufacturer .hall he ngtdh 101- 

lowed. 

8.2 Use a clean. dn. >Jmphne devtcc. If a 

hand sampler is used. warm tt abovc noom 

temperature to prevent condensatton on the 

filter paper. SThis mav usuallv he donc convenientiv bv plaeine the sampler on the hotler or 

furnace to be tested.t 

8.3 ]nsert fitter paper tn ;hc ,amplcr antl 

ttghten the tilter paper holdcr. Conncct the 

sampling device to the flue 2as probe tiL'hen 

takine smoke rrteasuremer.ts tn the lluc ptpe. 

pcisttion the end of the wmpttne pn+hr at the 

ccnter line of the tlue ptpr. 

8.4 Draw the requtree .ample If ,t hsnd 

sampler t. u+ed. permtt :hc presaurc> tn ttte Ilur 

gas stream and the sampier to cyualtze atier 

each stroke. 

8.5 Remove the filter paper. Compare the 

test spot backed with a ptece of White paper nr 

plasttc having 45". 0'' dasltpht lumtnuus Jtrectional reflectance of not less than 75 G, wtth 

the standard scale. 

9. Report 

9.1 Report the .moke denstt% a, the Smoi.e 

Spot Number on the stanslurJ scalc mu.t 

closdv corrcspondtne t.+ the tea Nlx)t. Interpolate diffcrences between two standard Smukc 

Spot Numbers to the nearest haif number. Repon Smoke Spot Numbers ht¢her than 9 a.c 

"Greater than No. 97 

NOTE 3—Wheremoreaccuratcresultsatedestred. 

the human factor tnvolved tn visuallo_ comparing 

Rlter paper test spots wtth smoke scale spots can be 

c6minated by reson to dtrect use of a suttablc photometer far evaluattnr tcst .rtt, Thts pr,ticJurc t ~ 

dckrtbed tn the Annez 

IU. Pretision 

10.1 This tezt ts reproductblc to wtthtn ±: 

of a Smoke Spc-st Numher under normal nonditions. 

Nrrrt 4-\urmal %:undttion• are detined as tn—c 

where no odv statn ts deposited on the dtsk 

A.17 
4D D 2156 

F It 't'ER Dt'SC 

COOLER REGULATOR 

CONDENSER vALVE 

SAMPLING ~ TIrvER 

1U13E 

\ 

jo

.t 

rvtOTOR 

Wl' I f 

L 

DRAIN DWPF4RAGM la~~A~~~ 

_ /,-~ 

THROTTUNG 

ORtFICE 

PUhtP 

F'if:. t Labutaton 1 - ,pe Smoke titrttr 

reflectcd from thts clean surface. Expo.e tcst smoke 

spot on filtcr paper to thc ph xometer ltght heam and 

measure the percentagc rcducuwm tn reflected itEht 

due to the presence ol smu e panicles on the fdter 

paper. Gross Smukc Spt,t Number shall be defined 

as eyuai to the percentage reductton tn reflected hEht 

dtvtded bv ten. 

41.2 Photometer Specifications 

A 1.2.1 The photometer to he empinved 6 r direct 

teIt spot number evaluat on 'hall he uf the cicctricall% 

k perated reflectance trpe emnluvtng a photuelectrtc 

cell, fitted wtth a spectal hoidertst to accommodate 

P1L' 

FiC. 2 Firld tieeviet Tr*e Sreoke Testtr 

ANIVEX 

A1. ALrt:RtiATIVF: PHOTOMETRIC METHOD 

ALI Direct Photometric Evaluation 

A I.1 1 The human factnr tnvolved in visualh 

compartng filter paper test s{x.ts wtth +moke Ncale 

spots cjn bc ehmtnated hN rcwrt to dtrect ux ot a 

~ uttahle photometer fur c%aluaung test ;pots To 

make thts dtrect photometrtc test spot evaluauun. the 

followtne procedure shall be cmplovedAI.I -I l blount a cleaa. unused fdtcr paper. 

baekctl bv a plaque painted % th S12O or matenai 

havtng a 45`. U davls g ht iuminuus dzrectwnal reflcLtance of not lcs,than '5'-, . in the heht beam ni a 

suitahle tvpe rctlectance phowmcter- 4djust thc photometcr to read 100 : rellectance tn tertns of the ItEht 

A.18 
0 D 2156 

tiper paper test zrecamens. It !n t t, he ca}Lhft ,t ,,! ar•rr, ,a,matel. :U. 441. tdl. and 741 -~ 0`t'. 0" da%lt¢ht 

mca.curine the 45. U Ja%h¢ht lumtnouc dlrectl.mal :umlmou.,dtrectu+nal rellectance. to permtt ph, ,t,+ntretlecuace !t !s to he iurnl+hcd completc wah i cter readmzs hetween Il) and dit It Iretattve a, .Icjn 

Ertn tnsttmulus lilter and wtth rcllectance standardn fdtcr paperi to be mada wethln z2 : accuracN 

Tlr Awerra+r Soereev for TearuR aad Alaern/r takrs wo pwuww rrsperrue rhe .oildu. o/ o>,v patertr nSh/s arsmed a. 

lvwoeaserr .+rA anv unn wlen/mned ur rhu uandard L'urs oi rhir uandard arr espnssJr advued rAar de/mn/narwn o_i Ihr randu! 

,1/ srl• swk parenr nghls. and rhe nrk o/ ulfnwerlwrwl of srrh rnealf. arr ennnh• IAelr o.w rrrpon.nCrin.. 

TMl1 SfarldQld tJ SIfh/Kl !r rrYLSlOrI QI aQt Ar rrYlrMYd rYfrv !1!'( 11'Jr' , 

yl,r n nn+ rrrrsrd. nthrr rrarrrmrd "r •'rrhdrar'n lavr .; ~ rn ~ nr+r ~ ~ rr :n.v ~ d rltkrr lor .rr/von n/ rhro uandard ur ror ~J~c+. n ~ . 

,!,ln~s,u ~nJshoriJbcaJdressrdl ~ .tST.1lHradqvarer, 1 our;nmmrnlswdirrrnrfrarr/4JConsldrrarulnala+erNlneQl'nr 

.rspowrlbk nrM/ralcol ~wtrrer, rlucA vwl wlav arrewL !f ror irrl rAar vwr eonnwr.n haw ao+ rerrnrd a falr brarvl; wr lkar+.r 

rkr raw rrrrlFwarw to rhe ASTM Cawuwrner on Srawdardf. JaJO Rare Sr., pkiladrlphla. Pa 10101 

A.19 

APPENDIX B 

SCAQMD Rule 1146.1 

Emissions of Oxides of Nitrogen From 

Small Industrial, Institutional, and Comrnercial Boilers, 

Steam 6enerators, and Process Heaters 

B.1 
(Adopted October 5, 1990) 

RULE 1146.1. EMISSIONS OF OXIDES OF NTTROGEN FROM SMALL 

INDUSTRL4i., INSTITUTiONAL,, AND COMMERCIAL BOILERS, 

STEAM GENERATORS, AND PROCESS HEATEILS 

(a) Definitions 

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

fuels bumed in a unit during a calendar year, based on the fuel's higher 

heating vaiue. 

(2) BOILER OR STEAM GENERATOR means any combustion equipment 

fired with liquid and/or gaseous fuel, used to produce steam or to heat 

water, and that is not used exciusively to produce electricity for sale. 

Boiler or Steam Generator does not include any 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 beat from the exhaust of any combustion equipment. 

(3) BTU means Britisb thermal unit or units.. 

(4) NO, EMISSIONS means the sum of nitric oxide and nitrogen dioxide in 

the flue gas, collectively expressed as nitrogen dioxide. 

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

and/or gaseous fuel and which transfers heat from combustion gases to 

water or process streams. Process Heater does not inciude any Idin or 

oven used for drying, baking, cooldng, calcining, or vitrifying; or any 

un5red waste heat recovery heater that is used to recover sensible heat 

from the exhaust of any combustion equipment. 

(6) RATED HEAT INPUT CAPACTTY means the heat input capacity 

specified on the nameplate of the combustion unit. If the combustion 

unit has beeti aitered or modi.fied such that its maximum heat input is 

different than the heat input capacity specified on the nameplate, the new 

maximtun heat input shaU be considered as the rated heat input eapacity. 

(7) 'THERM means 100,000 Btu. 

(8) IJNIT means a.ny boiler, steam generator, or process heater as defined in 

subparagraph (a)(2) or (a)(5). 

1146.1 - 1 
Rule 1146.1 (Cont.) (Adopted October 5,1990) 

(b) Applicability 

This rule applies to boilers, steam generators, and process heaters that 

are equal or greater than 2 million Btu per hour and lcss than 5 million 

Btu per hour rated heat input capacity used in any industrial, institutional, 

or commercial operation. 

(c) Requirements 

(1) The owner and/or operator of any unit subject to paragraph (b) shall 

operate such unit so that it - discharges into the atmosphere no more than 

30 ppm of NOXemissions (0.037 pound NOXper million Btu of heat 

input) and no more than 400 ppm of carbon monoxide. For each unit, a 

selection must be indicated in the application for permit to construct and 

operate between the ppm NOxor pounds of NOxper million BTU heat 

input compliance option. 

(2) The owner or operator of any unit(s) subject to paragraph (b), and with 

an ann.ual heat input of less than or equal to 18,000 therms per calendar 

year, shall: 

(A) be operated in a manner that mainta.ins 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) be tuned at least twice per year, (at intervals from 4 to 8 months 

apart) in aceordance with the procedure described in Attachment 

1, or other method as approved by the F.xecutive Officer. If the 

unit does not operate during a six-month period, an annual tuneup 

is acceptable. The owner or operator of any unit(s) who specifies 

the semi-annual tuneup option shall maintain a record for a period 

of two years verifying that the tuneup has been performed. The 

record shall contain any other information or documentation that 

the Fxecutive Offieer determines to be necessary and made 

accessible upon request from an authoriud District 

representative; or 

(C) meet the emission limits specified in subparagraph (c)(1). 

(3) Tfie owner or operator of any unit(s) subject to subparagraph (c)(2) shall 

subtnit, for the approval of the Executive Officer, a plan that 

1146.1- 2 
Rule 1146.1 (Cont.) (Adopted October 5, 1990) 

demonstrates compliance with subparagraph (c)(2). Such plan shall 

contain: 

(A) A list of all units with the rated heat input capaeity, anticipated 

annual heat input, and permit number; and 

(B) For each unit listed, a selection of one of the three options 

specified in subparagraph (c)(2) to achieve compliance with this 

rule; and 

(C) Non-resettable, totaiizing fuel meter(s) specifications; date of 

installation; and recorded fuel usage since installation. 

(4) Any owner or operator who chooses the pound per million Btu of heat 

input compliance option shali install a non-resettable, totalizing fuel 

meter for each fuel used on an individual unit basis, as approved by the 

Executive OfP'icer. 

(d) Compliance Deternaination 

(1) All units shail have the option of complying with either the pound per 

million Btu of heat input or parts per miIlion emission limits specified in 

subparagraphs (c)(1) and (c)(2)(C). 

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

condition, except no compliance determination shail be established 

during unit start up, shutdown, or under breakdown conditions. Start up 

or shutdown intervals tnay not last longer than is necessary to reach stable 

temperatures. In no case may the start up or shutdown interval last 

longer than specified in the permit to operate. In the event that permit 

conditions do not speeify a time li.mit, the start up or shutdown may not 

exceed six botus for units subject to paragraph (b). 

(3) All parts per million emission limits specified in subparagraph (c)(1) are 

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

over a period of 15 consecutive minutes. 

(4) Campliance with the NOXand CO entission requirements of 

subparagraph (c)(1) and the stack-gas oxygen conrentration requirement 

of subparagraph (c)(2)(A) shall be determined according to procedures in 

the District Source Test Manual or anv other test method determined to 

be equivalent and approved by the Executive Officer. Emissions 

1146.1- 3 
Rule 1146.1 (Cont.) (Adopted OctQber 5, 199d) 

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. 

(e) Compliance Schedule 

The owner or operator of units subject to this rule shall meet the following 

increments of progress: 

(1) For owners and/or operators of units subject to subparagraph (c)(1): 

(A) By January 1, 1993, submit required applications for perrnits to 

construct and operate, and 

(B) By July 1, 1994, demonstrate compliance with subparagraph (c)(1). 

(2) For owners and/or operators of units subject to subparagraph (c)(2): 

(A) By January 1, 1993, submit a plan pursuant to paragraph (c)(3), 

and 

(B) By December 31, 1993, demonstrate compliance with paragraph 

(c)(2)• 

(f) Exemption 

The provisions of subparagraph (c)(1) shall not apply provided the owner and/or 

operator: 

(1) Installs lry January 1, 1992, or at the time the unit is constructed, a nonresettable, totalizing fuel meter for each fuel that demonstrates that the 

unit(s) operated with an annual heat input at or below 18,000 therms per 

calendar year; and 

(2) Has ava.ilable for inspection by the Executive Officer by February 1, 1993, 

and February 1 of each year thereafter, aunual fuel-use data for the 

preceding calendar year. Records shall be maintained and made 

accessible to the Executive Officer or authorized District representative 

for a period of two years; and 

(3) Demonstrates by February 1, 1993, that the aztnual heat input is less than 

or equal to 18,000 therms. 

114b.1- 4 
Rule 1146.1 (Cont.) (Adopted October 5, 1990) 

(g) Lass of Exemption 

If any unit sub}ect to a control plan submitted pursuant to subparagraph (c)(3) 

exceeds 18,040 therms of annual heat input after 1992, the owners or operators 

shall: 

(1) Within 4 months from the end of the preceding calendar year, submzt 

required applications for permits to construct and operate, and 

(2) Within 18 months from the end of the preceding calendar year, 

demonstrate compliance with subparagraph (c)(1). 

A'ITACHMENT 1 

Equipment'Iuning Procedure t 

Nothing in this Equipment Tuning Procedure shall be construed to require any act or 

otnission 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 number 2(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 iower 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. 

Thuprocednre is based on a tune-up prooedure developed by KVB, Lnc. for the EPA. 

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

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

Bacharach Company. 

3Typical minimum oxygen leveLs for boilers at higb firing ratts are: 

1. For natural gas: OS percent - 3 percent. 

2. For liquid fuels: 2 percent - 4 percent. 

1146.1- 5 
Rule 1146.1 (Cont.) (Adopted October 5, 1990) 

3 

4.

5.

r.l. 

7. 

However, cornplete the remaining portion of this procedure to determine 

whether still lower oxygen levels are practical. 

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 fueis) or smoke-spot 

number (for Iiquid fuels), and observe flame conditdons for these hig}ser oxygen 

levels after boiler operation stabilizes. 

Decrease combustion air flow until the stack gas oxygen concantration is at the 

level measured in Step 2. From this level, gradualIy reduce the combustion air 

flow in small inerements. 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. 

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, excxssive flame carryover, or flame instability; or 

b. Stack gas CO concentrations greater tban 400 ppm; or 

C. Smoking at the stack; or 

d. Equipment-related limitations, such as low windbax Jfurnace pressure 

differential; built in air-flow limits, etc. ' 

Develop an 02/CO curve (for gaseous fuels) or 02/smoke cuive (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. 

From the ntuves prepared in Step 6, find the stack-ps oxygen levels where the 

CO emissions or smoke-spot ntunber equal tbe following values: 

Fuir1 Yeasurement 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 

1146.1 - 6 
Rule 1146.1 (Cont.) (Adopted October 5, 1990) 

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, bumer 

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 of 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 Iimits 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 fuing 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. 

1146.1 - 7 
APPENDIX C 

SCAQMD Rule 1146 

Emissions of Oxides of Nitrogen From 

Industrial. Institutional, and Conmercial Boilers, 

Steam 6enerators, and Process Heaters 

C.1 
(Adopted September 9, 1988)(Amended Januarv ti. 1989) 

RULE 1146. EMISSIONS OF OXIDES OF NITROGEN FROM 

INDUSTRIAL, INSTITUTIONAL, AND COMMERCIAL 

BOILERS, STEAN1 GENERATORS, AND PROCESS HEATERS 

(a) Definitions 

(l) Annual Capacity Factor means the ratio of the amount of fuei burned hv 

a unit in a calendar vear 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) .Annual Heat Input means the actual amount of heat released hv fuzls 

burned in a unit during a calendar vear. 

(3) Boiler or Steam Generator means any combustion equipment fired with 

liquid and/or 2aseous fuel and used to produce steam or to heat vvater 

and that is not used exclusively to produce electricity for saie. Boiler or 

Steam Generator does not include any 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. 

(4) BTU means British thermal unit. 

(5) 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 inciucle the 

sensible heat of incoming combustion air. 

(fi) NOx Emissions means the sum of nitric oxides and nitrogen dioxide in the 

flue gas, collectively expressed as nitrogen dioxide. 

(7) Process I--Ieater means any combustion equipment fired with liquicl 

and/or easeous 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, baking, cooking, calcining, or vitrifyino; or anv 

unfired waste heat recoverv heater that is used to recover sensible hzat 

from the exhaust of any combustion equipment. 

(8) 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 irnput is different than the 

1146 - 1 
Rule 1146 (Cont.) (Amended January 6, 1989) 

heat input capacity specified on the nameplate, the new maximum heat 

input shall be considered as the rated heat input capacity. 

(9) Therm means 100,000 Btu's. 

(10) Unit means any boiler, steam generator, or process heater as defined in 

subparagraph (3) or (7) of this paragraph. 

(b) Applicability 

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

greater than 5 miliion Btu's 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. 

(c) Requirements 

(1) The owner or operator of any unit(s) shall not discharge into the 

atmosphere oxides of nitrogen, expressed as nitrogen dioxide (NO2), in 

excess of the concentrations shown in the foilowing tabie. 

Gaseous 

Rated Heat or Liquid 

Input Capacity Annual Heat Input Fuels 

Equal to or 

greater than And 

Greoter than 9 

x 10 Btu's per yr 40Rib

m 

(0 per 

5 million Btu's (90,000 10 Btu's 

per hour Therms) of heat 

input) 

Equal to or Greater than 25°10 30 ppm 

greater than And annual capacity 

40 million factor 

Btu's per 

hour 

Carbon monoxide (CO) emissions from unit(s) subject to this 

subparagraph shall not exceed 400 ppm. 

1146 - 2 
Rule 1146 (Cont.) iAmended .January 6, 1989) 

(2) Any unit(s) with a rated heat input capacity ereater than or equal to ~ 

million Btu per hour and an annual heat input less than or equal to 9.0 x 

I09Btu per year, shall: 

(A) be operated in a manner that maintains stack gas oxvgen 

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

any 15-consecutive-minute averaging period: or 

(B) be tuned at least twice per year, once between March 15 and 

June 15, and once between September 15 and December 15 in 

accordance with the procedure described in Attachment 1. The 

owner or operator of any unit(s) who specifies the semi-annuul 

tune-up option shaIl maintain a record made accessible to the 

Executive Officer for a period of two vears verifving that the tuneup has been performed. The record shall contain any other 

information or documentation that the Executive Officer 

determines to be necessary; or 

(C) be operated in compliance with a 40 ppm (0.05 Ibs per 10 6 Btu of 

heat input) NOx emission level and a 400 ppm CO emission level. 

(3) The owner or operator of any unit(s) subject to subparagraph (c)(2) shall 

submit for the approval of the Executive Officer a plan that demonstrates 

compliance with subparagraph (c)(2). Such plan shall contain: 

(A) A list of all units with the rated heat input capacity and anticipateci 

annual heat input. 

(B) For each unit listed, a selection of one of the three options 

specified in subparagraph (c)(2) to achieve compliance with this 

rule. 

(4) 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 10 9Btu 

per year, or any units that are part of an Alternative Emission Control 

Plan, shall have a continuous in-stack nitrogen oxides monitor or 

equivalent verification system as approved by the - Executive Officer. 

Records shall be maintained and made accessible for a period of tnvo 

years in a form and manner as specified by the Executive Officer. 

1146 - 3 
Rule 1146 (Cont.) (Amended January 6, 1989) 

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

compliance option shall install totalizing fuel meters on an individual unit 

basis, as approved by the Executive Officer. 

(6) Any owner or operator claiming an exemption from any of the provisions 

of subparagraphs (c)(1) and/or (c)(4) based on annual heat input, shall: 

(A) install by February 1, 1989 for units with a rated heat input 

capacity equal to or greater than 5 but less than 40 million Btu per 

hour, or by May 1, 1989 for units with a rated heat input capacity 

equal to or greater than 40 million Btu per hour, or at the time the 

unit is constructed, a totalizing meter for each fuel that 

demonstrates that the unit(s) operated at or below the applicable 

heat input levels; and 

(B) have available for inspection by the Executive Officer by March 1, 

1989, and March 1, of each year thereafter, annual fuel use data 

for the preceding calendar year. Records shall be maintained and 

made accessibie to the Executive Officer for a period of two years; 

and 

(C) demonstrate that the annual heat input is less than or equal to the 

applicable amount listed in subparagraph (c)(1) and/or (c)(4). 

(cl) Alternative Emission Control Plan 

(1) An owner or operator may achieve compliance with paragraph (c) by 

achieving equivalent nitrogen oxides emissions reductions obtained by 

alternative control methods provided the applicant submits an 

Alternative Emission Control Plan that is enforceable by the District and 

receives approval of the Plan in writing from the Executive Officer prior 

to implernentation. The Alternative Emission Control Plan shall: 

(A) Contain, as a minimum, all data, records, and other information 

necessary to determine eligibility for alternative emission control, 

including but not limited to: 

(i) A iist of equipment subject to alternative emission 

control; 

(ii) Daily hours of utilization for applicable equipment; 

i146-4 
Rule 1146 (Cont.) (Amended January 6, 1989) 

(iii) Estimated emission of nitrogen oxides for each 

operation; ' 

(iv) Rated capacity; and 

(v) Historical and projected fuel use. 

(B) Present the methodology for estimation of equivalency of emission 

reductions under the proposed Alternative Emission Control Plan 

as compared to either the emission reductions otherwise required 

by the rule or to actual emissions, whichever is less. 

(C) Demonstrate that the permit units subject to the specified rule 

emission limitations are in compliance with or on an approved 

schedule for compliance with all applicable District rules. 

(2) Revision of Control Plan 

A revised controi plan may be submitted by the owner or operator, along 

with any required permit applications. Such a plan shall adhere to the 

emissions limits and the final compliance dates of this rule. New units, 

including functionally identical replacement units, shall not be 

incorporated into the plan. 

(e) 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 subparagraph (c)(1). 

(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. 

(3) All parts per million emission limits specified in paragraph (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 emission requirements and the stack gas 

oxygen concentration requirement of paragraph (c) shali be determined 

according to procedures in the District Source Test Manual or in any 

other manner approved by the Executive Officer. 

1146 - 5 
Rule 1146 (Cont.) (Amended January 6, 1989) 

(f) Compliance Schedule 

The owner or operator of units subject to this rule shall meet the following 

increments of progress: 

(1) For owners or operators of units subject to subparagraph (c)(2), submit, 

by September 1, 1989, a plan pursuant to subparagraph (c)(3) and by 

March 1, 1990, demonstrate final compliance with subparagraph (c)(2). 

(2) For owners or operators utiiizing the Alternative Emission Control Plan, 

pursuant to paragraph (d), by September 1, 1989, submit a control plan. 

(3) For owners or operators of units with a rated heat input capacity equaI to 

or greater than 10 million Btu per hour that are subject to the 40 ppm 

emission limit specified in subparagraph (c)(1), including those with an 

approved Alternative Emission Control Plan; 

(A) By March 1, 1990, submit required applications for permits to 

construct and operate. 

(B) By September 1, 1991 demonstrate compliance with subparagraph 

(c)(1) and, if applicable, subparagraph (c)(4). 

(4) For owners or operators of units with a rated heat input capacity equal to 

or greater than 5 million Btu per hour, but less than 10 milIion Btu per 

hour, that are subject to the 40 ppm emission limit specified in 

subparagraph (c)(1): 

(A) By March 1, 1991, submit required appiications for permits to 

construct and operate. 

(B) By March 1, 1992, demonstrate compliance with subparagraph 

(c)(1). 

(5) For owners or operators of units with a rated heat input capacity equal to 

or greater than 40 tnillion Btu's per hour and an annual capacity factor of 

25% that are subject to the 30 ppm emission limit specified in 

subparagraph (c)(1): 

(A) By July 1, 1991, submit required applications for permits to 

construct and operate. 

(B) By Juiy 1, 1993, demonstrate compliance with subparagraph (c)(1). 

1146 - 6 
Ruie 1146 (Cont.) (Amended January 6, 1989) 

(6) The provisions of subparagraph (c)(1) and/or (c)(4) shall become 

applicable for the life of the unit on March 1, of any calendar year if that 

unit operated for the previous calendar year at an annual heat input 

greater than the annual applicable heat input leveis. 

1146 - 7 
Rule 1146 (Cont.) (Amended January 6, 1989) 

ATTACHMENT 1 

Equipment Tuning Procedure 1 

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 vioEation 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. 

l. 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. 

'. At this firing rate, record stack gas temperature, oxygen concentration, and CO 

concentration (for gaseous fuels) or smoke-spot number 2(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 

typicaI minimum values 3 , and if CO emissions are low and there is not smoke, 

the unit is probably operating at near optimum efficiency - at this particuiar 

firing rate. 

I. 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. 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: 0.59o' - 3% 

2. For liquid fuels: 27c - 4% 

1146 - 8 
Rule 1146 (Cont.) (Amended Januan+ 6, 1989) 

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 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. 

(i. 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 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 

1146 - 9 
Rule 1146 (Cont.) (Amended January 6, 1989) 

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 of 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. l:f 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 accotnmodate 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. 

1146 - 10 
APPENDIX D 

SCAQMD Rule 1109 

Emissions of Oxides of Nitrogen From 

Boilers and Process Heaters 

in Petroleum Refineries 

D.1 
(Adopteci _\ovember 1. l985)(Amencied AuL!u ~ : 5 . 1 988) 

RULE 1109. EMISSIOiV'S OF OXIDES OF NITROGEN FROM BOiLERS AND 

PROCESS HEATERS IN PETROLEUNI REFINERIES 

;a) Definitions 

(1) BOILER means anv combustion eauipment fired titiith liyuici and/or 

gaseous fuel and used to produce steam, includini! a carbon monoxide 

boiier. 

(2) PROCESS HEATER means any combustion equipment fired with lic{uid 

ancd/or gaseous fuel and which transfers heat trom combustion Uases to 

process streams. 

t3) REF1NERl'•WIDI :ATE OF NITROGEN (')XIDES CMISSIONS 

means the ratio or the total mass rate of di,charUe into the atmosphere ur 

nitroven oxides from units (;ubject tc> the rute) when firing at their 

maximum ratecl capacitv to the sum of the maximum r;.itCCi capacities tor 

those units. 

(4) UNIT means anv petroleum refinery boiler or process heater. as definecl 

in subsections (1) and (2) of this section. with a permit to construct or a 

permit to operate prior to lklarch ?, 1984. 

(5) NITROGEN (UXIDES means the sum oi nitric uxicie ..ncl nitrogen 

dioxide in the *.lue ~-, as, collectivelv expressed as nitrouen dioxicle and 

averagecl over a period ot 1 -5consecutive minutes. 

(6) COti1BUSTI0,"1 %10DIFICATION means anv ,nodification ~~ r .thc 

burner, combustion air t1ow, or fuel flow svstem that reduces nitrc>uen 

oxides emissions. 

(7) vtAXIMUM RATED CAPACITY means maximum clesiLyn heat input ;rt 

the hieher heatini! value ot the fuel unless: 

!A) the boiler/process heater is limited hv permit condition to a Izsser 

heat input. in which case the iimitina condition shall he usecl aa the 

ma.ximum rated caqacitv: or 

kB) the noiler?process heater is operated above the m:iximum cJesi_ ~ n 

heat input. in which case the maximum operated rate shall he used 

at the maximum rated capacitv. 

(8) EMISSIONS RATE means the ratio of the mass rate ot uischaree into 

1109 - 1 
Rule 1109 (Cont.) tAmended August 5, 1988) 

the atmosphere of nitrogen oxides from a unit to the actual heat input €or 

that unit. 

(9) HEAT INPUT means the heat of combustion released by fuel oxidation 

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

the enthalpy of incoming combustion air. In the case of carbon monoxide 

boilers, the heat input includes the enthalpy of all regenerator off gases 

and the heat of combustion of the incoming carbon monoxide and of the 

auxiliary fuel. The enthalpy of the fluid catalvtic cracking unit 

regenerator off-gases refers to the total heat content of the gas at the 

temperature it enters the carbon monoxide boiler, referred to the heat 

content at 600F, as being zero. 

(b) Requirements 

(1) (A) From July 1, 1988 until December 31, 1992, the owner operator of 

anv petroleum refinery shall reduce emissions of nitrogen oxides 

from units subject to this rule so that if all such units were 

operated at their maximum rated capacity the refinery-wide rate of 

nitrogen oxides emissions from these units would not exceed: 

(i) 0.14 pound (0.064 kilogram) of nitrogen oxides per million 

BTU of heat input when operated on gaseous fuel; 

(ii) 0.308 pound (0.14 kilogram) of nitrogen oxides per million 

BTU of heat input when operated on liquid fuel; 

(iii) the weighted average of the limits of subsections 

(b)(1)(A)(i) and (b)(1)A(ii), when operated concurrently 

on both liquid and gaseous fueI. For purpose of this rule, 

the nitrogen oxides formed in the fluid catalytic cracking 

unit regenerator shall be assumed to be from the burning 

of gaseous fuel. 

(B) On December 31, 1992 and subsequent dates, the owner or 

operator of any petroleum refinery shall reduce emissions of 

nitrogen oxides from each unit subject to this rule so that: 

(i) From December 31, 1992 until December 31, 1995, 

emissions from units which represent at least 36 percent 

of the total heat input are less than or equal to 0.03 pound ? 

1109 - 2 
Rule 1109 (Cont.) iAmended August 5, 1988) 

per million BTU of heat input when firing at the 

maximum rated capacity, or as specified in the Alternative 

Emission Control Plan (AECP). Artv unit not meeting 

the 0.03 pound per million limit shall not exceed its pound 

per million BTU limit specified in the Approved Control 

Plan for compliance with (b)(1)(A); 

(ii) From December 31, 1995, emissions are less than or equal 

to 0.03 pound per million BTU of heat input when firing 

at the maximum rated capacity, or as specified in the 

A3ternative Emission Control Plan (AECP). 

(iii) For each unit firing at less than the maximum rated 

capacity, mass emissions of nitrogen oxides shall be less 

than or equal to the quantity that would occur at the 

applicable limit specified in (b)(1)(B)(i) and (b)(1)(B)(ii) 

at maximum rated capacity, or as specified in the AECP. 

(iv) Alternative Emission Control Plan (AECP) 

An owner/operator may achieve compliance with 

paragraphs (b)(1)(13)(i) and (b)(1)(B)(ii) by achieving 

equivalent nitrogen oxides emissions reductions obtained 

by alternative control methods provided the applicant 

submits an Alternative Emission Control Plan that is 

enforceable by the District and receives approval of the 

Plan in writing from the Executive Officer prior to 

implementation. 1"ne Alternative Emission Controi Plan 

shall: 

(1) Contain, as a minimum, all data, records, and 

other information necessarv to determine 

eligibility for alternative emission controi, 

including but not limited to: 

a) A list of eouipment subject to alternatiVe 

emission control; 

b) Daily hours of utilization for applicahle 

equipment; 

c) Estimated emission of nitrogen oxides for 

1109 - 3 
Ruie 1109 (Cont.) (Amended August 5, 1988) 

each operation; 

d) Rated capacity; and 

e) Historical and projected fuel use. 

(II) Present the methodology for estimation of 

equivalency of emission reductions under the 

proposed Alternative Emission Control Plan as 

compared to either the emission reductions 

otherwise required by the rule or to actual 

emissions, whichever is less. 

(II1) Demonstrate that the permit units subject to the 

specified rule emission Iimitations are in 

compliance with or on an approved schedule for 

compliance with all applicable District rules. 

(2) The owner or operator shall operate each unit subject to this rule such 

that the assigned maximum nitrogen oxides emissions rate for each unit 

(pounds or kilograms per million BTU heat input, expressed as nitrogen 

dioxide) is in accordance with the list approved by the Executive Officer 

pursuant to subsection (b)(6)(B), and any specified permit conditions. 

(3) The owner or operator of any petroleum refinery which has units subject 

to this rule shall submit to the Executive Officer a control plan for 

installation of nitrogen oxides emissions control equipment to meet the 

requirements of subsection (b)(1); 

Such plan shall contain as a minimum: 

(A) A list of all units with the maximum rated capacity for each unit, 

(S) .A list of units to be controlled and the type of control to be 

applied for all such units, including a construction schedule, 

(C) The method of calculation of the mass rate of nitrogen oxides 

emissions for each unit to achieve the refinery-wide emissions 

rates specified in subsection (b)(1), and 

(D) On-site nitrogen oxide offsets from co-generation facilities may be 

incorporated in the plan. 

(4) All units which are identified in the control plan required by subsection 

(b)(3) shall be tested, in a manner approved by the Executive Officer, for 

nitrogen oxides emissions while firing gaseous fuel and liquid fuel, if 

1109 - 4 
Rule 1109 (Cont. i i.amended August S. 1988) 

applicable, at the maximum rated capacity, or as near thereto as 

practicabie. Such tests shall be performed: 

(A) Within 180 days after compietion of modifications, but no later 

than 1 month before any applicable compliance date for units 

which are to be modified with nitrogen oxides control equipment. 

and 

(B) By December 1, 1986, for units which do not require modification. 

(5) Total nitrogen oxides emissions (pounds or kilograms per hour) and total 

heat input rates (million BTU's per hour) during the tests recluired by 

subsection (b)(4), while firing gaseous fuel and while firing liquid fuel. 

shall be used for determination of initial compliance with the refinen!- 

wide rate of emissions limits of subsection (b)(1). 

(6) After verification of initial compliance with the limits of subsection 

(b)(1))(A): 

(A) The owner or operator shall assign to each unit subject to this rule 

the maximum nitrogen oxides emissions rates (pounds or 

kilograms per million BTU heat input, expressed as nitrogen 

dioxide), while firing gaseous fuei or liquid fuel, which are 

allowable for that unit under the requirements of subsection 

(b)(1)(A). 

(B) The owner or operator shall submit to the E,xecutive Officer for 

approval a list, by the appiicable compiiance date, uf the maximum 

allowable nitrogen oxides emissions rates identified in subsection 

(b)(6)(A) and a copy of the approved list shall be maintained for 

verification of continued compliance with the requirements of 

subsection (b)(2). 

(C) Compliance with subsection (b)(1)(A) shafl be determined hv 

source testing any one unit subject to this rule, or additional units 

if required by the Executive Officer. No unit subject to this rule 

shall be operated at an emissions rate (pounds or kilograms per 

million BTU heat input, expressed as nitrogen dioxide) higher 

than that approved by the Executive Officer pursuant to 

subsection (b)(6)(B). 

(7) Each unit subject to this rule shall have a continuous in-stack nitrogen 

1109 - S 
Ruie 1109 (Cont.) (Amended August S. 1988) 

oxides monitor, or equivalent verification system, as approved by the 

Executive Officer at the time of compliance with the 0.03 pound per 

million BTU limit specified in subsections (b)(1)(B)(i) and (b)(1)(B)(ii). 

(A) Records shall be maintained and made accessible for a period of 

two years to the Executive Officer in a form and manner as 

specified by the Executive Officer. 

(B) Compliance with subsection (b)(1)(B) shall be determined by 

source testing and/or in-stack nitrogen oxides monitor data or 

other data as specified for the equivaient verification system. 

(c) Revision of Control Plan 

A revised control plan may be submitted by the owner operator, along with any 

required permit applications. Such a plan shall adhere to the emissions limits 

and the final compliance dates of this rule. New units, including functionally 

identical replacement units, shall not be incorporated into the plan. 

(d) Exemptions 

The requirements of Section (b) shall not apply to: 

(1) Boilers or process heaters with maximum rated capacities equal to or less 

than 40 million BTU per hour heat input. 

(2) Sulfur plant reaction boilers. 

(3) Upon approval by the E.xecutive Officer, units which are operated with a 

total heat input in a 12 month period of less than 10 percent of the 

maximum rated capaciry for that period. 

(e) Compliance Schedule 

The owner or operator of a petroleum refinery having units subject to this rule 

shail fulfill the following increments of progress: 

(1) For subsection (b)(1)(A), by July 1, 1988, demonstrate to the satisfaction 

of the Executive Officer final compliance with the rule. 

(2) For subsection (b)(1)(B)(i): 

(A) By April 1, 1989, submit a revised control plan, pursuant to 

subsection (b)(3) of the rule. 

(B) By September 1, 1989, submit required applications for permits to 

construct and operate. 

1109 - 6 
Rule 1109 (Cont.) iAmended August S. 1988) 

(C) Bv December 31, i992 demonstrate to the satisfaction of the 

Executive Officer compliance with (b)(1)(B)(i). 

(3) For subsection (b)(1)(B)(ii): 

(A) By 5eptember 1, 1992, submit a revised control plan, pursuant to 

subsection (b)(3) of the rule. 

(B) By February 1, 1993, submit required applications for permits to 

construct and operate. 

(C) By December 31, 1995, demonstrate to the satisfaction of the 

Executive Officer compliance with (b)(1)(B)(ii). 

1109 - 7 
APPENOIX E 

YCAPCD Rule 74.15 

Boilers, Steam 6enerators and Process Neaters 

E.1 
Rule 74.15. Boilers, Steam Generators and Process Heaters (Adopted 3/28/89) 

A. Applicability 

1. The provisions of this rule shall apply to boilers, steam 

generators and process heaters used in all industrial, 

institutional and commercial operations, except as follows: 

a. Utility electric pover generating units and any,auxiliary 

boiler used with a utility electric power generating unit. 

b. Water heaters. 

B. Requirements 

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

boiler, steam generator or process heater with a rated heat input 

capacity of equal to, or greater than, five (5) million BTU's per 

hour and an annual heat input rate of equal to, or greater than, 9 

x 10 ~ BTU's per calendar year, oxides of nitrogen emissions in 

excess of 40 parts per million volume. Carbon monoxide emissions 

from units subject to this rule shall not exceed 400 ppmv. 

Units subject to the above provisions shall test for compliance not 

less than once every 24 months. 

2. Any boiler, steam generator or process heater with a rated heat 

input capacity of equal to, or greater than, five (5) million BTU' ~ 

per hour, and having an annual heat input rate of lessthan 9 x 10 G BTU's per calendar year, shall comply with one of the folLoving 

~ ~ requirements: 

Q 

oz a ~ 

= 

a a. The unit shall be operated in a manner that maintains stack 

Z a Q ~ gas oxygen concentrations at less than or equal to three (3) 

w r Q _ percent on a dry basis for any 15-consecutive-minute 

~ ~ r_ ~j averaging period. Units subject to this provision shall test 

Q U for compliance every six (6) months; or 

Z V t` Z O

> 

; h b. T e unit shall be operated using a stack gas oxygen trim 

system set at three (3) percent oxygen. The tolerance of the 

0 o> setting shall be ± five (5) percent. Units subject to this 

0 CO provision shall test for compliance every twelve (12) months; 

~ or 

¢ 

C. The unit shall be tuned at least twice per calendar year, 

once between March 15 and June 15 and once between September 

15 and December 15, in accordance with the procedure 

described in Attachment 1; or 

d. The unit shall comply with the emission and testing 

requirements of Subsection B.1. 

4/89 

_ Attactunent 3 

Rule 74.15 : 1 
C. Exemptions 

1. The provisions of this rule shall not apply to anw boiler, steam 

generator or process heater with a rated heat input capacity of 

less than five (5) million BTiJ's per hour. 

2. The provisions of Subsection B.1 of this rule shall not apply to 

any boiler, steam generator or process heater operated on alternate 

fuel under the following conditions: 

a. Alternate fuel use is required due to the curtailment of 

natural gas service to the individual unit by the natural gas 

supplier. Alternate fuei 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. 

3. The provisions of Subsection B.1 of this rule shall not apply to 

the use of an emergency standby unit when a breakdown occurs to the 

primary unit, and the breakdown is reported pursuant to the 

breakdown reporting requirements of Ruie 32. Emissions resulting 

from the operation of the standby unit shall not exceed the total 

annual or hourly permitted emission rate of the primary unit. 

Operation of the standby unit shall not occur beyond the period of 

the primary unit's emergency breakdown. 

D. Recordkeeping Requirements 

1. Any person subject to the provisions of Subsection 8.2 of this ruie 

shall install by September 28, 1989, or at the time the unit is 

constructed, a totalizing fuel meter for each applicable unit and 

for each fuel. The meter shall be used to demonstrate that each 

unit operates at or below the applicable heat input level. 

Meters shall be accurate to t one (1) percent, as certified by the 

manufacturer in writing. After December 28, 1989, totalizing fuel 

meter readings 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 month, daily records shall be compiled into a monthly 

report. Both monthly 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 B.2.c of this 

rule shall submit a report to the District twelve (12) months after 

achieving compliance with Subsection B.2.c. Reports shall continue 

to be submitted every twelve (12) months. This report shall verify 

that each tune-up has been performed and that the results were 

satisfactory. The report shall contain all information or 

documentation that the Air Pollution control Officer may determine, 

in writing, to be necessary. 

4/89 Rule 74.15 : 2 
Any person utilizing alternate fuel, pursuant to the provisions of 

Subsection C.2 of this rule, shall maintain permanent daily records 

of each occurrence. Each record shall includa the type of fuel, 

the quantity of fuel, and the duration of the occurrence. Records 

shall be maintained for a period of four (4) years and shall be 

available for inspection by the Air Pollution Control Officer upon 

request. 

E. Test Methods 

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

determined using the following test methods: 

a. Oxides of Nitrogen - EPA Method 7E or ARB Method 100 

b. Carbon Monoxide - EPA Method 10 or ARB Method 100 

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

2. Emission tests resulting in compliance determinations for the 

requirements of Subsection B.1 shall be conducted on units in "asfound" operating condition. However, no emission test for this 

rule shall be conducted during start-up, shutdown or under 

breakdown conditions. 

3. The NOx parts per million emission limitation specified in 

Subsection B.1 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. 

F. Violations 

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

a violation o£ this rule. 

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

with the provisions of Subsection B.1 if the unit operates during 

any twelve (12) month period at a total annual heat input rate 

greater than the applicable annual heat input rate specified in 

Subsection B.2. 

G. Definitions 

1. "Boiler, Steam Generator": Any combustion equipment fired with 

liquid and/or gaseous fuel and used to produce steam. These terms 

do not include any unfired waste heat recovery boiler that is used 

to recover sensible heat from the exhaust of any combustion 

equipment. 

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

gaseous 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, baking, cooking, calcinating or vitrifying 

or any fuel-fired degreasing or metal finishing equipment. 

4/89 Rule 74.15: 3 
3. "Rated Heat Input Capacity" ~ The heat input capacity specified on 

the nameplate o= the unit's burner. If the burner 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, then the new maximum heat input 

shall be considered as the rated heat input capacity. 

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

Subsections G.1 and G.2 of this rule. 

5. "Water Heater": A device that heats water to a thermostaticallycontrolled temperature for delivery,on demand. 

H. Increments of Progress 

1. For units subject to Subsection B.1 and with a rated heat input 

capacity of equal to or greater than ten (10) million BTtT's per 

hour, complete Authority to Construct applications shall be 

submitted to the APCD before March 1, 1990, and final compliance 

shall be demonstrated before September 1, 1991. 

2. For units subject to Subsection B.1 and with a rated heat input 

capacity of equal to or greater than five (5) million BTU's per 

hour, but less than ten (10) million BTiI's per hour, complete 

Authority to Construct applications sha11 be submitted to the APCD 

before March 1, 1991, and final compliance shall be demonstrated 

before March 1, 1992. 

3. For units subject to Subsections B.2, final compliance shall be 

demonstrated by March 1, 1990. 

4/89 Rule 74.15: 4 
ATTACHMENT 1 

Equipment Tuning Procedure l 

Nothing in this Equipment Tuning Procedure shali 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. 

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 

concentratiIn, and CO concentration (for gaseous fuels) or smokespot number (for liquid fuels), and observe flame conditions 

after unit operation stabilizes at the firing rate selected. If 

the excess oxygen in the stack ias is at the lower end of the 

range of typical minimum values , 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 

ievels 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 oxxygen 

levels after boiler operation stabilizes. 

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 D2156 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 oaygen levels for boilers at high firing rates 

are: 

1. For natural gas: 0.5% - 3% 

2. For liquid fuels: 2% - 4% 

4/89 ATTACHMENT 1 Rule 74.15 : 5 
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 flov 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 vindbox/furnace 

pressure differential, built in air-flow limits, etc. 

6. Develop an 0 2 /CO curve (for gaseous fuels) or 0 2 /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: 

Zuel Measurement Va1ue 

Gaseous CO Emissions 400 ppm 

#1 & #2 oils smoke-spot number number 1 

#k 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 ievel. 

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. 

4/89 ATTACEMENT 1 gule 74.15: 6 
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 ratas that represent 

the upper and lover 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 ratas. 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 nev settings can accommodate the sudden changes 

that may occur in daily operation vithout adverse effects. Do 

this by increasing and decreasing load rapidly vhile 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 nev 

settings in a similar fashion. Then make sure that the final 

control settings are recorded at steady-state operating conditions 

for £uture reference. 

4/89 ATTACHIiENT 1 Rule 74.15: 7