State of California 

AIR RESOURCES BOARD 

DETERMINATION OF REASONABLY AVAILABLE CONTROL TECHNOLOGY 

AND BEST AVAILABLE RETROFIT CONTROL TECHNOLOGY 

FOR 

INDUSTRIAL, INSTITUTIONAL. 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 
ACl::HOWLEDGMENTS 

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: 

Principal Author 

Jim Guthrie 

Clerical Supoort 

Marline Hick.s 

Theresa Dade 

Technical Review Grouo 

Combustion Committee 

Don Price 

Craig Ullery Brigette Tollstrup Dan Speer Jim Guthrie 

Gary Quinn 

Reviewed and Approved by 

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 
Table of Contents 

Contents 

INTRODUC II ON ...................................................... · .. 1 

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

A. RACT Djscussjon ............................................. 1 

B. BARCT Discuss ion ............................................ 4 

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

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

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

C. Selective Noncatalytic Reduction ............................ 8 

D. Selective Catalytic Reduct jon ............................... 8 

II I. COST -EFFECTIVENESS .............................................. 9 

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

A. Economj c .................................................... 10 

B. Air Quality ........................••....................... 10 

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

D. Energy ...................................................... 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 .Heaters 

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 Determination 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 Pollution 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 

A. RACT Discussion 

On April 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 emission 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 Resources Board on September 10, 1987 

Ratedll Annual 

Heat Capacity 

lnmt1 Factor 

l20 and ,ilSO MMBtu/hr >10.0% 

>150 MMBtu/hr >5.0% 

Fuel 

~ 

Gas 

Fuel Oil #1 or #2 

Other Fuel Oi 1 

Gas 

Fuel Oil #1 or #2 

Other Fuel Oil 

NOx.lll. 

Emission 

Limits 

70 ppmv NOx or 

0.08 lbs N02/MMBtu 

115 ppm NOx or 

0.15 lbs N0 2/MMBtu 

150 ppmv NOX or 

0.20 lbs N0 2/MMBtu 

85 ppmv NOx or 

0.10 lbs N0 2/MMBtu 

135 ppmv NOxor 

0.18 lbs N02/MMBtu 

165 ppmv NOx or 

0.22 lbs NOziMMBtu 

AI 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. 

b.L Corrected to 3.00 percent by volume 02, dry, and averaged over 15 consecutive minutes. 

2 
Table 2 

Summary District Rules Reviewed for NOx Emissions 

from Non-Ut111ty Boilers and Process Heaters 

Rated 

Heat 

Irw..u..t. 

Annual 

Heat Input or 

Capacjty Factor 

NOxll 

Emission 

Ljmjts 

coil 

Emission 

Ljmjts 

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

~2 and <5 MMBtu/hr >18,000 therms~ 30 ppmv or 400 ppmv 0.037 lbs N0 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 N0 2/MMBtu 

140 MMBtu/hr >25~ 30 ppmv 400 ppmv 

-------SCAQMD's Rule 1109, Boilers and Process Heaters - Petrole~---------­

Refineries, (11/1/85, 8/5/88) 

>40 MMBtu/hr 0.03 lbs NO?/MMBtu 

@maximum rated 

capacity 

-------VCAPCD's Rule 74.15, Boilers and Process Heaters, (3/28/89)----------

l.5 MMBtu/hr 290,000 thermshl 40 ppmv 400 ppmv 

AL Units with annual heat inputs of less than 18,000 therms are subject to other requirements. 

hL Units with annual heat inputs of less than 90,000 therms are subject to other requirements. 

ll Corrected to 3.00 percent by volume o2, dry, and averaged over 15 consecutive minutes. 

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

B. BARCT Discussion 

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 non- electric-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 million Btu per hour, having annual heat inputs of 

greater than 18,000 therms; 40 ppmv NOx 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 2 per million Btu of heat input for units operating at maximum 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. 

4 
Table 3 

RACT/BARCT Summary for Industrial, Institutional 

and Commercial Boilers, Steam Generators, and Process Heaters 

Standards 

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

Rated 

Heat 

lrulu..t. 

l. 5 MMBtu/hr 

Annual.a.L 

Heat 

Input 

l. 90,000 therms 

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

Rated 

Heat 

lruul1 

l. 5 MMBtu/hr 

Annual.a.L 

Heat 

Inpyt 

l. 90,000 therms 

Fuel 

~ 

Gas 

Other U 

Exemption 

Fuel 

lYM 

Gas 

Other 

Exemption!Ji._ 

NOx.b.L. 

Emission 

Ljmits 

70 ppmvki 

115 ppmvfl 150 ppmv 

NOx.b.L. 

Emission 

Limits 

30 ppmv.U 

40 ppmv~ 150 ppmv 

co.b..L 

Emission 

Limits 

400 ppmv 

400 ppmv 400 ppmv 

co.b..L 

Emission 

Limits 

400 ppmv 

400 ppmv 400 ppmv 

ll Units with annual heat inputs of less than 90,000 therms are subject to other requirements . 

.b.L Corrected to 3.00 percent by volume o

2, dry, and averaged over 15 consecutive minutes. 

r.1 0.084 pounds .No2 per MMBtu of heat input. 

siL 0.150 pounds No 2 per MMBtu of heat input. 

.u 0.036 pounds N02 per MMBtu of heat input. 

fL 0.052 pounds N0 2 per MMBtu of heat input. 

!JL 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. 

5 
We chose 30 ppmv as the uniform BARCT NOx emission limit for gas firing 

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

and process heaters. This un1form 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 unit~ 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. Methanol 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 (N0 2) form in the combustion process, and 

some NO oxidizes to N0 2 in the stack. 

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

quantify N0 1 emis.sions as ~arts per million (ppm) by volume, reladve to dry stack gases at 3 percent 02 • Alternately, we may quantify NO emissions as 

pounds of N0 7 per million ~ritish thermal unit (MMBtu) of fuel input to the 

process, based on the higher heating value (HHV) 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. 

6 
Chemically-bound nitrogen of 1000 ppm by weight in fuel oil 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 ~f f~el-nitrogen 

to NO. For higher fuel-nitrogen contents the percent convers1on 1s lower. 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. By 1994, distillate fuel oils with nitrogen contents below 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 NO. Due 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, will 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 theoretically 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 low-NOx- emitting 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. 

A. Low-NOx Burners 

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 low- NOx 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. 

7 
B. Flue Gas Recirculation 

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 EGR 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. 

C. Selective Noncatalytic Reduction 

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 gai at a point in the flue specifically selected to provide opti~um reactisn temperature and residence time. In the temperature range of 1600 F to 2200 F, the reaction occurs through the injection of NH alone. 

Hydrogen (H,) can also be injected along0with NH3 to extend the effectiveness 

range of the 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. 

D. Selective Catalytjc Reduction 

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

reduces NOx with NH 3 over a heterogeneous catalyst in the presence of oxygen (O,). The process Is termed selective because the reducing agent NH 

preferentially attacks NOx rather than o,. However, the 02 enhances3the 

reaction and is a necessary part of the reaction scheme. Thus, SCR is 

potentially applicable to flue gas under oxidizing conditions, greater than 

one percent 02. 

In theory a 1:1 stoichiometric molar ratio of NH 3 to NO is sufficient to 

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

NH 3:NO ratio of 1:1 has typically r~duced NOx emissions ~y 80 to 90 percent 

8 
with a residual NH 3 concentration of less than 20 PBmv. The0 optimum temperature range ror 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 $1600 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 

Low-NOx Burners 

Flue Gas Recirculation 

Selective Nonc~talytjc 

Reduct jon 

Selective Catalytic Reduct jon 

Annual 

Capacity 

Factor 

101: 

501: 

90t; 

lOt 

50~ 

90~ 

10%: 

50~ 

90~ 

10~ 

sox 

90~ 

9 

Unit Size NOx Emission Reduction 

Range Cost-Effectiveness Range (MMBtu/hr) (1986$ thousand/ton NOx) 

2.3 to 27 

3.5 to 150 0.5 to 6.4 

0.3 to 4.0 

6.8 to 29 

3.5 to 350 1.6 to 6.8 

1.0 to 3.7 

2.3 to 20 

50 to 375 1. 5 to 6.0 

1.3 to 3.8 

24 to 66 

50 to 350 6.0 to 14 

4.0 to 9.0 
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 reduc1ng 

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

passing through ammonia injection systems increases directly wi~h the amoun~ 

entering. Where applicable, low-NOx burners may be more effect1ve at reduc1ng 

emissions when firing with high-nitrogen fuel. 

Best available 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 tw1ce 

the cost. 

IV. IMPACTS 

A. Economic 

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. Ajr Quality 

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

emissions and resultant decrease in atmospheric ozone and PMlO formation. 

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

amn1onia leakage from storage and handling systems, which will result in 

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

formation of PMlO in the atmosphere. 

C. Hazards 

Amnlonia 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 

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

were developed to reduce the hazards that could occur when handling amn10nia. 

The spent catalyst materials from the use of SCR comn1only 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 would 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. Energy 

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

systems. All 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 
( l) 

(2) 

(3) 

(4) 

(5) 

REFERENCES 

Calvert, S., and Englund, H.M. Handbook 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." 

Delacy, J.M. Introduction to Coen Low NOx Burner Techniques, Revision 

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

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 

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

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

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

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 Amended Rule 1109, Emissions of Oxides of 

Nitrogen from Boilers and Process Heaters in Petroleum Refineries, 

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

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

"Attachment A." 

(8) Karaba, J.M., Pyronics, Inc. Combustion Handbook, 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. Boiler 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,N Unit 3.0, 

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

12 
(12) 

(13) 

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 Control Techniques." 

Office of Research and Development. Guidelines for Industrial Boiler 

Performance Improvement, EPA-600/8-77-00Ja, 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) O'Rourke, D. Petro America, Inc. Facsimile transmission and telephone 

conversation, July 1991. 

(15) Robertson, W.S. Boiler Efficiency and Safety, ESSO Petroleum Company, limited, The MacMillan Press, Ltd., london, 1981. P. 29, et seq., 

NCalculation 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 Industrial, 

Institutional, and Commercial Boilers, Steam Generators, and Process 

Heaters, South Coast Air Quality Management District, El 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 ll46.l: Emissions of Oxides 

of Nitrogen from Small Industrial, Institutional, and Commercial 

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

Management District, El 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," EPRIIEPA 1991 Joint Symposium on 

Stationary Combustion NOx Control. Electric Power Research Institute. 

Palo Alto.·California, March 1991. 

13 
APPENDIX A 

RACT/BARCT Determination 

A.l 
DETERMINATION OF REASONABLY AVAILABLE CONTROL TECHNOLOGY AND 

BEST AVAILABLE RETROFIT CONTROL TECHNOLOGY 

FOR INDUSTRIAL. INSTITUTIONAL. AND COMMERCIAl BOILERS, 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 corrrnercial 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 in 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 THERMAL UNIT (Btu) means the amount of heat0 requireg to raise the temperature of one pound of water from 59 F to 60 F at 

one atmosphere. 

E. HEAT INPUT means the chemical heat released due to fuel combustion in a uoit, using the higher heating value of the fuel. This does 

not include the sensible heat of incoming combustion air. 

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

G. HIGHER HEATING VALUE {HHV) means the total heat liberated per 

mass of fuel burned (Stu 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 D 3588-89 for gaseous 

fuels. 

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

dioxide in the flue gas. 

I. NONGASEOUS 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°F and one atmosphere. 

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

P. THREE PREVIOUS CALENDAR YEARS means the three consecutive years 

immediately preceding the year in which final compliance is 

required by this determination, or the three consecutive years 

immediately 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 than 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. 

8. 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 (O,) concentrations at less than or equal to 3.00 percent by volume 

on a dry basis; or 

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

3.00 percent by volume oxygen (01 ). The tolerance of the setting shall be plus or minus fTve (z 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 

Pollution 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 sp~cified in Subsection III A. 

{FOR BARCT) 

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

3) 

40 parts per million by volume, or 0.052 pound per million Btu of heat input, when operated on nongaseous fuel, or 

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) 

2) 

be operated in a manner that maintains stack-gas oxygen concentrations at less than or equal to 3.00 percent by volume 

on a dry basis; or 

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 Pollution 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. 

IV. 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. 

V. Compliance Requirements 

A. Compliance 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 following: 

A.5 
(a) 

(b) 

(c) 

A list of all units with their rated heat inputs and 

anticipated annual heat inputs. 

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. 

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) Within four years from the date of adoption of this 

determination, demonstrate final compliance with all 

applicable standards and requirements of the determination. 

B. Compliance Determjnatjon 

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

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

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

in Subsection III A. 

2) All 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 shall 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) All ppmv emission 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]corrected 20.95~ - 3.00~ • ~ [ppm NOx]measured 20.95% - [~ 02]measured 

[ppm CO]corrected 20.95~ - 3.00~ ~ [ppm CO]measured ~ 

20.95% - [% 02]measured 

4} All pounds-per-million-Btu emission rates shall be calculated 

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

A.6 
5) 

6) 

(7) 

(8) 

(9) 

(10) 

All 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. 

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 

Integrated sampling methods for oxides 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. 

All 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. 

A violation of the plan required under Subsection VA (1) shall constitute a violation of this determination. 

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. Administrative Regujrements 

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

this determination shall monitor and record for each unit the HH~ 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. Historical 

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 complying 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. Egujpment Regujrements 

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 allow 

instantaneous monitoring of the operational characteristics of 

the NOx reduction equipment. 

A.B 
Attachment 1 

Tuning Procedure lL 

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, I~dustrial 

Risk Insurers, National Fire Prevention Association, the Californ1a 

Department of Industrial Relations (Occupational Safety and Health 

Division), the Federal Occupational Safety and Health Administration, or 

other relevant regulations and requirements. 

1. 

2. 

3. 

4. 

1/ 

Z.l 

'J./ 

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 conz1ntration, 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 the11 stack gas is at the lower end of the range of typ1cal minimum values , and if CO emissions are low and there is no smoke, the unit is probably operating at near optimum efficiency - at this particular firing rate. 

However, complete the remaining portion of this procedure to determine 

whether still lower oxygen levels are practical. 

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. 

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. 

This tuning procedure is based on a tune-up procedure developed by KVB, Inc. for the EPA. This procedure is included as Attachment 2 to this 

determination. 

The smoke-spot number can be determined with ASTM test method D-2156 or 

with the Bacharach method. ASTM test method 0-2156 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. Typical minimum oxygen levels for boilers at high firing rates are: 

1. For natural gas: 0.5 - 3% 

2. For liquid fuels: 2- 4X 

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

limits is reached: 

6. 

7. 

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. 

Develop an 0?/CO curve (for gaseous fuels) or 02/smoke curve (for liquid fuels) similar to those shown in Figures 1 and z using the excess oxygen 

and CO or smoke-spot number data obtained at each combustion air flow 

setting. 

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: 

Elll Measurement ~ 

Gaseous CO Emissions 400 ppm 

#1 and #2 0 i 1 s smoke-spot number number 1 

#4 0; 1 smoke-spot number number 2 

#5 0 i 1 smoke-spot number number 3 

Other oils smoke-spot number number 4 

The above conditions are referred to as the CO or smoke thresholds, or 

as the minimum excess oxygen levels. 

Compare this minimum value of excess oxygen to the expected value 

provided by the combustion unit manufacturer. If the minimum level 

found is substantially higher than the value provided by the combustion 

unit manufacturer, burner adjustments can probably be made to improve 

fuel and air mix, thereby allowing operations with less air. 

A.lO 
4/89 

tl 

" 

Figure l 

Oxygen/CO Characteristic Curve 

GratJual C0/02 

cnaractensr1c 

I Sreeo COI0 7 cnaract•r,~oc 

Aooroorra/11 oa.rarmg 

margm trom mm1mum 02 

I Auromartc controls 

"" COiimtr i I ~OOo\mldO/USlea tO tf'tiS 

O?ltlvPI 

I 

~~ 

Oxygen 1n flue gas. "c 

Figure 2 

Oxygen/Smoke Characteristic Curve 

\ 

Sraao sma1r111 o2 crtar•crer~srtc 

t GratJua/ 

smo1<e107 cnaractttrlslrc Aooroorrat~ ooer•flnC) 

~ ~ \ margm rrom mm1mum 07 1 hr--Auromauc oo•let 

"'

=~Eg_. Sm-ol<e\llm-11 - controls aa1

usre<J - /0 /filS 02 IIIVIII 

---------

1 I 

Mm•mum 0 2 _.-I 

Oxygen '" flue gas. • .• 

A'M'ACHHEN'r 1 Rule 74.15: 8 

APPENDIX F 

Significant Comments and Responses 

F.l 
Kern Oil & Refining Company (5/31/91) 

Conrnent 1. 

MThe proposed BAR[CT] limits of 30 ppm NOxon 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. •sest Available 

Retrofit Control Technology" means 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. 

Comment 2. 

MThe 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.M 

Response: 

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 emitting 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. 

Comment 3. 

·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." 

Response: 

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 ~xceed 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 million by volume (ppmv), corrected to 3 percent o~ygen (02), relative to dry stack gases, when firing residual fuel 

011. 

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

Comment 4. 

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. 

Response: 

In our drafting of the proposed determination, we included a prov1s1on 

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 (7/10/91) 

Comment 5. 

NARB 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.'" 

Response: 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 all 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. 

Comment 6. 

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

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

[the SCAQMD ~nd Ventura County] districts will 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 
Response: 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. 

Comment 7. 

•rhis 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." 

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

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

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

Comment B. 

"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. ~ 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? 

Response: 

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 will allow adequate residence time 

within the reaction temperature window. 

Comment 9. 

"There is no basis for the 40 ppm limit for units burning non-gaseous fuel (Page 3). No information is provided on the source of this limit 

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

applicable?" 

Response: 

Information has been added to the report regarding the use of methanol 

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

F.6 
Comment 10. 

"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." 

Resoonse: 

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. 

Comment 11. 

"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." 

Response: 

Low-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. 

Comment 12. 

·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." 

Response; 

We do not believe that the report is misleading. 

Comment 13. 

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

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

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

1 imit in the BARCT sect ion 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 exemption to the RACT standard, also. 

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

Conrnent 14. 

"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?" 

Response: 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. 

Comment 15. 

"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 curtailment." 

Response: 

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 PMIO. In Ventura County there is a strong daily correlation between no~ exceeding the 0.07 ppm 1-hour ambient ozone and not exceeding 50 ~g/m 24-hour PM10. 

Conxnent 16. 

"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." 

Response: 

The intent of the exemption of 150 ppmv NOx for firing a nongaseous back-up fuel is to allow 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 oil; however, the range is 1000 to 8000 ppm by 

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

firing has been met with staged combustion without flue gas 

recirculation. 

Corrrnent 17. 

Mif 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?" 

Response: The BARCT standard for oil firing is cost-effective with flue 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 methanol or ~specially blendedM oil. 

Comment 18. 

•suyers 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." 

Response: 

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

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

Conxnent 19. 

•rhe 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?p 

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.lO 
Comment 20. 

•rhe 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, in 

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

burner replacement (135 MMBtu/hr boiler)." 

Response: 

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.ll 
t 

E 

Q. 

" 

" 

01 "' 

• 

g 

E 

.. 

"' .. 

0 

c 

0 

E 

c 

0 

.0 

; 

u 

t 

Figure l 

Oxygen/CO Characteristic Curve 

Gractvel C0!02 

ch•racrenst1c 

SIHIIC0/0, 

cllaracr.nttiC 

Appropfl/lte ooeratrng 

margrn from mm,rnum O, 

I 

Oxygen '" Uue gas. "1. 

Figure 2 

Oxygen/Smoke Characteristic Curve 

Staal) 3moka/02 

charactart31ic 

Gradual 

smou102 

cnera.;l.,rtriiC 

Smok.,ltmtl -'--

"'"'""""'~ 

Approprtale OP<Jr•ltng 

rnargm trorn rnm1murn 02 

.AvrorneiiC bo1lar 

controls 1d1ustad 

to rrus 0, laval 

O•ygan on flue gas. "1. -----~--

Source: 

A. 11 

KVB Inc. 
8. Add 0.5 to 2.0 percent to the m1n1mum excess oxygen level found in Step 7 and reset burner controls to operate automatically at this higher stack gas oxygen level. This margin above the minimum oxygen level 

accounts for fuel variations, variations in atmospheric conditions, load 

changes, and nonrepeatability or play in automatic controls. 

9. If the load of the combustion unit varies significantly during normal 

operation, repeat Steps 1-8 for firing rates that represent the upper and lower limits of the range of the load. Because control adjustments at one firing rate may affect conditions at other firing rates, it may not be possible to establish the optimum excess oxygen level at all 

firing rates. If this is the case, choose the burner control settings that give best performance over the range of firing rates. If one 

firing rate predominates, 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 
7UNING iNDUSiRIAL BCILERS- ~I 

Attachment 2 

Establish excess-air levels 

Use tl'le test program outlined below to rdent1fy the minimum amount of excess oxygen 

reauired tor combustion of gaseous. liqwd. and solid fuels in industrial boilers 

By DE Shore and M W McElroy, KVB Inc 

Once '0ur boiler t> in gov<i working 

t:raer 1 '~e P~rt I vi this sencs. April 

19;7). the next maJor step 1n 1mprov1ng 

"mcienC\ ::~nd in reduc1n2 em1ss1ons. 1s 

'.v cstao1tsh the iuwest level of excess 

·J~vgen at wh1ch the unll ~.ln operate 

:·:.lt.elv Jnc sull meet the clean·a1r laws. 

Since ~ost industrial boilers operate 

.wer a re~sonably broad load range. tests 

e1ust be run at several tinng rates to 

..:ctermtne the m1n1mum excess·o,ygen 

'..:\'Ci fur e::~cn. Only then can the 

~ombusuon-control system be tuned for 

voumum fuel economy. 

.-\ t each lirin2 rate inveslll!ated. excess 

v.\ ygen 1 n the rtue gas shou-ld be vaned 

from 1-2'1. above the normal operating 

point. down to where the boiler just 

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

emtssions e.,ceed 400 ppm. This latter 

.:ondit ion is referred to as the smoke or 

CO thresnoic!. or >Imply as the nummum-

·J.I:I'g"l'n f'O/ni. The smoke threshold generJiil apt'nes to coal and oil tiring. because 

-.moktng U>Uaii,· occur' bclorc CO ~m1sstons reach st~ntricanl lcl'els. The (0 

threshold pcn;tns to gaseous fuels. 

The smoke threshold for soltd and 

liqutd fuels reuresems the lowest oosstble 

~~cess-oxygen :e,·ei at whtch acceptable 

stack .:onatttons sull can be matntamed. 

In terms of the Bacharach smoke-spot 

number 1 SS'- \ scale. the max1mum 

desirable smoke number for coai ts 4 

1 measured d.:J"' nstream or· the oust 

~ollectorl. Fur '-.:l o ( resHiual\ oti. 11 

~iso ts 4: :-..o 5 Jna low-sulfur restd. a 

SSN of J: ;>;o. 4. aSSN of 2. and No. 2. 

a SSN of less than I. 

A proven method for determining the 

minimum amount of excess o~ygen 

required for combusuon involves developing so-called o~ygen1CO and oxygen/smoke characteristic curves, like 

those shown tn Figs 5 and 6. Based on 

test measurements. these curves show 

how boiler smJI.e and CO levels change 

as e~cess o" gcn is varted. 

Each of the figures deptcts two 

Jistinct curi'C>. rllu>traung the e\treme> 

tn smoke and CO bcha\·tor that rna~ be 

encountered. One curve e~hibits a verv 

gradual increase tn CO or smoke as the 

mtnimum excess-oHgen condltton 1s 

reached. The other has a gradual slope at 

relatively high o~~·gen levels. and a steep 

slope near the mmimum·o~ygen potnt. 

For cases represenw:i by this second 

curve. unpredictablv high levels of smoice 

ur CO. or potenuall\ unstable condt· 

tions. can occur ~'lin small changes 1n atr 

Row. 

Thus. caution is requtred on your part 

when reducing atr now near the smoke 

or CO threshold- that 1s. careiully 

monnor instruments and controls, flame 

appearance. and stack conditions simultaneously. Decrease the level of excess 

oxygen in very small increments until 

there arc enough data to show whether 

the boiler exhibits a gradual or steeo 

~haracteristic curve. 'ote. too. that I'C'tH 

boiler may e~hibll a gradual character· 

istic at one tiring r~te and a steep one at 

another. 

Adjusting boiler controls for low-excess oxygen -a step-by-step procedure 

~ . .Establilh til• d••ir.cj firing rata and sw1tch comoustton 

controls trom automatic to manual operation. Make sure tJJI salery 

;nttJriOCK$ are Still tuncuonmg. 

~. Rec:ora boiler 1nd at1ck d1t1 (pressures. temoeratures. e1c1. 

.;no ocserve flame concttlorTS atter botler operation stao,hzes at 

':-le parucu:ar tmng rate selected. If you find that the amO<Jnt ot 

~~cess oxvgen ln the flue gas IS at the tower ena of the ra09e ot 

··.o1c8I m.nomum vaoves tsee textJ, and if CO 8•10 smoke are at 

·=ce:na::te 1evels. the bo!ler orooably IS already operating at near 

~:Jt1mu~ .;mctencv- ar rms ()artiCUlar lirmg rate. It may Still t>e 

-'"s~rac•e. ~ow::wer. t:: comotete tne rematmng por11on cl trl1s 

=rocecur~. to oeterm•ne whether Stilt tower teve1s are practical A 

'1oro o· :aut1on: Oo not assume that excess-oxvgen senonQs at 

:ner rr·•nc rates atso are erose to the opttmum. 

~- tncraase atr flow to the rurn1ce until reaomgs or o:-tcess 

. 'V'le,.. a! tne stac~ or.crease ov 1·2"/o. Agam. oe sure t" :a•e 

~aomgs aner oo:ter ooerat1on stao111zes. ana note any cr.anc~s 1n 

' Jme condiiions. 

:. R•turn air flow to the normal level ana t:>eg1n SIOWiv to 

· :ouce •: further. In small tncrements. Watch 1he stack tor any 

.. ans c• smoKe. ano constanuv ocserve the ftame. Recora sracK 

•ce~s-o<vgen reacmg. smoKe-soot number. the concentrat•?~ o~ 

:::J :r "..:e oas. ana stacl< temoerature fotlowtng eacn chanoe 

"·;·r-erroer not rc recuce a,; o:ow oy tnrotlllng the curr.er a" 

regt51ers. because this alters the fuel and aJr moxtng characten$-

tiCS and comptlcatea tne tests. ~. If you n.m tests at tow nring 

rates. whiCh is not generally recommended lsee step 9), keeo a 

~lose watch on the wtndboXJturnace pressure dillerential. If it 

crops too low. a fuel trip wtlt ba initiated by tne ourner sateguaros 

system. 

S. Continue to r•duce air flow at•pwne until you reacn one of 

:nese limits: 

• Unacceotacle flame condittons-sucn as name 1mprngement 

on lurnace walls or ourner pans. excess1ve name carryover. or 

t:ame 1nsta01hty. 

• H•gll level of CO in the flue gas. 

• SmoMong at tile stack. Do not contuse smoKe woth water 

.aoor. sulfur. or dust plumes. wh•cn usually are w1111e or gray m 

c.ooearance. ano rememoer to obs.!rve 1~:a1 alf·t:ollutton cral· 

rances. 

• IncomPlete ourntng 01 solid fuelS. F.-ecoQn1ze tn1s bv nu;n 

caroon carryover '" cust collectors or oncreasea auant1toes 01 

~omoustoCies on the asn. 

• Equipment-related limitations-sucn as 1ow wmaboxtturnace 

~ressure dotlerenuat. cuut-tn asr-flow limns. e!c . 

o. Develop O,iamoke or O,ICO cherectertetic: curvea. s•m•tar 

:o tnose snown 1n F'igs 4 anCl 5. using tM excess oxygen ana CO 

:· ~moK~soot numoer oata ootaineo at eacn alf·ltow setllng. 

A. 13 
A a.ip llljllj •• •xJiell ra4illa may 

indicate a burner malfunction or other 

fuel- or cqu1pment-related problems. But 

realize that different burner designs and 

fuels generally have different minimumoll:ygen requirements. In addition, many 

burners e~hibit a higher minimumoJtygen level at low firing rates than they 

do at high firing rates. For these reasons. 

11 is difficult to specify a range of 

minimum levels that would be considered normal for all boilers. 

Results of tests at many industrial 

power plants arc provided, however, to 

help you judge whether the minimumoJtygen levels you measure are typical 

values. The data: For natural gas, the 

typical range of minimum eltcess oxygen 

at high firing rates is 0.5-3%; for liquid 

fuels. 2-4%: for pulverized coal, 3-6%; 

and for stoker-fired coal. 4-8%. 

Boiler startup records showing initial 

eliCCSS-<Illygen conditions provide a valuable reference point for your tuneup 

program. If current minimum·Oltygen 

levels arc higher than expected, any 

necessary maintenance or repairs should 

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

Once the minimum-<~llygen setting is 

established. the next step is to determine 

the appropriate operating margin above 

minimum o"ygen where the boiler can be 

operated routinely. This lowest practical 

ollygen level for the boiler offers the: 

optimum setting for high efficiency and, 

in most cases. the lowest NO. emissions. 

The excess-ox}gen margin above the 

minimum-oxygen point accommodates: 

• Rap1d boiler modulation. which 

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

• Nonrepeatability or play in automatic controls 1 E 'cess1ve play should be 

corrected.) 

• Normal vanauons in atmosphenc 

conditions. which also can change the 

level of excess o'ygen on umts not 

equipped wtth temperature- and pressure-compensated combustion-air 

systems. Th1s b an 1mportant factor. 

which often is nc2lected. Extreme variations in ambienr" conditions can easily 

produce changes in excess oxygen of I% 

or more. 

• Changes in fuel properties, which 

may require varying amounts of excess 

air at the burner 

Typical marg1ns above minimum oxygen may range from 0.5% to 2%, 

depending on the characteristics of the 

particular boiler....::ontrol system and the 

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

combustion consultant probably can 

establish a narrov•er range for your unit. 

Another point: If the boiler is to be 

operated at a constant firing rate for 

extended periods. the smallest possible 

margin should be selected. 

Re<:ognizi111 excessive play. A simple 

test can help you determine if there is 

eJtcessivc play (poor repeatability) in 

your combustion-control system. All you 

have to do is to repeat a firing-rate 

condition. allowing fuel and air controls 

to function in a normal manner. 

Approach the selected firing rate from 

both higher anri lo~er firing. rates. and 

compare stack e"ess-ol(ygen levels recorded after each run. Make" sure boiler 

operation stab1hzes before taking read-

.. ~Unge~Menn cMrt orr.-. • qulc:tc way 

to determine If boiler emiSIIon8 rn.t 

codes. Baenerach scale. more accurate, Is 

better for burner adjustments 

ings. E.11cess-oxygcn data should repeat 

to within a few tenths of a percent; a 

greater difference indicates excessive 

wear or tolerance problems in air dampers. ·control shafts. valve cams, controllers, etc (Fig 7). 

Atmospheric Yariatioas. Changes in air 

density at the forced-draft-fan inlet 

cannot be corrected like control-system 

play. Recognize that. ~~o·hile the f-d fan 

delivers a certain •olumc of air to the 

burner. as the air density changes. the 

number of pounds of air supplied to the 

7. AM the llllnlmuln ex~ level tor your boiler from 

the curYeS ~ 1n ltep a. bu1 do not adjuSt the burner 

controls to this value. Though this may be the point of maximum 

etftciency, as well a minimal NO, emialoM, It usually Is tmprw:.. 

tical to operate the boiler at this Mttlng. because of the tendency 

to smoke. or to increase CO to dangerously high levels. as load 

changes. 

approaCh, one llwoiYing repMa.d tllllta, ITIIIY be ....ury. But If 

one firing rate predomlnat-. Mttlngs llhould opllrl'a oondtuona 

at that tate. 

Compare this minimum 9alue of excess oxygen to the expected 

value provided by the boiler manufacturer. It the r.1lnlmum level 

you found Is substantially hlghet- than tile vendor's, burner adjustments probabty can Improve fuel and air mixing, thereby allowing 

operation with less air. 

a. Eatabliah the margin, In excess oxygen above the minimum 

value. requ1red for fuel variations, load changes. and atmospheroc 

conditions. Add this to the minimum value and reset burner 

controls to operate automatically at the higher level-the lowest 

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

emissions lyplcalty will be lower at the new setting than they were 

oriqinalty. 11 they are higher, however. try to reduce them by 

adjusting tr>e burner. 

8. Aapnt ata~ 1 .. lor HCh tiring rate to be t .. tad. Bear 1n 

mind that. for some control systems. It Is not possible to establish 

the optimum excess-oxygen level at each firing rate. Reason: 

Contr()j ad,ustments at o~ firing rate also may affect conditions 

at other tiring ratM. In such cases, choose the settings that g•ve 

be$t performance over a range of firing rates. A trial-and-error 

Many experts agree that It generally Ill 11e.t not to mae any 

adJustments to your contrOl system while the bolter Ia operating at 

low loads. Air-flow requirements at low·flre COt'ldltlons usually are 

dictated by name Ignition characteristics and stability (and they 

can be critical and dl1flcult to evaluate) rather than by etftclency. If 

procesa requirements ron:e your boiler to operata at low ~a 

rrNc:h of the ttme, check w1tt1 the boiler manufacturer"l aervlca 

group or a qualified combustion consultant before lltabllshing 

excess-oxygen levels. 

10. Verify that y0t1r new MHint• can accommodlte the 

sudden load changes that may occur in daily operation without 

adverse affects. Do this by Increasing and decreasing load rapidly 

while observing the flame and stack. If you detect undesirable 

conditions. reset the combustion controls to provide a slightly 

higher leYel of excess oxygen at the affected firing rates. Next. 

verify these new settings In a similar fashion. Then malla sure that 

the final control settings are recorded at stead~-state operating 

conditions lor future reference. 

0~ final note: When an alternative fuel is bumac:l, perform 

these same tests and adjustments for the 5eCOnd fuel. Since it is 

not always possible to achieve optimum excess-oxygen ~s for 

both fuels at all firing rates, you m~nt establiSh the bast conditions 

at normal firing rates. 

A .14 . ' 
' -----

\.f1mmum C: /. 

.. .,,,-e. r: 

._·orocr,a~e ::-::·.-tJ•"'~": 

-d.'~1n ~rQ<TJ ~·,"nl;ffl Co? 

' 

"---

...;"-~rom.arrc ~o·1er 

:.,.-,;~0,> JC .... s.'ec 

1 

\ 

\ 

.. : :. [ 

r -··: " 

S,e. Oxygen/CO •nd OJrYgen/•moke en•rec:t•n•tic curve• tden11ty the m1ntmum amount of excess oxygen reQuired lor comous11on 

burner varies. influencmg the amount of 

excess O)(ygen. When .;ombustton a1r 1s 

>upplied from the boiler room. mamtainmg a constant boiler-room temperature mmimizes the oroblcm. but atmosoheric-pressure effects are unavoidable. 

Evaluating new Mttinga 

After the boiler has been tuned and 

returned to normal automatic firing. pay 

close attention to the unu for a few 

weeks. until confidence is gained in the 

new operating mode. Watch for any 

signs of unusual tube fouling or flame 

patterns. which might be corrected by 

further burner adjustments. Also. look 

for any equzpment or operating changes 

that may alter the minimum·o)(ygen 

I eve!- such as variations in fuel properties. inadvertent chan~cs in burner 

>ettings. new bo1ler·co~trol setpolnts. 

air-control-damper deterioratiOn. and 

air-preheater pluggagc. Assure conunuous high efficiency and low NO, emts· 

>tons on a continuous basis by planing 

periodic stack measurements (excess 

oxygen. CO . .smoite. temperature) on 

graph paper. and comparing these trends 

to the baseline data obtamea during the 

boiler-test program. 

Burner adjustments 

.-\s noted earlier. adJUStments to the 

.:ontrol svstem alone sometimes cannot 

1mprove efficiency and1or reduce pollutant emissions to desirable levels. In such 

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

Often. you can achieve: your operating 

goals by making changes m: 

• Burner air-register settings (on 

swirl- or circular-type burners). 

• Oil-burner tip position with respect 

to the burner throat. 

e Oil-gun diffuser position with respect to the burner up J.nd· burner 

throat. 

• Fuel-oil temperature 

• Fuel-oil atomizmg pre.ssure. 

• Coal-spreader pos1110n. 

• Cual stze. 

The effects of such ad iustments on 

:-.10. formatiOn and on m1n;mum e:>~cessvxygcn levels vary irom un1t to \)nil. and 

are difficult to preaict. Thereiore. you 

should usc a trial-and-error procedure 

7. E.IC .. IiYe pi•Y 

on posiUonmg 

comoust1on 

comrols can be 

10en11fled by 

mar~•ng linkage 

posruon lor a 

partiCular liri119 

rate anCl tllen 

aooroacnmg tnat 

rate from Oath 

h1gher anCl lower 

firing rates. 

Lmkage position 

ror tne two test 

runs snouiCl matcn 

tne ongmal setttng 

A.ls 

when making changes. But b.: sure your 

program is sufficiently orpmzcri to 

assure adequate stack and flame monttorine. Observe the general pretauuons 

g1ven- for the excess·o~ygen ad1ustments 

1 see box t. Such modificauon1 to the 

ririn~ svstem are best facwrco 1nto the 

exceSs-oxygen adjustment tests tstep 7 in 

boxl. This insures that changes are 

completed before the final controlsvstem adjustments arc made. 

· Also. aiter adjusting the burner, make 

a complete set of stack. measurements to 

determine whether the change is producing the desired effects. Finally. make all 

burner adjustments slowly. to allow 

adeQuate time to evaluate each move. 

Look for any other changes •n burner 

settings or fuel properties that n-.1ght also 

affect the flow of air or fuel to tile boiler 

~nd produce uncontrolled sh1fts 1n the 

~xcess-oxygcn level. 

The r:~nge of adjustment oos.sible ior 

the parameters listed above deoends on 

the design of the burner or stoKer and 1ts 

par!lcular operating charactcmt1Cs. E~­

ample: It may be possible to var' the airregister settings on one boiler !rom 50'1-

to 80% of full open. while or another 

unit lillie or no adjustment ,; ~~acucol. 

For the latter. further openmg c:· the a1r 

register I reductng an Swirl I :::a:- cause 

flame mstability. while by cios1ng off the 

01r regtster 1 more sw1rl1 ~ou rr ~' "'1den 

the llame. ~JUSinf!: tlJme ~~t:-:ngement 

un the burner throat or furr."cc l!dewali>. Read the boiler operat~ng manual 

ior 1nforma11on on \OUr hr:~f ~quipment. 

\ n important r"actor '" ·:-~tatn1ng 

complete combustion of fuel c:: al low 

~xccss-o~ysen levels is .a ma1~t;11n the 

proper atomtzing temperature. This IS 

dictated b~ the fuel \·1scom~ recommended by the burner manufacturer. 

Typical v1scosny ranges fo~ ,·arious 

liquid fuels and burner types arc g1vcn m 

Fig !S. For stoker firing. coal SIZe 1 Fig 9) 

is imoort:mt. RGS 
Attachment 3 

~~ o..l9natton: D 2158- 80 

Standard Test Method for 

SMOKE DENSITY IN FLUE GASES FROM BURNING 

DISTILLO. TE FUELS' 

Tl'u~ JUnll.Jrd 15 l:l.lUC'd ~o~ooer tht li .. ed c.JtslJniiUOn 0: l ~t'l. 1h(' l1umN'r ·mm~lal('l\ roJJov.1n' lh(' o,ksa,.n~IIOn lnd.catn thr "'tar,. ontvna! 

~ r.Ut'l('f'!oC"n01 

~oouon 

~1lon 

or.'" lht ca.s.t ul rtv1S10n. th~ ~r of Wt I'T"''~on " "umt"'t't '" parr nth~ tndiC"~tn th(' vur ol last rea~ 1111nd1CJto .Jn cdlton.aJ cl'l~niC Sin~ the." J.Ut rt"lS.Ion ~r rtlPtJfO\-ll 

I. &o~ 

I I Th1s method ~0\'cT' the evaluauon of 

>moke densuv m the 11ue ea>e~ from bumme 

dJsllllale fuels. It IS intende-d primanly for us~ 

wuh home heating egu1pment bummg kerosene 

or hcatlnl! Oil~. h rna\· be used m the laboratorY 

or In lhe iield to compare fuels for clean bum· 

mg ur ,,, .:,>mpare healm~ eyu1pment 

2. Applicable Document 

2.1 .4Snf SJandard: 

E Q7 Test Method for 45-". o.· DirectiOnal 

RdkL'tJnn· FJclOr of Opaque Spt"nm~ns fl' 

Broad Band Filt.:r Refl.:<'lllmctrv' 

3. Summary of Method 

3.1 A test smoke spot is obtamed by pulling 

a fued ~olume of flue gas through a fued area 

of standard filter paper. The color (or shade! 

of the spot thus produced tS vtsually matched 

wtth a standard scale. and the smoke dcnsny IS 

e~pres.sed as a "Smoke Spot Number:· 

.a. Significance 

4 I Th1s method provtde~ a means of ~:on· 

trolling smoke producuon m home hc:aung 

equtpmcnt to an at.:..:c:ptabk lev·el. Exces't'e 

smoke dcn,itv advc:rselv affects cffkJc:ncv b' 

hc:at-e"hane~r fouhne · · · 

4.2 The range of sni'oke densmes cov·crc:d by 

tht' method ts that llihJch h<1' been found parucularl~ perttnc:ntto home-heaung applicauon. 

It L< more 'ens•uve t•' ,fTlall amnunts of smtlk.e 

than >C:>c:ral other ,m,•lc tc'b J' mJKatc<.i m 

the: folluw1ng comp<~rt>un: 

Sm",l.e Sro-.,t lchlm. pcr~.cnl R•n@elm&n 

"umbtr Tr41nsm1U10n SmCI&< Sumt>t, 

IIIII I) 

,, 

"' 

~.a 

I~ I) 

... Q 10 ~ 

5. Oe!>~:riprion ofT "rm~ 

5.1 The test result is reponed as the "Smob 

Spot Number." which IS the number of the 5p01 

on the standard SQlc: most closely matchinr; the 

color lor shade) of the rest spot. 

b. Appanuu, 

o.l Samplm{! Dnrcc- .>.,SUitable dt\'ICe pre>-

\ldmg a total flue: ga' ,ample: volume of 36 9«• 

:!: 1650 em' at I6°C 1 atm !2250:: 100 in.' at 

t>O<f. I aim) for each b.4~ em' 1 I m .. ') etTectrv·e 

sur1ace area of filter paper shall be employed 

The sampling dcvtee and connections shall bt 

of such construction that the total travel of nue 

gas sample from flue to filter paper shall .DOl 

cx~cd 410 mm 1 16 m 1. The dev1ce shall pro-

··•de for coohng the sample below the charrin! 

temperature for the filler paper but not belo·•• 

the dev. pomt of the sample. Suitable laboratory and ponable field servJcc cguipmc:nt 15 

tllu5tratc:d 1n Fig~. I and 2 

~: Smo~e SnJ/1'- Th.: 'make '..:ale re<JUirc:d 

r ht., ml"~hud r .. undt·r Hh· tun~.hnu~n ot -'"I M c,,mmmtr !).: .~n P:otrOI<"um PTt'odu.,:l" J~d Luhn\::.&nh 

r urtrnt c:dtttnn Jf'lfUm~t.l \y~ .:~ I ~"0 Pul"ll-.nrtJ 1.ln~ 

• , .. j' t lr,~;r..Jil\ r'U~h .. n~·lJ .. , n :. ,...,... -,., l I 1 ""''' C'lft'\ •••U'\ ec:· : • r j) ; •• . '• • ' "". ~ ' 

~""loloo.t· tJ..... I' I \I )IJIIo.~~.J'iJ' "tll ~~ o: 

A .16 
constsU of ten ~pots numbered consecutively 

from L) to 9. rangtng m e~ual photometnc steps 

from whue throul!h neutral shades <lf gray to 

t>lack. tmpnnted-or clthe,....-t~e processed on 

while paper or plasuc swd ha' mg a surface 

reflectance of bet~ .. een ~: ~ Jnd ~- 5 .-, 45•. 0° 

Javhght lumtnou~ dtre.:uunal ret1ectance mac· 

co~ance wnh Method E 9~ The smoke scale 

spot number tS defined a> the reducuon tdue to 

~mokc) Ill renected tnctdcnt hght divtded by 

10. Thu.s. the first 'f"'L v. hh:h rs the color of 

the ummprmted scale. "'Ill he ~l'. tl. smce m 

the case of thts spot there "'til be no reductiOn 

m reflected tnctdcnt hght dtrectcd thereon. The 

last spm. howe,·er. ts ,-cry d.uk. reflecnng on I: 

10 <;- pf the inctdent lti!:ht drrected thereon: thus 

tn thts case the rcducitC\n m r.:tlc,ted tnctdent 

lil!ht t> 90 .:-;_ ~~ohtch 21\C~ h:> tht~ darkest spot 

thl" "J,, <.1 lnterm,·dtJ·t~ •r'•'' ~-~mt-cr., ~rc 'trntlarlv e.stabhshed Ltmn' .ul permtsstblc reflectance vanauon of an,· smoke scale spot shall 

not exceed ::1:3 c; retail\c reflectance rNotes I 

and 2). 

Non I- Such ,m.,~c ~~I<· ••c •utft.:tenth ac·· 

.:Untie for field u~ and fur m4n\ laboratory smoke 

tCSIIIIS applicauons. However. spec.aJiy t..ahbrated 

JC&Ja (known a.s ccn•ficd •mokc .scalcsl wlll sometimes be required. A ccnlficd smoke scale iJ obuincd 

bv indivtduallv cahbraun~ each smoke spot of a normal 'mokr .'Cilc 

Non :_- Wherr ltlt' 'molt 't4. .. dc 1" rnuca.:ted -.-.·nh 

a pl~~lll.' rH 1un~ro:~rc:n1 CPH'r the ~,·tm,truclhm ~m~ 

rl<>\cd \hJII tlC _,uLn :hat" h<r. th< >moke 'l'<'l•>n lht 

tilter p•per IS Y~ewed fur m~h:htng wnh !he num~r 

spou on 1he smoke 'C~Ie. b<>th 'hall be VISible lhrough 

the same thtdness Jnd numt>cr of sheets of •ransparcnt prot(CtJve co-ver 

7. "htcrials 

7. I Tes1 Filler Pap~r. made from white filler 

paper stock havmg a _;urface rellectance of 82.5 

Ill M7.5 r; 45°.0° da\lt2hl lumtnnu~ dtrccuonal 

reflectance. tn accord-;nce 11o11h the Method 

E 97. When clean atr .:u standard cond111ons " 

draw·n lhrough dean !liter paper at a rate of 

47.6 cm'h-cm: 111::~ m. mm-rn'l cn·.:~tl\c: 

surface area uf liltcr paper. the: prc."ure drc•r 

acros> the filter paper \hould f;~ll bet.,.,een hmth 

of 13 and 64 mm 10.5 and :!.5 tn.l Hg. 

0 2156 

8. Proc:edur~ 

1!.1 The samphn~ pr,"IC!'dure U3Cd ts .:nucal 

Therefore. the procedure recommended hy the 

equipment manufacturer 'hall he ngtdh illl· 

lowed. 

~.:! lJ3C a clean. dn. wmphng dt::\lcc If .1 

hand sampler ts used . ....-arm 11 abo"e r<>Om 

temperature to prevent ~ondensa110n on the 

filter paper. 1Th1s m.:~v usual!~ be done conveniently hy placmg the ~mpler on the h,•tlc:r or 

furnace to be tested. l 

X.J Insert filtc:r paper m : h~ ~<~mrlcr JnJ 

lighten the tiller paper holder. C onncct the 

sampling devtce 10 the Oue ga~ probe When 

tal(ln!! smoke measurements '" the flue· p1p~. 

p<>~lli:,n !he end ,,f the: 'Jmrttn~ rr.•hc at the 

..:enter line of the tlue ptpc 

X.4 Draw the requtrccJ >Jmple If ~ hand 

>ampler I' U'Cd. rc:rmll ~h.· pre,,urc' In tile llul' 

gas stream and the sampier to equahze after 

each stroke. 

lU Remove the filter paper. Compare the 

test srot backed with ol ptece of v.·hite paper or 

plasuc having 4~"- o·' dJ~hght lummou> dire:<.:· 

tiona! reflectance of not Jess than 75 '(. wuh 

the standard scale. 

9. Report 

9.1 Report the >moke den>u' J> the: Sm0~e 

Spot Number C\n 1he ~tJnJarJ \Calc mu'l 

do,c:Jy currc,pondmg tc> the te:>l 'f"'l- lntcrr•'· 

late differences between 1140 sto~ndard Smol>.c 

Spot Number.~ to the nearest half number. Repon Smoke Spot ~umber> h1gher than 9 as 

··Greater than No. lJ.-

Non l-Where more ""urate result> He de>Hcd. 

the human factor •n•·oh·el.l 1n ,-,.u•lh ~"mp;trtng 

tiller paper test spou wuh smoke scale spots can be 

ehmm;ued by rcson tc d.rect U!< of a sutt.ahlc photometer for c•·aluaun2 ""I •f'<"' Th,, rr•>.:<Jurr " 

Jc«:nl>c:d tn the Anne-, 

I 0. Precision 

10.1 Thts lest '' rc:produ'lble llJ w11h1n ::!: ·• 

of a Smoke Sr<'t \,umhcr under nnrmdl cPn· 

dtllons. 

~on 4 -:--. .. umal t.:I,Jn~u .... m .. ,.,e deline&J "·"' tn1''' 

where nc o•l~ statn " cleposucd on the dr~k 

A .1 7 
DRAIN COCK 

THROTTLING 

OR IF" ICE 

I'ILT£R""I>ER--

F'll~ OISC 

I 

I 

l.b 

,.--.-MOTOR 

'"'---' J 

/ OC SCHARG£.--..;,l_......__ I ( 

I 

riG. l f~kl ~r.W~ Ty~ Srnob TO<rrr 

ANNEX 

.... 1. ALH:R.''IiATI\'E PHOTOMETRIC :\1HHOD 

A 1.1 Oirn:t Photornetnc [• aluation 

.... I. I I The human faCIM tn>ol•cd rn .,,ualh 

companng filler paper rcsr Sl"'" 11111h ,mokc ><~le 

spot> 'an be chmrnatcd t>• rc"-'n to d rrect u•e ol a 

.uuat>lc phorometer for e•alu"''"! te" 'i""'' T,, 

m.llte thrs dtre~l phocomctr" test ~l"ll cvalu~uon. rhc 

folio"''"! procedure shall be emploved· 

"I. II I "1oun1 a clean. unuse<.l frller paper. 

bachu h~ a plaque parnreJ "'"h "1!0 or marenal 

havmg a 45 · .. U' davhghtlumrnuu> d.rccuonal relle<-

lancc of nnl It'' !han "5 ·~ m lhe hehl beam ,,- • 

surlahlc rvrc relle<tan<c phor.,mcrer .\dJUSI lhc ph<>-

romerer to ru.J 100 "; rcllccl..ln~ 1n 1crms oi 1hc h~hl 

A. 18 

ref\ccrcd from thrs ~lean surface. Expo,.., rcsr smoke 

spot on filler paper 10 rhe ph->!omcter hghr beam and 

measure the percentage rcc.luctl\•n 1n reflccrcd h!hl 

due tu the prc:.cnco ol ,mol.e panrcles un the frller 

;>"per. Gros> Smoke Sp<•r ~umt-.:r shall be <lefincd 

., equal to !he pc:rccnla!• rcuuctl\ln '" reflected h!ht 

drvrded by ten. 

...1.2 Photometer SP«ification• 

"I.!. I The photometer t.• he emph'ycd f.,r drrcc1 

<e'l ·'I"" number evalual"'" •hall be of the clc~ln<alh 

<>peratcd rellc~l;u\~c "P" em[lluyrng a pholoclcctn< 

.:ell. filled 1011h • spec1al holdcrtsl to accommodalc 
,,11~r pa~r te~t ~re..:1men!~- It • ., hl ~ ~.:~r-;ahi<" \"I 

!11C.L'unnll til< 4:\ · U · Ja, hrht lummous dlre\:ll••n~l 

~11ccunce 11 " t•> he ,·urnJShed '''ml"lcte ,.-uh ~ 

Jrft" tnst•mulus tiller ;nd wnh rc11ccl.1nce .nandard, 

0 215e 

.~~ ~rrn\'(.Jm,;uch :o. ~~. N) -tnd ~o '"; 4<• (I"' da..,lur.h• 

:!Jmtn,)u., d~re~lh~n.al rrtlc..:t.,~n\.:c. to pcrmn l"h .. n\,'nt· 

etcr ru1Jm2' between IU anoJ ~~ '~ lrdauvr to .:lcJn 

filter f'.lf>er-1 w he made wuhm :!:2 <; ac~:urae\ 

., AMIWirM S«N'flf for T~nr11c 111U1 MMn'Mll tOrs ,.., ,.UUIO't '~SJ'ft'JIII( tl., •aiuiut.· of"'""' p41~1 n~ltts asunni "' 

~Jdlt Milt Ml' unn lltrrtiiO~d ut titu natvMuC. Uurt ,-tins D4fiUUir• tl'~ tzp~nht~tlvaud tlft~t d"""''"41W" o_t ,,., 'rlllfdJI\ Jif •r .rwlt fld'~"' n,lt.u. Q/Ui til~ ruk o_( Ut{f111J""''" tJ/ .IWt'lt "'"11- ~rr ~ir tlt~•r O•'llf rt~Jblltt\:. 

T\u 1tand.tvd tJ 1&1/'ttffl If' rrn~ton Dt QJt\· tlltttt '"' tltr ~~OIU'"'' !ul.,uraJ ,-o,'"Uft'l!" affd JPUUI ,_,, rr-v""'"d ~ ... ,.,.\ ,fl·r \ t'J" 

ytJ If"'''~ 'tvtud. trlltt',. rrarf',.I'H"~d·J' •llltdr.;.w:n )m.u ···•'"""f"'H' ,Jrr" :1uani t'llho fo,. "f"\I1Jt.trt nf rJur iiDIIdllrd of' lor ~J..i..t1:1. n.J. 

~ 

,~rt.,:.;r..U ~,.J $ltiJu.iJ b~ w.Jdt~J.s~,J ru .-t:l!.\1 HtQiJqwiJru·•t ) ~ut .-nmmrtuJ "'U rt,·t>t~·rrortfiiJ rortJid~rarUJttQI 11 '",."'"'f ol .''H' 

l«ituuc'ai €tHitlfUIIN. 'rltlu€1t ""'* ,..,.,. cstntll If vo11 fffl tAM ...,.,, tOiftllft#'JtiJ Jww 1t41 '«'n'~" a [111r .;.,..,..~ ....,., JJtowuJ 

.-, - • ...,, •-- "' tiw A ST!ol c-""'"" Sr..,..rrtr. 1~10 ~St .. l'ltlkldrl,lwl. I' a JO ICJJ 

A .19 

APPENDIX B 

SCAQMD Rule 1146.1 

Emissions of Oxides of Nitrogen From 

Small Industrial, Institutional, and Commercial Boilers. 

Steam Generators. and Process Heaters 

8.1 
RULE 1146.1. 

(a) Definitions 

(Adopted October 5, 1990) 

EMISSIONS OF OXIDES OF NITROGEN FROM SMALL 

INDUSTRIAL, INSTITtmONAL, AND COMMERCIAL BOILERS, 

STEAM GENERATORS, AND PROCESS HEATERS 

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

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

heating value. 

(2) BOilER OR STEAM GENERA TOR means any combustion equipment 

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

water, and 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 or any unfired waste heat recovery boiler that is used 

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

(3} BTU means British thermal unit or units .. 

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

the flue gas, collectively expressed as nitrogen dioxide. 

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

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

water or process streams. Process Heater does not include any kiln or 

oven used for drying, baking, cooking. calcining, or vitrifying; or any 

unfired waste heat recovery beater that is used to recover sensible heat 

from the exhaust o~ any combustion equipment. 

(6) . RATED HEAT INPliT CAPACITY means the heat input capacity 

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

unit bas beeb altered or modified such that its maximum heat input is 

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

maximum heat input shall be considered as the rated heat input capacity. 

(7) TiiERM means 100,000 Btu. 

(8) UNIT means any 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 ~on Btu per hour and less 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-<lischarges into the atmosphere no more than 

30 ppm of NOx emissions (0.037 pound NOx per 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 NOx or pounds of NOx per million BTIJ heat 

input compliance option. 

(2) The owner or operator of any unit(s) subject to paragraph (b), and with 

an annual heat input of less than or equal to 18,000 therms per calendar 

year, shall: 

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

concentrations at le~ than or equalto 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 

apan) in accordance with the procedure described in Attachment 

1, or other method as approved by the Executive 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 Executive Officer determines to be necessary and made 

accessible upon request from an authorized District 

representative; or 

(C) meet the emission limits specified in subparagraph (c)(l). 

(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 

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 capacity, anticipated 

annual heat input, and pennit 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, totalizing fuel meter(s) specifications; date of 

installation; and recorded fuel usage since installation. 

(4) Any owner or operator who chooses the pound per rrullion Btu of heat 

input compliance option shall install a non-resettable, totalizing fuel 

meter for each fuel used on an individual unit basis, as approved by the 

Executive Officer. 

(d) Compliance Determination 

(1) All units shall have the option of complying with either the pound per 

million Btu of heat input or parts per million emission limits specified in 

subparagraphs (c)(l) and (c)(2)(C). 

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

condition, except no compliance determination shall be established 

during unit stan up, shutdown, or under breakdown conditions. Stan up 

or shutdovm intervals may 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 specify a time limit, the stan up or shutdown may not 

· exceed six hours for units subject to paragraph (b). 

(3) All pans per million emission limits specified in subparagraph (c)(l) are 

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

over a period of 15 consecutive minutes. 

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

subparagraph (c)(l) and the stack-gas oxygen conr:entration requirement 

of subparagraph (c)(2)(A) shall be determined according to procedures in 

the District Source Test Manual or any other test method detennined to 

be equivalent and approved by the Executive Officer. Emissions 

1146.1- 3 
Rule 1146.1 (Cont.) (Adopted OctoberS, 1990) 

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)(l): 

(A) By January 1, 1993, submit required applications for permits to 

construct and operate, and 

(B) By July 1, 1994, demonstrate compliance with subparagraph (c)(l). 

(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 by January 1, 1992, or at the time the unit is constructed, a nonrescuable, 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 available for inspection by the Executive Officer by February 1, 1993, 

and February 1 of each year thereafter, annual fuel-use data for the 

preceding cale~dar 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 annual heat input is less than 

or equal to 18,000 tberms. 

1146.1-4 
Rule 1146.1 (Cont.) (Adopted October 5, 1990) 

(g) Loss of Exemption 

If any unit subject to a control plan submitted pursuant to subparagraph (c)(3) 

exceeds 18,000 therms of annual heat input after 1992, the owners or operators 

shall: 

(1) Within 4 months from the end of the preceding calendar year, submit 

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 Tuning Procedure1 

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

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

regulation or requirement established by Factory Mutual, Industrial Risk Insurers, 

National Fire Prevention Association, the California Depanment 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 numberl (for liquid fuels), and 

observe flame conditions after unit operation stabilizes at the firing rate 

selecte.d. If the excess oxygen in the stack gas is at the lower end of the range of 

typical minimum values3, and if CO emissions are low and there is not smoke, 

the unit is probably· operating at near optimum efficiency at this particular firing 

rate. 

1

This tuDiDg pr04:Cdure is based on a nme-up procedure developed by KVB,lnc. for the EPA. 

lrbe smoke-spot number c:.an be determined 'With ASTM Test Method D-2156 or with the Bacharach 

method. ASTM Test Method D-2156 i5 included in a tuneup kit that can be purchased from the 

Bacharach Company. 

lrypicaJ minimum oxygen levels for boilers at high firing rates are: 

1. For natural gas: 0.5 percent - 3 percent. 

2. For liquid fuels: 2 percent - 4 percent. 

1146.1-5 
Rule 1146.1 (Cont.) (Adopted October 5, 1990) 

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 .. bumer pans, excessive flame carryover, or flame instability; or 

b. Stack gas CO concentrations greater than 400 ppm; or 

c. Smoking at the stack; or 

d. Equipment-related· limitations, such as low windbox/fumace pressure 

differentiaL; built in air-flow limits, etc. · 

6. Develop an Q.UCO curve (for gaseous fuels) or 02.1smoke curve (for liquid 

fuels) similar to those shown in Figures 1 and 2, using the excess oxygen and CO 

or smoke-spot number data o~tained 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: 

~ Measurement .YW 

Gaseous CO emissions 400 ppm 

#1 and #2 oils smoke-spot number number 1 

#4 on smoke-spot number number 2 

#5 oil smoke-spot number number 3 

Other oils smoke-spot number number4 

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, 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. If this is the case, choose the burner 

control settings that give best performance over the range of firing rates. If one 

firing rate predominates, settings should optimize conditions at that rate. 

10. Verify that the new settings can accommodate the sudden load changes that may 

occur in daily operation without adverse effects. Do this by increasing and 

decreasing load rapidly while observing the flame and stack. If any of the 

conditions in Step 5 result, reset the combustion controls to provide a slightly 

higher level of excess oxygen at the affected firing rates. Next, verify these new 

settings in a similar fashion. Then make sure that the final control settings are 

recorded at steady-state operating conditions for fu~e reference. 

1146.1- 7 
APPENDIX C 

SCAQMD Rule 1146 

Emissions of Oxides of Nitrogen From Industrial. Institutional. and Commercial Boilers, Steam Generators. and Process Heaters 

C.l 
RULE 1146. 

(a) Definitions 

(Adopted September 9. 1988)(Amended January 6. !9R9) 

EMISSIO~S OF OXIDES OF NITROGEN FROM 

INDUSTRIAL, INSTITUTIONAL, AND COMMERCIAL 

BOILERS, STEA.t"1 GENERATORS, AND PROCESS HEATERS 

( 1) Annual Capacity FactOr means the ratio of the amount of fuei burned hy 

a unit in a calendar year to the amount of fuel it could have burned if it 

had operated at the rated heat input capacity for 100 percent of the time 

during the calendar year. 

(2) .1\nnual Heat Input means the actual amount of heat released hy fueb 

burned in a unit during a calendar year. 

(3) Boiler or Stearn Generator means any combustion equipment fired with 

liquid and/or gaseous fuel and used to produce steam or w heat W<Jter 

and 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 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~~ 

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

sensible heat of incoming combustion air. 

(6) NOx Emissions means the sum of nitric oxides and nitrogen dioxide in rhe 

flue gas, collectively expressed as nitrogen dioxide. 

(7) .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 include any kiln or 

oven used for drying, baking, cooking. calcining, or vitrifying; or anv 

unfired waste heat recovery heater that is used to recover sensihle heat 

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 heen 

altered or modified such that its maximum heat input is different than the 

1146- l 
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 million 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 (N02), in 

excess of the concentrations shown in the following table. 

Gaseous 

Rated Heat or Liquid 

Input Capacity Annual Heat Input Fuels 

Equal to or Gre~ter than 9 40§pm 

greater than And x 10 Btu's per yr (0. 5 lb per 

5 million Btu's (90,000 10 Btu's 

per hou~ Therms) of heat 

input) 

Equal to or Greater than 25% 30ppm 

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.) !Amended .January 6. 1989) 

(2) Any unit(s) with a rated heat input capacity greater than or equal to 5 

million Btu per hour and an annual heat input less than or equal to 9.0 x 

I o9 Btu per year, shall: 

(A) be operated in a manner that maintains stack gas oxygen 

concentrations at less than or equal to 3 percent on a dry basis f(}r 

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 l. The 

owner or operator of any unit(s) who specifies the semi-annual 

tune·up option shall maintain a record made accessible to t ht: 

Executive Officer for a period of two years verifying 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 lbs per 106 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 anticipated 

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

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

per year, 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 two 

years in a form and manner as specified by the Executive Officer. 

1146- 3 
Rule ll46 (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)(l) 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 'Nith 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 accessible 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)(l) and/or (c)(4). 

( tl) 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 

Altern.ative Emission Control Plan that is enforceable by the District and 

receives approval of the Plan in writing from the Executive Officer prior 

to implementation. 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 list of equipment subject to alternative emission 

control; 

(ii) Daily hours of utilization for applicable equipment; 

1146.4 
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 control 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 pans per million emission limits 

specified in subparagraph (c)( I). 

(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) A!l 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) shall be determined 

according to procedures in the District Source Test Manual or in any 

other manner approved by the Executive Officer. 

1146-5 
Rule 1 146 (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 utilizing 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 equal 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)(l) 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 million Btu per 

hour, that are subject to the 40 ppm emission limit specified in 

subparagraph (c)(l): 

(A) By March 1, 1991, submit required applications for permits to 

construct and operate. 

(B) By March 1, 1992, demonstrate compliance with subparagraph 

(c)(l). 

(5) For owners or operators of units with a rated heat input capacity equal to 

or gre~ter than 40 million 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 July 1, 1993, demonstrate compliance with subparagraph (c)(l). 

1146-6 
Rule 1146 (Cont.) (Amended January 6, 1989) 

(6) The provisions of subparagraph (c)(l) 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 levels. 

1146- 7 
Rule 1146 (Cont.) (Amended January 6, 1989) 

A 1T ACHMENT 1 

Equipment Tuning Procedure 1 

:-Jothing in this Equipment Tuning Procedure shall be construed to require any act or 

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

regulation or requirement established by Factory Mutual, Industrial Risk Insurors, 

National Fire Prevention Association, the California Department of Industrial 

Relations (Occupational Safety and Health Division), the Federal Occupational Safety 

and Health Administration, or other relevant regulations and requirements. 

I. 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 number2 (for liquid fuels), and 

observe flame conditions after unit operation stabilizes at the firing rate 

selected. If the excess oxygen in the stack gas is at the lower end of the range of 

typical minimum values3, and if CO emissions are low and there is not smoke, 

the unit is probably operating at near optimum efficiency - at this particular 

firing rate. 

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: 0.5%- 3% 

2. For liquid fuels: 2%- 4% 

1146-8 
Rule 1146 (Cont.) (Amended January 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. Nter each increment, record the stack gas 

temperature, oxygen concentration, CO concentration (for gaseous fuels) and 

smoke-spot number (for liquid fuels). Also observe the flame and record any 

changes in its condition. 

5. Continue to reduce combustion air flow stepwise, until one of these limits is 

reached: 

a. Unacceptable flame conditions - such as flame impingement on furnace 

walls or burner parts, excessive flame carryover, or flame instability. 

b. Stack gas CO concentrations greater than 400 ppm. 

c. Smoking at the stack. 

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

differential, built in air-flow limits, etc. 

6. Develop an o2;co curve (for gaseous fuels) or 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 emis~ions 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 

#4oil smoke-spot number number 2 

#5 oil smoke-spot number number 3 

Other oils smoke-spot number number4 

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. 

~. 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. If this is the case, choose the burner 

control settings that give best performance over the range of firing rates. If one 

firing rate predominates, settings should optimize conditions at that rate. 

10. Verify that the new settings can accommodate the sudden load changes that may 

occur in daily operation without adverse effects. Do this by increasing and 

decreasing load rapidly while observing the flame and stack. If any of the 

conditions in Step 5 result, reset the combustion controls to provide a slightly 

higher level of excess oxygen at the affected firing rates. Next, verify these new 

settings in a similar fashion. Then make sure that the final control settings are 

recorded at. steady-state operating conditions for future reference. 

1146. 10 
APPENDIX D 

SCAQMO Rule 1109 

Emissions of Oxides of Nitrogen From 

Boilers and Process Heaters 

in Petroleum Refineries 

0.1 
RULE 1109. 

':-\dopteu :\ovember l. i':l~5)(Amenued Au~u:-.t ~. !()H~) 

EMISSIONS OF OXIDES OF NITROGEN FROM BOILERS A:-.ID 

PROCESS HEATERS IN PETROLEUl\1 REFINERIES 

i a) Definitions 

( 1) BOILER means any combustion equipment fired with liquid :..tnd/or 

gaseous fuel and used to produce steam. including a c:ubon monoxide 

boiler. 

(2) PROCESS HEATER means any combustion equipment fired with liljuid 

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

process streams. 

1.3) REFINERY·WIDE !{ATE UF :\ITROGE:\ t'l\:lDES E\IISSIO:\S 

means the r:.1tto or' the total mass rate of discharge into the atmosphere ur 

nitrogen oxides :·~om units {subject to the ruie l when firing. at the!r 

maximum rated c:.~pacity to the sum of the maximum rated capacities tor 

those units. 

( 4) UNIT means any petroleum refinery boiler or process heater. as defined 

in subsections ( 1) and (2) of this section. with a permit to construct or a 

permit to operate prior to March 2. 1984. 

(5) ~ITROGEN OXIDES means the sum or' nitric oxide ~.nJ nnrogen 

dioxide in the tlue gas. collectively expressed as nitrogen Jioxide and 

averaged over a period ot 15 consecutive minutes. 

(6) COMBUSTI0,\1 \10DIFICATION means ;my :nodific:.~uon 11t tn~ 

burner. combustion air t1ow, or fuel flow system that reduces nitrogen 

oxides emissions. 

(7) \1AXIMUM RATED CAPACITY means maximum design heat inout at 

the higher heating value of the fuel unless: 

fA) the hoiler/process heater is limited hy permit condition to a ksser 

heat input. in which case the limiting condition shall he useJ a~ the 

maximum rated capacity: or 

~B) me ho!ler.'process heater is operated above the ril:L\Imum Jes1gn 

heat input. in which case the maximum operated rate shall he useJ 

at the maximum rated capacny. 

(8) EMISSIONS RATE means the ratio of the mass r:He or uisch:.~rge into 

1109 - 1 
Rule 1109 (Cont.) (Amended August 5, 1988) 

the atmosphere of nitrogen oxides from a unit to the actual heat input for 

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 catalytic 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 60°F, as being zero. 

(b) Requirements 

(1) (A) From July 1, 1988 until December 31, 1992, the owner operator of 

any 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)(l)(A)(i) and (b)(1)A(ii), when operated concurrently 

on both liquid and gaseous fuel. 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. 19S8) 

per million BTU of heat input when firing at the 

maximum rated capacity, or as specified in the Alternative 

Emission Control Plan (AECP). Any 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)(l)(A); 

(ii) From December 31, 1995, emissions are less than or equ:.tl 

to 0.03 pound per million BTU of heat input when firing 

at the maximum rated capacity, or as specified in the 

Alternative Emission Control Plan ( AECP). 

(iii) For each unit firing at less than the maximum r:1ted 

capacity. mass emissions of nitrogen oxides shall be less 

than or equal to the quantity that would occur at the 

applicable limit specified in (h)(l)(B)(i) and (b)( l)(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)(l)(B)(i) and (b)(l)(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. The Alternative Emission Control Ptan 

shall: 

(I) Contain. as a minimum, all data, records, and 

other information necessary to determine 

eligibility for alternative emission control. 

including but not limited to: 

a) A list of equipment subject to alternatin:! 

emission control: 

b) Daily hours of utilization for applicable 

equipment; 

c) Estimated emission of nitrogen oxides for 

1109. 3 
Rule 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. 

(III) 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) 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)(l); 

Such plan shall contain as a minimum: 

(A) A list of all units with the maximum rated capacity for each unit, 

(B) . 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.l 1 Amended August 5. 1988) 

applicable. at the maximum rated capactty. or as near thereto ~:i 

practicable. Such testS shall be performed: 

(A) Within 180 days after completion 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 required by 

subsection (b)(4), while firing gaseous fuel and while firing liquid fuel. 

shall be used for determination of initial compliance with the refinerywide rate of emissions limits of subsection (b)( 1). 

(6) After verification of initial compliance with the limits of subsection 

(b)(l))(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 fuel or liquid fuel, which are 

allowable for that unit under the requirements of subsection 

(b)(l)(A). 

(B) The owner or operator shall submit to the Executive Officer for 

approval a list. by the applicable compliance date, of 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)( l)(A) shall 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 
Rule 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)(l)(B)(i) and (b)( l)(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)(l)(B) shall be determined by 

source testing and/or in-stack nitrogen oxides monitor data or 

other data as specified for the equivalent 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. !'Jew 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 Executive Officer, units which are operated with a 

total heat input in a 12 month period of less than 10 percent of the 

maximum rated capacity for that period. 

(e) Compliance Schedule 

The owner or operator of a petroleum refinery having units subject to this rule 

shall fulfill the following increments of progress: 

( 1) For subsection (b)( l)(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.) tAmended August 5. 1988) 

(C) By December 31. 1992 demonstrate to the satisfaction of the 

Executive Officer compliance with (b)(l)(B)(i). 

(3) For subsection (b)(l)(B)(ii): 

(A) By September l, 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)(l)(B)(ii). 

1109. 7 
APPENDIX E 

VCAPCD Rule 74.15 

Boilers. Steam Generators and Process Heaters 

E.l 
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 power generating units and any auxiliary 

boiler used with a utility electric power generating unit. 

b. ~ater heaters. 

B. Requirements 

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0 ~o< ~~ 

z~ ~ 

UU~< 

>z- <: 0~ u ou8 u ~ r~ 

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4/89 

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 less than 9 x 10 

BTU's per calendar year, shall comply with one of the following 

requirements: 

a. 

b. 

c. 

d. 

The unit shall be operated in a manner that maintains stack 

gas oxygen concentrations at less than or equal to three (3) 

percent on a dry basis for any 15-consecutive-minute 

averaging period. Units subject to this provision shall test 

for compliance every six (6) months; or 

The unit shall be operated using a stack gas oxygen trim 

system set at three (3) percent oxygen. The tolerance of the 

setting shall be ± five (5) percent. Units subject to this 

provision shall test for compliance every twelve (12) months; 

or 

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; o~ 

The unit shall comply with the emission and testing 

requirements of Subsection 8.1. 

Attachment 3 Rule 74.15: l 
C. Exemp~ions 

1. The provisions or this rule shall not apply to any boiler, steam 

generator or process heater with a ra~ed heat input capacity of 

less than five (5) million BTU's per hour. 

2. The provisions of Subsection B.l 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 fuel use in this case shall not exceed 

the period of natural gas curtailment. 

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

system. Alternate fuel use in this case shall not exceed 50 

hours per year. 

3. The provisions of Subsection B.l 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 Rule 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 

4/89 

1. Any person subject to the provisions of Subsection B.2 of this rule 

shall install by Sep~ember 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 tha~ each 

unit operates at or below the applicable heat input level. 

Meters shall be accurate to ± one (1) percen~. 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 mon~h. 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 repor~ shall contain all information or 

documentation that the Air Pollution Control Officer may determine, 

in writing, to be necessary. 

Rule 74.15: 2 
3. Any person utilizing alternate fuel, pursuant eo the provisions of 

Subseceion c.2 of this rule, shall maintain permanent daily records 

of each occurrence. Each record shall include 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.l 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.l 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 of this rule. 

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

with the provisions of Subsection B.l if the unit operates during 

any twelve (12) mon~h period at a total annual heat input rate 

greater than the applicable annual heat input rate specified in 

Subsection B.2. 

G. Definitions 

1. 

2. 

4/89 

"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. 

"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, cocking, calcinating or vitrifying 

or any fuel-fired degreasing or metal finishing equipment. 

Rule 74.15: 3 
J. "Rated Heat Input Capacity": The heat input capacity specified on 

the nameplate of the unit's burner. If the burner has been 

permanently altered or ~edified 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 vriting 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.l 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. 

2. 

3. 

4/89 

For units subject to Subsection B.l and with a rated heat input 

capacity of equal to or greater than ten (10) million BTU'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. 

For units subject to Subsection B.l 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 BTU's per hour, complete 

Authority to Construct applications shall be submitted to the APCD 

before March 1, 1991, and final compliance shall be demonstrated 

before March 1, 1992. 

For units subject to Subsections B.2, final compliance shall be 

demonstrated by March 1, 1990. 

Rule 74.15: 4 
ATTACHMENT 1 

Equipment Tuning Procedure1 

Nothing in this Equipment Tuning Procedure shall be construed to require 

any act or omission that would result in unsafe conditions or would be 

in violation of any regulation or requirement established by Factory 

Mutual, Industrial Risk Insurers, National Fire Prevention Association, 

the California Department of Industrial Relations (Occupational Safety 

and Health Division). the Federal Occupational Safety and Health 

Administration, or other relevant regulations and requirements. 

1. Operate the unit at the firing rate most typical of normal 

operation. If the unit experiences significant load variations 

during normal operation, operate it at its average firing rate. 

2. At this firing rate, record stack gas temperature, oxygen 

concentrati~n, 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 ~as 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 

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. 

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 oxygen levels for boilers at high firing rates 

are: 

4/89 

1. 

2. 

For natural gas: 

For liquid fuels: 

0.5X - 3X 

2X - 4X 

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 temperatuxe, oxygen 

concentration, CO concentration (for gaseous fuels) and smoke-spot 

number (for liquid fuels). Also observe the flame and record any 

changes in its condition. 

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

these limits in reached: 

a. Unacceptable flame conditions - such as flame impingement on 

furnace valls 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 vindboxjfurnace 

pressure differential, built in air-flow limits, etc. 

6. Develop an o2;co curve (for gaseous fuels) or o2;smoke curve (for 

liquid fuels) similar to those shown in Figures 1 and 2 using the 

excess oxygen and CO or smoke-spot number data obtained at each 

combustion air flow setting. 

7. From the curves prepared in Step 6, find the stack gas oxygen 

levels where the CO emissions or smoke-spot number equal the 

following values: 

4/89 

Fuel Measurement Value 

Gaseous CO Emissions 400 ppm 

fll & fi2 oils smoke-spot number number l 

t;4 oil smoke-spot number number 2 

/15 oil smoke-spot number number 3 

Other oils smoke-spot number number 4 

The above conditions are referred to as CO or smoke threshold, or 

as the minimum excess oxygen level. 

Compare this minimum value of excess oxygen to the expected value 

provided by the combustion unit manufacturer. If the minimum 

level found is substantially higher than the value provided by the 

combustion unit manufacturer, burner adjustments can probably be 

made to improve fuel and air mixing, thereby allowing operation 

with less air. 

ATTACHMENT l Rule 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 

o~gen 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 l-8 for firing rates that represent 

the upper and lower limits of the range of the load. Because 

control adjustments at one firing rate may affect conditions at 

other firing rates, it may not be possible to establish the 

optimum excess oxygen level at all firing rates. If this is the 

case, choose the burner control settings that give best 

performance over the range of firing rates. If one firing rate 

predominates, settings should optimize conditions at that rate. 

10. Verify that the new settings can accommodate the sudden changes 

that may occur in daily operation without adverse effects. Do 

this by increasing and decreasing load rapidly while observing the 

flame and stack. If any of the conditions in Step 5 result, reset 

the combustion controls to provide a slightly higher level of 

excess oxygen at the affect firing rates. Next, verify these new 

settings in a similar fashion. Then make sure that the final 

control settings are recorded at steady-state operating conditions 

for future reference. 

4/89 AT'l'ACHMEN'l' l Rule 74.15: 7