### 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 INTRODUCIION......................................................·..1 I. RACT/BARCT RECOMMENDATION.......................................1 A. RACT Djscussjon.............................................1 B. BARCT Discussion ............................................4 II. CONTROL TECHNOLOGY..............................................6 A. Low-NOx Burners.............................................7 B. Flue Gas Recirculation......................................8 C. Selective Noncatalytic Reduction............................8 D. Selective Catalytic Reductjon...............................8 III. 

### COST-EFFECTIVENESS..............................................9 IV. 

### IMPACTS.........................................................10 A. Economjc....................................................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 Aof 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 N02/MMBtu 150 

### ppmv NOX 

### or 0.20 lbs N02/MMBtu 85 

### ppmv NOx or 0.10 lbs N02/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 N02/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 

## o 2, 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 No2 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 No2 

### per MMBtu of heat input. 

## .u 0.036 pounds N02 

### per MMBtu of heat input. 

### fL 0.052 

### pounds 

### N02 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 (N02) form in the combustion process, and some NO oxidizes to N02 in the stack. We refer to NO and NO cumulatively as oxides of nitrogen (NO ), and we quantify N01 

### 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 N07 

### 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. 

### Aretrofit 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 (NH3), 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 along0

### with 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 NH3 

### 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 NH3 to NO is sufficient to reduce NOx to molecular nitrogen (N ) and water vapor (H 0). In practice a NH3:NO ratio of 1:1 has typically

### r~duced NOx emissions

### ~y 80 to 90 percent 8

### with a residual NH3 

### 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** 

### Reductjon Selective Catalytic Reductjon 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. Amajority 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 ofAir 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 

### ASuggested Control Measure for the Control of Emissions of Oxides ofNitrogen 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 ofNitrogen 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 ofNitrogen 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 D2015-85 for solid fuels; (2) ASTM D240-87 or 

### A.2

### ASTM D2382-88 for liquid hydrocarbon fuels; or (3) ASTM D 1826-88, or ASTM 0 1945-81 in conjunction with ASTM D3588-89 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.42) 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 Awhich 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 Bto 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 Aand 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.65)

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 Aand 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. Aviolation 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 Ashall 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

### i1 

### s smoke-spot number number 1 

### #4 0; 1 

### smoke-spot number number 2 

### #5 0i1 

### 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.lO4/89 

# tl

" Figure l Oxygen/CO Characteristic Curve

GratJualC0/02 cnaractensr1c ISreeo COI07

**cnaract•r,~oc**

Aooroorra/11oa.rarmg margm trommm1mum02 

# I Auromartc controls "" COiimtr 

# iI



## ~OOo\mldO/USlea tO tf'tiS O?ltlvPI I



## ~~

Oxygen 1n flue gas. "c Figure 2 Oxygen/Smoke Characteristic Curve

\ Sraaosma1r111o2

**crtar•crer~srtc** 

# t GratJua/ smo1<e107 cnaractttrlslrc

**Aooroorrat~** ooer•flnC)



### ~ **~** \ margmrrommm1mum 07 

# 1 hr--Auromaucoo•let



# "' **=~Eg_.** Sm-ol<e\llm-11

- controls aa1usre<J

- /0 /filS 02 IIIVIII



## ---------
1 

# I Mm•mum 02

# _.-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** (0

### 2), 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. Aflue 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 section is intended to regulate." Response; We disagree; the "exemption" limit is for units which normally burn only gas and applies only when gas is unavailable for purchase. Units with emission control equipment designed for gas-firing are allowed a 150 ppm limit for burning "back-up" fuel. We have extended the applicability of this 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: Aprecedent 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/lteooeratrng margrn from mm,rnumO, 

## 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
.AvrorneiiCbo1lar controls 1d1ustad torrus 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 .:ondition is referred to as the smoke or COthresnoic!. or >Imply as the nummum- ·J.I:I'g"l'nf'O/ni. The smoke threshold generJiil apt'nes to coal and oil tiring. because -.moktng U>Uaii,· occur' bclorc CO

**~m1s** stons 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 1measured d.:J"' nstream or· the oust

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

**~iso** ts 4: :-..o 5 Jna low-sulfur restd. a SSN ofJ: ;>;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. Theotherhas 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 ofsmoice 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-excessoxygen

## -astep-by-step procedure

**~**. .Establilh til• d••ir.cj firing rata and sw1tch comoustton controlstrom automaticto manual operation. Makesure tJJIsalery ;nttJriOCK$ areStill tuncuonmg.

**~.** Rec:oraboiler 1ndat1ckd1t1(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 noteany

**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.becausethis alters the fuel and aJr moxtng characten$- tiCS and comptlcateatne tests.

**~.** Ifyou 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 toolow. a fuel trip wtlt bainitiated by tne ourner sateguaros system.

S. Continueto r•duce airflow at•pwneuntil you reacn one of :neselimits:

• 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-relatedlimitations-sucn as 1owwmaboxtturnace

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

.

o. Develop O,iamokeorO,ICOcherectertetic: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. 13A a.ip llljllj •• •xJiell ra4illa may indicate a burner malfunction or other fuel- orcqu1pment-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 ofminimum 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 beforemaking 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 minimumo"ygen wherethe boilercanbe 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 automaticcontrols 1E'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. Ifyou 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 todetermineIfboileremiSIIon8rn.t codes. Baenerach scale. moreaccurate, Is betterfor burneradjustments 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).

AtmosphericYariatioas. Changes inair 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. AMthellllnlmuln**ex~** leveltoryour boilerfrom the curYeS**~** 1n ltep a. bu1 do not adjuSt the burner controls to this value. Though this may be thepoint ofmaximum etftciency, as wella minimal NO,emialoM, Itusually Is tmprw:.. tical to operate the boilerat this Mttlng. because ofthetendency 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'aoondtuona at thattate.

Comparethis minimum 9alue ofexcessoxygentotheexpected value provided by the boiler manufacturer. It the r.1lnlmum level youfound Issubstantiallyhlghet-thantilevendor's,burneradjustmentsprobabty canImprove fuel and air mixing, therebyallowing operation with lessair.

a. Eatabliah themargin, In excess oxygen abovethe 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-thelowest practical setting at theparticularfiring rate. Formost boilers. NO. emissions lyplcalty will belower atthe new settingthan 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 somecontrol systems.ItIs notpossibleto 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 adJustmentsto yourcontrOl systemwhilethebolterIaoperatingat lowloads. Air-flow requirementsatlow·flre COt'ldltlonsusually are dictated by name Ignition characteristics and stability (and they can becritical and dl1flculttoevaluate)ratherthan byetftclency.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 decreasingloadrapidly 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. verifythesenewsettingsIn a similarfashion. Then mallasurethat the final control settings are recorded at**stead~-state** operating conditions lorfuture reference.**0~** final note: When an alternative fuel is bumac:l, perform these sametests and adjustments for the 5eCOnd fuel. Since it is not always possibleto achieve optimum excess-oxygen**~s**for both fuels at all firing rates,you**m~nt**establiSh thebastconditions 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 Ieve!- 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 adiustments on :-.10. formatiOn and on m1n;mum**e:>~cess** vxygcn 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 boxt. Such modificauon1 to the**ririn~** svstem are best facwrco 1nto the exceSs-oxygen adjustment tests tstep 7in boxl. This insures that changes are completed before the final controlsvstem adjustments arc made.
· Also. aiter adjusting the burner, make acomplete set ofstack. measurements to determinewhetherthe changeis 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 ofair 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 ofthe burner or stoKer and 1ts par!lcular operating charactcmt1Cs.**E~­** ample: It may bepossible 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 Ireductng an Swirl I :::a:- cause flame mstability. while by cios1ng offthe 01r regtster 1more 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 ~quip**  ment.

\ 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 1Fig 9) is imoort:mt. RGSAttachment 3



## ~~ o..l9natton:D2158- 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

..edc.JtslJniiUOn 0:l

**~t'l.** 1h(' l1umN'r

**·mm~lal('l\** roJJov.1n' lh('

**o,ksa,.n~IIOn** lnd.catn thr "'tar,. ontvna!

**~oouon** or.'" lhtca.s.t ul rtv1S10n.

**th~ ~r**  ofWt

**I'T"''~on** " "umt"'t't '" parr

**nth~ tndiC"~tn**  th(' vurol last

**rea~**

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

**~1lon** 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~** wuhhomeheatingegu1pmentbummgkerosene orhcatlnl!

**Oil~.** h rna\· be used m thelaboratorY or In lheiield to compare fuels for clean bum· mg ur ,,, .:,>mpare

**healm~** eyu1pment 2. Applicable Document

2.1 .4SnfSJandard: EQ7 Test Method for 45-". 

### o.· DirectiOnal

RdkL'tJnn·FJclOrofOpaque

**Spt"nm~ns** fl' Broad Band Filt.:r Refl.:<'lllmctrv' 3. Summary ofMethod

3.1 A test smoke spot is obtamed by pulling afued

**~olume** offlue gasthrough a fued area of standard filter paper. The color (or shade! ofthe spot thus produced tS vtsually matched wtth a standard scale. andthe smokedcnsny 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 Therange ofsni'oke densmescov·crc:d by tht' method ts that llihJch h<1' been found par**ucularl~** perttnc:nttohome-heaungapplicauon. 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 Thetest result is reponedas the "Smob SpotNumber."which IS the numberofthe5p01 on thestandardSQlc: mostclosely matchinr;the color lorshade) ofthe rest spot. b. Appanuu,

o.l Samplm{! Dnrcc- .>.,SUitable dt\'ICepre>- \ldmg atotal flue: ga' ,ample: volumeof36 9«• :!: 1650em' at I6°C 1atm !2250:: 100 in.'at t>O<f. I aim)for each

**b.4~** em' 1I m..')etTectrv·e sur1ace area offilter paper shall be employed The sampling dcvtee and connections shall bt ofsuchconstruction that the total travel of

### nue gas sample from flue to filter paper shall .DOl

**cx~cd** 410 mm 116 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

rht.,

**ml"~hud** r .. undt·r Hh·

**tun~.hnu~n** ot -'"IM 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.16constsU of ten

**~pots** numbered consecutively from L) to9. 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 numbertS defined a> the reducuontdueto

**~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 ofthts spot there "'til be no reductiOn m reflectedtnctdcnthght dtrectcdthereon.The last spm. howe,·er. ts ,-cry d.uk. reflecnng on

### I: 10<;- pftheinctdent 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 sometimesbe required. Accnlficdsmokescale iJobuincd 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** spouon 1hesmoke

**'C~Ie.**b<>th 'hallbeVISiblelhrough thesame thtdnessJnd numt>crofsheetsof•ransparcnt prot(CtJve co-ver 7. "htcrials

7.I Tes1 Filler

**Pap~r.** made from white filler paperstock havmg a_;urface rellectanceof82.5 IllM7.5 r; 45°.0° da\lt2hl

**lumtnnu~** dtrccuonal reflectance. tn accord-;nce 11o11h the Method E97. 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> thefilter 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 filterpaper.1Th1s

**m.:~v usual!~**  be doneconveniently 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. Conncct the sampling devtce 10 the Oue

**ga~** probe When tal(ln!! smoke measurements '" the flue·

**p1p~.**

**p<>~lli:,n** !he end ,,fthe:

**'Jmrttn~** rr.•hc at the ..:enter line ofthe 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 pteceofv.·hite paper or plasuchaving

**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 halfnumber. Repon Smoke Spot

**~umber>** h1gher than 9 as ··Greater than No. lJ.-

Non l-Wheremore""urateresult>Hede>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!< ofa sutt.ahlc photometer for c•·aluaun2 ""I •f'<"' Th,, rr•>.:<Jurr " Jc«:nl>c:d tn the Anne-, I0. 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.17DRAIN COCK

THROTTLING ORIF"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 A1.1 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 drrect 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 havmga45· .. U' davhghtlumrnuu>d.rccuonal relle<- lancc of nnl It'' !han "5

**·~** m lhe hehl beam ,,- • surlahlcrvrc relle<tan<c phor.,mcrer .\dJUSI lhc ph<>- romerertoru.J 100 ";

**rcllccl..ln~** 1n 1crmsoi1hc

**h~hl**

A. 18 ref\ccrcd from thrs

**~lean** surface. Expo,.., rcsr smoke spot on filler paper 10 rhe ph->!omcterhghr 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 !hepc: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"" numberevalual"'" •hallbeofthe

**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•mulustiller;ndwnh 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**uttitunatvMuC. Uurt,-tinsD4fiUUir•

**tl'~ tzp~nht~tlvaud** 
**tlft~t**d"""''"41W"o_t ,,., 'rlllfdJI\ Jif•r.rwlt

**fld'~"'**n,lt.u. Q/Ui

**til~** ruko_(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" :1uanit'llho fo,. "f"\I1Jt.trt nf rJur iiDIIdllrdof' 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 Ifvo11 fffltAM ...,.,, tOiftllft#'JtiJJww 1t41

**'«'n'~"**a[111r

**.;.,..,..~** ....,., JJtowuJ .-,- •...,,•-- "' tiwAST!ol

### c-""'""Sr..,..rrtr.

**1~10 ~St** .. l'ltlkldrl,lwl. I' a JOICJJ

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

8.1RULE 1146.1.

(a) Definitions (AdoptedOctober5, 1990) EMISSIONSOFOXIDESOFNITROGENFROMSMALL INDUSTRIAL,INSTITtmONAL,AND COMMERCIALBOILERS, STEAM GENERATORS,AND PROCESSHEATERS

(1) ANNUALHEAT INPUT means the actual amount ofheat released by fuels burned in a unit during a calendar year, based on the fuel's higher heatingvalue. (2) BOilERORSTEAMGENERA TORmeans any combustionequipment 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 combustionturbine orany unfiredwasteheatrecoveryboilerthatis used torecoversensibleheatfromtheexhaustofanycombustionequipment. (3} BTUmeansBritishthermalunitorunits
.. (4) NOxEMISSIONS meansthe sum ofnitric oxide and nitrogen dioxide in theflue gas, collectivelyexpressedas nitrogendioxide. (5) PROCESSHEATERmeans any combustionequipmentfiredwith liquid and/or gaseous fuel and which transfers beat from combustiongases 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 fromtheexhaust

**o~**anycombustionequipment. (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 differentthantheheatinputcapacityspecifiedonthenameplate,thenew maximumheatinputshallbeconsideredastheratedheatinputcapacity. (7) TiiERMmeans 100,000Btu. (8) UNITmeans anyboiler, steamgenerator, or process heateras defined in subparagraph (a)(2)or(a)(5).

1146.1- 1Rule 1146.1 (Cont.) (AdoptedOctober5, 1990)

(b) Applicability This rule applies to boilers, steam generators, and process heaters that
are equal or greaterthan2

**~on**Btuper hour and less than5 million Btuperhourratedheatinputcapacityusedinanyindustrial,institutional,
orcommercialoperation. (c) Requirements 

### (1) The owner and/or operator of any unit subject to paragraph (b) shall operatesuchunitsothatit-<lischargesinto theatmosphere no more than 30 ppm of NOx emissions (0.037 pound NOx per million Btu of heat input) and nomorethan400 ppmofcarbonmonoxide. Foreachunit, a selectionmustbeindicatedinthe applicationfor permitto constructand operatebetweentheppmNOxorpounds ofNOx permillion BTIJ heat inputcomplianceoption. (2) The owner oroperator ofany unit(s) subject to paragraph (b), and with
anannualheatinput ofless thanorequalto 18,000thermspercalendar year, shall: (A) be operated 

### in a manner that maintains stack-gas oxygen concentrationsat

**le~**thanorequalto3percentona drybasisfor

· any15-consecutive-minuteaveragingperiod;or (B) betuned atleast twiceper

**year~** (atintervalsfrom 4 to 8months apan) in accordancewith theprocedure described in Attachment 1, or other method as approved by the Executive Officer. 

### Ifthe unitdoesnotoperateduringa six-monthperiod,anannualtuneup 

### is acceptable. Theowneroroperatorof

### any unit(s)who specifies thesemi-annualtuneupoptionshallmaintainarecordforaperiod oftwo

### years verifying that the tuneup has beenperformed. The record shall contain

### any otherinformationordocumentationthat the Executive Officer determines to be necessary and made accessible upon request from an authorized District representative;or (C) meettheemissionlimitsspecifiedinsubparagraph(c)(l). (3) Theowneroroperatorofanyunit(s) subjectto subparagraph (c)(2) shall submit, for the approval of the Executive Officer, a plan that


### 1146.1-2Rule 1146.1 (Cont.) (Adopted October5, 1990)

demonstrates compliance with subparagraph (c)(2). Such plan shall contain: (A) A list of all units with the rated heat input capacity, anticipated annualheatinput,andpennitnumber; 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;andrecordedfuelusagesinceinstallation. (4) Any owner or operator who chooses the pound per rrullion Btu ofheat input compliance option shall install a non-resettable, totalizing fuel meterfor eachfuel used on an individual unit basis, as approved by the ExecutiveOfficer. (d) ComplianceDetermination (1) All units shall have the option of complying with either the pound per millionBtuofheatinputorpartspermillionemission limits specifiedin 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 duringunit stanup, shutdown, or underbreakdownconditions. Stanup
orshutdovmintervalsmaynotlastlongerthanis necessaryto reachstable temperatures. 

### In no case may the start up or shutdown interval last longerthan specifiedin the permitto operate. 

### Inthe eventthatpermit conditions do not specifya time 

### limit, the stanup or shutdown may not

· exceed

### sixhoursforunitssubjecttoparagraph(b). (3) All panspermillion emissionlimits specifiedin subparagraph(c)(l) are referencedat3 percentvolume stack-gasoxygen on a drybasis averaged
overaperiodof15 consecutiveminutes. (4) Compliance with the NOx and CO emission requirements of subparagraph (c)(l) andthe stack-gas oxygen conr:entration requirement ofsubparagraph(c)(2)(A)shallbe determinedaccording toproceduresin the District SourceTest Manual or any othertest method detennined to be equivalent and approved 

### by the Executive Officer. Emissions

1146.1- 3Rule 1146.1 (Cont.) (AdoptedOctoberS, 1990)

determined to exceed any limits established by this rule through the use ofany oftheabove-referenced testmethodsshallconstituteaviolationof thisrule. (e) ComplianceSchedule The owner or operator of units subject to this rule shall meet the following incrementsofprogress: (1) Forownersand/oroperatorsofunitssubjecttosubparagraph(c)(l): (A) By January 1, 1993, submit required applications for permits to constructandoperate,and (B) ByJuly 1, 1994,demonstratecompliancewithsubparagraph (c)(l). (2) Forownersand/oroperatorsofunitssubjecttosubparagraph(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 Theprovisionsofsubparagraph (c)(1) shallnotapplyprovidedtheownerand/or operator: (1) Installs by January 1, 1992, or atthe time theunit is constructed, a nonrescuable, totalizingfuel meter for each fuel that demonstrates that the unit(s) operatedwith anannualheatinputatorbelow 18,000thermsper calendaryear;and 

### (2) HasavailableforinspectionbytheExecutiveOfficerbyFebruary 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 foraperiodoftwoyears; and 

### (3) DemonstratesbyFebruary 1, 1993,thatthe annualheatinputis less than
orequalto 18,000tberms.



### 1146.1-4Rule 1146.1 (Cont.) (AdoptedOctober5, 1990)

(g) LossofExemption Ifany unit subject to a control plan submitted pursuant to subparagraph (c)(3) exceeds 18,000 therms ofannual heat input after 1992, the owners or operators shall: (1) Within 4 months from the end of the preceding calendar year, submit requiredapplicationsforpermitstoconstructandoperate,and (2) Within 18 months from the end· of the preceding calendar year, demonstratecompliancewith subparagraph(c)(1).


### A

ITACHMENT 1 EquipmentTuningProcedure1 Nothinginthis EquipmentTuning 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 HealthDivision), the Federal OccupationalSafety andHealthAdministration,orotherrelevantregulationsandrequirements. 1. Operatethe unit at the firing rate most

### typical ofnormal operation. 

### Iftheunit experiences significantloadvariations duringnormaloperation,operateitatits averagefiringrate. 2. Atthis firing rate, record stack-gas temperature, oxygen concentration. and CO concentration (for gaseous fuels) orsmoke-spot numberl (for liquid fuels), and observe flame conditions after unit operation stabilizes at the firing rate selecte.d. 

### Ifthe

### excess oxygen 

### inthe stackgas isatthelowerendoftherange of typical minimumvalues3
, and ifCO emissions are low and there is not smoke, theunitisprobably·operatingatnearoptimumefficiency atthisparticularfiring rate. 1ThistuDiDgpr04:Cdureisbasedonanme-upproceduredevelopedbyKVB,lnc.fortheEPA. 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 BacharachCompany. lrypicaJminimum oxygenlevels forboilersat highfiringratesare: 1. Fornaturalgas: 0.5 percent
-3percent. 2. Forliquidfuels: 2percent
-4percent. 1146.1-5Rule 1146.1 (Cont.) (AdoptedOctober

### 5, 1990)
However, complete the remaining portion of this procedure to determine whetherstillloweroxygenlevels arepractical. 3. Increasecombustionairflowtothefurnaceuntilstack-gasoxygenlevelsincrease byonetotwopercentoverthelevelmeasured

### inStep

### 2. AsinStep2,recordthe stack-gas temperature, CO concentration (for gaseous fuels) or smoke-spot number (for liquidfuels), andobserve flame conditionsforthese higheroxygen levelsafterboileroperationstabilizes. 4. Decrease combustionairflow untilthe stack gas oxygenconcentration is atthe levelmeasured 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 changesinitscondition. 

### 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,excessiveflamecarryover,orflameinstability;or b. Stackgas

### CO concentrationsgreaterthan

### 400ppm;or c. Smokingatthestack;or d. Equipment-related·limitations, such as 

### low windbox/fumace pressure differentiaL;built

### inair-flowlimits,etc. · 6. Develop an Q.UCO curve (for gaseous fuels) or 02.1smoke curve (for liquid fuels)similartothose

### showninFigures 

### 1and2,

### usingthe

### excess oxygenand

### CO
orsmoke-spotnumberdata

**o~tained** ateachcombustionairflowsetting. 7. Fromthe

### .curves prepared

### in Step 6, find the

### stack-gas oxygenlevelswhere the 

### COemissionsorsmoke-spotnumberequalthefollowing

### values:

**~** Measurement 

## .YW Gaseous COemissions 400ppm #1and#2oils smoke-spotnumber number 1 #4on smoke-spotnumber number2 #5oil smoke-spotnumber number3 Otheroils smoke-spotnumber number4

1146.1-6

### Rule 1146.1 (Cont.) (Adopted October5, 1990)



### The above conditions are referred to as the CO or smoke thresholds, or as the minimumexcess oxygenlevel. Comparethisminimumvalue ofexcess oxygentotheexpectedvalueprovidedby 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 allowingoperationwithless air. 

### 8. Add 0.5 to 2.0 percentofthe minimum excess oxygen level found in Step 7and reset burner controls to operate automatically at this higher stack-gas oxygen level. This margin above the minimumoxygenlevel accountsforfuel variations, variationsin atmosphericconditions, load changes, and nonrepeatability orplay in automaticcontrols. 9. If

### the load ofthe combustion unit varies significantly during normal operation, repeatSteps 1-8 for firing rates thatrepresent the upper and lowerlimits ofthe range ofthe load. Because control adjustments at one firing rate may affect conditions at otherfiring 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 settingsthatgive bestperformance overthe range offiring rates. 

### Ifone firingratepredominates,settingsshouldoptimizeconditionsatthatrate. 10. Verifythatthe new settingscanaccommodatethesuddenloadchangesthatmay 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 ofexcess oxygen attheaffected firing rates. Next, verify these new settings 

### in a similarfashion. Thenmake sure that the final 

### control settings are recordedatsteady-stateoperatingconditionsfor

**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.lRULE 1146.

(a) Definitions (Adopted September9. 1988)(AmendedJanuary6. !9R9)

**EMISSIO~S** OFOXIDESOFNITROGENFROM INDUSTRIAL, INSTITUTIONAL,AND COMMERCIAL BOILERS,STEA.t"1 GENERATORS,AND PROCESS HEATERS
(1) Annual Capacity FactOr means the ratio ofthe amount of fuei burned hy a unit in a calendaryear to the amount of fuel it could have burned if it had operated at the rated heat input capacity for 100 percent ofthe time duringthe calendaryear. (2) .1\nnual Heat Input means the actual amount of heat released hy fueb burnedin a unit during a calendaryear. (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 usedto recoversensible heatfrom the exhaust ofa combustion turbine or any unfired waste heat recovery boiler that is used to recover sensible heatfrom the exhaustofanycombustionequipment. (4) BTUmeans British thermal unit. (5) Heat Input means the chemical heat released due to fuel combustion

**in~~** unit, using the higher heatingvalue ofthe fuel. Thisdoes not include the sensible heat ofincoming combustion air. (6) NOx Emissions means the sum ofnitricoxidesand nitrogen dioxide in rhe flue gas, collectivelyexpressed 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 ofanycombustionequipment. (8) Rated HeatInput Capacitymeans the heatinputcapacityspecified on the nameplate of the combustion unit. If the combustion unit has heen altered ormodified such thatits maximumheat input is different than the
1146- lRule 1146 (Cont.) (AmendedJanuary 6, 1989)
heat input capacity specified on the nameplate, the new maximum heat inputshallbe consideredastheratedheatinputcapacity. (9) Thermmeans 100,000Btu's. (10) Unit means any boiler, steam generator, or process heater as defined in subparagraph(3) or(7) ofthisparagraph.
(b) Applicability This rule appliesto boilers, steamgenerators,andprocess heaters ofequalto or greater than 5 million Btu's per hour rated heat input capacity used in all industrial, institutional, and commercialoperationswith the exceptionof: (1) boilersused byelectricutilitiestogenerateelectricity; and (2) boilers and process heaters with a rated heat input capacity greater than 40 millionBtuperhourthatareusedinpetroleumrefineries; and (3) sulfurplantreactionboilers.
(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
excessoftheconcentrationsshowninthefollowing table. Gaseous RatedHeat orLiquid InputCapacity AnnualHeatInput Fuels Equalto or

**Gre~ter**than9 40§pm greaterthan And x 10 Btu'speryr (0. 5lb per 5 million Btu's (90,000 10 Btu's per

**hou~** Therms) ofheat input) Equal to or Greaterthan25% 30ppm greaterthan And annualcapacity 40million factor Btu'sper hour Carbon monoxide (CO) emissions from unit(s) subject to this subparagraphshall notexceed400ppm.

1146-2Rule 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 

### Io9 Btu peryear, 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 averagingperiod: 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 tht: 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 tobe necessary; or (C) be operated in compliance with a 40 ppm (0.05 lbs per 106 Btu of heatinput) NOx emission level and a 400 ppmCOemission level. (3) The owner or operator ofany unit(s) subject to subparagraph (c)(2) shall submitfor the approval ofthe Executive Officer a plan that demonstrates compliancewith subparagraph (c)(2). Such plan shall contain: (A) A list ofall 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 millionBtu per hour and an annual heat input greater than 200x 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 manneras specifiedby the Executive Officer.

1146- 3Rule ll46 (Cont.) (AmendedJanuary6, 1989) (5) Any owner or operator who chooses the pound per million Btu complianceoptionshallinstall totalizingfuel meterson anindividualunit basis, as approvedby theExecutive Officer. (6) Any owner oroperatorclaiming an exemptionfrom any ofthe provisions ofsubparagraphs(c)(l) and/or(c)(4)basedonannualheatinput.shall: (A) install by February 1, 1989 for units with a rated heat input capacityequaltoorgreaterthan5but less than40 millionBtuper hour, orby May 1, 1989 for units 'Nith a rated heat inputcapacity equalto orgreaterthan40 million Btuperhour, or atthe timethe unit is constructed, a totalizing meter for each fuel that demonstrates that the unit(s) operated at or below the applicable heatinputlevels; and (B) have available for inspection by the Executive Officer by March 1, 1989, and March 1, ofeach year thereafter, annual fuel use data for the precedingcalendaryear. Records shall be maintainedand made accessible to the Executive Officer for a period oftwoyears; and (C) demonstrate that the annual heatinput is less than orequal to the applicable amountlisted in subparagraph (c)(l)and/or(c)(4).
(tl) AlternativeEmissionControl 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 EmissionControl Plan that is enforceable by the Districtand receives approval ofthe Plan in writing from the Executive Officer prior to implementation. TheAlternative EmissionControl Plan shall: (A) Contain, as a minimum, all data, records, and other information necessary to determine eligibility for alternative emission control, includingbut notlimited to: (i) A list of equipment subject to alternative emission control; (ii) Daily hoursofutilization for applicableequipment;
1146.4Rule 1146 (Cont.) (AmendedJanuary 6, 1989) (iii) Estimated emission of nitrogen oxides for each operation; · (iv) Rated capacity; and (v) Historical andprojectedfuel use. (B) Presentthe methodologyfor estimationofequivalency ofemission reductions underthe proposed Alternative Emission Control Plan as compared to either the emission reductions otherwise required bytherule orto actualemissions,whichever is less. (C) Demonstrate that the permit units subject to the specified rule emission limitations are in compliance with or on an approved schedulefor compliancewith all applicable Districtrules. (2) Revision ofControlPlan Arevised control planmay 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 incorporatedintotheplan. (e) ComplianceDetermination (1) An owner or operator ofany unit(s) shall have the option of complying with eitherthe pound per million Btu orpansper 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 duringstart-up, shutdown, orunderbreakdownconditions. (3) A!l parts per million emission limits specified in paragraph (c) are referenced at 3percentvolume stackgas oxygen on a dry basis averaged overaperiod 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 othermannerapproved

### bytheExecutive Officer.

1146-5Rule 1146 (Cont.) (AmendedJanuary6, 1989) (f) ComplianceSchedule The owner or operator of units subject to this rule shall meet the following incrementsofprogress: (1) Forowners or operators ofunits subject to subparagraph (c)(2), submit, by September 1, 1989, a plan pursuant to subparagraph (c)(3) and by March 1, 1990,demonstratefinal compliancewithsubparagraph(c)(2). (2) Forowners oroperators utilizing the Alternative Emission Control Plan, pursuanttoparagraph(d),by September 1, 1989,submita controlplan. (3) Forowners oroperators ofunits with a ratedheatinputcapacityequalto orgreater than 10 million Btu per hour that are subject to the 40 ppm emission limit specified in subparagraph (c)(1), including those with an approvedAlternativeEmissionControlPlan; (A) By March 1, 1990, submit required applications for permits to constructandoperate. (B) By September 1, 1991 demonstrate compliancewithsubparagraph (c)(l)and,ifapplicable, subparagraph (c)(4). ( 4) Forowners oroperatorsofunitswith a ratedheatinputcapacityequalto or greater than 5 million Btu perhour, 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 constructandoperate. (B) By March 1, 1992, demonstrate compliance with subparagraph (c)(l). (5) Forowners or operatorsofunits with a ratedheatinputcapacityequalto or

**gre~ter** than40millionBtu's perhour andanannualcapacityfactorof 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 constructandoperate. (B) ByJuly 1, 1993, demonstrate compliancewith subparagraph (c)(l).

1146-6Rule 1146 (Cont.) (AmendedJanuary6, 1989)
(6) The provisions of subparagraph (c)(l) and/or (c)(4) shall become applicablefor the life ofthe unit on March 1, ofany calendaryear

### ifthat unit operated for the previous calendar year at an annual heat input greaterthanthe annualapplicableheatinputlevels.

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

A1T ACHMENT 1 EquipmentTuningProcedure1 :-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 HealthAdministration, orotherrelevantregulations and requirements. I. Operate the unit at the firing rate most typical ofnormal operation. Ifthe 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. Ifthe excess oxygen in the stackgas is at the lowerend ofthe range of typical minimum values

### 3, and if

### CO emissions are low and there is not smoke, the unit is probably operating at near optimum efficiency

- at this 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 numbercanbe determinedwith ASTM Test Method D-2156 orwith the Bacharach method. ASTM Test Method D-2156 is included in a tuneup kit thatcan bepurchased from theBacharachCompany.
3. Typical minimum oxygen levels for boilers at high firing rates are: 1. Fornaturalgas: 0.5%- 3% 2. Forliquidfuels: 2%- 4%

1146-8Rule 1146 (Cont.) (Amended January6, 1989)
However, complete the remaining portion of this procedure to determine whetherstill loweroxygen levels are practical. 3. Increase combustion airflow to the furnace until stackgas oxygen levels increase byone totwopercentoverthe level measured in Step2. As in Step2, record the stack gas temperature, CO concentration (for gaseous fuels) or smoke-spot number (for liquid fuels), and observe flame conditions for these higheroxygen levels afterboileroperationstabilizes. 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 changesin 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 orburnerparts, excessive flame carryover, orflame instability. b. Stackgas COconcentrationsgreaterthan400ppm. c. Smokingatthestack. 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 

### 02/smoke curve (for liquid fuels) similarto those shown in Figures 1and 2using the excess oxygen and CO
orsmoke-spotnumberdataobtained at each combustionairflow setting. 7. From the curves prepared in Step 6, find the stack gas oxygen levels where the CO

**emis~ions** or smoke-spotnumberequal the followingvalues: Fuel Measurement Value Gaseous COEmissions 400ppm # 1and#2oils smoke-spotnumber number 1 #4oil smoke-spotnumber number2 #5oil smoke-spotnumber number3 Otheroils smoke-spotnumber number4

1146-9Rule 1146 (Cont.) (Amended January 6, 1989)
The above conditions are referred to as the CO or smoke thresholds, or as the minimumexcess oxygen level. Comparethis minimumvalueofexcessoxygen to the expectedvalueprovided by the combustion unit manufacturer. Ifthe 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 allowingoperationwith less air.

**~.** Add 0.5 to 2.0 percent ofthe minimum excess oxygen level found in Step7 and reset burner controls to operate automatically at this higher stack gas oxygen level. This margin above the minimumoxygen level accounts for fuel variations, variations in atmospheric conditions, load changes, and nonrepeatability or play in automaticcontrols. 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 ofthe range of the load. Because control adjustments at one firing rate may affect conditions at otherfiring 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 thatgive bestperformance over the range offiring rates. Ifone firing ratepredominates, settingsshould optimizeconditionsatthatrate. 10. Verifythat the new settings canaccommodate the sudden load changes thatmay 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 ofexcess 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 operatingconditionsfor future reference.

1146. 10

### APPENDIX D SCAQMO 

### Rule 1109 Emissions of Oxides of Nitrogen From Boilers and Process Heaters in Petroleum Refineries

0.1RULE 1109. ':-\dopteu :\ovember l.

**i':l~5)(Amenued Au~u:-.t**  **~. !()H~)**  EMISSIONS OF OXIDES OF NITROGEN FROM BOILERS A:-.ID PROCESSHEATERS IN PETROLEUl\1 REFINERIES

ia) 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 ofdischarge into the atmosphere ur nitrogen oxides

**:·~om** units {subject to the ruiel when firing. at the!r maximum rated

**c:.~pacity** to the sum ofthe maximum rated capacities tor thoseunits. (4) UNIT means any petroleum refinery boiler orprocess heater. as defined in subsections (1) and (2) ofthis section. with a permit to construct or a permitto operate prior to March2. 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 heatingvalue ofthe fuel unless: fA) the hoiler/process heater is limitedhy permit condition to a ksser heat input. in which case the limitingcondition 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. inwhich case the maximumoperated rate shall he useJ atthe maximum rated capacny. (8) EMISSIONS RATE means the ratio of the mass r:He or

**uisch:.~rge** into

1109

- 1Rule 1109 (Cont.) (AmendedAugust 5, 1988)
the atmosphereofnitrogenoxides from aunit to the actualheatinputfor thatunit. (9) HEATINPUT means the heat ofcombustion released by fuel oxidation in a unit, using the higherheatingvalue ofthe fuel. This does not include the enthalpyofincomingcombustion air. In the case ofcarbonmonoxide boilers, the heat input includes the enthalpy of all regenerator offgases and the heat ofcombustion ofthe incoming carbon monoxide and ofthe 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 contentat 60°F, as beingzero. (b) Requirements (1) (A) FromJuly 1, 1988 until December31, 1992, the owner operatorof any petroleum refinery shall reduce emissions of nitrogen oxides from units subject to this rule so that if all such units were operatedattheirmaximumratedcapacitytherefinery-widerateof nitrogenoxidesemissionsfrom these unitswould notexceed: (i) 0.14pound(0.064kilogram) ofnitrogenoxidespermillion BTUofheatinputwhenoperatedongaseousfuel; (ii) 0.308 pound (0.14 kilogram) ofnitrogenoxidespermillion BTUofheatinputwhenoperatedonliquidfuel; (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. Forpurpose ofthis rule, the nitrogen oxides formed in the fluid catalytic cracking unit regenerator shall be assumed to be from the burning ofgaseousfuel. (B) On December 31, 1992 and subsequent dates, the owner or operator of any petroleum refinery shall reduce emissions of nitrogenoxidesfrom eachunit subjecttothis rule sothat: (i) From December 31, 1992 until December 31, 1995, emissions from units which represent at least 36 percent ofthetotalheatinput are less thanorequal to 0.03 pound

1109- 2Rule 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 poundpermillion limit shall not exceed its pound per million BTU limit specified in the Approved Control Planfor compliancewith (b)(l)(A); (ii) FromDecember31, 1995, emissions are less than orequ:.tl to 

### 0.03 pound per million BTU ofheat 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) atmaximumratedcapacity,or

### as specified inthe AECP. (iv) AlternativeEmission 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. includingbut notlimited 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
1109.3Rule 1109 (Cont.) (AmendedAugust 5, 1988)
each operation; d) Ratedcapacity; and e) Historicalandprojectedfuel 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,whicheveris less. (III) Demonstrate that the permit units subject to the specified rule emission limitations are in compliance with or on an approved schedule for compliancewith all applicableDistrictrules. (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 pursuantto subsection (b)(6)(B),andany specifiedpermitconditions. (3) The owner or operator ofany 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 requirementsofsubsection(b)(l); Suchplanshall containas a minimum: (A) A list ofall unitswith themaximumratedcapacityfor eachunit, (B)
.A list of units to be controlled and the type of control to be appliedfor all such units, including aconstructionschedule, (C) The method of calculation of the mass rate of nitrogen oxides emissions for each unit to achieve the refinery-wide emissions ratesspecifiedinsubsection (b)(1 ), and (D) On-site nitrogen oxide offsets from co-generation facilities may be incorporatedintheplan. (4) All units which are identified in the control plan required by subsection (b)(3)shall be tested, in a mannerapproved by the ExecutiveOfficer, for nitrogen oxides emissions while firing gaseous fuel and liquid fuel, if


### 1109.4Rule 1109 (Cont.l 1Amended August 5. 1988) applicable. at the maximum rated capactty. or as near thereto**~:i** practicable. Such testS shallbeperformed: (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,forunitswhichdo notrequire modification. (5) Total nitrogen oxides emissions (poundsor 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 ofemissions limits ofsubsection (b)(1). (6) After verification of initial compliance with the limits of subsection (b)(l))(A): (A) The owneroroperatorshall assign to eachunit subjectto 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, ofthe maximum allowable nitrogen oxides emissions rates identified in subsection (b}(6)(A) and a copy ofthe 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 ifrequired 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-

# sRule 1109 (Cont.) (AmendedAugustS. 1988)


### oxides monitor, or equivalent verification system. as approved by the Executive Officer at the time of compliance with the 0.03 pound per millionBTU limitspecifiedinsubsections(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 specifiedby theExecutiveOfficer. (B) Compliance with subsection (b)(l)(B) shall be determined by source testing and/or in-stack nitrogen oxides monitor data or otherdataas specifiedfortheequivalentverificationsystem. (c) Revision ofControl Plan Arevised 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 identicalreplacementunits, shallnotbe incorporatedintotheplan. (d) Exemptions TherequirementsofSection (b) shallnotapplyto: (1) 

### Boilers orprocess heaterswithmaximumratedcapacitiesequal to or less than40 million BTU perhourheatinput. (2) Sulfurplantreaction boilers. (3) Upon approval by the Executive Officer, units which are operatedwith a total heat input in a 12 month period of less than 10 

### percent of the maximumratedcapacityfor thatperiod. (e) ComplianceSchedule The owner or operator ofa petroleum refinery having units subject to this rule shallfulfill the following incrementsofprogress: (1) For subsection (b)(

### l)(A), by 

### July 1, 1988, demonstrate to the satisfaction ofthe ExecutiveOfficerfinal compliancewith therule. (2) Forsubsection(b)(1 )(B)(i): (A) By April 1, 1989, submit a revised control plan. pursuant to subsection (b)(3)oftherule. (B) 

### By September 1, 1989, submitrequired applications for permitS to constructandoperate.
1109-6Rule 1109 (Cont.) tAmended August 5. 1988)
(C) By December 31. 1992 demonstrate to the satisfaction of the ExecutiveOfficer compliancewith (b)(l)(B)(i). (3) Forsubsection(b)(l)(B)(ii): (A) By September l, 1992. submit a revised control plan. pursuant to subsection (b)(3)ofthe rule. (B) 

### By February 1, 1993, submit required applications for permits to constructand operate. (C) By December 31, 1995, demonstrate to the satisfaction of the ExecutiveOfficercompliancewith (b)(l)(B)(ii).

1109.7

### APPENDIX E VCAPCD Rule 74.15 

### Boilers. Steam Generators and Process Heaters



### E.lRule 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



### ~

**~**

**~** UJ

**~**



### ~ 

## c 

## z

**~** uu

**~**

**~~>** 0

**~o<**

**~~**

**z~ ~** 

**UU~<** <: >z-

**0~** u 

## ou8

**~** 

## u

**r~**

**~z-** o>

**~** 

## z-.

# =

**~~o** [i

**o3~** >

**u~o** 

### Oo

**~~**

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: lC.

**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: 23. 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: 3J. "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: 4ATTACHMENT 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: 54. 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 

### o 2

### ;co curve (for gaseous fuels) or 

### o 2;smoke curve (for liquid fuels) similar to those shown in Figures 1 and 2 using the excess oxygen and CO or smoke-spot number data obtained at each combustion air flow setting. 7. From the curves prepared in Step 6, find the stack gas oxygen levels where the CO emissions or smoke-spot number equal the following values:

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: 68. 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