### State of California AIR RESOURCES BOARD

DETERMINATION OF REASONABLY AVAILABLE CONTROL TECHNOLOGY AND BEST AVAILABLE RETROFIT CONTROL TECHNOLOGY FOR INDUSTRIAL, INSTITUTIONAI. AND COMMERCIAL BOILERS, STEAM GENERATORS, AND PROCESS HEATERS

Prepared by
Criteria Pollutants Branch Stationary Source Division

Approved by the Technical Review Group

of the California Air Pollution Control Officers' Association

July 18, 1991This determination was prepared by the Air Resources Board staff in cooperation with the Combustion Committee of the California Air Pollution Control Officers' Association's Technical Review Group. We would like to particularly thank:

rt •.. ERfi1iT

~ Tii

Jim Guthrie

Marline Hicks Theresa Dade

Don Price Craig Ullery Brigette Tolistrup Dan Speer Jim Guthrie Gary Quinn Ventura County APCD Bay Area AQMD Sacramento Metropolitan AQMD San Diego County APCD ARB South Coast Air Quality Management District

Peter D. Venturini, Chief, Stationary Source Division Ronald A. Friesen, Assistant Chief, Stationary Source Division Dean C. Simeroth, Chief, Criteria Pollutants Branch Robert D. Fletcher, Manager, Fuels Section

### Contents LIU

INTRODUCTION

......................................................... 1


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



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

### B. BARCT Discussion

........ 

### ...................................4

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



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

### B. Flue Gas Recirculation

. ....................................8 

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

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

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

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



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

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

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

### D. Enrav

.................................................. 

### .11

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

APPENDICES

A. RACT/BARCT DETERMINATION

B. SCAQMD RULE 1146.1 - Emissions of Oxides of Nitrogen From Small Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters.

C. SCAQMD RULE 1146 - Emissions of Oxides of Nitrogen From Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Veaters

D. SCAQMD RULE 1109 - Emissions of Oxides of Nitrogen From Boilers and Process Heaters in Petroleum Refineries

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

F. SIGNIFICANT COMMENTS AND RESPONSESINTRODUCTION

This report presents the proposed determinations of reasonably available control technology (RACT) and best available retrofit control technology (BARCT) for industrial, institutional, and commercial boilers, steam generators, and process heaters. The RACT/BARCT Determination is presented in Appendix A of this document. The determinations follow the "California Clean Air Act Guidance for the Deterrnination of Reasonably Available Control Technology and Best Available Retrofit Control Technology," approved by the California Air Resources Board (ARB) on April 13, 1990. The determinations have been reviewed and approved by the Technical Review Group (TRG) of the California Air ?ollution Control Officers' Association (CAPCOA).
In developing the proposed RACT and BARCT determinations, the staff reviewed a statewide suggested control measure (SCM) and several district rules. Tables 1 and 2 present summaries of the SCM and the district rules that the staff reviewed. The Technical Support Document (TSD) for the SCM is available upon request. The complete texts of the applicable district rules are contained in Appendices B-E.

I. RACT/BARCT RECOMMENDATION

On Aprii 29, 1987, the TRG approved a suggested control measure for the control of emissions of oxides of nitrogen (NOx) from industrial, institutional, and commercial boilers, steam generators and process heaters. This SCM was subsequently approved by the ARB on September 10, 1987. The SCM applies to units with rated heat inputs of 10 million British thermal units per hour (MMBtu/hr) and up, except units with rated heat inputs of greater than 40 MMBtu/hr that are based in petroleum refineries.

The lowest ernission limits contained in the SCM apply to units with rated heat inputs of greater than or equal to 20 million Btu per hour and less than or equal to 150 million Btu per hour, operating with annual capacity factors of greater than 10 percent. The limits for these units are 70 parts per million by volume (ppmv) NOx for gaseous fuel operations and 115 ppmv NOx for.number 1 or number 2 grade fuel oil.
For the RACT determination, we have extended the application of these limits to all units with rated heat inputs of greater than or equal to 5 million Btu per hour, operating with annual heat inputs of greater than or equal to 90,000 therms. We have also applied the limit for operating on number 1 or number 2 grade fuel oil to operation with all types of nongaseous fuels. Units which normally burn only gas are allowed a 150 ppmv NOx emission limit for burning nongaseous fuel for not more than 168 hours per year, if gas is unavailable for purchase.

1Table 1


### Emission Limits Contained in the Suggested Control 

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

RatedIL Annual NOx hL Heat Capacity Fuel Emission I flDSdt FactoL 

## Jy= Limits

120 and <150 MMBtu/hr >10.0X Gas 70 ppmv NO x or 0.08 lbs NO 2 /MMBtu

Fuel Oi1 #1 or #2 115 ppm NO x or 0.15 lbs NO 2 /MMBtu

Other Fuel Oil 150 ppmv NO x or 0.20 lbs NO 2 /MMBtu

>150 MMBtu/hr >5.0% Gas 85 ppmv NO x or 0.10 lbs NO 2 /MMBtu

Fuel Oil #1 or #2 135 ppmv NO x or 0.18 ibs NO 2 /MMBtu

Other Fuel Oil 165 ppmv NO x or 0.22 lbs NO 2 /MMBtu

AL Units with rated heat inputs of greater than or equal to 10 MMBtu/hr, and less than 20 MMBtu/hr, and with annual capacity factors of greater than 10.0%, are subject to other requirements. hL Corrected to 3.00 percent by volume 0 2 , dry, and averaged over 15 consecutive minutes.

2Table 2

Sunrnary District Rules Reviewed for NOx Emissions from Non-Utility Boilers and Process Heaters

Rated Annual NOxf.L C0 rl Heat Neat Input or Emission Emission Input Ca a p city Factor Limits Limits

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

12 and <5 MMBtu/hr >18,000 thermsIL 30 ppmv or 400 ppmv 0.037 lbs NO 2 /MMBtu

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

>_5 MMBtu/hr < 90,000 thermshL 40 ppmv or 400 ppmv 0.05 lbs NO 2 /MMBtu
>_40 MMBtu/hr >25x 30 pprnv 400 ppmv

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

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

>40 MMBtu/hr >lOx 0.03 lbs NO /MMBtu @ maximum rited capacity

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

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

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

## kL Units with annual heat inputs of less than 90,000 therms are subject to other requirements. r.L Corrected to 3.00 percent by volume 0 2 , dry, and averaged over 15 consecutive minutes.

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



### F.P05i11:i4>•

~ • ~ As shown in Table 2, both the South Coast Air Quality Management District (SCAQMD) and the Ventura County Air Pollution Control District(VCAPCD) have adopted source specific rules for NOx emission control on nonelectric-generating boilers, steam generators, and process heaters. SCAQMD Rule 1109, adopted November 1, 1985, and amended August 5, 1988, applies to units with rated heat inputs of greater than 40 MMBtu/hr located at petroleum refineries. SCAQMD Rule 1146, adopted September 9, 1988, and amended January 6, 1989, applies to units with rated heat inputs of 5 MMBtu/hr and up not located at petroleum refineries. SCAQMD Rule 1146.1, adopted October 5, 1990, applies to units with rated heat inputs from 2 MMBtu/hr to less than 5 MMBtu/hr. VCAPCD Rule 74.15, adopted March 28, 1989, applies to units with rated heat inputs of 5 MMBtu/hr and up, except water heaters.
The emission limits contained in district rules are 30 ppmv NOx for units with rated heat inputs of greater than or equal to 2 million Btu per hour and less than 5 miilion Btu per hour, having annual heat inputs of greater than 18,000 therms; 40 ppmv Nbx for units with rated heat inputs of greater than or equal to 5 million Btu per hour, having annual heat inputs of greater than 90,000 therms; 30 ppmv NOx for units with rated heat inputs of greater than or equal to 40 million Btu per hour, operating at annual capacity factors of greater than 25 percent; and 0.03 pounds NO 2 per miliion Btu of heat input for units operating at maxirnum rated capacity with rated heat inputs of greater than 40 million Btu per hour, sited at petroleum refineries and operating at annual capacity factors of greater than or equal to 10 percent.
For the BARCT determination, we have applied the 30 ppmv NOx emission limit to all units burning gas, having rated heat inputs of greater than or equal to 5 million Btu per hour and operating with annual heat inputs of greater than or equal to 90,000 therms. For units burning nongaseous fuels, we have applied the 40 ppmv NOx emission limit to all units having rated heat inputs of greater than or equal to 5 million Btu per hour, operating with annual heat inputs of greater than or equal to 90,000 therms. Units which normally burn only gas are allowed a 150 ppmv NOx emission limit for burning nongaseous fuel for not more than 168 hours per year, if gas is unavailable for purchase.Table 3 RACT/BARCT Summary for Industrial, Institutional and Commercial Boilers, Steam Generators, and Process Heaters

Standards

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

Rated Annual" 

### ~ Heat Heat Fuel 

# Inpsl.t. Ingut

~ 

# 7.=

> 5 MMBtu/hr > 90,000 therms Gas

Other Exemptiona L NOx bL

Emission

70 ppmvf.L
115 ppmv 

### ~ 150 ppmv C0 L Emission 

### Limits
400 ppmv
400 ppmv 400 ppmv



### NOx bl Fuel Emission 

# 1= Li mits

Gas 30 ppmv&L

Other 40 ppmvfL

150 ppmvbl - ExemptiongL C 0k L Emission Limits
400 ppmv
400 ppmv 400 ppmv ---------- BARCT ----------

Rated Annual AL Heat Heat 

### IADJIt I D RSIt —
> 5 MMBtu/hr > 90,000 therms

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



### ~ Corrected to 3.00 percent by volume O z , dry, and averaged over 15 consecutive minutes.

~ 0.084 pounds NO 2 per MMBtu of heat input.



### ~ 0.150 pounds NO 2 per MMBtu of heat input.

' L 0.036 pounds NO 2 per MMBtu of heat input. " 0.052 pounds NO 2 per MMBtu of heat input.


### 9 L For not more than 168 hours per calendar year, only when gas is not available for purchase.
hL 0.215 pounds NOx per MMBtu of heat input.

~~We chose 30 ppmv as the uniforrn BARCT NOx emission limit for gas firing of all industrial, institutional, and commercial boilers, steam generators, and process heaters. This uniform emission limit reflects improvements in technology which have occurred in the last few years. We believe that most units can meet this limit by installing new burners with flue gas recirculation. Some units may need to add selective noncatalytic reduction or other emission control technology instead of flue gas recirculation due to particular unit design problems. We believe that 30 ppmv is the appropriate BARCT NOx emission limit due to the many units currently operating within this limit without the use of flue gas emission controls. New units

- of the near future may achieve emission limits below 15 ppmv NOx without the use of flue gas emission controls. However, for districts which have recently adopted rules which allow higher emissions, the incremental cost-effectiveness of requiring 30 ppmv may be high for some affected units. Therefore, districts which have adopted rules covering the applicability of this determination, within three years prior to the date of approval of this determination, are deemed to comply with this determination.
In the SCAQMD, specially blended low-NOx fuel oil, which has low sulfur, nitrogen, and aromatic hydrocarbon contents, is being used to meet the 40 ppmv limit of Rule 1146. Since the low-NOx fuel oil is blended in small quantities, it is much more expensive than number 2 fuel oil. Therefore, this low-NOx fuel oil is being used primarily for dual fuel firing capability at this time. Methanoi is also being used in the SCAQMD to meet the 40 ppmv limit with dual fuel firing capability. We believe that, in the future, liquid fuel firing at 40 ppmv NOx may be economically competitive with gas firing at 30 ppmv NOx.
A summary of the BARCT determination is also presented in Table 3.

II. CONTROL TECHNOLOGY Nitric oxide (NO) forms in process equipment such as boilers and heaters, which operate on the combustion of fuel and air. The NO may then be emitted to the atmosphere along with other products of combustion in the flue gas. Smaller amounts of nitrogen dioxide (NO 2 ) form in the combustion process, and some NO oxidizes to NO 2 in the stack. We refer to NO and NO cumulatively as oxides of nitrogen (NO ), and we quantify NO emissions as 

## ~ arts per million (ppm) by volume, relative to dry stack gases x at 3'percent 0. Alternately, we may quantify NO emissions as pounds of NO per million 

# i ritish thermal unit (MMBtu) of fuel input to the process, basid on the higher heating value (HHY) and flow rate of the fuel. The formation of NO by combustion processes is governed primarily by (1) the chemically-bound nitrogen content of the fuel, (2) the oxygen concentration of the flame, (3) the temperature of the flame, and {4} the length of time for which the combustion gases are held at the flame temperature.Chemically-bound nitrogen of 1000 ppm by weight in fuel oi1 could result in NO formation of up to 83 ppm by volume, relative to dry stack gases at 3 percent 0. This estimate is based on 65 percent conversion of fuel-nitrogen to N0. Fgr higher fuel-nitrogen contents the percent conversion is iower. For lower fuel-nitrogen contents, the percent conversion is higher. Residual fuel oils may have nitrogen contents of between 1000 ppm and 8000 ppm by weight. In California, distillate fuel oils with nitrogen contents between 200 and 600 ppm by weight are typically available. Sy 1994, distillate fuel oils with nitrogen contents beiow 10 ppm by weight may be available as a result of statewide regulations limiting the sulfur content of motor vehicle diesel fuel. Chemically-bound nitrogen of 10 ppm in fuel oil could not convert to more than 1 ppm of N0. Oue partly to chemically-bound nitrogen in fuel oils, the combustion of fuel oils produces more NO than the combustion of natural gas at the same conditions. Generally, premixed flames, such as in natural gas combustion, wili produce less NO than diffusion flames, such as in oil droplet combustion, with the same amount of excess air. This is because the peak temperatures in diffusion flames occur at surfaces of theoreticaliy correct air-to-fuel ratios, while the peak temperatures for premixed flames are lower due to excess-air dilution. For most applications reducing NOx emissions from industrial, institutional, and commercial boilers, steam generators, and process heaterscan be broken down into four methods. These are (1) retrofitting of 1ow-NOxemitting burners, (2) retrofitting of flue-gas-recirculation systems (3) installation of ammonia injection systems for selective noncatalytic reduction, and (4) installation of ammonia injection systems along with catalytic reactors for selective catalytic reduction. These methods are discussed below.

Low-NOx burners employ low excess air combustion, air staging, fuel staging, or combustion product recirculation to lower NOx formation in the flame. Low excess air combustion and combustion product recirculation decrease the oxygen available for NOx formation. Combustion product recirculation also lowers the bulk flame temperature, and consequently lowers the NOx formation rate and equilibrium concentration. Staged-air burners lower available oxygen at points in the combustion chamber where the temperature is h.igh. Staged-fuel burners lower the temperature at points inthe combustion chamber where available oxygen is high. Retrofitting of lowNOx burners may require derating of equipment, because flame lengths may be significantly increased.
Low-NOx burners are applicable to most gas-fired and oil-fired units. For gas-fired units, the control effectiveness ranges from 10 to 55 percent. For units fired with low-nitrogen oil, the control effectiveness is expected to be within the same range.~ 

## MUMMM 

## MWM • {
Flue gas recirculation (FGR) for NOx control consists of extracting a portion of the flue gas from the economizer outlet and returning it to the furnace, admitting the flue gas through the furnace windbox. Flue gas recirculation lowers the bulk furnace gas temperature and reduces oxygen concentration in the combustion zone. A retrofit installation of FGR consists of adding a fan, ductwork, dampers, and controls as well as possibly having to increase existing fan horsepower due to increased draft loss. FGR is an effective control technique for both gas-fired and distillate oil-fired units. FGR is not effective at reducing NOx formation originating from fuel-bound nitrogen. The control effectiveness of flue gas recirculation ranges from 60 to 70 percent for gas-fired units. The control effectiveness of FGR for units firing low-nitrogen oil is expected to be within the same range.

- ► • ~ 

### . ;nLq

~ 

### : -

~ 

### :M

~ 

### {
Exxon Research and Engineering Company has developed, patented, and is offering for license, a noncatalytic process called Thermal DeNOx for removing oxides of nitrogen from flue gas in stationary combustion sources. Thermal DeNOx is based on the gas phase homogeneous reaction between NOx in flue gas and ammonia (NH 3 ), which produces nitrogen and water. In general, NH is injected into the hot flue gas by means of either air or steam carrier ga 

## ~ at a point in the flue specifically selected to provide optiTum reacti8n temperature and residence time. In the temperature range of 1600 F to 2200 F, the reaction occurs through the injection of NHalone. Hydrogen (H ) can also be injected along o with NH 3 to extend the e?fectiveness range of thi deNOx reaction down to 1300 F.
NOx reductions of up to 90 percent have been demonstrated on an oil field steam generators where favorable process conditions exist. DeNOx performanceusing earlier technology ranges from 50 to 70 percent reduction for most oilfired and gas-fired process heaters and steam boilers.


# M M 

## MMUMMM

1 9MM I Xr. •

~ Selective catalytic reduction (SCR) refers to a process that chemically reduces NOx with NH over a heterogeneous catalyst in the presence of oxygen (0 ) The process 

## ~ s termed setective because the reducing agent NH priferentially attacks NOx rather than 0. However, the 0 enhances 3 the reaction and is a necessary part of the


## ~ eaction scheme.


## ~ hus, SCR is potentially applicable to flue gas under oxidizing conditions, greater than one percent 0 2

. In theory a 1:1 stoichiometric molar ratio of NH to NO is sufficient to reduce NOx to molecular nitrogen (N ) and water vapor 3 (H 0). In practice a NH 3 :N0 ratio of 1:1 has typically riduced NOx emissions gy 80 to 90 percent

8with a residual NH concentration of less than 20 pBmv. The o optimum temperature range ?or the catalytic reaction is 570 F to 845 F.
SCR retrofitting requires a reactor, which contains the catalytic material, and an ammonia storage and injection system. Due to the increased pressure drop across the reactor, some increase in boiler fan horsepower, or possibly a new fan, may be necessary. SCR has been extensively employed in Japan on gas-fired and oil-fired industrial and utility boilers.

III. COST-EFFECTIVENESS Flue-gas recirculation and ammonia injection are probably the most universally applicable methods for reducing NOx emissions from industrial, institutional, and commercial boilers, and process heaters. The unit cost of NOx emission reduction with FGR ranges from E1600 to $7800 per ton at 50 percent capacity factors. The unit cost of NOx emission reduction with ammonia injection ranges from $1500 to $6000 per ton at 50 percent capacity factors. Low-NOx burners are generally less expensive, and SCR is generally more expensive, than these methods. The ranges are reflective that unit costs generally increase with decreasing equipment size. Furthermore, unit costs increase rapidly with decreasing capacity factors below 25 percent. Table 4 presents a summary of cost-effectiveness ranges for the different technologies.



### Table 4

Cost-Effectiveness of Selected NOx 

### Emission Control Technologies

Annual Unit Size NOx Emission Reduction Capacity Range Cost-Effectiveness Range Factor (MMBtu/hr) (1986E thousand/ton NOx)

Low-N x Burners 10% 2.3 to 27 50% 3.5 to 150 0.5 to 6.4 90% 0.3 to 4.0

Elue Gas Recirculation 10% 6.8 to 29 50% 3.5 to 350 1.6 to 6.8 90% 1.0 to 3.7 Selective Noncatalytic 10% 2.3 to 20 Reduction 50% 50 to 375 1.5 to 6.0 90% 1.3 to 3.8 Selectiye Catalytic 10% 24 to 66 Reduction 50% 50 to 350 6.0 to 14 90% 4.0 to 9.0

9Reasonably available control technology (RACT) requirements can be met with either FGR or ammonia injection. However, for oil-firing, switching to a lower nitrogen-content fuel may be required. FGR is ineffective at reducing NOx formation originating from fuel nitrogen, and the absolute amount of NOx passing through ammonia injection systems increases directly with the amount entering. Where applicable, low-NOx burners may be more effective at reducing emissions when firing with high-nitrogen fuel.Best avaiiable retrofit control technology (BARCT) requirements for gasfiring may be met by installing new burners with either FGR or ammonia injection. However, both methods, or SCR, may be necessary for up to twice the cost.

IV. IMPACTS



### •i•o The potential economic impacts of this determination are the capital cost of emission control equipment and the increased operating cost associated with emission control equipment. If combustion equipment is operated with lower excess air after, or instead of, retrofitting control equipment; there will be a cost benefit due to increased thermal efficiency.

B. Air Oualitv The most significant impact of this determination is the decrease in NOx emissions and resultant decrease in atmospheric ozone and PM10 formation. Other potential impacts inciude ammonia slip from SNCR and SCR systems and ammonia leakage from storage and handling systems, which will result in emissions of ammonia to the atmosphere. Ammonia emissions will increase the formation of PM10 in the atmosphere.

C. Hazards
Ammonia is a toxic, highly reactive compound and its use, storage, and transport can be hazardous, especially in the case of worker exposure to highly concentrated ammonia vapor or contact with liquid ammonia. Occupational Safety and Health Administration (OSHA) regulations specify the rnethods for the use, storage, and transport of ammonia. These regulations were developed to reduce the hazards that could occur when handling ammonia.
The spent catalyst materials from the use of SCR commonly contain small amounts of hazardous materials, including vanadium pentoxide. This compound is toxic if inhaled. A majority of catalysts used in California are now reclaimed and recycled by the manufacturer, so that their disposal should pose no significant environmental impacts. For those facilities that do not recycle their catalysts, the spent material wouid have to be deposited in a Class I landfill. The only operational Class I disposal site in California is located in Kings County.

10D. 

### Energv
Additional fan energy will be required to operate FGR, SNCR, and SCR systems. Ali of the systems require additional mass flows and gas velocities, which will increase flow losses through the furnaces and downstream passages. The FGR ducting and SCR reactor are additional flow impedances.

11REFERENCES

(1) Calvert, S., and Englund, H.M. 

### Nandbook of 

### Air Pollution Technology, John Wiley and Sons, Inc., New York, 1984. Chapter 5, "Gaseous Pollutant Characteristics," Chapter 9, "Control of Gases by Chemical Reaction," and Chapter 35, "Atmospheric Chemistry." (2) DeLacy, J.M. 

### Introduction to Coen Low NOx Burner Techniques, Revision A, Coen Company, Inc., Burlingame, California, November 1986.
(3) Energy Section, Stationary Source Division. 

### Technical Support Document for A Suggested Control Measure for the Control of Emissions of Oxides of Nitrogen from Industrial, Institutional, and Commerical Boilers, Steam Generators and Process Heaters, California Air Resources Board, Sacramento, April 1987. Chapter X, "Cost and Cost-Effectiveness of NOx Controis," and Appendix C, "Cost Calculation Methodology." (4) Exxon Research and Engineering Company. "Improved ER&E Thermal DeNOx Process," Exxon Technology, Florham Park, New Jersey, July 1987. (5) Glassman, I. 

### Combustion, Academic Press, Inc., New York, 1977. Chapter 8, "Environmental Combustion Considerations." (6) Goff, T., Kern County. Telephone conversation, June 1991. (7) Howard, G., Neggo, R., and Wallerstein, B., Rule Development Division. 

### Staff Report, Proposed Arrrended Rule 1109, Emissions of Oxides of Nitrogen from Boilers and Process Neaters in Petroleum Refineries, South Coast Air Quality Management District, E1 Monte, California, October, 1987. Section VII, "Other Environmentai Impacts," and "Attachment A." (8) Karaba, J.M., Pyronics, Inc. 

### Cornbustion Nandbook, Industrial Heating Equipment Association, Inc., Washington D.C., 1970. Session I. "Fundamentals of Combustion." (9) Keenan, J.H., and Kaye, J. 

### Gas Tables, John Wiley and Sons, Inc., New York, 1948. Table 1, "Air at Low Pressures (for One Pound)." (10) Keenan, J.H., Keyes, F.G., Hill, P.G., and 

### Moore, J.G. 

### Steam Tables, John Wiley and Sons, Inc., New York, 1969. Table 3, p. 14, "Water Vapor at Low Pressures." (11) KVB, Inc. 6oiler Efficiency 

### Improvement Training Seminar, KVB, Inc.,Tustin, California. United States Department of Energy Contract No. CR04-70190, November 1977. Unit 1.0, "Boiler Energy Overview," Unit 3.0, "Boiler Efficiency and Controlling Factors," and Unit 4.0, "Efficiency Calculation."

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

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

### Applications: NOx Combustion Modification, 

### U.S. Environmental Protection Agency, Washington, D.C., December 1979. EPA-600/7-79-178f. Section 2, "Emission ControT Techniques."


### (13) Office of Research and Development. Guidelines 

### for Industrial Boiler Performance 

### Improvement, EPA-600/8-77-003a, United States Environmental Protection Agency, Research Triangle Park, North Carolina, January 1977. Section 2.0, "Fundamentals of Combustion," and Section 3.0, "Preparation for Boiler Tests." (14) 0'Rourke, D. Petro America, Inc. Facsimile transmission and telephone conversation, July 1991.


### (15) Robertson, W.S. Boiler ffficiency 

### and Safety, ESSO Petroleuro Company, Limited, The MacMillan Press, Ltd., London, 1981. P. 29, et seq., "Calculation of Combustion Efficiency." (16) Shields, C.D. 

### Boilers, F.W. Dodge Corporation, New York, 1961. Chapter 1, "Boiler Types," Chapter 2, "Steel Firetube Boilers," Chapter 3, "Steel Watertube Boilers," and Chapter 30, "Boiler Performance."


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

### Proposed Amended 

### Rule 1146 - Emissions 

### of Oxides of Nitrogen from Irtdustrial, Institutional, 

### and Commercial Boilers, Steam Generators, and Process Neaters, 

### South Coast Air Quality Management District, E1 Monte, California, December 1988. Appendix B. "Cost-Effectiveness Calculations." (18) Votlucka, P., Smith, S., and Johnson, S.L., Office of Planning and Rules. Staff 

### Report for: Proposed Rule 

### 1146.1: Emissions of Oxides of Nitrogen 

### from Small Industrial, Institutional, and Comnercial Boilers, Steam 

### Generators, and 

### Process Neaters, South Coast Air Quality Management District, E1 Monte, California, September 1990. Appendix A, "Cost-Effectiveness Calculations." (19) Yang, S., Pohl, J.H., Bortz, S.J., Yang, R.J., and Chang, W. "Development of Low NOx Gas Burners," EPRI/EPA 1991 Joint Symposium on Stationary Combustion NOx Control, Electric Power Research Institute, Palo Alto,.California, March 1991.

13

### APPENDIX A

RACT/BARCT Determination

A.1DETERMINATION OF REASONABLY AVAILABLE CONTROL TECHNOLOGY AND BEST AVAILABLE RETROFIT CONTROL TECHNOLOGY FOR INDUSTRIAL. INSTITUTIONAL, AND COMMERCIAL BOIIERS, STEAM GENERATORS. AND PROCESS HEATERS

I. Applicability This determination applies to boilers, steam generators, and process heaters with rated heat inputs of greater than or equal to 5 million Btu per hour, used in all industrial, institutional, and commercial operations. This determination does not apply to boilers used by electric utilities to generate electricity, waste heat recovery boilers that are used to recover sensible heat from the exhaust of combustion turbines, dryers in which the material being dried is iri direct contact with the products of combustion, cement and lime kilns, glass melting furnaces, and smelters.

II. Definitions

A. ANNUAL HEAT INPUT means the total heat input of fuels burned by a unit in a calendar year, as determined from the HHV and cumulative annual usage of each fuel.

B. BARCT means "best available retrofit control technology," defined in section 40406 of the California Health and Safety Code as "an emission limitation that is based on the maximum degree of reduction achievable, taking into account environmental, energy, and economic impacts by each class or category of source."

C. BOILER 

## OR STEAM GENERATOR means any combustion equipment fired with any fuel and used to produce steam that is not used exclusively to produce electricity for sale. BOILER or STEAM GENERATOR does not include any waste heat recovery boiler that is used to recover sensible heat from the exhaust of a combustion turbine.



## D. BRITISH TNERMAL UNIT (Btu) means the amount of heat requireg to raise the temperature of one pound of water from 59 ° F to 60 F at one atmosphere.

E. NEAT INPUT means the chemical heat released due to fuel combustion in a unit, using the higher heating value of the fuel. This does not include the sensible heat of incoming combustion air.

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



## G. HIGNER HEATING VALUE (HHV) means the totaT heat liberated per mass of fuel burned (8tu per pound), when fuel and dry air at standard conditions undergo complete combustion and all resultant products are brought to their standard states at standard conditions. HHV shall be determined by one of the following test methods: (1) ASTM D 2015-85 for solid fuels; (2) ASTM D 240-87 or

A.2ASTM D 2382-88 for liquid hydrocarbon fuels; or (3) ASTM D 1826-88, or ASTM 0 1945-81 in conjunction with ASTM Q 3588-89 for gaseous 

### fuels.
H. NOx EMISSIONS (NOx) means the sum of nitric oxides and nitrogen dioxide in the flue gas.


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

### conditions.
J. PARTS PER MILLION (BY VOLUME) (ppmv) means the ratio of the number of gas molecules of a given species, or group, to the number of millions of total gas molecules.


### K. PROCESS HEATER means any combustion equipment fired with any fuel, and which transfers heat from combustion gases to water or process streams. PROCESS HEATER does not include any dryers in which the material being dried is in direct contact with the products of combustion, cement or lime kilns, glass melting furnaces, or smelters.

L. RACT means "reasonably available control technology."


### M. RATED HEAT INPUT (million Btu per hour) means the heat input capacity specified on the nameplate of the combustion unit. If the combustion unit has been altered or modified such that its maximum heat input is different than the heat input capacity specified on the nameplate, the maximum heat input shall be considered as the rated heat input.



## N. STANDARD CONDITIONS means 68 0 F and one atmosphere.

0. 

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

P. THREE PREVIOUS CALENDAR YEARS means the three corssecutive years irtmediately preceding the year in which final compliance is required by this determination, or the three consecutive years imnediately preceding each calendar year of compliance thereafter.

Q. UNIT means any boiler, steam generator or process heater as defined in Sections C and K, above.

A.3III. Standards (FOR RACT)

A. For units with rated heat inputs of greater than or equal to 5 million Btu per hour and annual heat inputs of greater thart or equal to 90,000 therms for any of the three previous calendar years, NOx emissions shall not exceed the following levels:
1) 70 parts per million by volume, or 0.084 pound per million Btu of heat input, when operated on gas, or
2) 115 parts per million by volume, or 0.150 pound per million Btu of heat input, when operated on nongaseous fuel, or
3) the heat-input weighted average of the limits specified in 1) and 2), above, when operated on combinations of gas and nongaseous fuel. Emissions from units subject to this subsection shall not exceed a carbon monoxide concentration of 400 parts per million by volume.

B. Units with rated heat inputs of greater than or equal to 5 million Btu per hour and annual heat inputs of less than 90,000 therms for each of the three previous calendar years shall: 1) be operated in a manner that maintains stack-gas oxygen (0 ) concentrations at less than or equal to 3.00 percent by voiume on a dry basis; or 2) be operated with a stack-gas oxygen trim system set at 3.00 percent by volume oxygen (0 ). The tolerance of the setting shall be plus or minus five (± 5.0) percent; or 3) be tuned at ieast once per year by a technician that is qualified, to the satisfaction of the Executive Officer/Air Poilution Control Officer, to perform a tune-up in accordance with the procedure described in Attachment 1; or 4) be operated in compliance with the applicable emission levels specified in Subsection III A.

(FOR BARCT)

A. For units with rated heat inputs of greater than or equal to 5 miilion Btu per hour and annual heat inputs of greater than or equal to 90,000 therms for any of the three previous calendar years, NOx emissions shall not exceed the following levels: 1) 30 parts per million by volume, or 0.036 pound per million Btu of heat input, when operated on gas, or

A.42) 40 parts per million by volume, or 0.052 pound per million Btu of heat input, when operated on nongaseous fuel, or
3) the heat-input weighted average of the limits specified in 1) and 2), above, when operated on combinations of gas and nongaseous fuel. Emissions from units subject to this subsection shall not exceed a carbon monoxide concentration of 400 parts per million by volume.

B. Units with rated heat inputs of greater than or equal to 5 million Btu per hour and annual heat inputs of less than 90,000 therms for each of the three previous calendar years shall:
1) be operated in a manner that maintains stack-gas oxygen concentrations at less than or equal to 3.00 percent by volurne on a dry basis; or 2) be operated with a stack-gas oxygen trim system set at 3.00 percent by volume oxygen. The tolerance of the setting shall be plus or minus five (± 5.0) percent; or 3) be tuned at least once per year by a technician that is qualified, to the satisfaction of the Executive Officer/Air Poilution Control Officer, to perform a tune-up in accordance with the procedure described in Attachment i; or 4) be operated in compiiance with the applicable emission ievels specified in Subsection III A.

IY. Exemptions

A. Units subject to the requirements of Subsection III A which normally burn only gas shall comply with a 150 ppmv, or 0.215 pound per million Btu of heat input, NOx emission limit when burning nongaseous fuel, if gas is unavailable for purchase. This exemption is good for not more than 168 hours of operation per calendar year, excluding equipment and emission testing time not exceeding 48 hours per calendar year.

Y. Compliance Requirements

A. Comoliance Schedule
The owner or operator of units subject to this determination shall fulfill the following increments of progress: 1) Submit, within two years from the date of adoption of this determination, a plan containing the foliowing:

A.5(a) A list of all units with their rated heat inputs and anticipated annual heat inputs. (b) For owners or operators of units subject to Subsection III A, for each unit listed, the selected method of achieving the applicable standard or standards of Subsection III A.
(c) For owners or operators of units to Subsection III B, for each unit listed, a selection of one of the four options specified in Subsection III B to achieve compliance with this determination. 2) 4lithin four years from the date of adoption of this determination, demonstrate final compliance with all applicable standards and requirements of the determination.

.iIN I I- ii

~ • • ~ 1) An owner or operator of any unit(s) shali have the option of complying with either the pounds-per-million-Btu emission rates or parts-per-million-by-volume emission limits specified in Subsection III A. 2) A11 emission determinations shall be made in the as-found operating condition, except that emission determinations shall include at a minimum one source test conducted at the maximum firing rate allowed by the district permit, and no compliance determination sha11 be established within two hours after a continuous period in which fuel flow to the unit is zero, or shut off, for 30 minutes or longer. 3) A11 ppmv emiss{on limits specified in Subsections III A and IV A are referenced at dry stack-gas conditions and 3.00 percent by volume stack-gas oxygen. Emission concentrations shall be corrected to 3.00 percent oxygen as follows:

[ppm NOx] = 

### 20.95% - 3.00% x(pp m NOx]

corrected 20,95% - [% 0 ] measured 2 measured

= 20.95% - 3.00%

, ~ [ppm CO]corrected 20.95% - [% 0 ] [ppm CO]measured 2 measured
4) A11 pounds-per-million-Btu emission rates shall be caiculated as pounds of nitrogen dioxide per million Btu of heat input.

A.b5) Ali emission concentrations and emission rates shall be based on 15-consecutive-minute averages. The averages shall be calculated from no less than five data sets, recorded from samplings on intervals of no greater than three minutes. 6) Compliance with the NOx emission requirements and the stackgas carbon monoxide and oxygen requirements of Section III shall be determined using the following test methods. (a) Oxides of Nitrogen - ARB Method 100
(b) Carbon Monoxide - ARB Method 100 (c) Stack Gas Oxygen - ARB Method 100
(d) NOx Emission Rate (Heat Input Basis) - EPA Method 19
(7) Integrated sampling methods for ozides of nitrogen, stack-gas oxygen, and stack-gas carbon dioxide, as approved by the Executive Officer/Air Pollution Control Officer, may be acceptable for determination of compliance with NOx emission concentration or rate limits.
(8) Ail units covered under Subsections III A and III B shall be tested for compliance not less than once every 12 months, except that units complying with Subsection III B(3) shall be tuned not less than once every 12 months. (9) A violation of the plan required under Subsection V A(1) shall constitute a violation of this determination. (10) The cumulative annual usage of each fuel shall be monitored from utility service meters, purchase or tank fill records, or by any other acceptable methods, as approved by the Executive Officer/Air Pollution Control Officer.

C. 

### Administra ive Requirements
1) The owners or operators of units subject to Section III of this determination shail monitor and record for each unit the NHU and cumulative annual usage of each fuel. The owners and operators of units exempt from Subsection III A in accordance with Subsection IV A shall monitor and record for each unit the cumulative annual hours of operation on each nongaseous fuel. This data shall be updated weekly and made available to district or state auditors upon their request. Nistorical annual data for the three previous calendar years shall be kept and made available by the owners and operators. 2) The owners or operators of units subject to Section III of this determination shall submit compliance test reports on each unit for each fuel burned, including any fuels which may

A.7be burned in accordance with Subsection IV A, not less than once every 12 months; except that tune-up verification reports shall be submitted not less than once every 12 months for each unit cornplying with Subsection III B(3) for each fuel burned. Test reports shall include the operational characteristics ofall flue-gas NOx reduction equipment. The first test or tuneup report, for each unit subject to Section III of this determination, shall be submitted within four years from the date of adoption of this determination.

D. 

### F.quipment Req irements
1) Owners or operators of units which simultaneously fire combinations of different fuels, and are subject to the requirements of Subsection III A, shall install mass flow rate meters in each fuel line. Alternatively, volumetric flow rate meters may be installed in conjunction with temperature and pressure probes in each fuel line. 2) Owners or operators of units which employ flue-gas NOx reduction technology, and are subject to the requirements of Subsection III A, shall install meters as applicable to ailow instantaneous monitoring of the operational characteristics of the NOx reduction equipment.

A.8Attachment 1 Tuning Procedure IL

Nothing in this Tuning Procedure shall be construed to require any act or omission that would result in unsafe conditions or would be in violation of any regulation or requirement established by Factory Mutual, Industrial Risk Insurors, National Fire Prevention Association, the California Department of Industrial Relations (Occupational Safety and Health Division), the Federal Occupational Safety and Health Administration, or other reievant regulations and requirements.

1. Operate the unit at the firing rate most typical of normal operation. If the unit experiences significant load variations during normal operation, operate it at its average firing rate.

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

~ gntration, and CO concentration (for gaseous fuels) or smoke-spot number (for liquid fuels), and observe flame conditions after unit operation stabilizes at the firing rate selected. If the excess oxygen in the stack gas is at the lower end of the range of typical minimum values

~ / , and if CO ernissions are low and there is no smoke, the unit is probably operating at near optimum efficiency - at this particular firing rate. However, complete the remaining portion of this procedure to determine whether still lower oxygen levels are practical.

3. Increase combustion air flow to the furnace until stack gas oxygen levels increase by one to two percent over the level measured in Step 2. As in Step 2, record the stack gas temperature, CO concentration (for gaseous fuels) or smoke-spot number (for liquid fuels), and observe flame conditions for these higher oxygen levels after boiler operation stabilizes.

4. Decrease combustion air flow until the stack gas oxygen concentration is at the level measured in Step 2. From this level gradually reduce the combustion air ftow, in srnall increments. After each increment, record the stack gas temperature, oxygen concentration, CO concentration (for gaseous fuels) and smoke-spot number (for liquid fuels). Also, observe the flame and record any changes in its condition.

1/ This tuning procedure is based on a tune-up procedure developed by KVS, Inc. for the EPA. This procedure is included as Attachment 2 to this determination. 2/ The smoke-spot number can be determined with ASTM test method D-2156 or with the Bacharach method. ASTM test method D-2156 is included as Attachment 3 to this determination. The Bacharach method is included in a tune-up kit that can be purchased from the Bacharach Company. 2/ Typical minimum oxygen levels for boilers at high firing rates are: 1. For natural gas: 0.5 - 3% 2. For liquid fuels: 2- 4%



### A.95. Continue to reduce combustion air flow stepwise, until one of these limits is reached:

a. Unacceptabie flame conditions - such as flame impingement on furnace walls or burner parts, excessive flame carryover, or flame instability.

b. Stack gas CO concentrations greater than 400 ppm.

c. Smoking at the stack.

d. Equipment-related limitations - such as low windbox/furnace pressure differential, built in air-flow limits, etc. 6. Develop an 0/CO curve (for gaseous fuels) or 0/smoke curve (for liquid fuels) similir to those shown in Figures 1 and i using the excess oxygen and CO or smoke-spot number data obtained at each combustion air flow setting. 7. From the curves prepared in Step 6, find the stack gas oxygen levels where the CO emissions or smoke-spot number equal the following values:



## Eut1 Measurement Value

Gaseous CO Emissions 400 ppm

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

#4 Oil smoke-spot number number 2

#5 Oil smoke-spot number number 3

Other oils smoke-spot number number 4
The above conditions are referred to as the CO or smoke thresholds, or as the minimum excess oxygen levels.
Compare this minimum value of excess oxygen to the expected value provided by the combustion unit manufacturer. If the minimum level found is substantialiy higher than the value provided by the combustion unit manufacturer, burner adjustments can probably be made to improve fuel and air mix, thereby allowing operations with less air.

A.10! I 'e a

n a v c_

m ~ 

### o ~ 0


### E

~ 

### Figure 1
Ozygen/CO Characteristic Curve

Sreso C0/07
crraracrrnanc

Graaual CO/Oz cnaratrerrsnc
Approartate oaerarrng margrn trom mtnrmum Oz

r Automabc ControlS CO limrr aoiustea ro rnia t400 aaml O? iever

Mtnrmum OZ ~~

1

O■ygen in hue gas.


### Figure 2
Oxygen/Smoke Characteristic Curve

Sreso smoas/OZ crtaracrerrsrrc

l 

### m d E c

c ~

Y E N Graeuar 

# ~

Smoka/07 OnaracrerlSllC \ Aoproanare oaeraung j margtn rrom mrnomum 01



# ~ Automauc poder Smoxe rrmrt conrrors aausrea 

# ~ to rrus O? rever

Minrmum OZ

~ I i

Oxygen l in nue gas, °o

—0—

4/89 ATTACFMENT 1 Rule 74. 15 : 8

## APAEkDIX F Siqnificant Conments and Responses

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

"The proposed BAR[CT] limits of 30 ppm NOx on gas fuel and 40 ppm NOx on liquid fuel are substantially lower than the limits contained in ARB's 1987 Suggested Control Measure ('SCM')..."
Response: We agree with this statement. The SCM was approved by the California Air Pollution Control Officer's Association's (CAPCOA's) Technical Review Group (TRG) on April 20, 1987, and approved by the Air Resources Board (ARB) on September 10, 1987. The SCM was developed to guide the air pollution control and air quality management districts in their consideration and development of rules and regulations. The SCM is based on reducing oxides of nitrogen (NOx) emissions from industrial, institutional, and commercial boilers, steam generators, and processheaters by approximately 40 to 45 percent with an average costeffectiveness of about $1.00 to $3.00 per pound of NOx removed. Since the approval of the SCM, four district rules have been adopted or amended, which have more stringent standards than the SCM. These rules have taken advantage of improvements in NOx emission control technology in the last few years. The proposed RACT/BARCT determination also reflects these improvements.
Furthermore, on September 30, 1988, the California Legislature enacted the California Clean Air Act (CCAA), which requires each district with serious or severe air pollution to include in its attainment plan a requirement for the application of best available retrofit control technology (BARCT) to existing stationary sources. "Best Available Retrofit Control Technology" means an emission limitation that is based on the maximum degree of reduction achievable, taking into account environmentai, energy, and economic impacts by each class or category of source.

"The proposed BARCT limits go beyond the technology that is available for retrofitting existing equipment... We estimate that a 94 percent reduction would be required to meet the proposed 40 ppm limit... In any event, the cost of providing SCR on our existing heaters and boilers would probably exceed the cost of new heaters and boilers... We suggest that the BARCT for NOx emissions from boilers and process heaters either exempt devices that are permitted to burn residual fuel oil, or include a NOx limit for those devices that is achievable by combustion modifications such as low NOx burners and flue gas recirculation." Resp2nse• We know of no technological reason why selective catalytic reduction (SCR) cannot achieve 94 percent reduction to meet 40 ppm NOx; however, we believe that the commentor should also consider the cost of

F.2retrofitting low-NOx ernitting burners plus a lesser degree of SCR. A NOx reduction of 0.78 pounds per million Btu is likely to be relatively cost-effective. The cost-effectiveness estimates contained in the technical support document (TSD) for the SCM are based on NOx reductions of 0.05 to 0.35 pounds per million Btu. The difference between the cost of retrofitting an existing unit to meet the BARCT standard and the cost of installing a new unit with best available control technology (BACT) is dependent on the size of the unit, the type of emission control equipment required to meet standards, and other site-specific factors. For a large unit burning residual fuel oil, retrofitting to meet BARCT is probably much less expensive than installing a new unit with BACT. This is due to the facts that the cost of a unit increases with its size, and that flue gas emission controls would be required in either case. On the other hand, if a small gas-fired unit requires flue gas emission controls to meet the BARCT standard, and a new unit without flue gas emission controls complies with BACT, then the cost difference between the two choices may be negligible, or the new unit may cost less than the retrofit. In deciding whether to retrofit or replace a unit, the age of the unit at the final compliance date should also be considered. An exemption for units burning residual fuel oil does not encompass the scope of the CCAA requirement of BARCT for existing stationary sources, nor does a standard based solely on combustion modifications. Flue gas recirculation is not effective at reducing NOx emissions originating from fuel-bound nitrogen.

"South Coast Air Quality Management District ('SCAQMD') Rule 1109, Section (b)(1)(A)(ii) requires devices operated or liquid fuel to meet a NOx limit of 0.308 pounds per million [B]tu."



### Resoonse: SCAQMD Rule 1109 was amended on August 5, 1988. For 36 percent of the refinery-wide heat input to applicable units by December 31, 1992, and for 100 percent of the refinery-wide heat input to applicable units by December 31, 1995, the rule will require that NOx emissions from each applicable unit not exceed 0.03 pound per million Btu of heat input when firing at the maximum rated capacity. This limit is approximately equal to 21•parts per miliion by volume (ppmv), corrected to 3 percent oxygen (0 2 ), relative to dry stack gases, when firing residual fuel oil.

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

The proposed limits contained in the determination would make the use of residual fuel oil unaffordable and thus adversely impact the ability to obtain competitive natural gas rates, and operate during periods of natural gas curtailment.

Res o n nse: In our drafting of the proposed determination, we included a provision which allows the use of residual fuel oil for up to 168 hours during a calendar year in the event that natural gas is curtailed, subject to an oxides of nitrogen emission limit of 115 ppm. Based on this comment and our subsequent review of emission limits, we have increased the oxides of nitrogen emission limit to 150 ppm. We believe that the use of low-NOx burners designed to meet the emission limit for natural gas can readily achieve the 150 ppm limit when using residual oil.

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

"ARB states on Page 3[of the 7/5/91 revision] of the determination report (report) that 'most units can meet [the 30 ppm] limit by installing new burners with flue gas recirculation.' No evidence in support of this belief is presented in the report. The paragraph goes on to say that '30 ppm is the appropriate BARCT NOx emission limit due to the many units currently operating within this limit without the use of flue gas emission controls.' Again, not one case is sited to support this claim. If these units exist, we need to know the circumstances under which they operate. It is also unclear how any unit, new or retrofitted, can meet a 30 ppm NOx limit 'without the use of flue gas emission controls."'



### ges onse : We do not have a list of units which are meeting the 30 ppm limit. We believe the most convincing evidence for the appropriateness of a 30 ppm BARCT limit is the SCAQMD's recent adoption of Rule 1146.1 for units 2 to 5 million BTU per hour in size. The 30 ppm standard for these small units is based solely on combustion modifications. The same or similar control technologies as which are the bases of the standard for the small units have been, and will be, applied to larger units. Burner manufacturers have not challenged the technical feasibility of the 30 ppm standard for larger units, though they have indicated to us that not a11 units can be economically retrofitted to meet the standard solely with combustion modifications. For some units selective noncatalytic reduction or selective catalytic reduction may be the preferred method of NOx emission control. Economic and other considerations have caused, and will cause, operators of units less than 50 million Btu per hour in size to favor combustion modifications over flue-gas emission controls in their selection of retrofit emission control equipment.

"Even though the report states that 'consideration should be given to the incremental cost-effectiveness of achieving the lower 30 ppm,' both [the SCAQMD•and Ventura County] districts wi11 be forced to spend asubstantial amount of time proving that the incremental costeffectiveness of achieving the lower 30 ppm limit is too high."

F.5Bespon;g : The determination has been modified to state that districts which have adopted rules between July 18, 1988 and July 18, 1991, covering the applicability of this determination, are considered to be in compliance with this determination.

"This lack of factual support [for the 30 ppm limit] is made worse by ARB's position that BARCT should be 'technology forcing' when Health and Safety Code Section 40406 states that BARCT means `the maximum degree of reduction achievable.' This means that any technology that cannot yet be achieved goes beyond the definition of BARCT. Any technology that has not been proven successful is inappropriate."
Resp9.a 5e : This RACT/BARCT determination is not "technology forcing." All of the technologies described in the report, and which may be necessary forcornpliance with the BARCT determination, are proven, available, and inuse in California.

"Selective Non-catalytic Reduction (SNCR) is discussed on Page 7. Table 2 implies that the applicable range for this technology is 50 MMBTU/hr or more. It is not clear if units in this size range have flue gas temperatures in the 1600 to 2200 degree F range. Stack gas temperatures for the two large units in our report are 591 degrees F (Arcturus) and 760 degree[s] F(Rocketdyne). SNCR is offered as a viable possibility on Page 3, but, in fact, it may work on only a small percentage of units. On what units will SNCR work?
RespQJIsg = SNCR injection is not normally retrofitted to the stack or flue gas ducting. A flue gas temperature of 1600 to 2200 degrees F indicates an extremely low combustion efficiency. Normally an SNCR injection grid is retrofitted within a unit at the downstream end of the furnace. SNCR will work on all units which wili allow adequate residence time within the reaction temperature window.

"There is no basis for the 40 ppm lirnit for units burning non-gaseous fuel (Page 3). No information is provided on the source of this limit or how it wi11 be met. Under what circumstances is this limit applicable?"

ResoonseInformation has been added to the report regarding the use of inethanoland specially blended oil to meet a 40 ppm limit for units burning nongaseous fuel.

F.fi"Limiting total use of non-gaseous back-up fuel to 168 hours per year is unreasonable. Back-up fuel is typically used during natural gas curtailments; we cannot assume (without vast statistical support) that

... curtailments will always last less than 168 hours (seven days) per year. Back-up fuel equipment must be tested periodically; a 168 to 200 hour per year limit on testing would be reasonable."


### ResQonse• A 168-hour allowance for burning back-up fuel will enable unit operators to qualify for a noncore (lower) rate for purchasing gas. If the higher NOx emission concentration of 150 ppm were not subject to a time limitation, it could not be allowed under the RACT/BARCT determination. Operators must be prepared to either (1) pay a higher rate for gas, (2) have a back-up gas supply, (3) meet RACT/BARCT standards for nongaseous fuel firing, or (4) shut down, when gas is unavailable for purchase for more than 168 hours per year. 

### We have added an allowance of 48 hours per year for equipment and emission testing with back-up fuel burning.

"Selective Catalytic Reduction (SCR) needs additional discussion (Page 8). As noted above for SNCR, stack gas temperatures in the 570 to 845 degree F range occur only in very large units (over 100 MMBTU/hr). Does this mean that flue gas preheaters will be required? On.Page 9, the cost effectiveness of SCR is all but ignored. This technology is extremely expensive, which is exactly why it was not considered to be a reasonable emission control technology for industrial boilers in Ventura."

### ReiponseLow-pressure heating boilers operate at saturated steam temperatures not exceeding 250 degrees F. They may have flue gas temperatures as low as 400 degrees F. For most units, a flue-gas temperature below 570 degrees F is difficult to achieve without an economizer and an air preheater. An SCR reactor should be appropriately located in the flue gas ducting to optimize the catalytic reaction. It is unlikely thatSCR technology will be necessary to control NOx emissions from lowpressure heating boilers. However, if it is necessary, a boiler may have to be modified to operate at a higher flue gas temperature and lower combustion efficiency. The cost-effectiveness of SCR technology will be high for small boilers firing gas. However, there are other technologies available for use in complying with the BARCT standard.

'On Page 11 [of the 7/15/91 version], under Hazards, it is misleading to say that 'a majority of catalysts used in California are now reclaimed and recycled by the manufacturer.' 

### We believe that most of the catalyst material in the state is in Ventura County (by virtue of

F.7the IC engine rule) and, while some manufacturers may provide this service, we know of no organized recycling system. We are optimistic that increased use of catalyst material will lead to such a system."



### Res o p nse: We do not believe that the report is misleading.

"The RACT limit for 'other' fuels (III.A.2) should be increased to 150 ppm, similar to the 'exemption' limit in the BARCT section (IY.A). For RACT, 'other' fuels means fuel oil, and fuel oil is what the 150 ppm limit in the BARCT section is intended to regulate."


### Response• We disagree; the "exemption" limit is for units which normally burn only gas and applies only when gas is unavailable for purchase. Units with emission control equipment designed for gas-firing are allowed a 150 ppm limit for burning "back-up" fuel. We have extended the applicability of this exernption to the RACT standard, also.

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

"Section IV. of the draft determination BARCT rule (Appendix A) provides that boilers shall meet 150 ppmv or 0.215 lb NOx/MMBtu for no more than a total of 216 hours per year, including testing time, when natural gas is unavailable for purchase. Our experience with dual fired boilers indicates, that for at least boilers operating 24 hours per day, such a limited firing period is highly unrealistic. Pursuant to the above requirement, will the District require the temporary shutdown of a boiler if beyond the control of the owner operator gaseous fuel cannot be burned?"
Res,Ronse: The boiler operator may either (1) comply with the BARCT standard for nongaseous fuel firing, (2) obtain a back-up gas supply, (3) pay a higher (core-customer) rate for natural gas, or (4) shutdown the boiler.

"Gas supply curtailments are more likely to occur during the winter months due to increased public demand. In areas that are not likely to exceed ozone standards during the winter, restrictions on the use of fuel oil during these months may have little effect on ozone levels, yet may be difficult to comply with because of the increased likelihood of curtaiiment."



### Res o p nse_ A precedent has been set by Ventura County APCD's Rule 59, "Electrical Power Generating Equipment - Oxides of Nitrogen Emissions," to allow winter-month flexibility for fuel oil burning on days for which ambient ozone is predicted to not exceed 0.07 ppm. Districts should be careful in considering this approach. Emissions from fuel oil burning contribute directly and indirectly to ambient PM10. In Ventura County there is a strong daily correlation between no 

## ~ exceeding the 0.07 ppm 1-hour ambient ozone and not exceeding 50 μg/m 24-hour PM10.

"Is the intent of 150 ppmv for firing on nongaseous fuel not to allow the burning of No. 6 oil with standard nitrogen content? For No. 6 fuel, compliance with this limit would require controls beyond flue gas recirculation and burner replacement."



### Res o

~ 

### nse: The intent of the exemption of 150 ppmv NOx for firing a nongaseous back-up fuel is to aliow the use of residual fuel oil for back-up situations without necessitating additional emission control equipment beyond that required for gas firing. There is no standard for nitrogen

F.9content of residual fuel oiT; however, the range is 1000 to 8000 pprn by weight. 0.150 1bs/MMBtu (104 ppmv) NOx with Kern County residual fuel firing has been met with staged combustion without flue gas recirculation.

"If a significant amount of boilers in California are fired primarily on fuel oil, is the present supply of "specially blended" low nitrogen fuel oil sufficient to meet state wide needs? If not, than do the retrofit cost figures include installation of natural gas supply equipment?"

Res o

~ nse_ The BARCT standard for oil firing is cost-effective with fiue gas emission controls. Some boiler operators may determine that switching to gas firing with combustion modifications to meet a lower limit is less costly and therefore more cost-effective. The cost-effectiveness of using methanol or "specially blended" oil with combustion modifications to meet the BARCT standard will depend on the future demands and prices of inethanol or "specially blended" oil.

"Buyers have the option of lower gas costs if the supplier does not guarantee supply at all or most times. Do these cost figures include natural gas cost increases from the supplier which would result because the buyer (source) would not have the option of random curtailments."
Reaponse: The exemption for back-up fuel burning when gas is unavailable for purchase wiil enable the buyer to qualify for a noncore gas rate.

"The use of natural gas will increase with the various clean fuels programs for both stationary and mobile sources. Has the availability of future natural gas supplies been studied adequately to warrant the virtual elimination of fuel oil?"
Response• The economical choice of fuel and emission control equipment is left to the market interaction between the fuel suppliers, the control equipment suppliers, and the unit operators. Oil firing with flue-gas emission controls is considered to be available and cost-effective. The fuel supply and cost-effectiveness resulting from market interaction can only be better.

F.10"The NOx retrofit of a boiler may cause an increase in CO emissions. In some circumstances an increase to 400 ppm could cause an emissions change greater than 550 lbs/day. Although many low NOx burner manufacturers are reluctant to guarantee less than 400 ppm CO 3 in fresno County 100 ppm has been both required and achieved after FGR and burner replacement (135 MMBtu/hr boiler)."



### Res o p

~ 

### se_ In most districts, any CO increase from permitted levels will activate the new source review process. By necessity, operators will have to maintain CO emissions at levels which will not activate the new source review process. Therefore, operators should consider CO emissions as a factor in their selection of NOx emission control equipment.

F.ilm O O 7

C 0

~ ~

o c 0 E 0 n 

## m U



## ~ 0 a E 

## ~ c



## ~

~

: Y s: u7 Figure 1



### Oxygen/CO Characteristic Curve



# ~
E a Graduar COr 02 Ularactensrrc $tNp Co/o? cnaractoretrc

Appropnate o0eratrng margrn from mrnrmum O?

AulomalrC Controfs CO

~ imrt adlUSred to tnls N00 a 1 pml Op ferel
\

M+nrmum O?

O■ ygen in flue gas. % - -r



## Figure 2

Oxygen/Smoke Characteristic Curve

St••p amok.102 characterearlc

Graduar smokeiO ~

~ haratlsrrshc Approprrafs opsfafrrtg

~ margrn trom m+nrmum OZ

Automatrc Doder smoke trmrt controts adfusted ` to rArs O? rerel

Mrnrmum 0 2

Oxygan rn flua pas. X --r—



## Source: KVB Inc,

A.lz8. Add 0.5 to 2.0 percent to the minimum excess oxygen level found in Step 7 and reset burner controls to operate automatically at this higher stack gas oxygen level. This margin above the minimum ozygen level accounts for fuel variations, variations in atmospheric conditions, load changes, and nonrepeatability or play in automatic controls.

9. If the load of the combustion unit varies significantly during normal operation, repeat Steps 1-8 for firing rates that represent the upper and lower limits of the range of the load. Because control adjustments at one firing rate may affect conditions at other firing rates, it may not be possible to establish the optimum excess oxygen level at all firing rates. If this is the case, choose the burner control settings that give best performance over the range of firing rates. If one firing rate predominates, setting should optimize conditions at the rate.

10. Verify that the new settings can accommodate the sudden load changes that may occur in daily operation without adverse effects. Do this by increasing and decreasing load rapidly while observing the flame and stack. If any of the conditions in Step 5 result, reset the combustion controls to provide a slightly higher level of excess oxygen at the affected firing rates. Next, verify these new settings in a similar fashion. Then make sure that the final control settings are recorded at steady-state operating conditions for future reference.

A.12

# ~ 

# 'UNING iN©US i RIAL 3C1LER

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# -- ~ 

# 1

Attachment 2 

# Establish excess-air levels

Use the test program outiined befow to tdentify the minimum amount of excess oxygen reauireo for combustion of gaseous. liquid, and sotid fuels in industrial boilers
8y D E Sitore and M W McElroy, KV6 Inc

Once

~ our boiler Is in good workine r,rder I<ce Fart I oi this series. Aprii 1977l. the next ma;or step in tmprovtng .:fticienct. ind tn reductnc emtssions, ts :.o cstaoitsh the iuwest level oi excess iwgen at which thc untt can operate ::aiclv 3na still mett the clean-air laws. aincc :^ost industrtal boiicrs operatc over a reasonabiv broad load range. tests rnust be run at several firina rates to ietermine the mtnlmum excess-otivgen cvei ior each. Univ then can the combustion-control svstem bc tuned for obtimum fuel economv. At each tirin¢ rate investi2ated, excess oxygen In thc ftue gas shouid be varted from 1-Y: 7

c above the normal operating point. down to where the boiler just starts to smoke (Fig 4), or to where CO cmissions cxceed 400 ppm. This lattcr condition is referred to as the smoke or CO thresnoid. or slmpiy as the nnrtrrrtunt- ,j.rt•Qen pornt. The smoke threshoid generk apnnes to coak and oil tiring. because.moktne usuaih occurs bcturc CO emisstons reach sleniticant lcvels. The CO threshold pertalns to easeous fuels. The smoke threshoid for solld and liquid fuels recresrnts the iowest posstble excess-oxygen ;ecei at Ahtch acceptabie stack conaittons snll can be maintained. In terms of the 8acharactt smoke-spot number ISSNl scale, the maxtmum desirable smokc number for coai is 4 imeasured doμnstream or' the dust coliectort. For

~ o o irestduall oii. it aiso is 4: No. ? and low-suifur resl(i. a SSN of 3: tio. 4. a SSN of 2: and No. 2. a SSN of less than I. A proven mcthod for determining the minimum amount of excess oxygenrequircd for combustion invoives developing so-called oxygeniCO and oxygen/smoke characteristic curves, like those shown in Figs i and 6. Based on test measurements. thesc curves show how boiler sm:)ke and CO ievels change as cxeess oxN ecn is varied. Each of the fieures depicts two distinct cunts. rllustratlne the extrcmes in smoke and CO behavior that mav be encountered. One curve exhibits a verv eradual increasc in CO or smoke as thc minimum excess-osv¢en conditton rs rcached. The other has a gradual slope at reiatively high oxvecn icvcis. and a steep slope near the minimum-oxygen potnt. For cases rcprescntcd by this second curve, unpredictably high leveis of smokeor CO, or potenttall} unstable conditions, can occur wtth small chan2es tn atr flow. Thus, caution is required on your part when reducing atr dow near the smoke or CO threshold—that is, carcPullv monitor instrumenu and controls, flameappt:arance. and stack conditions simultaneousty. Decrease the level of excess oxygen in very small increments until there are enough data to show whether the boiler exhibits a gradual or stceo characteristic curtie. \ote. too, that trurboiier may exhibit a¢raduai charactcristic at one firing rate and a steep onc at another.



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

:. Establieh the desired firing rate and switch comiwstton controfs h'om automatiC to menual operatton. Make sure ali salety ;nrarrocxs are stifl luncrroning. Z. Recora boiler and stack data tpressures, temoeretures. etcl. ana ooserve flame conbitiorrs after boder operatton stabil¢es at '.^.e Rarticu;ar f:rina rate selecteo. If you tind that the amount ot cxcess oxygen in the flue gas ts at the lower ena of the range of

' . .olcal m,nrmum vatves tsee textf, and it CO arta smoke are at .ccec[acle revels. the boder orooably rs already operattng at near =D1rmuT 9rticlencv—ar r/1ts particLlar Jiring rate. It may stlll be -estracie. now3ver, t; comDlete the rematning portton :t tMs =roceQure, to aetermrne whether slill lower levets are practic8t. A .vora o' zautlon: rJo not assume tnat excess-oxvgen sett,ngs at

- ;ner rr- , nc rates also are close to the optinturrt. _. tncrsase atr flow to the turnace untll reaorngs ot e

~ cess wrterr
, at tne stacK rrcrease ov 1-2%a. Agatn. oe sure tc taKe :aorrlas arter boller operauon staollizes. ano note any cr,ances rn 3me conaltlons. =. Return air ftow to the normal leval ano begln srow!v to

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

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

~ ce5s-oYvoen reatllno, ZmoKe-soot nt}mber, lne eoncentratr7n Of '. :r n;;e oas. ane stacK temoerature tollowtng eacn chanoe.

7 ._r^Qmper not tC reaUce arT t:ow oy tnrottllno the curner atr reglstera# because this altera the tuel and air mvring charactenstics and compllcates the testa. Itlso. It you nm teate at low firing rates. which is not generally recotnmended (see step 9), keeo a uose walctl on the wrndboxifurnaee preswre difterentiet. II it crops too low, a fuel trip wdl be initiated by tne ourner sateguaras system. S. t:ontinue to reduee atr flow stepwne untll you reach one of hese hmits: e Unacceotable flame contlitions—sucrt as riame Imptngement on turnace waI1S or ourner p3rts, excesstve ttame carryover, or S.ame rnstaDNlty. • Hrgh level of CO irl the flue gas. * SmoKlna at tne staek. ao not c9ntUse smoKe wrth waler .aoor. suifur. or dust plume3, whch usuanv are wfvte or oray rn,scoearance. ano remember to obsarve ucar arr-ooiuunon crarcances.

0 IncomDlete burntng ot solid fuets. n-:coenrze tnts bv nrgn caroon carrvover t7 aust collectors or rncreasea 0uantltles 0t Comoust,btes In tne asn. a Equtpment-related limitations—sucn as iow wtnaboxiturnace

~ res5ure dttterentlal. Duitt-in asr-ffow Itmlts. etc. s. Develop O,/ srnoke or O,/CO charaetertslic curves, s mrtar

, o tr,ose snown tn Figs 4 and S. using tne excess oxygen ana CO :r smoKe-soot number aata obtained at eacn alr-flow setting.

=••wa.r.

~ av ratc


## A.13A irgb oiaistNw-ezygra reatiatg may indicate a burner malfunction or other fuel- or eq ui pment- related probiems. But realize that difTerent burner designs andfuels gtncrally have difrerent minimumoxygen requirements. ln addition, manyburners exhibit a higher minimumoxygcn level at low firing rates than they do at high firing rates. For these reasons. it is difficult to spccify a range ofminimum levels that would be considcrcd normal for all boilcrs. Rcsults of tests at many industrial power plant.s arc provided, howevcr, tohelp you judge whether the minimumoxygen levels you mtasure are typical values. The data: For natural gas, the typical range of minimum excess oxygen at high firing rates is 0.5-3 ° .b; for liquid fuels, 2-4%: for pulverized coal, 3-690; and for stokcr-fircd coal, 4-8%. Boilcr startup records showing initialcxcess-oxygcn conditions provide a valuabic refcrence point for your tuneup program. If current minimum-oxygen levels arc higher than expected, any necessary maintenance or repairs shouldbe completed beforc making final adjustments to the combustion-control system. Once the minimum-oxygen setting is established, the next stcp is to determine the appropriate operating margin above minimum oxygen where the boiler can be operated routinely. This lowest practical oxygen level for the boiler ofTers the optimum setting for high ef&ciency and, in most cascs. the lowest NO, emissions. The exccss-oxygen margin above the minimum-oxygen point accommodates:■ Rapid boiler modulation, whichcould cause smoking or a high concentration of eombustibkes in the flue gas.• Nonrepeatability or play in automatie controls I Ecccssive piay should be eorrectcd.)■ Normal vanations in atmospheric conditions, which also can change the level of exccss ocygen on units notequipped with temperaturc- and pressure-compensated combustion-air systcros. This ts an important factor, which often is nealected. Extreme variations in ambicni conditions can easily produce changes in excess oxygen of 1%

or more.■ Changes in fuel properties, which may require varving amounts of excess air at the burner.Typical margins above minimum oxygen may range from 0.5% to 2`9c, depending on the characteristics of thc partieular boiler-control system and thefuel being burned. if you think it necessary, the boiler manufacturer or a combustion consultant probably can establish a narrower range for your unit. Another point: (f the boiler is to be operated at a oortstant firing rate for extended periods, the smallcat possible margin should be sefected. Recognizing excessive play. A simple test can help you determine if there is cxcessive play (poor repeatability) in your combustion-control system. All you havc to do is to repeat a firing-rate eondition, allowing fuel and air oontrols to function in a normal manner. Approach thc selected firing rate from both higher and lower firing rates, andeompare stack excess-oxygen Ievels rccorded after each run. Make

- sure boileroperation stabilizes before taking reada. lfMqefntmn Ntart oMen a quldc way to determtne If boller anissiorts mest codes. Badtarach ecaie, moro aCCUrate, is better tor burrter adlustments

ings. Excess-oxygen data shoaid repeat to within a few tenths of a percent; a greater difference indicates excessivewear or toicrance problems in air dampcrs, controi shafts, valve cams, eontrollers, etc (Fig 7). Atmospheric rariatiom. Changes in air density at the forced-draft-fan inlet cannot be corrected like control-system play. Rtcognize that. while the f-d fan deiivers a certain volume of air to the burncr, as the air density ehanges. the numbcr of pounds of air supplied to thc

7. FMd tlw rnktYaultt axoaes-oxypat fwM for your boiler from the asras praparod Irt step 6, but do not ad)ust ttro burner controls to this value. Thougtt this may be trie point of maxinwm efflclertcy, as weN as minlmal NO, embaions, it uaually is Impraatical to operate the bofler at this setting, beeauae of the tendency to smoke, or to increase CO to dangerousty high levels. as load changes. Compare this minimum value of exeess oxygen to the expected value provfded by the boMer manufacturer. It the r.tlnimum IevNyou found Is substanthdly higher than the vendor's, bumer adiustments probably can Improve fuel and air mixing, thereby allowing operatEon with iess alr. S. Establish tMa margin. In excess oxygen above ihe minimum value, required for tuel variations, load changes, and atmospheric conditions. Add thls to the rninimum value and reset burner controls to operate automatically at the higher levei—the lowest practical setting at the particular firing rate. For most boilers. NO, emissions typica7ry wul be lower at the new setting than they were originalty, tt they are higher, hovrever, try to reduce them by adjusting tne burner. 9. Rapat stapa ta for each fkring rate to be t>•sted. Bear in mind that. for some control systema. It Is not posslble to establish the optimum exoass-0xygen level at each firing rate. Reason: Control adjustments at one firing rate also may affect conditions at other firing rates. In such cases, choose the Settings that give best performance over a range of firing rates. A triat-and-error approach, one InvoMrq rpeated tests, rrtay be rteoawary. 9ut tf one flring ra3e predominatee, settlnga aftotaid opUrt oortdltlons at that t•ate. Many experts agree that 1t ger arally ts beat not to make any ad)ustments to your control system whNe the boiier Is operating at low loads. Air-flow requirements at low-Ilre conditlons usuatty are dictated by flame Ignition characterlstics and stability (and they can be critical and dMflcult to evaluate) rattter than by eRidency. lf p ocees requiremsnts foreae your boiler to operate at low loads much of the tlme, check wltb tfte boiler manufacttxse's servke group or a qualified combuetion consultanl before estabgshing excess-oxygen levels. 10. Yertfy tftat your nevm aettings can aeeommodata the sudden load changes that may occur in deily operation without adverse affects. Oo this by Incressing and decreasing load rapidly while observing the flame and stack. If you deteet undesirable conditlons, reset the combustion controls to provide a slightly higher level of exeess oxygen at the affeeted flring rates. Next, vetify these new saftings In a slmilar fashion. Then make sure that the finat control settings are recorded at steady-state operating conditions for tuture reference. One flnal note: When an aitemative hiel is burnatl, perform these same tests and adjustments for the second fuel. Sinee it is not ahvays possibie to achleve optimum excess-oxygen levels tor both fuels at all firing rates, you must establish fhe besl eonditions at normel firing rates.

Powar.uaY •.-- S7EAMGENERA710tt 77 A.14.~ prr!c".+rE 7CC•,

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Oxvaen in +rue oas '- —1 1 - 5,6. Oxygsn/CO and otrygen/smoke characteristie ourves identity the mrnrmum amount of excess oxygen required for combustton

burner varies. influencing the amount of excess oxvgen. When combustion air issupplied from thc boiier room. maintaining a constant boiler-room temperature mtnimizes the oroblem. but atmospheric-pressure etTccts are unavoidable. Evsluati!ng new settings After the boiler has been tuncd and returned to normal automatic firing, pay close attention to the unit for a few weeks, until conhdence is gained in the new operating mode. Watch for any signs of unusual tube fouling or flame patterns, which might be corrccted by further burner adjustmcnts. Also, look for any cquipment or operating changes that may aIter the minimum-oxygenlevei—such as variations in fuel properties. inadvertent chan¢es in burner

~ ettings, new boiler•controi sctpoints. air-control-damper dcterioratton, andair-preheater piuggage. Assure continuous high efficiency and low NO, emissions on a continuous basis by plottinK periodic stack measurements (cxcess oxygen, CO, smokc. temperature) on ¢raph paper, and comparing thesc trends to the baseiine data obtainea durintt the boiler-test program. Burner adjustments

~ \s noted earlier. adiustments to the ,:ontrol svstem alone sometimes cannotimprove cf6ciency andior reduce pollutant emissions to desirable levels. In suchcases. you should carcfully inspect combustion equipment for proper operation. Often, you can achieve your operating goals by making changcs in: ■ Burner air-register settings (on swirl- or circular-type burners). • Oil-burner tip position with respect to the burner throat.+ Oil-gun difTuser position with respect to the burner tip snd• burner throat. • Fuel-oil temperature • Fuel-oil atomizing pressure. • Coal-spreader position. • Cual size. The effccu of such adiustmertts onNIO, formation and on mtnrmum excessoxygen Ievels vary from unit to unit. and are difficult to preoict. Therefore, you should use a trial-and-error procedure when making ehanges. But be sure vour program is sufficientiv organized toassure adeauate stack and flame monitoring. Observe thc gcneral precauttons gtven for the excess-oxygen adiustments (see boxl. Sueh modiPtcattons to the firin¢ svstem are best fa

ctoreo tnto the excess-oxvgen adjustment tests (step 7 in box). This insures that changes arccompleted before the final controlsystcm adjustments are made. Aiso. after adjusting the burner, make a complete set of stack measurements todetermine whether the change is producing the desired effects. F'inally. makc all burner adjustments slowiy, to allow adeauate time to evaluate esch move. Look for any other changes rn burner settings or fuel properties that mtght also atTect the flow of air or fuel to the boiler and produce uncontrolled shifts in the cxccss-oxvgen level. The range of adjustment possible for the parameters listed above depends on the design of the burner or stoi:er and itsparticular operating charactertstres. Example: It may be possible to van the airregister settings on one boiler from :Or'e to 80% of full open. while or enother unit fittle or no adjustment i

~ c-lcttcal. For the fatter. further openrnp Dr !he atr register Ireducing air swirll -:a} cause flame tnstabilitv. while bv ciosrns ofi the atr rcgtsier tmore swtrit vou rr_

~ wrdert the tlame. causing flame imc:necmenton the burner throat or furn_,e sidewalls. Rcad thc boiler operat:ng manuaifor informatton on %our hr:r.g tquipment. 1n important ilctor in o_tarnrng complete combustion ol fuel e:; at low cxcess-oxvgen Icveis is ,o mairtarn thc proper atomizing temperature. This is dictated b
~ the fucE

~ tscostt
~ recommended bv the burner manutacturer. Typical viscostty ranges for various liquid fuels and burner types arc gtven in Fig ts. For stoker firing, coal sizc I Fig 9) is imnortant. i4G8

°c •e• Msy 19•' T. E:usttire play ,n posrtronrng combustion controts can be rclentrfted by marKrng lrnkage posrtion for a panrcular firing rate and then aDproacnrn(j that rate from Doth hrgher ano lower firing rates. Linkage posnion tor tne two test runs snoutd match the origrnai setting



## A.15Attachment 3



# I~ DesFpnatlon: D 2736 — 80

Standard Test Method for 

### SMOKE DENSITY IN FLUE GASES FROM BURNING DESTILLATE FUELS'

Thts sun.Urd ts tuued under the I11ed devgnaluon 021'0. the numher immedulcl% lollow•tnp Ihe ucsRnanon ,ndtcotes the ytu, unpnal a000uon or. In lhe case ul revsldn. the vur of last nR•rsuon \ numhet rn parcntheses indicates tht rpr PI ISI ropprpp ` A sunrrrnoa e)'}{tlon tr 1 indtcatcs dn cditunal chanEe stnce UNC iut re%ts+nn nr reappro%Ji.

1. Scope 1,1 This method Co.crS the evaluatton of smoke densnv tn the Ilue eases from burntne dtstillate fuels. It is intended primarilv for use wtth home heating equtpment burntnc kerosino or heattne otls. It mav be used in the laboratorvor tn the tield to compare fuels 1•or clean burnlne ur t. :ampare heattn_ eyutpment

Z- Applicable Document
2.1 .4ST.if Standard: E 97Test Method for 45-'. 0-' Directtonal Retltctancc Factor of Opaquc Spcctmcns h} Broad Band Filtcr RefJcctumctrv=

3. Summtrv of vlethod 3.1 A test smoke spot is obtained by pulline a futed volume of flue gas through a ftxed area of standard filter paper. The coior (or shade) of the spot thus produced ts vuually matched with a standard scale, and the smoke denstty ts expressed as a"Smoke Spot Number."

A. SignificanceJ I This method provtdes a means of controlJtne smoke productton tn home heatine equtpment to an acccptable level. EzcesstNe smoke densitv adverselv affects effictencv b%heat-e><chaneer foultne4.2 The range ofsmoke densines covered bythts method ts that whtch has been found particularh perttnent to hnme-heattng applicatton. )t ta more sensittve tn .mall amtronts of smoke tfian aeteral othcr ,moke test, ,t, ln.11c•at:d tn the folluwlne compartson: Smake spot Icham. percent Rtngetman `umber Transmtulon Smnke Numbet

F IB J

lo c
t. Description of Termti 5.1 The test result is reporrted as the "Smoire Spot Number." which is the number of the spot on the standard scale most closety matchin6 tbe color (or shade) of the test spot.
6. Apparatus b.l SamphnR De+-ue—A wttable devtce provldtng a totai flue eati samplc volume of 36 900

~ 1650 cm` at Ih ° C. I atm (2250 = 100 in.' at 60 0 F. I atm) for each b.45 cm` ( I in.') efiective surface area of filter paper shall be employed The sampling devtce and connecttons shall be of such constructton that the total travel of ttue gas sampie from flue to ftlter paper shall not exceed 410 mm 116 tn.). The devtce shall proa vtde for cooltng the sample below the charrinE temperature for the filter paper but not belor'the deA point of the sample. Suitable labaratory and ponable field servtce equipment ts tllustrated tn Fie>. I and 2.
t+ - Smr!!<e S<u!r—The smoke.cale requtred

r hn mr!hud n undcr ihclunaltctuun M>ti I\1 C,rmmttiR IY: on Prtrokum Pr'tlurt4 und t.uhncam. t urtont cdltuon u{+pr—td \ur _ 4 IVkfr PuMmnrd OC10e'

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### A.16Ch o 2156
conststs of ten spots numbered consecuttvelv from t) to 9. ranetne m eyual photometnc steps from white throueh neutral shades uf gray to black. tmpnnted or otherktse processed on whtte paper or plasttc itock ha , tng a surface retlectance of betNeen S_ ` snd •4' S%45`. 0°davlteht lumtnous dtrecaonai rcilectance m accordance with Method E 9' The smoke scale spot number is defined a> the reductton (due to smoke) tn reflected tnctdent li¢_ht divided bv 10. Thus. the first :pot. wht.h ts the color of the untmprinted scale. will he No. ll. stnce in the case of this spot there util be no reductton tn reflected incident hght dtrected thereon. The last spot. however. ts tierc dark. reflecnne onlv IU `', of the inctdent lisht dtrected therenn: thus tn this case the reduction tn rttlected trtctdent litht is 90 1-

,, ahich eues w this darkest ,pot thc'`10 v lnterrnedt,tte ^imher.. arc +tmtlarly establishcd. Limn> of permtsstble retlectance vanatton of anv smoke scale spot shall not exceed t3 r rclatnc retlectance (Notes I and 2).Nuir I- Such .mnt,e scalc, are suffictenth accurate for field use and fur manv laburatorv smoke testm6 applicattons. However, specsallv cittbratedsnles {known as certrfied smoke scates) wdl someumea be required. A certtfied smoke scate is obuined bv tndividuallv calibtattnE each smoke spot of a narmal ,moke ceale Nort :- Wherc thc mnke .4 1 e n protected w'ith a plaauc nr transparem cr.er thc ronxtrucuon empic+ved sh,iVl bc .aucn thji w her. the ,,moke
, pa+t +n the filter paper Iti vlQwed fur mat.htnz with the numher
s po ts on the smnke scatc. tx+th shall be vtstble throughthe same thtcknesc and number of sheets oi transparent protecuve cover

7. Haterrals 7.1 Tesr fiher Paper, made from white filter paper stsxk having a.urface rellectance of R2.5 to N7.5'45°. 0' davlteht lumtnous dtrecttonal re(lectance, in accordance wtth the Method E 97. When cJcan atr aI standard cnndittons ts drawn throueh clean lilter paper at a rate ol 47.6 cm'/s-cm' I 11_5 tn , mtn-tn't eflectt%e surface area ol filter paper. the prc.%sure drvp acrosn the filtcr paper

~ hould fill betKecn itmrt, of 13 and 64 mm 10.5 and 2.5 tn.t He. S. Procedure 8] The sampline prcxrdurc used is .nucal Therefore, the procedure recommended hv the equipment manufacturer .hall he ngtdh 101- lowed. 8.2 Use a clean. dn. >Jmphne devtcc. If a hand sampler is used. warm tt abovc noom temperature to prevent condensatton on thefilter paper. SThis mav usuallv he donc convenientiv bv plaeine the sampler on the hotler or furnace to be tested.t 8.3 ]nsert fitter paper tn ;hc ,amplcr antl ttghten the tilter paper holdcr. Conncct the sampling device to the flue 2as probe tiL'hen takine smoke rrteasuremer.ts tn the lluc ptpe. pcisttion the end of the wmpttne pn+hr at the ccnter line of the tlue ptpr. 8.4 Draw the requtree .ample If ,t hsnd sampler t. u+ed. permtt :hc presaurc> tn ttte Ilur gas stream and the sampier to cyualtze atier each stroke. 8.5 Remove the filter paper. Compare the test spot backed with a ptece of White paper nrplasttc having 45". 0'' dasltpht lumtnuus Jtrectional reflectance of not less than 75 G, wtth the standard scale.
9. Report 9.1 Report the .moke denstt% a, the Smoi.e Spot Number on the stanslurJ scalc mu.tclosdv corrcspondtne t.+ the tea Nlx)t. Interpolate diffcrences between two standard SmukcSpot Numbers to the nearest haif number. Repon Smoke Spot Numbers ht¢her than 9 a.c "Greater than No. 97

NOTE 3—Wheremoreaccuratcresultsatedestred. the human factor tnvolved tn visuallo _ comparing Rlter paper test spots wtth smoke scale spots can bec6minated by reson to dtrect use of a suttablc photometer far evaluattnr tcst .rtt, Thts pr,ticJurc t

~ dckrtbed tn the Annez

IU. Pretision 10.1 This tezt ts reproductblc to wtthtn ±: of a Smoke Spc

- st Numher under normal nonditions. Nrrrt 4-\urmal %:undttion• are detined as tn—c where no odv statn ts deposited on the dtsk

A.174D D 2156

F It 't'ER Dt'SC

COOLER REGULATOR CONDENSER vALVE

SAMPLING ~ TIrvER 1U13E
\ 

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L DRAIN DWPF4RAGM l a~~A~~~ _ /,-

~

THROTTUNG ORtFICE

PUhtP

F'if:. t Labutaton 1

- ,pe Smoke titrttr

reflectcd from thts clean surface. Expo.e tcst smoke spot on filtcr paper to thc ph xometer ltght heam and measure the percentagc rcducuwm tn reflected itEht due to the presence ol smu e panicles on the fdter paper. Gross Smukc Spt
, t Number shall be defined as eyuai to the percentage reductton tn reflected hEht dtvtded bv ten.

41.2 Photometer Specifications A 1.2.1 The photometer to he empinved 6 r direct teIt spot number evaluat on 'hall he uf the cicctricall% k perated reflectance trpe emnluvtng a photuelectrtc cell, fitted wtth a spectal hoidertst to accommodate P1L'

FiC. 2 Firld tieeviet Tr*e Sreoke Testtr

ANIVEX

A1. ALrt:RtiATIVF: PHOTOMETRIC METHOD

ALI Direct Photometric Evaluation
A I.1 1 The human factnr tnvolved in visualh compartng filter paper test s{x.ts wtth +moke Ncale spots cjn bc ehmtnated hN rcwrt to dtrect ux ot a

~ uttahle photometer fur c%aluaung test ;pots To make thts dtrect photometrtc test spot evaluauun. thefollowtne procedure shall be cmplovedAI.I -I l blount a cleaa. unused fdtcr paper. baekctl bv a plaque painted % th S12O or matenai havtng a 45`. U davls g ht iuminuus dzrectwnal reflcLtance of not lcs , than '5' -, . in the heht beam ni asuitahle tvpe rctlectance phowmcter- 4djust thc photometcr to read 100 : rellectance tn tertns of the ItEht



### A.180 D 2156

tiper paper test zrecamens. It !n t t , he ca}Lhft ,t ,,! ar•rr,

, a,matel. :U. 441. tdl. and 741 -

~ 0`t'. 0" da%lt¢ht mca.curine the 45. U Ja%h¢ht lumtnouc dlrectl.mal :umlmou.
, dtrectu+nal rellectance. to permtt ph, , t,+ntretlecuace !t !s to he iurnl+hcd completc wah i cter readmzs hetween Il) and dit It Iretattve a

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

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

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

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

TMl1 SfarldQld tJ SIfh/Kl !r rrYLSlOrI QI aQt Ar
, rrYlrMYd rYfrv !1!'( 11'Jr' yl,r n nn+ rrrrsrd. nthrr rrarrrmrd "r •'rrhdrar'n lavr .;

~ rn

~ nr+r ~ ~ rr :n.v

~ d rltkrr lor .rr/von n/ rhro uandard ur ror ~J~ c+. n

~ . ,!,ln

~ s,u

~ nJshoriJbcaJdressrdl

~ .tST.1lHradqvarer, 1 our;nmmrnlswdirrrnrfrarr/4JConsldrrarulnala+erNlneQl'nr .rspowrlbk nrM/ralcol

~ wtrrer, rlucA vwl wlav arrewL !f ror irrl rAar vwr eonnwr.n haw ao+ rerrnrd a falr brarvl; wr lkar+.r rkr raw rrrrlFwarw to rhe ASTM Cawuwrner on Srawdardf. JaJO Rare Sr., pkiladrlphla. Pa 10101



### A.19

### APPENDIX B

SCAQMD Rule 1146.1 Emissions of Oxides of Nitrogen From Small Industrial, Institutional, and Comrnercial Boilers,

Steam 6enerators, and Process Heaters

B.1

### (Adopted October 5, 1990)
RULE 1146.1. EMISSIONS OF OXIDES OF NTTROGEN FROM SMALL

INDUSTRL4i., INSTITUTiONAL,, AND COMMERCIAL BOILERS, STEAM GENERATORS, AND PROCESS HEATEILS

(a) Definitions (1) ANNUAL. HEAT INPUT means the actual amount of heat released by fuels bumed in a unit during a calendar year, based on the fuel's higher heating vaiue. (2) BOILER OR STEAM GENERATOR means any combustion equipment fired with liquid and/or gaseous fuel, used to produce steam or to heat water, and that is not used exciusively to produce electricity for sale. Boiler or Steam Generator does not include any waste heat recovery boiler that is used to recover sensible heat from the exhaust of a combustion turbine or any unfired waste heat recovery boiler that is used to recover sensible beat from the exhaust of any combustion equipment. (3) BTU means Britisb thermal unit or units.. (4) NO, EMISSIONS means the sum of nitric oxide and nitrogen dioxide in the flue gas, collectively expressed as nitrogen dioxide. (S) PROCESS HEATER means any combustion equipment fired with liquid and/or gaseous fuel and which transfers heat from combustion gases to water or process streams. Process Heater does not inciude any Idin or oven used for drying, baking, cooldng, calcining, or vitrifying; or any un5red waste heat recovery heater that is used to recover sensible heat from the exhaust of any combustion equipment. (6) RATED HEAT INPUT CAPACTTY means the heat input capacity specified on the nameplate of the combustion unit. If the combustion unit has beeti aitered or modi.fied such that its maximum heat input is different than the heat input capacity specified on the nameplate, the new maximtun heat input shaU be considered as the rated heat input eapacity. (7) 'THERM means 100,000 Btu. (8) IJNIT means a.ny boiler, steam generator, or process heater as defined in subparagraph (a)(2) or (a)(5).

1146.1 - 1Rule 1146.1 (Cont.) (Adopted October 5,1990)



## (b) Applicability

This rule applies to boilers, steam generators, and process heaters that are equal or greater than 2 million Btu per hour and lcss than 5 million Btu per hour rated heat input capacity used in any industrial, institutional, or commercial operation.
(c) Requirements (1) The owner and/or operator of any unit subject to paragraph (b) shall operate such unit so that it

- discharges into the atmosphere no more than 30 ppm of NO X emissions (0.037 pound NO X per million Btu of heat input) and no more than 400 ppm of carbon monoxide. For each unit, a selection must be indicated in the application for permit to construct and operate between the ppm NO x or pounds of NO x per million BTU heat input compliance option. (2) The owner or operator of any unit(s) subject to paragraph (b), and with an ann.ual heat input of less than or equal to 18,000 therms per calendar year, shall: (A) be operated in a manner that mainta.ins stack-gas oxygen concentrations at less than or equal„to 3 percent on a dry basis for any 15-consecutive-minute averaging period; or (B) be tuned at least twice per year, (at intervals from 4 to 8 months apart) in aceordance with the procedure described in Attachment 1, or other method as approved by the F.xecutive Officer. If the unit does not operate during a six-month period, an annual tuneup is acceptable. The owner or operator of any unit(s) who specifies the semi-annual tuneup option shall maintain a record for a period of two years verifying that the tuneup has been performed. The record shall contain any other information or documentation that the Fxecutive Offieer determines to be necessary and made accessible upon request from an authoriud District representative; or (C) meet the emission limits specified in subparagraph (c)(1). (3) Tfie owner or operator of any unit(s) subject to subparagraph (c)(2) shall subtnit, for the approval of the Executive Officer, a plan that

1146.1- 

## 2

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

demonstrates compliance with subparagraph (c)(2). Such plan shall contain: (A) A list of all units with the rated heat input capaeity, anticipated annual heat input, and permit number; and (B) For each unit listed, a selection of one of the three options specified in subparagraph (c)(2) to achieve compliance with this rule; and (C) Non-resettable, totaiizing fuel meter(s) specifications; date of installation; and recorded fuel usage since installation. (4) Any owner or operator who chooses the pound per million Btu of heat input compliance option shali install a non-resettable, totalizing fuel meter for each fuel used on an individual unit basis, as approved by the Executive OfP'

icer.
(d) Compliance Deternaination (1) All units shail have the option of complying with either the pound per million Btu of heat input or parts per miIlion emission limits specified in subparagraphs (c)(1) and (c)(2)(C). (2) All emission determinations shall be made in the as-found operating condition, except no compliance determination shail be established during unit start up, shutdown, or under breakdown conditions. Start up or shutdown intervals tnay not last longer than is necessary to reach stable temperatures. In no case may the start up or shutdown interval last longer than specified in the permit to operate. In the event that permit conditions do not speeify a time li.mit, the start up or shutdown may not exceed six botus for units subject to paragraph (b). (3) All parts per million emission limits specified in subparagraph (c)(1) are referenced at 3 percent volume stack-gas oxygen on a dry basis averaged over a period of 15 consecutive minutes. (4) Campliance with the NO X and CO entission requirements of subparagraph (c)(1) and the stack-gas oxygen conrentration requirement of subparagraph (c)(2)(A) shall be determined according to procedures in the District Source Test Manual or anv other test method determined to be equivalent and approved by the Executive Officer. Emissions

1146.1- 3

### Rule 1146.1 (Cont.) (Adopted OctQber 5, 199d)



## determined to exceed any limits established by this rule through the use of any of the above-referenced test methods shall constitute a violation of this rule.
(e) Compliance Schedule The owner or operator of units subject to this rule shall meet the following increments of progress: (1) For owners and/or operators of units subject to subparagraph (c)(1): (A) By January 1, 1993, submit required applications for perrnits to construct and operate, and (B) By July 1, 1994, demonstrate compliance with subparagraph (c)(1). (2) For owners and/or operators of units subject to subparagraph (c)(2): (A) By January 1, 1993, submit a plan pursuant to paragraph (c)(3), and (B) By December 31, 1993, demonstrate compliance with paragraph (c)(2)•
(f) Exemption The provisions of subparagraph (c)(1) shall not apply provided the owner and/or operator: (1) Installs lry January 1, 1992, or at the time the unit is constructed, a nonresettable, totalizing fuel meter for each fuel that demonstrates that the unit(s) operated with an annual heat input at or below 18,000 therms per calendar year; and (2) Has 

## ava.ilable for inspection by the Executive Officer by February 1, 1993, and February 1 of each year thereafter, aunual fuel-use data for the preceding calendar year. Records shall be maintained and made accessible to the Executive Officer or authorized District representative for a period of two years; and (3) Demonstrates by February 1, 1993, that the aztnual heat input is less than or equal to 18,000 therms.

114b.1- 4

### Rule 

### 1146.1 (Cont.) (Adopted October 5, 1990)

(g) Lass of Exemption If any unit sub}ect to a control plan submitted pursuant to subparagraph (c)(3) exceeds 18,040 therms of annual heat input after 1992, the owners or operators shall: (1) Within 4 months from the end of the preceding calendar year, submzt required applications for permits to construct and operate, and (2) Within 18 months from the end of the preceding calendar year, demonstrate compliance with subparagraph (c)(1).

A'ITACHMENT 1 Equipment'Iuning Procedure t
Nothing in this Equipment Tuning Procedure shall be construed to require any act or otnission that would result in unsafe conditions or would be in violation of any regulation or requirement established by Factory Mutual, Industrial Risk Insurers, National Fire Prevention Association, the California Department of Industrial Relations (Occupational Safety and Health Division), the Federal Occupational Safety and Health Administration, or other relevant regulations and requirements. 1. Operate the unit at the firing rate most typical of normal operation. If the unit experiences significant load variations during normal operation, operate it at its average firing rate. 2. At this firing rate, record stack-gas temperature, oxygen concentration, and CO concentration (for gaseous fuels) or smoke-spot number 2 (for liquid fuels), and observe flame conditions after unit operation stabilizes at the firing rate selected. If the excess oxygen in the stack gas is at the iower end of the range of typical minimum 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.
Thuprocednre is based on a tune-up prooedure developed by KVB, Lnc. for the EPA. 2 The smoke-spot number can be determined with ASTM Test Method D-2156 or witb the Bacharach method. ASTM Test Method D-2156 is included in a tuneup kit that can be purchased from the Bacharach Company. 3 Typical minimum oxygen leveLs for boilers at higb firing ratts are: 1. For natural gas: OS percent - 3 percent. 2. For liquid fuels: 2 percent - 4 percent.

1146.1- 5

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

3

4.

5.



## r.l.

7. However, cornplete the re mainin 

## g portion of this procedure to determine whether still lower oxygen levels are practical. Increase combustion air flow to the furnace until stack-gas oxygen levels increase by one to two percent over the level measured in Step 2. As in Step 2, record the stack-gas temperature, CO concentration (for gaseous fueis) or smoke-spot number (for Iiquid fuels), and observe flame conditdons for these hig}ser oxygen levels after boiler operation stabilizes. Decrease combustion air flow until the stack gas oxygen concantration is at the level measured in Step 2. From this level, gradualIy reduce the combustion air flow in small inerements. After each increment, record the stack-gas temperature, oxygen concentration, CO concentration (for gaseous fuels), and smoke-spot number (for liquid fuels). Also observe the flame and record any changes in its condition. Continue to reduce combustion air flow stepwise, until one of these limits is reached:

a. Unacceptable flame conditions, such as flame impingement on furnace walls or ; burner parts, excxssive flame carryover, or flame instability; or b. Stack gas CO concentrations greater tban 400 ppm; or

C. 

## Smoking at the stack; or d. Equipment-related limitations, such as low windbax Jfurnace pressure differential; built in air-flow limits, etc. ' Develop an 02/CO curve (for gaseous fuels) or 0 2 /smoke cuive (for liquid fuels) similar to those shown in Figures 1 and 2, using the excess oxygen and CO or smoke-spot number data obtained at each combustion air flow setting. From the ntuves prepared in Step 6, find the stack-ps oxygen levels where the CO emissions or smoke-spot ntunber equal tbe following values: 

# Fuir1 Yeasurement 

### Value 

## Gaseous CO emissions 400 ppm #1 and #2 oils smoke-spot number number 1 #4 oil smoke-spot number number 2 #5 oil smoke-spot number number 3 Other oils smoke-spot number number 4

1146.1 - 6

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

The above conditions are referred to as the CO or smoke thresholds, or as the minimum excess oxygen level. Compare this minimum value of excess oxygen to the expected value provided by the combustion unit manufacturer. If the minimum level found is substantially higher than the value provided by the combustion unit manufacturer, bumer adjustments can probably be made to improve fuel and air mixing, thereby allowing operation with less air. 8. Add 0.5 to 2.0 percent of the minimum excess oxygen level found in Step 7 and reset burner controls to operate automatically at this higher stack-gas oxygen level. This margin above the minimum oxygen level accounts for fuel variations, variations in atmospheric conditions, load changes, and nonrepeatability or play in automatic controls. 9. If the load of the combustion unit varies significantly during normal operation, repeat Steps 1-8 for firing rates that represent the upper and lower Iimits of the range of the load. Because control adjustments at one firing rate may affect conditions at other firing rates, it may not be possible to establish the optimum excess oxygen level at all firing rates. If this is the case, choose the burner control settings that give best performance over the range of fuing rates. If one firing rate predominates, settings should optimize conditions at that rate. 10. Verify that the new settings can accommodate the sudden load changes that may occur in daily operation without adverse effects. Do this by increasing and decreasing load rapidly while observing the flame and stack. If any of the conditions in Step 5 result, reset the combustion controls to provide a slightly higher level of excess oxygen at the affected firing rates. Next, verify these new settings in a similar fashion. Then make sure that the final control settings are recorded at steady-state operating conditions for future reference.

1146.1 - 7

### APPENDIX C

SCAQMD Rule 1146

Emissions of Oxides of Nitrogen From Industrial. Institutional, and Conmercial Boilers, Steam 6enerators, and Process Heaters

C.1

### (Adopted September 9, 1988)(Amended Januarv ti. 1989)

RULE 1146. EMISSIONS OF 

### OXIDES OF NITROGEN FROM

INDUSTRIAL, INSTITUTIONAL, AND COMMERCIAL BOILERS, STEAN1 GENERATORS, AND PROCESS HEATERS



### (a) Definitions (l) Annual Capacity Factor means the ratio of the amount of fuei burned hv a unit in a calendar vear to the amount of fuel it could }have burned if it had operated at the rated heat input capacity for 100 percent of the time during the calendar year. (2) .Annual Heat Input means the actual amount of heat released hv fuzls burned in a unit during a calendar vear. (3) Boiler or Steam Generator means any combustion equipment fired with liquid and/or 2aseous fuel and used to produce steam or to heat vvater and that is not used exclusively to produce electricity for saie. Boiler or Steam Generator does not include any waste heat recovery boiler that is used to recover sensible heat from the exhaust of a combustion turbine or any unfired waste heat recovery boiler that is used to recover sensible heat from the exhaust of any combustion equipment. (4) BTU means British thermal unit. (5) Heat Input means the chemical heat released due to fuel combustion in a unit, using the higher heating value of the fuel. This does not inciucle the sensible heat of incoming combustion air. (fi) NOx Emissions means the sum of nitric oxides and nitrogen dioxide in the flue gas, collectively expressed as nitrogen dioxide. (7) Process I--Ieater means any combustion equipment fired with liquicl and/or easeous fuel and which transfers heat from combustion gases to water or process streams. Process Heater does not include any kiln or oven used for drying, baking, cooking, calcining, or vitrifyino; or anv unfired waste heat recoverv heater that is used to recover sensible hzat from the exhaust of any combustion equipment. (8) Rated Heat Input Capacity means the heat input capacity specified on the nameplate of the combustion unit. If the combustion unit has been altered or modified such that its maximum heat irnput is different than the

1146 - 

### 1

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



### heat input capacity specified on the nameplate, the new maximum heat input shall be considered as the rated heat input capacity. (9) Therm means 100,000 Btu's. (10) Unit means any boiler, steam generator, or process heater as defined in subparagraph (3) or (7) of this paragraph.

(b) Applicability This rule applies to boilers, steam generators, and process heaters of equal to or greater than 5 miliion Btu's per hour rated heat input capacity used in all industrial, institutional, and commercial operations with the exception of: (1) boilers used by electric utilities to generate electricity; and (2) boilers and process heaters with a rated heat input capacity greater than 40 million Btu per hour that are used 

## in petroleum refineries; and (3) sulfur plant reaction boilers.

(c) Requirements (1) The owner or operator of any unit(s) shall not discharge into the atmosphere oxides of nitrogen, expressed as nitrogen dioxide (NO2), in excess of the concentrations shown in the foilowing tabie.

Gaseous Rated Heat or Liquid Input Capacity Annual Heat 

### Input Fuels Equal to or greater than And Greoter than 9 x 10 Btu's per yr 40Rib m (0 per 5 million Btu's (90,000 10 Btu's per hour Therms) of heat input) Equal to or Greater than 

### 25°10 30 ppm greater than And annual capacity 40 million factor Btu's per hour Carbon monoxide (CO) emissions from unit(s) subject to this subparagraph shall not exceed 400 ppm.

1146 

### - 2Rule 1146 (Cont.) 

### iAmended .January 6, 1989)

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

### million Btu per hour and an annual heat input less than or equal to 9.0 x I0 9 Btu per year, shall: (A) be operated in a manner that maintains stack gas oxvgen concentrations at less than or equal to 3 percent on a dry basis fur any 15-consecutive-minute averaging period: or (B) be tuned at least twice per year, once between March 15 and June 15, and once between September 15 and December 15 in accordance with the procedure described in Attachment 1. The owner or operator of any unit(s) who specifies the semi-annuul tune-up option shaIl maintain a record made accessible to theExecutive Officer for a period of two vears verifving that the tuneup has been performed. The record shall contain any other information or documentation that the Executive Officer determines to be necessary; or (C) be operated in compliance with a 40 ppm (0.05 Ibs per 10 6 Btu of heat input) NOx emission level and a 400 ppm CO emission level. (3) The owner or operator of any unit(s) subject to subparagraph (c)(2) shall submit for the approval of the Executive Officer a plan that demonstrates compliance with subparagraph (c)(2). Such plan shall contain: (A) A list of all units with the rated heat input capacity and anticipateci annual heat input. (B) For each unit listed, a selection of one of the three options specified in subparagraph (c)(2) to achieve compliance with this
rule. 

### (4) Any unit(s) with a rated heat input capacity greater than or equal to 40 million Btu per hour and an annual heat input greater than 200 x 10 9 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 tnvo years in a form and manner as specified by the Executive Officer.

1146 - 3

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



### (5) Any owner or operator who chooses the pound per million Btu compliance option shall install totalizing fuel meters on an individual unit basis, as approved by the Executive Officer.

(6) Any owner or operator claiming an exemption from any of the provisions of subparagraphs (c)(1) and/or (c)(4) based on annual heat input, shall: (A) install by February 1, 1989 for units with a rated heat input capacity equal to or greater than 5 but less than 40 million Btu per hour, 

### or by May 1, 1989 for units with a rated heat input capacity equal to or greater than 40 million Btu per hour, or at the time the unit is constructed, a totalizing meter for each fuel that demonstrates that the unit(s) operated at or below the applicable heat input levels; and (B) have available for inspection by the Executive Officer by March 1, 1989, and March 1, of each year thereafter, annual fuel use data for the preceding calendar year. Records shall be maintained and made accessibie to the Executive Officer for a period of two years; and (C) demonstrate that the annual heat input is less than or equal to the applicable amount listed in subparagraph (c)(1) and/or (c)(4).

(cl) Alternative Emission Control Plan (1) An owner or operator may achieve compliance with paragraph (c) by achieving equivalent nitrogen oxides emissions reductions obtained by alternative control methods provided the applicant submits an Alternative Emission Control Plan that is enforceable by the District and receives approval of the Plan in writing from the Executive Officer prior to implernentation. The Alternative Emission Control Plan shall: (A) Contain, as a minimum, all data, records, and other information necessary to determine eligibility for alternative emission control, including but not limited to: (i) A iist of equipment subject to alternative emission

control; (ii) Daily hours of utilization for applicable equipment;

i146-4

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



### (iii) Estimated emission of nitrogen oxides for each

operation; ' (iv) Rated capacity; and (v) Historical and projected fuel use. (B) Present the methodology for estimation of equivalency of emission reductions under the proposed Alternative Emission Control Plan as compared to either the emission reductions otherwise required by the rule or to actual emissions, whichever is less. (C) Demonstrate that the permit units subject to the specified rule emission limitations are in compliance with or on an approved schedule for compliance with all applicable District rules. (2) Revision of Control Plan A revised controi plan may be submitted by the owner or operator, along with any required permit applications. Such a plan shall adhere to the emissions limits and the final compliance dates of this rule. New units, including functionally identical replacement units, shall not be incorporated into the plan.

(e) Compliance Determination (1) An owner or operator of any unit(s) shall have the option of complying with either the pound per million Btu or parts per million emission limits specified in subparagraph (c)(1). (2) All emission determinations shall be made in the as-found operating condition, except no compliance determination shall be established during start-up, shutdown, or under breakdown conditions. (3) All parts per million emission limits specified in paragraph (c) are referenced at 3 percent volume stack gas oxygen on a dry basis averaged over a period of 15 consecutive minutes. (4) Compliance with the NOx emission requirements and the stack gas oxygen concentration requirement of paragraph (c) shali be determined according to procedures in the District Source Test Manual or in any other manner approved by the Executive Officer.

1146 

### - 5

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



### (f) Compliance Schedule The owner or operator of units subject to this rule shall meet the following increments of progress: (1) For owners or operators of units subject to subparagraph (c)(2), submit, by September 1, 1989, a plan pursuant to subparagraph (c)(3) and by March 1, 1990, demonstrate final compliance with subparagraph (c)(2). (2) For owners or operators utiiizing the Alternative Emission Control Plan, pursuant to paragraph (d), by September 1, 1989, submit a control plan. (3) For owners or operators of units with a rated heat input capacity equaI to or greater than 10 million Btu per hour that are subject to the 40 ppm emission limit specified in subparagraph (c)(1), including those with an approved Alternative Emission Control Plan; (A) By March 1, 1990, submit required applications for permits to construct and operate. (B) By September 1, 1991 demonstrate compliance with subparagraph (c)(1) and, if applicable, subparagraph (c)(4). (4) For owners or operators of units with a rated heat input capacity equal to or greater than 5 million Btu per hour, but less than 10 milIion Btu per hour, that are subject to the 40 ppm emission limit specified in subparagraph (c)(1): (A) By March 1, 1991, submit required appiications for permits to construct and operate. (B) By March 1, 1992, demonstrate compliance with subparagraph (c)(1). (5) For owners or operators of units with a rated heat input capacity equal to or greater than 40 tnillion Btu's per hour and an annual capacity factor of 25% that are subject to the 30 ppm emission limit specified in subparagraph (c)(1): (A) By July 1, 1991, submit required applications for permits to construct and operate. (B) By Juiy 1, 1993, demonstrate compliance with subparagraph (c)(1).

1146 - 6

### Ruie 1146 (Cont.) (Amended January 6, 1989)



### (6) The provisions of subparagraph (c)(1) and/or (c)(4) shall become applicable for the life of the unit on March 1, of any calendar year if that unit operated for the previous calendar year at an annual heat input greater than the annual applicable heat input leveis.

1146 - 7

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

ATTACHMENT 1



### Equipment Tuning Procedure 1

Nothing in this Equipment Tuning Procedure shall be construed to require any act or omission that would result in unsafe conditions or would be in vioEation of any regulation or requirement established by Factory Mutual, Industrial Risk Insurors, National Fire Prevention Association, the California Department of Industrial Relations (Occupational Safety and Health Division), the Federal Occupational Safety and Health Administration, or other relevant regulations and requirements. l. Operate the unit at the firing rate most typical of normal operation. If the unit experiences significant load variations during normal operation, operate it at its average firing rate. '. At this firing rate, record stack gas temperature, oxygen concentration, and CO concentration (for gaseous fuels) or smoke-spot number 2 (for liquid fuels), and observe flame conditions after unit operation stabilizes at the firing rate selected. If the excess oxygen in the stack gas is at the lower end of the range of typicaI minimum values 3 , and if CO emissions are low and there is not smoke, the unit is probably operating at near optimum efficiency - at this particuiar firing rate.

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

2. The smoke-spot number can be determined with ASTM Test Method D-2156 or with the Bacharach method. ASTM Test Method D-2156 is included in a tuneup kit that can be purchased from the Bacharach Company.

3. Typical minimum oxygen levels for boilers at high firing rates are: 1. For natural gas: 0.59o

' - 3% 2. For liquid fuels: 27c - 4%

1146 

### - 8

### Rule 1146 (Cont.) (Amended Januan+ 6, 1989)



### However, complete the remaining portion of this procedure to determine whether still lower oxygen levels are practical. 3. Increase combustion air flow to the furnace until stack gas oxygen levels increase by one to two percent over the level measured in Step 2. As in Step 2, record the stack gas temperature, CO concentration (for gaseous fuels) or smoke-spot number (for liquid fuels), and observe flame conditions for these higher oxygen levels after boiler operation stabilizes. 4. Decrease combustion air flow until the stack gas oxygen concentration is at the level measured in Step 2. From this level gradually reduce the combustion air flow, in small increments. After each increment, record the stack gas temperature, oxygen concentration, CO concentration (for gaseous fuels) and smoke-spot number (for liquid fuels). Also observe the flame and record any changes in its condition. 5. Continue to reduce combustion air flow stepwise, until one of these limits is reached:

a. Unacceptable flame conditions - such as flame impingement on furnace walls or burner parts, excessive flame carryover, or flame instability. b. Stack gas CO concentrations greater than 400 ppm.

C. 

### Smoking at the stack. d. Equipment-related limitations - such as low windbox/furnace pressure differential, built in air-flow limits, etc. (i. Develop an 02/CO curve (for gaseous fuels) or 02/smoke curve (for liquid fuels) similar to those shown in Figures 1 and 2 using the excess oxygen and CO or smoke-spot number data obtained at each combustion air flow setting. 7. From the curves prepared in Step 6, find the stack gas oxygen levels where the CO emissions or smoke-spot number equal the following values: Fuel Measurement Value Gaseous CO Emissions 400 ppm # 1 and #2 oils smoke-spot number number 1 #4 oil smoke-spot number number 2 #5 oil smoke-spot number number 3 Other oils smoke-spot number number 4

1146 

### - 9

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



### The above conditions are referred to as the CO or smoke thresholds, or as the minimum excess oxygen level. Compare this minimum value of excess oxygen to the expected value provided by the combustion unit manufacturer. If the minimum level found is substantially higher than the value provided by the combustion unit manufacturer, burner adjustments can probably be made to improve fuel and air mixing, thereby allowing operation with less air. 8. Add 0.5 to 2.0 percent of the minimum excess oxygen level found in Step 7 and reset burner controls to operate automatically at this higher stack gas oxygen level. This margin above the minimum oxygen level accounts for fuel variations, variations in atmospheric conditions, load changes, and nonrepeatability or play in automatic controls. 9. If the load of the combustion unit varies significantly during normal operation, repeat Steps 1-8 for firing rates that represent the upper and lower limits of the range of the load. Because control adjustments at one firing rate may affect conditions at other firing rates, it may not be possible to establish the optimum excess oxygen level at all firing rates. l:f this is the case, choose the burner control settings that give best performance over the range of firing rates. If one firing rate predominates, settings should optimize conditions at that rate. 10. Verify that the new settings can accotnmodate the sudden load changes that may occur in daily operation without adverse effects. Do this by increasing and decreasing load rapidly while observing the flame and stack. If any of the conditions in Step 5 result, reset the combustion controls to provide a slightly higher level of excess oxygen at the affected firing rates. Next, verify these new settings in a similar fashion. Then make sure that the final control settings are recorded at steady-state operating conditions for future reference.

1146 - 10

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

D.1

### (Adopteci _\ovember 1. l985)(Amencied AuL!u

~ 

### : 5

. 1 988)

RULE 1109. EMISSIOiV'S OF OXIDES OF NITROGEN FROM BOiLERS AND

PROCESS HEATERS IN PETROLEUNI REFINERIES

;a) Definitions (1) BOILER means anv combustion eauipment fired titiith liyuici and/or gaseous fuel and used to produce steam, includini! a carbon monoxide boiier. (2) PROCESS HEATER means any combustion equipment fired with lic{uid ancd/or gaseous fuel and which transfers heat trom combustion Uases to process streams. t3) REF1NERl'•WIDI :ATE OF NITROGEN (')XIDES CMISSIONS means the ratio or the total mass rate of di,charUe into the atmosphere ur nitroven oxides from units (;ubject tc> the rute) when firing at their maximum ratecl capacitv to the sum of the maximum r;.itCCi capacities tor those units. (4) UNIT means anv petroleum refinery boiler or process heater. as definecl in subsections (1) and (2) of this section. with a permit to construct or a permit to operate prior to lklarch ?, 1984. (5) NITROGEN (UXIDES means the sum oi nitric uxicie ..ncl nitrogen dioxide in the * .lue

~ 

### -

, as, collectivelv expressed as nitrouen dioxicle and averagecl over a period ot 1

- 5

### consecutive minutes. (6) COti1BUSTI0,"1 %10DIFICATION means anv ,nodification

~~ 

### r .thc burner, combustion air t1ow, or fuel flow svstem that reduces nitrc>uen oxides emissions. (7) vtAXIMUM RATED CAPACITY means maximum clesiLyn heat input ;rt the hieher heatini! value ot the fuel unless: !A) the boiler/process heater is limited hv permit condition to a Izsser heat input. in which case the iimitina condition shall he usecl aa the ma.ximum rated caqacitv: or kB) the noiler?process heater is operated above the m:iximum cJesi_

~ 

### n heat input. in which case the maximum operated rate shall he used 

### at the maximum rated capacitv. (8) EMISSIONS RATE means the ratio of the mass rate ot uischaree into

1109 - 1

### Rule 1109 (Cont.) tAmended August 5, 1988)

the atmosphere of nitrogen oxides from a unit to the actual heat input €or that unit. (9) HEAT INPUT means the heat of combustion released by fuel oxidation in a unit, using the higher heating value of the fuel. This does not include the enthalpy of incoming combustion air. In the case of carbon monoxide boilers, the heat input includes the enthalpy of all regenerator off gases and the heat of combustion of the incoming carbon monoxide and of the auxiliary fuel. The enthalpy of the fluid catalvtic cracking unit regenerator off-gases refers to the total heat content of the gas at the temperature it enters the carbon monoxide boiler, referred to the heat content at 60 0 F, as being zero.

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

anv petroleum refinery shall reduce emissions of nitrogen oxides from units subject to this rule so that if all such units were operated at their maximum rated capacity the refinery-wide rate of nitrogen oxides emissions from these units would not exceed: (i) 0.14 pound (0.064 kilogram) of nitrogen oxides per million BTU of heat input when operated on gaseous fuel; (ii) 0.308 pound (0.14 kilogram) of nitrogen oxides per million BTU of heat input when operated on liquid fuel; (iii) the weighted average of the limits of subsections (b)(1)(A)(i) and (b)(1)A(ii), when operated concurrently on both liquid and gaseous fueI. For purpose of this rule, the nitrogen oxides formed in the fluid catalytic cracking unit regenerator shall be assumed to be from the burning of gaseous fuel. (B) On December 31, 1992 and subsequent dates, the owner or operator of any petroleum refinery shall reduce emissions of nitrogen oxides from each unit subject to this rule so that: (i) From December 31, 1992 until December 31, 1995, emissions from units which represent at least 36 percent of the total heat input are less than or equal to 0.03 pound ?

1109 

### - 2

### Rule 1109 (Cont.) iAmended August 5, 1988)

per million BTU of heat input when firing at the maximum rated capacity, or as specified in the Alternative Emission Control Plan (AECP). Artv 

### unit not meeting the 0.03 pound per million limit shall not exceed its pound per million BTU limit specified in the Approved Control Plan for compliance with (b)(1)(A); (ii) From December 31, 1995, emissions are less than or equal to 0.03 pound per million BTU of heat input when firing at the maximum rated capacity, or as specified in the A3ternative Emission Control Plan (AECP). (iii) For each unit firing at less than the maximum rated capacity, mass emissions of nitrogen oxides shall be less than or equal to the quantity that would occur at the applicable limit specified in (b)(1)(B)(i) and (b)(1)(B)(ii) at maximum rated capacity, or as specified in the AECP. (iv) Alternative Emission Control Plan (AECP) An owner/operator may achieve compliance with paragraphs (b)(1)(13)(i) and (b)(1)(B)(ii) by achieving equivalent nitrogen oxides emissions reductions obtained by alternative control methods provided the applicant submits an Alternative Emission Control Plan that is enforceable by the District and receives approval of the Plan in writing from the Executive Officer prior to implementation. 1"ne Alternative Emission Controi Plan shall: (1) Contain, as a minimum, all data, records, and other information necessarv to determine eligibility for alternative emission controi, including but not limited to: a) A list of eouipment subject to alternatiVe emission control; b) Daily hours of utilization for applicahle equipment; c) Estimated emission of nitrogen oxides for

1109 - 

### 3

### Ruie 1109 (Cont.) (Amended August 5, 1988)



### each operation; d) Rated capacity; and e) Historical and projected fuel use. (II) Present the methodology for estimation of equivalency of emission reductions under the proposed Alternative Emission Control Plan as compared to either the emission reductions otherwise required by the rule or to actual emissions, whichever is less. (II1) Demonstrate that the permit units subject to the specified rule emission Iimitations are in compliance with or on an approved schedule for compliance with all applicable District rules. (2) The owner or operator shall operate each unit subject to this rule such that the assigned maximum nitrogen oxides emissions rate for each unit (pounds or kilograms per million BTU heat input, expressed as nitrogen dioxide) is in accordance with the list approved by the Executive Officer pursuant to subsection (b)(6)(B), and any specified permit conditions. (3) The owner or operator of any petroleum refinery which has units subject to this rule shall submit to the Executive Officer a control plan for installation of nitrogen oxides emissions control equipment to meet the requirements of subsection (b)(1); Such plan shall contain as a minimum: (A) A list of all units with the maximum rated capacity for each unit, (S) .A list of units to be controlled and the type of control to be applied for all such units, including a construction schedule, (C) The method of calculation of the mass rate of nitrogen oxides emissions for each unit to achieve the refinery-wide emissions rates specified in subsection (b)(1), and (D) On-site nitrogen oxide offsets from co-generation facilities may be incorporated in the plan. (4) All units which are identified in the control plan required by subsection (b)(3) shall be tested, in a manner approved by the Executive Officer, for nitrogen oxides emissions while firing gaseous fuel and liquid fuel, if

1109 - 4

### Rule 1109 (Cont. 

### i i.amended August S. 1988)

applicable, at the maximum rated capacity, or as near thereto as practicabie. Such tests shall be performed: (A) Within 180 days after compietion of modifications, but no later than 1 month before any applicable compliance date for units which are to be modified with nitrogen oxides control equipment. and 

### (B) By December 1, 1986, for units which do not require modification. (5) Total nitrogen oxides emissions (pounds or kilograms per hour) and total heat input rates (million BTU's per hour) during the tests recluired by subsection (b)(4), while firing gaseous fuel and while firing liquid fuel. shall be used for determination of initial compliance with the refinen!- wide rate of emissions limits of subsection (b)(1). (6) After verification of initial compliance with 

### the limits of subsection (b)(1))(A): (A) The owner or operator shall assign to each unit subject to this rule the maximum nitrogen oxides emissions rates (pounds or kilograms per million BTU heat input, expressed as nitrogen dioxide), while firing gaseous fuei or liquid fuel, which are allowable for that unit under the requirements of subsection (b)(1)(A). (B) The owner or operator shall submit to the E,xecutive Officer for approval a list, by the appiicable compiiance date, uf the maximum allowable nitrogen oxides emissions rates identified in subsection (b)(6)(A) and a copy of the approved list shall be maintained for verification of continued compliance with the requirements of subsection (b)(2). (C) Compliance with subsection (b)(1)(A) shafl be determined hv source testing any one unit subject to this rule, or additional units if required by the Executive Officer. No unit subject to this rule shall be operated at an emissions rate (pounds or kilograms per million BTU heat input, expressed as nitrogen dioxide) higher than that approved by the Executive Officer pursuant to subsection (b)(6)(B). (7) Each unit subject to this rule shall have a continuous in-stack nitrogen

1109 - 

### S

### Ruie 1109 (Cont.) (Amended 

### August S. 1988)

oxides monitor, or equivalent verification system, as approved by the Executive Officer at the time of compliance with the 0.03 pound per million BTU limit specified in subsections (b)(1)(B)(i) and (b)(1)(B)(ii). (A) Records shall be maintained and made accessible for a period of two years to the Executive Officer in a form and manner as specified by the Executive Officer. (B) Compliance with subsection (b)(1)(B) shall be determined by source testing and/or in-stack nitrogen oxides monitor data or other data as specified for the equivaient verification system.
(c) Revision of Control Plan A revised control plan may be submitted by the owner operator, along with any required permit applications. Such a plan shall adhere to the emissions limits and the final compliance dates of this rule. New units, including functionally identical replacement units, shall not be incorporated into the plan.
(d) Exemptions The requirements of Section (b) shall not apply to: (1) Boilers or process heaters with maximum rated capacities equal to or less than 40 million BTU per hour heat input. (2) Sulfur plant reaction boilers. (3) Upon approval by the E.xecutive Officer, units which are operated with a total heat input in a 12 month period of less than 10 percent of the maximum rated capaciry for that period.
(e) Compliance Schedule The owner or operator of a petroleum refinery having units subject to this rule shail fulfill the following increments of progress: (1) For subsection (b)(1)(A), by July 1, 1988, demonstrate to the satisfaction of the Executive Officer final compliance with the rule. (2) For subsection (b)(1)(B)(i): (A) By April 1, 1989, submit a revised control plan, pursuant to subsection (b)(3) of the rule. (B) By September 1, 1989, submit required applications for permits to construct and operate.

1109 

### - 6

### Rule 1109 (Cont.) iAmended August S. 1988)



### (C) Bv December 31, i992 demonstrate to the satisfaction of 

### the Executive Officer compliance with (b)(1)(B)(i). 

### (3) For subsection (b)(1)(B)(ii): (A) By 5eptember 1, 1992, submit a revised control plan, pursuant to subsection (b)(3) of the rule. (B) By February 1, 1993, submit required applications for permits to construct and operate. (C) By December 31, 1995, demonstrate to the satisfaction of the Executive Officer compliance with (b)(1)(B)(ii).

1109 - 7

### APPENOIX E



### YCAPCD Rule 74.15
Boilers, Steam 6enerators and Process Neaters

E.1

### Rule 74.15. Boilers, Steam Generators and Process Heaters (Adopted 3/28/89)

A. Applicability

1. The provisions of this rule shall apply to boilers, steam generators and process heaters used in all industrial, institutional and commercial operations, except as follows:

a. Utility electric pover generating units and any , auxiliary boiler used with a utility electric power generating unit.

b. Water heaters.

B. Requirements

1. No person shall allow the discharge into the atmosphere from any boiler, steam generator or process heater with a rated heat input capacity of equal to, or greater than, five (5) million BTU's per hour and an annual heat input rate of equal to, or greater than, 9 x 10 ~ 

### BTU's per calendar year, oxides of nitrogen emissions in excess of 40 parts per million volume. Carbon monoxide emissions from units subject to this rule shall not exceed 400 ppmv.
Units subject to the above provisions shall test for compliance not less than once every 24 months.

2. Any boiler, steam generator or process heater with a rated heat input capacity of equal to, or greater than, five (5) million BTU' ~ 

### per hour, and having an annual heat input rate of less 

### than 9 x 10 

# G BTU's per calendar year, shall comply with one of the folLoving

~ 

### requirements: ~ Q oz a ~ 

# =

a a. The unit shall be operated in a manner that maintains stack 

# Z a Q ~ 

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

w r Q



### _ percent on a d ry 

### basis for any 15-consecutive-minute



## ~ ~ r_ ~j averaging period. Units subject to this provision shall test Q U for compliance every six (6) months; or 

### Z V t 

### ` 

# Z O > ; b. T h e unit shall be operated using a stack gas oxygen trim

system set at three (3) percent oxygen. The tolerance of the 0 o> setting shall be ± five (5) percent. Units subject to this 0 CO provision shall test for compliance every twelve (12) months;

~ or 

## ¢ C. The unit shall be tuned at least twice per calendar year, once between March 15 and June 15 and once between September 15 and December 15, in accordance with the procedure described in Attachment 1; or

d. The unit shall comply with the emission and testing requirements of Subsection B.1.

4/89

_ Attactunent 3 Rule 74.15 : 1C. Exemptions

1. The provisions of this rule shall not apply to anw boiler, steam generator or process heater with a rated heat input capacity of less than five (5) million BTiJ's per hour.

2. The provisions of Subsection B.1 of this rule shall not apply to any boiler, steam generator or process heater operated on alternate fuel under the following conditions:

a. Alternate fuel use is required due to the curtailment of natural gas service to the individual unit by the natural gas supplier. Alternate fuei use in this case shall not exceed the period of natural gas curtailment.

b. Alternate fuel use is required to maintain the alternate fuel system. Alternate fuel use in this case shall not exceed 50 hours per year.

3. The provisions of Subsection B.1 of this rule shall not apply to the use of an emergency standby unit when a breakdown occurs to the primary unit, and the breakdown is reported pursuant to the breakdown reporting requirements of Ruie 32. Emissions resulting from the operation of the standby unit shall not exceed the total annual or hourly permitted emission rate of the primary unit. Operation of the standby unit shall not occur beyond the period of the primary unit's emergency breakdown.

D. Recordkeeping Requirements

1. Any person subject to the provisions of Subsection 8.2 of this ruie shall install by September 28, 1989, or at the time the unit is constructed, a totalizing fuel meter for each applicable unit and for each fuel. The meter shall be used to demonstrate that each unit operates at or below the applicable heat input level.
Meters shall be accurate to t one (1) percent, as certified by the manufacturer in writing. After December 28, 1989, totalizing fuel meter readings shall be recorded at the end of each operating day in units of either cubic feet per day or gallons per day. At the end of each month, daily records shall be compiled into a monthly report. Both monthly reports and daily records shall be maintained for a period of four (4) years and shall be made available for inspection by the Air Pollution Control Officer upon request.

2. Any person subject to the provisions of Subsection B.2.c of this rule shall submit a report to the District twelve (12) months after achieving compliance with Subsection B.2.c. Reports shall continue to be submitted every twelve (12) months. This report shall verify that each tune-up has been performed and that the results were satisfactory. The report shall contain all information or documentation that the Air Pollution control Officer may determine, in writing, to be necessary.

4 /89 

### Rule 74.15 : 2

### Any person utilizing alternate fuel, pursuant to the provisions of Subsection C.2 of this rule, shall maintain permanent daily records of each occurrence. Each record shall includa the type of fuel, the quantity of fuel, and the duration of 

### the occurrence. Records shall be maintained for a period of four (4) years and shall be available for inspection by the Air Pollution Control Officer upon request.

E. Test Methods

1. Compliance with the emission requirements in Section B shall be determined using the following test methods:

a. Oxides of Nitrogen - EPA Method 7E or ARB Method 100 b. Carbon Monoxide - EPA Method 10 or ARB Method 100

C. 

### Stack Gas Oxygen - EPA Method 3A or ARB Method 100

2. Emission tests resulting in compliance determinations for therequirements of Subsection B.1 shall be conducted on units in "asfound" operating condition. However, no emission test for this rule shall be conducted during start-up, shutdown or under breakdown conditions.

3. The NOx parts per million emission limitation specified in Subsection B.1 is expressed as nitrogen dioxide. The limitations for both NOx and CO are referenced at three (3) percent volume stack gas oxygen on a dry basis averaged over 15 consecutive minutes.

F. Violations

1. Failure to comply with any provision of this rule shall constitute a violation o£ this rule.

2. Any unit subject to the provisions of Subsection B.2 shall comply with the provisions of Subsection B.1 if the unit operates during any twelve (12) month period at a total annual heat input rate greater than the applicable annual heat input rate specified in Subsection B.2.

G. Definitions

1. "Boiler, Steam Generator": Any combustion equipment fired with liquid and/or gaseous fuel and used to produce steam. These terms do not include any unfired waste heat recovery boiler that is used to recover sensible heat from the exhaust of any combustion equipment.

2. "Process Heater": Any combustion equipment fired with liquid and/or gaseous fuel and which transfers heat from combustion gases to water or process streams. Process Heater does not include any kiln or oven used for drying, baking, cooking, calcinating or vitrifying or any fuel-fired degreasing or metal finishing equipment.

4/89 Rule 74.15: 33. "Rated Heat Input Capacity"

~ The heat input capacity specified on the nameplate o= the unit's burner. If the burner has been permanently altered or modified such that the maximum heat input is different than the input capacity specified on the nameplate, and this alteration or modification has been approved in writing by the Air Pollution Control officer, then the new maximum heat input shall be considered as the rated heat input capacity.

4. "Unit": Any boiler, steam generator or process heater as defined in Subsections G.1 and G.2 of this rule.

5. "Water Heater": A device that heats water to a thermostaticallycontrolled temperature for delivery , on demand.

H. Increments of Progress

1. For units subject to Subsection B.1 and with a rated heat input capacity of equal to or greater than ten (10) million BTtT's per hour, complete Authority to Construct applications shall be submitted to the APCD before March 1, 1990, and final compliance shall be demonstrated before September 1, 1991.

2. For units subject to Subsection B.1 and with a rated heat input capacity of equal to or greater than five (5) million BTU's per hour, but less than ten (10) million BTiI's per hour, complete Authority to Construct applications sha11 be submitted to the APCD before March 1, 1991, and final compliance shall be demonstrated before March 1, 1992.

3. For units subject to Subsections B.2, final compliance shall be demonstrated by March 1, 1990.

4/89 Rule 74.15: 4ATTACHMENT 1

Equipment Tuning Procedure l

Nothing in this Equipment Tuning Procedure shali be construed to require any act or omission that would result in unsafe conditions or would be in violation of any regulation or requirement established by Factory Mutual, Industrial Risk Insurors, National Fire Prevention Association, the California Department of Industrial Relations (Occupational Safety and Health Division). the Federal Occupational Safety and Health Administration, or other relevant regulations and requirements.

1. Operate the unit at the firing rate most typical of normal operation. If the unit experiences significant load variations during normal operation, operate it at its average firing rate.

2. At this firing rate, record stack gas temperature, oxygenconcentratiIn, and CO concentration (for gaseous fuels) or smokespot number (for liquid fuels), and observe flame conditions after unit operation stabilizes at the firing rate selected. If the excess oxygen in the stack ias is at the lower end of the range of typical minimum values , and if the Co emissions are low and there is not smoke, the unit is probably operating at near optimum efficiency - at this particular firing rate: However, complete the remaining portion of this procedure to determine whether still lower oxygen levels are practical.

3. Increase combustion air flow to the furnace until stack gas oxygen ievels increase by one to two percent over the level measured in Step 2. As in Step 2, record the stack gas temperature, CO concentration (for gaseous fuels) or smoke-spot number (for liquid fuels), and observe flame conditions for these higher oxxygen levels after boiler operation stabilizes.

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

2. The smoke-spot number can be determined with ASTM Test Method D2156 or with the Bacharach method. ASTM Test Method D-2156 is included in a tuneup kit that can be purchased from the Bacharach Company.

3. Typical minimum oaygen levels for boilers at high firing rates are:

1. For natural gas: 0.5% - 3% 2. For liquid fuels: 2% - 4%

4/89 ATTACHMENT 1 

### Rule 74.15 : 5

### 4. Decrease combustion air flow until the stack gas oxygen concentration is at the level measured in Step 2. From this level gradually reduce the combustion air flow, in small increments. After each increment, record the stack gas temperature, oxygen concentration, 

### CO concentration (for gaseous fuels) and smoke-spot number (for liquid fuels). Also observe the flame and record any changes in its condition.

5. Continue to reduce combustion air flov stepwise, until one of these limits in reached:

a. Unacceptable flame conditions - such as flame impingement on furnace walls or burner parts, excessive flame carryover, or flame instability.

b. Stack gas CO concentrations greater than 400 ppm.

C. 

### Smoking at the stack.

d. Equipment-related limitations - such as low vindbox/furnace pressure differential, built in air-flow limits, etc.

6. Develop an 0 2 /CO curve (for gaseous fuels) or 0 2 /smoke curve (for liquid fuels) similar to those shown in Figures 1 and 2 using the excess oxygen and CO or smoke-spot number data obtained at each combustion air flow setting.

7. From the curves prepared in Step 6, find the stack gas oxygen levels where the CO emissions or smoke-spot number equal the following values:

Zuel Measurement Va1ue

Gaseous CO Emissions 400 ppm

#1 & 

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

#k oil smoke-spot number number 2
#5 oil ' smoke-spot number number 3

Other oils smoke-spot number number 4
The above conditions are referred to as CO or smoke threshold, or as the minimum excess oxygen ievel.
Compare this minimum value of excess oxygen to the expected value provided by the combustion unit manufacturer. If the minimum level found is substantially higher than the value provided by the combustion unit manufacturer, burner adjustments can probably be made to improve fuel and air mixing, thereby allowing operation with less air.

4/89 ATTACEMENT 1 gule 74.15: 6

### 8. Add 0.5 to 2.0 percent to the minimum excess oxygen level found in Step 7 and reset burner controls to operate automatically at this higher stack gas oxygen level. This margin above the minimum oxygen level accounts for fuel variations, variations in atmospheric conditions, load changes, and nonrepeatability or play in automatic controls.

9. If the load of the combustion unit varies significantly during normal operation, repeat Steps 1-8 for firing ratas that represent the upper and lover limits of the range of the load. Because control adjustments at one firing rate may affect conditions at other firing rates, it may not be possible to establish the optimum excess oxygen level at all firing ratas. If this is the case, choose the burner control settings that give best performance over the range of firing rates. If one firing rate predominates, settings should optimize conditions at that rate.

10. Verify that the nev settings can accommodate the sudden changes that may occur in daily operation vithout adverse effects. Do this by increasing and decreasing load rapidly vhile observing the flame and stack. If any of the conditions in Step 5 result, reset the combustion controls to provide a slightly higher level of excess oxygen at the affect firing rates. Next, verify these nev settings in a similar fashion. Then make sure that the final control settings are recorded at steady-state operating conditions for £uture reference.

4/89 ATTACHIiENT 1 Rule 74.15: 7