2|February 23, 2010 ICAPCD RULE 400.2 APPENDIX B

Section E of the rule includes monitoring and recordkeeping to insure compliance. New 

and existing emission Units that do not require modification to comply with the rule shall 

be in full compliance upon adoption of the rule. However, for existing sources not in 

compliance with Rule 400.2 limits, a compliance schedule, incorporated in section I, 

allows sources to ease into compliance at a later date. The compliance schedule for units 

that require equipment modification is as follows:

 By June 30, 2010, submit a complete application for an Authority to Construct for all 

modifications to non-exempted emission units.

 By June 30, 2011, be in full compliance with the requirements of the rule.

II BACKGROUND

Boilers or Steam Generators are closed vessels in which water is heated and where 

steam is generated or superheated, or any combination thereof, under pressure or 

vacuum by the application of heat from the combustion of fuels. Process heaters are 

closed vessels where heat is transferred to fluids, process stream or other material. 

Boilers, steam generators and process heaters have no direct contact between the 

products of combustion and the material to be heated.

NOx forms during the combustion of fuel, and other products of combustion are emitted to 

the atmosphere in the flue gas stream. The formation of NOx resulting from the 

combustion processes is governed primarily by the chemically-bound nitrogen content of 

the fuel, the oxygen concentration of the flame, the temperature of the flame, and the 

length of time the combustion gases are held at the flame temperature.

III CONTROL TECHNOLOGIES

For most applications reducing NOx emissions from boilers, steam generators and 

process heaters can be broken down into four methods. These are: (1) retrofit low NOx 

emitting burners, (2) retrofit flue gas recirculation systems (3) installation of ammonia or 

urea injection systems for selective noncatalytic reduction, and (4) installation of 

ammonia or urea injection systems along with catalytic reactors for selective catalytic 

reduction.
3|February 23, 2010 ICAPCD RULE 400.2 APPENDIX B

A Low NOx Burners

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

combustion product recirculation to lower NOx formation in the flame. Low excess air 

combustion and combustion product recirculation decrease the oxygen available for 

NOx formation. Combustion product recirculation also lowers the bulk flame 

temperature, and consequently lowers the NOx formation rate and equilibrium 

concentration. Staged air burners lower available oxygen at points in the combustion 

chamber where the temperature is high. Staged fuel burners lower the temperature at 

points in the combustion chamber where available oxygen is high. Installation of low 

NOx burners on existing units 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 conventional 

fuel oils or crude oil the anticipated reduction will be lower due to the effects of 

chemically bound nitrogen in the fuel. It is likely that Low NOx burners using staged 

combustion and O2 control can achieve the gas-fire standards contained in the rule. 

However, it is anticipated most liquid fuel fired units will require low nitrogen content 

"clean fuels" and Low NOx burners and other controls to comply with the emission 

limitation of the proposed rule.

B Flue Gas Recirculation (FGR)

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, duct work, 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 gas fired units, but 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. For units fired with conventional fuel 

oils or crude oil the anticipated reduction will be lower due to the effects of chemically 

bound nitrogen in the fuel.

C Selective Catalytic Reduction (SCR)

SCR is a process that chemically reduces NOx with ammonia (NH3) over a 

heterogeneous catalyst in the presence of oxygen (O2). The process is termed 

selective because the reducing agent ammonia (NH3) preferentially attacks NOx rather 

than O2. However, the O2 enhances the reaction and is a necessary part of the reaction 

scheme. Thus, SCR is potentially applicable to flue gas under oxidizing conditions, 

greater than one percent O2.
4|February 23, 2010 ICAPCD RULE 400.2 APPENDIX B

SCR retrofit 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. 

D Selective Non-Catalytic Reduction (SNCR)

SNCR processes for NOx control have been developed by several companies using 

ammonia and urea as reagents. These non-catalytic reduction processes are based on 

the gas phase homogeneous reaction between NOx in the flue gas and the reagents 

utilized by the process.

In general, ammonia (NH3) or urea based reagent is injected into the hot flue gas by 

means of either air or steam carrier gas at a point in the flue specifically selected to 

provide optimum reaction temperature and residence time. In the temperature range of 

1600°F to 2200°F, the reaction occurs through the injection of these reagents. 

Hydrogen can also be injected along with ammonia to extend the effectiveness range of 

the DeNOx reaction down to 1300°F.

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

generator where favorable process conditions exist. The SNCR performance using 

earlier technology ranges from 50 to 70 percent reduction for most oil fired and gas fired 

process heaters and steam boilers.

IV EMISSIONS REDUCTIONS FOR RULE 400.2

The ICAPCD staff conducted a survey of the permit database to identify the number of 

boilers, steam generators, and process heaters which will need to be replaced or 

retrofitted to comply with the new RACT requirements. The retrofitting of the emission 

units will fructify in a reduction of the emissions inventory for the facilities. Approximately 

13 units rated 5 million Btu per hour or greater are operated at three of Imperial 

County’s major source facilities and will be affected by the requirements of Rule 400.2. 

The ICAPCD survey indicates that one of the boilers (Unit 4) operated by Imperial 

Irrigation District at the El Centro Generating Facility would be out of compliance with 

the new emission limits. Unit 4 is currently equipped with a SCR and the source has 

been committed to restrict operation of this unit and to comply with the limits under the 

alternative compliance schedule; this boiler operates irregularly throughout the year and 

fuel usage will be limited to a maximum of 30%. A second boiler (Unit 3) operated at 

this facility will be shutdown and replaced with a re-powering project which will be in full 

compliance with BACT standards. Spreckels Sugar Company has indicated that its 

natural gas boilers will be retrofitted with Flue Gas Recirculation technology. In 

addition, one of natural gas process heaters operated by US Gypsum will be retrofitted 

to low Nox Burner in order to comply with RACT standards. The ICAPCD survey has 

not identified any existing boilers or process heaters operated at minor sources that 

may be out of compliance with the proposed RACT standards.
5|February 23, 2010 ICAPCD RULE 400.2 APPENDIX B

Summarized results of the average estimated NOx emissions reductions in lbs/year and 

tons/year are given in Table 1. The average emission reductions for IID and US 

Gypsum emissions units are derived from an average of three years of results extracted 

from source tests submitted to ICAPCD by each company. In the case of Spreckels 

Sugar information only two years of source test data is available; therefore, the average 

emission reductions are an average of two years of results extracted from source tests 

submitted to ICAPCD by Spreckels Sugar.

Table 1 Summary NOx Emissions 

Reductions Estimated for Rule 400.2 Limits

Facility 

Name

Emission 

Unit

Average 

Yearly 

Reductions 

(lbs/year)

Average 

Yearly 

Reductions 

(Tons/year)

IID Boiler 

No. 4 253,447 126.7

Holly 

Sugar

CE 

Boiler 16,565 8.3

Holly 

Sugar

Union 

Boiler 826 0.4

Holly 

Sugar

Auxiliary 

Boiler 123 0.1

U.S. 

Gypsum

Line # 1 

Stack 1 3,772 1.9

U.S. 

Gypsum

Line # 1 

Stack 2 3,877 1.9

U.S. 

Gypsum

Line # 1 

Stack 3 8,049 4.0

TOTAL 286,659 143.3

The average NOx emissions reductions for each emissions unit listed on Table 1 are 

calculated in the following tables.
6|February 23, 2010 ICAPCD RULE 400.2 APPENDIX B

Imperial Irrigation District Boiler No. 4 (3 Year Average)

Facility 

Name

Emission 

Unit

Total 

MMBtu

Curren

t ppmv

Current 

Emissions 

(lb/year)

New 

ppmv

New 

Emissions 

(lbs/year)

Reductions 

(lbs/year)

3% O2

IID Boiler No. 4 

(year 2008)

2,662,1

45 129 525,500 70 225,787 299,713

IID Boiler No. 4 

(year 2007)

1,692,3

05 149 336,600 70 143,531 193,069

IID Boiler No. 4 

(year 2006)

2,143,9

95 126 449,400 70 181,841 267,559

IID Boiler No. 4 Average Reduction Per Year 253,447

Spreckels Sugar Company, Inc - CE Boiler (3 Year Average)

Facility 

Name

Emission 

Unit

Total 

MMBtu

Current 

ppmv

Current 

Emissions 

(lb/year)

New 

ppmv

New 

Emissions 

(lbs/year)

Reductions 

(lbs/year)

3% O2

Spreckels 

Sugar

CE Boiler 

(year 

2007)

410,36

7 100 49,721 70 34,805 14,916

Spreckels 

Sugar

CE Boiler 

(year 

2002)

385,45

3 109 50,906 70 32,692 18,214

Spreckels 

Sugar CE Boiler Average Reduction per Year (2 year Avg.) 16,565

Note: Only Source test data for 2007 & 2002 are available
7|February 23, 2010 ICAPCD RULE 400.2 APPENDIX B

Spreckels Sugar Company, Inc - Union Boiler (*2 Year Average)

Facility 

Name

Emission 

Unit

Total 

MMBt

u

Current 

ppmv

Current 

Emissions 

(lb/year)

New 

ppmv

New 

Emissions 

(lbs/year)

Reductions 

(lbs/year)

3% O2

Spreckels 

Sugar

Union 

Boiler 

(year 

2007)

64,08

0 66 5,124 70 5,435 -311

Spreckels 

Sugar

Union 

Boiler 

(year 

2002)

95,24

7 87 10,040 70 8,078 1,962

Spreckels 

Sugar Union Boiler Average Reduction per Year (2 year Avg.) 826

Note: Only Source test data for 2007 & 2002 are available

Spreckels Sugar Company, Inc - Auxiliary Boiler (3 Year Average)

Facility 

Name

Emission 

Unit

Total 

MMB

tu

Current 

ppmv

Current 

Emissions 

(lb/year)

New 

ppmv

New 

Emissions 

(lbs/year)

Reductions 

(lbs/year)

3% O2

Spreckels 

Sugar

Auxiliary 

Boiler 

(year 

2006)

17,98

4 75 1,634 70 1,525 109

Spreckels 

Sugar

Auxiliary 

Boiler 

(year 

2005)

22,46

7 75 2,042 70 1,906 136

Spreckels 

Sugar Auxiliary Boiler Average Reduction per Year (2 year Avg.) 123

Note: 75 ppmv value was used from 2008 source test results
8|February 23, 2010 ICAPCD RULE 400.2 APPENDIX B

U.S. Gypsum - Line #1 (Stack #1) (3 Year Average)

Facility 

Name

Emission 

Unit

Total 

MMBtu

Current 

ppmv

Current 

Emissions 

(lb/year)

New 

ppmv

New 

Emissions 

(lbs/year)

Reductions 

(lbs/year)

3% O2

U.S. 

Gypsum

Stack #1 

(Year 

2008)

8,402 63 641 30 305 336

U.S. 

Gypsum

Stack #1 

(Year 

2007)

31,729 80 3,075 30 1,153 1,922

U.S. 

Gypsum

Stack #1 

(Year 

2006)

276,896 57 19,123 30 10,065 9,058

U.S. 

Gypsum Stack #1 No Reduction per year (3 year Avg.) 3,772

U.S. Gypsum - Line #1 (Stack #2) (3 Year Average)

Facility 

Name

Emission 

Unit

Total 

MMBtu

Current 

ppmv

Current 

Emissions 

(lb/year)

New 

ppmv

New 

Emissions 

(lbs/year)

Reductions 

(lbs/year)

3% O2

U.S. 

Gypsum

Stack #2 

(Year 

2008)

52,863 60 3,843 30 1,922 1,921

U.S. 

Gypsum

Stack #2 

(Year 

2007)

130,874 75 11,893 30 4,757 7,136

U.S. 

Gypsum

Stack #2 

(Year 

2006)

88,566 54 5,795 30 3,219 2,575

U.S. 

Gypsum Stack #2 No Reduction per year (3 year Avg.) 3,877
9|February 23, 2010 ICAPCD RULE 400.2 APPENDIX B

U.S. Gypsum - Line #1 (Stack #3) (3 Year Average)

Facility 

Name

Emission 

Unit

Total 

MMBtu

Current 

ppmv

Current 

Emissions 

(lb/year)

New 

ppmv

New 

Emissions 

(lbs/year)

Reductions 

(lbs/year)

3% O2

U.S. 

Gypsum

Stack #3 

(Year 

2008)

135,905 66 10,868 30 4,940 5,928

U.S. 

Gypsum

Stack #3 

(Year 

2007)

282,397 68 23,267 30 10,265 13,002

U.S. 

Gypsum

Stack #3 

(Year 

2006)

143,538 60 10,435 30 5,217 5,217

U.S. 

Gypsum Stack #3 No Reduction per year (3 year Avg.) 8,049