1.4 Natural Gas Combustion

1.4.1 General1-2

Natural gas is one of the major combustion fuels used throughout the country. It is mainly used 

to generate industrial and utility electric power, produce industrial process steam and heat, and heat 

residential and commercial space. Natural gas consists of a high percentage of methane (generally above 

85 percent) and varying amounts of ethane, propane, butane, and inerts (typically nitrogen, carbon 

dioxide, and helium). The average gross heating value of natural gas is approximately 1,020 British 

thermal units per standard cubic foot (Btu/scf), usually varying from 950 to 1,050 Btu/scf. 

1.4.2 Firing Practices3-5

 There are three major types of boilers used for natural gas combustion in commercial, industrial, 

and utility applications: watertube, firetube, and cast iron. Watertube boilers are designed to pass water 

through the inside of heat transfer tubes while the outside of the tubes is heated by direct contact with the 

hot combustion gases and through radiant heat transfer. The watertube design is the most common in 

utility and large industrial boilers. Watertube boilers are used for a variety of applications, ranging from 

providing large amounts of process steam, to providing hot water or steam for space heating, to 

generating high-temperature, high-pressure steam for producing electricity. Furthermore, watertube 

boilers can be distinguished either as field erected units or packaged units. 

Field erected boilers are boilers that are constructed on site and comprise the larger sized 

watertube boilers. Generally, boilers with heat input levels greater than 100 MMBtu/hr, are field erected. 

Field erected units usually have multiple burners and, given the customized nature of their construction, 

also have greater operational flexibility and NOx control options. Field erected units can also be further 

categorized as wall-fired or tangential-fired. Wall-fired units are characterized by multiple individual 

burners located on a single wall or on opposing walls of the furnace while tangential units have several 

rows of air and fuel nozzles located in each of the four corners of the boiler. 

Package units are constructed off-site and shipped to the location where they are needed. While 

the heat input levels of packaged units may range up to 250 MMBtu/hr, the physical size of these units are 

constrained by shipping considerations and generally have heat input levels less than 100 MMBtu/hr. 

Packaged units are always wall-fired units with one or more individual burners. Given the size 

limitations imposed on packaged boilers, they have limited operational flexibility and cannot feasibly 

incorporate some NOx control options. 

Firetube boilers are designed such that the hot combustion gases flow through tubes, which heat 

the water circulating outside of the tubes. These boilers are used primarily for space heating systems, 

industrial process steam, and portable power boilers. Firetube boilers are almost exclusively packaged 

units. The two major types of firetube units are Scotch Marine boilers and the older firebox boilers. In 

cast iron boilers, as in firetube boilers, the hot gases are contained inside the tubes and the water being 

heated circulates outside the tubes. However, the units are constructed of cast iron rather than steel. 

Virtually all cast iron boilers are constructed as package boilers. These boilers are used to produce either 

low-pressure steam or hot water, and are most commonly used in small commercial applications. 

Natural gas is also combusted in residential boilers and furnaces. Residential boilers and 

furnaces generally resemble firetube boilers with flue gas traveling through several channels or tubes with 

water or air circulated outside the channels or tubes. 

1.4.3 Emissions3-4
The emissions from natural gas-fired boilers and furnaces include nitrogen oxides (NOx), carbon 

monoxide (CO), and carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), volatile organic 

compounds (VOCs), trace amounts of sulfur dioxide (SO2), and particulate matter (PM). 

Nitrogen Oxides - 

Nitrogen oxides formation occurs by three fundamentally different mechanisms. The principal 

mechanism of NOx formation in natural gas combustion is thermal NOx. The thermal NOx mechanism 

occurs through the thermal dissociation and subsequent reaction of nitrogen (N2) and oxygen (O2) 

molecules in the combustion air. Most NOx formed through the thermal NOx mechanism occurs in the 

high temperature flame zone near the burners. The formation of thermal NOx is affected by three 

furnace-zone factors: (1) oxygen concentration, (2) peak temperature, and (3) time of exposure at peak 

temperature. As these three factors increase, NOx emission levels increase. The emission trends due to 

changes in these factors are fairly consistent for all types of natural gas-fired boilers and furnaces. 

Emission levels vary considerably with the type and size of combustor and with operating conditions 

(e.g., combustion air temperature, volumetric heat release rate, load, and excess oxygen level). 

The second mechanism of NOx formation, called prompt NOx, occurs through early reactions of 

nitrogen molecules in the combustion air and hydrocarbon radicals from the fuel. Prompt NOx reactions 

occur within the flame and are usually negligible when compared to the amount of NOx formed through 

the thermal NOx mechanism. However, prompt NOx levels may become significant with ultra-low-NOx

burners. 

The third mechanism of NOx formation, called fuel NOx, stems from the evolution and reaction of 

fuel-bound nitrogen compounds with oxygen. Due to the characteristically low fuel nitrogen content of 

natural gas, NOx formation through the fuel NOx mechanism is insignificant. 

Carbon Monoxide - 

The rate of CO emissions from boilers depends on the efficiency of natural gas combustion. 

Improperly tuned boilers and boilers operating at off-design levels decrease combustion efficiency 

resulting in increased CO emissions. In some cases, the addition of NOx control systems such as low 

NOx burners and flue gas recirculation (FGR) may also reduce combustion efficiency, resulting in higher 

CO emissions relative to uncontrolled boilers. 

Volatile Organic Compounds - 

The rate of VOC emissions from boilers and furnaces also depends on combustion efficiency. 

VOC emissions are minimized by combustion practices that promote high combustion temperatures, long 

residence times at those temperatures, and turbulent mixing of fuel and combustion air. Trace amounts 

of VOC species in the natural gas fuel (e.g., formaldehyde and benzene) may also contribute to VOC 

emissions if they are not completely combusted in the boiler. 

Sulfur Oxides - 

Emissions of SO2 from natural gas-fired boilers are low because pipeline quality natural gas 

typically has sulfur levels of 2,000 grains per million cubic feet. However, sulfur-containing odorants 

are added to natural gas for detecting leaks, leading to small amounts of SO2 emissions. Boilers 

combusting unprocessed natural gas may have higher SO2 emissions due to higher levels of sulfur in the 

natural gas. For these units, a sulfur mass balance should be used to determine SO2 emissions. 

Particulate Matter - 

Because natural gas is a gaseous fuel, filterable PM emissions are typically low. Particulate 

matter from natural gas combustion has been estimated to be less than 1 micrometer in size and has 

filterable and condensable fractions. Particulate matter in natural gas combustion are usually larger 

molecular weight hydrocarbons that are not fully combusted. Increased PM emissions may result from 

poor air/fuel mixing or maintenance problems. 
Greenhouse Gases -6-9

CO2, CH4, and N2O emissions are all produced during natural gas combustion. In properly tuned 

boilers, nearly all of the fuel carbon (99.9 percent) in natural gas is converted to CO2 during the 

combustion process. This conversion is relatively independent of boiler or combustor type. Fuel carbon 

not converted to CO2 results in CH4, CO, and/or VOC emissions and is due to incomplete combustion. 

Even in boilers operating with poor combustion efficiency, the amount of CH4, CO, and VOC produced is 

insignificant compared to CO2 levels. 

Formation of N2O during the combustion process is affected by two furnace-zone factors. N2O 

emissions are minimized when combustion temperatures are kept high (above 1475o

F) and excess oxygen 

is kept to a minimum (less than 1 percent). 

Methane emissions are highest during low-temperature combustion or incomplete combustion, 

such as the start-up or shut-down cycle for boilers. Typically, conditions that favor formation of N2O 

also favor emissions of methane. 

1.4.4 Controls4,10

NOx Controls - 

Currently, the two most prevalent combustion control techniques used to reduce NOx emissions 

from natural gas-fired boilers are flue gas recirculation (FGR) and low NOx burners. In an FGR system, 

a portion of the flue gas is recycled from the stack to the burner windbox. Upon entering the windbox, 

the recirculated gas is mixed with combustion air prior to being fed to the burner. The recycled flue gas 

consists of combustion products which act as inerts during combustion of the fuel/air mixture. The FGR 

system reduces NOx emissions by two mechanisms. Primarily, the recirculated gas acts as a dilutent to 

reduce combustion temperatures, thus suppressing the thermal NOx mechanism. To a lesser extent, FGR 

also reduces NOx formation by lowering the oxygen concentration in the primary flame zone. The 

amount of recirculated flue gas is a key operating parameter influencing NOx emission rates for these 

systems. An FGR system is normally used in combination with specially designed low NOx burners 

capable of sustaining a stable flame with the increased inert gas flow resulting from the use of FGR. 

When low NOx burners and FGR are used in combination, these techniques are capable of reducing NOx

emissions by 60 to 90 percent. 

Low NOx burners reduce NOx by accomplishing the combustion process in stages. Staging 

partially delays the combustion process, resulting in a cooler flame which suppresses thermal NOx

formation. The two most common types of low NOx burners being applied to natural gas-fired boilers 

are staged air burners and staged fuel burners. NOx emission reductions of 40 to 85 percent (relative to 

uncontrolled emission levels) have been observed with low NOx burners. 

Other combustion control techniques used to reduce NOx emissions include staged combustion 

and gas reburning. In staged combustion (e.g., burners-out-of-service and overfire air), the degree of 

staging is a key operating parameter influencing NOx emission rates. Gas reburning is similar to the use 

of overfire in the use of combustion staging. However, gas reburning injects additional amounts of 

natural gas in the upper furnace, just before the overfire air ports, to provide increased reduction of NOx

to NO2. 

Two postcombustion technologies that may be applied to natural gas-fired boilers to reduce NOx

emissions are selective noncatalytic reduction (SNCR) and selective catalytic reduction (SCR). The 

SNCR system injects ammonia (NH3) or urea into combustion flue gases (in a specific temperature zone) 

to reduce NOx emission. The Alternative Control Techniques (ACT) document for NOx emissions from 

utility boilers, maximum SNCR performance was estimated to range from 25 to 40 percent for natural 

gas-fired boilers.12 Performance data available from several natural gas fired utility boilers with SNCR 

show a 24 percent reduction in NOx for applications on wall-fired boilers and a 13 percent reduction in 
NOx for applications on tangential-fired boilers.11 In many situations, a boiler may have an SNCR system 

installed to trim NOx emissions to meet permitted levels. In these cases, the SNCR system may not be 

operated to achieve maximum NOx reduction. The SCR system involves injecting NH3 into the flue gas 

in the presence of a catalyst to reduce NOx emissions. No data were available on SCR performance on 

natural gas fired boilers at the time of this publication. However, the ACT Document for utility boilers 

estimates NOx reduction efficiencies for SCR control ranging from 80 to 90 percent.12

Emission factors for natural gas combustion in boilers and furnaces are presented in Tables 1.4-1, 

1.4-2, 1.4-3, and 1.4-4.11 Tables in this section present emission factors on a volume basis (lb/106

 scf). 

To convert to an energy basis (lb/MMBtu), divide by a heating value of 1,020 MMBtu/106

 scf. For the 

purposes of developing emission factors, natural gas combustors have been organized into three general 

categories: large wall-fired boilers with greater than 100 MMBtu/hr of heat input, boilers and residential 

furnaces with less than 100 MMBtu/hr of heat input, and tangential-fired boilers. Boilers within these 

categories share the same general design and operating characteristics and hence have similar emission 

characteristics when combusting natural gas. 

Emission factors are rated from A to E to provide the user with an indication of how “good” the 

factor is, with “A” being excellent and “E” being poor. The criteria that are used to determine a rating 

for an emission factor can be found in the Emission Factor Documentation for AP-42 Section 1.4 and in 

the introduction to the AP-42 document. 

1.4.5 Updates Since the Fifth Edition 

The Fifth Edition was released in January 1995. Revisions to this section are summarized below. 

For further detail, consult the Emission Factor Documentation for this section. These and other 

documents can be found on the Emission Factor and Inventory Group (EFIG) home page 

(http://www.epa.gov/ttn/chief). 

Supplement D, March 1998 

 Text was revised concerning Firing Practices, Emissions, and Controls. 

 All emission factors were updated based on 482 data points taken from 151 source tests. Many 

new emission factors have been added for speciated organic compounds, including hazardous air 

pollutants. 

July 1998 - minor changes 

 Footnote D was added to table 1.4-3 to explain why the sum of individual HAP may exceed VOC 

or TOC, the web address was updated, and the references were reordered. 
Table 1.4-1. EMISSION FACTORS FOR NITROGEN OXIDES (NOx) AND CARBON MONOXIDE 

FROM NATURAL GAS COMBUSTIONa

Combustor Type 

(MMBtu/hr Heat Input) 

[SCC] 

NOx

b 

Emission Factor 

(lb/106 scf) 

Emission 

 Factor 

 Rating 

Emission Factor 

(lb/106 scf) 

Large Wall-Fired Boilers  (>100) 

[1-01-006-01, 1-02-006-01, 1-03-006-01]

 Uncontrolled (PreNSPS)

c 280 A 84 

 Uncontrolled (Post-NSPS)

c 190 A 84 

 Controlled - Low NOx burners 140 A 84  Controlled - Flue gas recirculation 100 D 84 Small Boilers (<100) 

[1-01-006-02, 1-02-006-02, 1-03-006-02, 1-03-006-03]

Uncontrolle

d 100 B 84 

Controlled - Low NOx burners 50 D 84 Controlled - Low NOx burners/Flue gas recirculation 32 C 84 

Tangential-Fired Boilers (All Sizes) [1-01-006-04]

Uncontrolle

d 170 A 24 

Controlled - Flue gas recirculation 76 D 98 

Residential Furnaces (<0.3) [No SCC]

Uncontrolle

d 94 B 40 

a Reference 11. Units are in pounds of pollutant per million standard cubic feet of natural gas fired. To convert from lb/10 6 scf to kg

Emission factors are based on an average natural gas higher heating value of 1,020 Btu/scf. To convert from 1b/10 6 scf to lb/MMBt

emission factors in this table may be converted to other natural gas heating values by multiplying the given emission factor by the ratvalue to this average heating value. SCC = Source Classification Code. ND = no data. NA = not applicable. b Expressed as NO2. For large and small wall fired boilers with SNCR control, apply a 24 percent reduction to the appropriate NO X e

tangential-fired boilers with SNCR control, apply a 13 percent reduction to the appropriate NO X emission factor. c NSPS=New Source Performance Standard as defined in 40 CFR 60 Subparts D and Db. Post-NSPS units are boilers with greater th

input that commenced construction modification, or reconstruction after August 17, 1971, and units with heat input capacities betwee

that commenced construction modification, or reconstruction after June 19, 1984. 
TABLE 1.4-2. EMISSION FACTORS FOR CRITERIA POLLUTANTS AND GREENHOUSE 

GASES FROM NATURAL GAS COMBUSTIONa

Pollutant Emission Factor 

(lb/106

 scf) Emission Factor Rating 

CO2

b

 120,000 A 

Lead 0.0005 D 

N2O (Uncontrolled) 2.2 E 

N2O (Controlled-low-NOX burner) 0.64 E 

PM (Total)c

 7.6 D 

PM (Condensable)c

 5.7 D 

PM (Filterable)c

 1.9 B 

SO2

d

 0.6 A 

TOC 11 B 

Methane 2.3 B 

VOC 5.5 C 

a

 Reference 11. Units are in pounds of pollutant per million standard cubic feet of natural gas fired. 

Data are for all natural gas combustion sources. To convert from lb/106

 scf to kg/106 m3, multiply by 

16. To convert from lb/106

 scf to 1b/MMBtu, divide by 1,020. The emission factors in this table may 

be converted to other natural gas heating values by multiplying the given emission factor by the ratio of 

the specified heating value to this average heating value. TOC = Total Organic Compounds. 

VOC = Volatile Organic Compounds. 

b

 Based on approximately 100% conversion of fuel carbon to CO2. CO2[lb/106 scf] = (3.67) (CON) 

(C)(D), where CON = fractional conversion of fuel carbon to CO2, C = carbon content of fuel by weight 

(0.76), and D = density of fuel, 4.2x104

 lb/106 scf. c

 All PM (total, condensible, and filterable) is assumed to be less than 1.0 micrometer in diameter. 

Therefore, the PM emission factors presented here may be used to estimate PM10, PM2.5 or PM1

emissions. Total PM is the sum of the filterable PM and condensible PM. Condensible PM is the 

particulate matter collected using EPA Method 202 (or equivalent). Filterable PM is the particulate 

matter collected on, or prior to, the filter of an EPA Method 5 (or equivalent) sampling train. 

d

 Based on 100% conversion of fuel sulfur to SO2. 

 Assumes sulfur content is natural gas of 2,000 grains/106

 scf. The SO2 emission factor in this table can 

be converted to other natural gas sulfur contents by multiplying the SO2 emission factor by the ratio of 

the site-specific sulfur content (grains/106

 scf) to 2,000 grains/106 scf. 

 
TABLE 1.4-3. EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS FROM 

NATURAL GAS COMBUSTION (Continued) 

TABLE 1.4-3. EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS FROM 

NATURAL GAS COMBUSTIONa

CAS No. Pollutant Emission Factor 

(lb/106

 scf) Emission Factor Rating 

91-57-6 2-Methylnaphthaleneb, c 2.4E-05 D 

56-49-5 3-Methylchloranthreneb, c <1.8E-06 E 

7,12-

Dimethylbenz(a)anthraceneb,c

<1.6E-05 E 

83-32-9 Acenaphtheneb,c <1.8E-06 E 

203-96-8 Acenaphthyleneb,c <1.8E-06 E 

120-12-7 Anthraceneb,c <2.4E-06 E 

56-55-3 Benz(a)anthraceneb,c <1.8E-06 E 

71-43-2 Benzeneb

 2.1E-03 B 

50-32-8 Benzo(a)pyreneb,c <1.2E-06 E 

205-99-2 Benzo(b)fluorantheneb,c <1.8E-06 E 

191-24-2 Benzo(g,h,i)peryleneb,c <1.2E-06 E 

207-08-9 Benzo(k)fluorantheneb,c <1.8E-06 E 

106-97-8 Butane 2.1E+00 E 

218-01-9 Chryseneb,c <1.8E-06 E 

53-70-3 Dibenzo(a,h)anthraceneb,c <1.2E-06 E 

25321-22-

6 

Dichlorobenzeneb

 1.2E-03 E 

74-84-0 Ethane 3.1E+00 E 

206-44-0 Fluorantheneb,c 3.0E-06 E 

86-73-7 Fluoreneb,c 2.8E-06 E 

50-00-0 Formaldehydeb 7.5E-02 B 

110-54-3 Hexaneb

 1.8E+00 E 

193-39-5 Indeno(1,2,3-cd)pyreneb,c <1.8E-06 E 

91-20-3 Naphthaleneb

 6.1E-04 E 

109-66-0 Pentane 2.6E+00 E 

85-01-8 Phenanathreneb,c 1.7E-05 D 

74-98-6 Propane 1.6E+00 E 
TABLE 1.4-3. EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS FROM 

NATURAL GAS COMBUSTION (Continued) 

CAS No. Pollutant Emission Factor 

(lb/106

 scf) Emission Factor Rating 

129-00-0 Pyreneb, c 5.0E-06 E 

108-88-3 Tolueneb 3.4E-03 C 

a

 Reference 11. Units are in pounds of pollutant per million standard cubic feet of natural gas fired. 

Data are for all natural gas combustion sources. To convert from lb/106

 scf to kg/106 m3, multiply 

by 16. To convert from 1b/106

 scf to lb/MMBtu, divide by 1,020. Emission Factors preceeded with a 

less-than symbol are based on method detection limits. 

b

 Hazardous Air Pollutant (HAP) as defined by Section 112(b) of the Clean Air Act. 

c

 HAP because it is Polycyclic Organic Matter (POM). POM is a HAP as defined by Section 112(b) of 

the Clean Air Act. 

d The sum of individual organic compounds may exceed the VOC and TOC emission factors due to 

differences in test methods and the availability of test data for each pollutant. 
TABLE 1.4-4. EMISSION FACTORS FOR METALS FROM NATURAL GAS COMBUSTIONa

CAS No. Pollutant Emission Factor 

(lb/106

 scf) Emission Factor Rating 

7440-38-2 Arsenicb 2.0E-04 E 

7440-39-3 Barium 4.4E-03 D 

7440-41-7 Berylliumb <1.2E-05 E 

7440-43-9 Cadmiumb 1.1E-03 D 

7440-47-3 Chromiumb 1.4E-03 D 

7440-48-4 Cobaltb

 8.4E-05 D 

7440-50-8 Copper 8.5E-04 C 

7439-96-5 Manganeseb

 3.8E-04 D 

7439-97-6 Mercuryb

 2.6E-04 D 

7439-98-7 Molybdenum 1.1E-03 D 

7440-02-0 Nickelb

 2.1E-03 C 

7782-49-2 Seleniumb

 <2.4E-05 E 

7440-62-2 Vanadium 2.3E-03 D 

7440-66-6 Zinc 2.9E-02 E 

a

 Reference 11. Units are in pounds of pollutant per million standard cubic feet of natural gas fired. 

Data are for all natural gas combustion sources. Emission factors preceeded by a less-than symbol are 

based on method detection limits. To convert from lb/106

 scf to kg/106 m3, multiply by l6. To convert 

from lb/106

 scf to 1b/MMBtu, divide by 1,020. 

b

 Hazardous Air Pollutant as defined by Section 112(b) of the Clean Air Act. 
References For Section 1.4 

1. Exhaust Gases From Combustion And Industrial Processes, EPA Contract No. EHSD 71-36, 

Engineering Science, Inc., Washington, DC, October 1971. 

2. Chemical Engineers' Handbook, Fourth Edition, J. H. Perry, Editor, McGraw-Hill Book 

Company, New York, NY, 1963. 

3. Background Information Document For Industrial Boilers, EPA-450/3-82-006a, 

U. S. Environmental Protection Agency, Research Triangle Park, NC, March 1982. 

4. Background Information Document For Small Steam Generating Units, EPA-450/3-87-000, U. S 

. Environmental Protection Agency, Research Triangle Park, NC, 1987. 

5. J. L. Muhlbaier, "Particulate and Gaseous Emissions From Natural Gas Furnaces and Water 

Heaters", Journal Of The Air Pollution Control Association, December 1981. 

6. L. P. Nelson, et al., Global Combustion Sources Of Nitrous Oxide Emissions, Research Project 

2333-4 Interim Report, Sacramento: Radian Corporation, 1991. 

7. R. L. Peer, et al., Characterization Of Nitrous Oxide Emission Sources, Prepared for the 

U. S. EPA Contract 68-D1-0031, Research Triangle Park, NC: Radian Corporation, 1995. 

8. S. D. Piccot, et al., Emissions and Cost Estimates For Globally Significant Anthropogenic 

Combustion Sources Of NOx, N2O, CH4, CO, and CO2, EPA Contract No. 68-02-4288, Research 

Triangle Park, NC: Radian Corporation, 1990. 

9. Sector-Specific Issues and Reporting Methodologies Supporting the General Guidelines for the 

Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of 

1992 (1994) DOE/PO-0028, Volume 2 of 3, U.S. Department of Energy. 

10. J. P. Kesselring and W. V. Krill, "A Low-NOx Burner For Gas-Fired Firetube Boilers", 

Proceedings: 1985 Symposium On Stationary Combustion NOx Control, Volume 2, 

EPRI CS-4360, Electric Power Research Institute, Palo Alto, CA, January 1986. 

11. Emission Factor Documentation for AP-42 Section 1.4—Natural Gas Combustion, Technical 

Support Division, Office of Air Quality Planning and Standards, U. S. Environmental Protection 

Agency, Research Triangle Park, NC, 1997. 

12. Alternate Control Techniques Document - NOx Emissions from Utility Boilers, 

EPA-453/R-94-023, U. S. Environmental Protection Agency, Research Triangle Park, NC, March 

1994.