Date: January 9, 2013

Subject: Kraft Pulping Liquor and Woody Biomass Methane (CH4) and Nitrous 

Oxide (N2O) Emission Factor Literature Review 

EPA Contract No. EP-W-11-054; Task Order No. 04

From: Katie Hanks

Corey Gooden

To: Mike Hannan

U.S. Environmental Protection Agency

Washington, DC 20460 

I. Introduction

On November 16, 2012 the American Forest & Paper Association (AF&PA) and the 

American Wood Council (AWC) petitioned the U.S. Environmental Protection Agency (EPA) to

reconsider and revise the methane (CH4) and nitrous oxide (N2O) emission factors within 40 

CFR Part 98, Subparts AA and C for combustion of spent pulping liquor and wood residuals.

These emission factors are used to calculate and report annual emissions from pulp mill recovery

furnaces and wood-fired stationary combustion units under EPA’s mandatory greenhouse gas 

reporting program (GHGRP). In support of their petition, AF&PA and AWC (the “petitioners”) 

submitted a recent study performed by the National Council for Air and Stream Improvement 

(NCASI), Technical Bulletin 998, which contains new CH4 and N2O emissions test data that 

were not previously available to the GHGRP. Table 1 summarizes the existing GHGRP emission 

factors and the revised emission factors recommended by the petitioners.

Table 1 – Comparison of Existing and Recommended CH4 and N2O Emission Factors

Greenhouse Gas

Existing GHGRP 

Emission Factor

(kg/MMBtu)

Petitioners’

Recommended Emission 

Factor

(kg/MMBtu)

Percent 

Difference 

(%)

Table AA-1 – Spent Pulping Liquor

Methane 0.030 0.0019 94

Nitrous Oxide 0.005 0.00042 92

Table C-2 – Solid Biomass

Methane 0.032 0.0049 85

Nitrous Oxide 0.0042 0.0019 55

The purpose of this memorandum is to review the basis for the current GHGRP spent 

pulping liquor and wood residual combustion emission factors, integrate the new CH4 and N2O 

emissions test data provided in NCASI Technical Bulletin 998 with previously available 
2

emissions test data, and recommend possible regulatory amendments based on this work. Section 

II of this memorandum discusses the recovery furnace (spent pulping liquor) emission factors. 

Section III discusses the wood and wood residuals emission factors.

II. Recovery Furnace CH4 and N2O Emission Factors

A. Recovery Furnace Literature Review 

The CH4 and N2O emission factors for kraft pulping liquor combustion in pulp mill 

recovery furnaces are provided in Table AA-1 of 40 CFR part 98 Subpart AA. Table AA-1 is 

reproduced in Exhibit 1 below. 

The CH4 and N2O emission factors in Table AA-1 were based on the World Resources 

Institute/World Business Council for Sustainable Development (WRI/WBCSD) protocol 

developed by NCASI in 2005.

1 Appendix A1 contains a reproduction of the CH4 and N2O 

emission factor summary table from the WRI/WBCSD protocol and Appendix A2 contains other 

relevant pages from the WRI/WBCSD protocol. As shown in Appendix A1, four international 

references were cited in the WRI/WBCSD protocol.

2,3,4,5 The median of three of the emission 

 1 Calculation Tools for Estimating Greenhouse Gas Emissions from Pulp and Paper

Mills. Version 1.1. July 8, 2005. Prepared by the National Council for Air and Stream

Improvement for The Climate Change Working Group of The International Council of

Forest and Paper Associations (ICFPA). http://www.wbcsd.org/web/projects/forestry/pulp-andpaper-tool-guidance.pdf

2 Japan Paper Association (JPA). 2002. Various personal communications between JPA and Reid 

Miner of NCASI. Tokyo: Japan Paper Association. 

3 Swedish Environmental Protection Agency (Swedish EPA). 2004. Sweden’s national

Exhibit 1

Table AA–1 to Subpart AA of Part 98—Kraft Pulping Liquor Emissions Factors for 

Biomass-Based CO2, CH4, and N2O

Wood furnish

Biomass-based emissions factors

(kg/mmBtu HHV)

CO2 a CH4 N2O

North American Softwood 94.4 0.030 0.005

North American Hardwood 93.7

Bagasse 95.5

Bamboo 93.7

Straw 95.1 a

Includes emissions from both the recovery furnace and pulp mill lime kiln.
3

factors from the references formed the basis for the CH4 emission factors recommended in the 

WRI/WBCSD protocol (0.0025 kg/MMBtu), and the median of two studies was the basis for the 

recommended N2O emission factor (0.002 kg/MMBtu). The second reference (JPA 2002) did 

not have an N2O factor and therefore could not be used in calculating the WRI/WBCSDrecommended median N2O emission factor. The fourth reference (EEA 2004) was mentioned in 

the WRI/WBCSD protocol for comparison, but was not used in calculating the WRI/WBCSDrecommended median CH4 and N2O emission factors.

Given that the WRI/WBCSD CH4 and N2O emission factors were based on only two or 

three references which appeared to be uncertain based on the wide range in emissions from the 

references, the highest of the referenced emission factors was selected for inclusion in the U.S. 

EPA’s GHGRP Table AA-1 as a conservative measure. The highest values chosen from the 

WRI/WBCSD protocol for Table AA-1 were 30 kilograms (kg) of CH4 per terajoule (TJ) which 

converts to 0.030 kg CH4 per million British thermal units [MMBtu] and 5 kg N2O/TJ (0.005 

kg/MMBtu). These emission factors originated from the Swedish EPA report. The 0.030 kg 

CH4/MMBtu and 0.005 kg N2O/MMBtu emission factors were included in the original

greenhouse gas reporting rule (74 FR 16448, April 10 2009).

In their November 2012 petition for rulemaking, the petitioners stated that the current 

Table AA-1 emission factors (0.030 kg CH4/MMBtu and 0.005 kg N2O/MMBtu) are overly 

conservative, especially in light of the new information submitted in NCASI Technical Bulletin 

998. To investigate the petitioners’ concerns, RTI searched for each of the references from the 

WRI/WBCSD protocol to determine whether the references contained actual emissions test data 

that could be compared to the new data in Technical Bulletin 998.

We were unable to locate any formal documentation of the JPA 2002 reference from the 

WRI/WBCSD protocol. We successfully located the remaining references, and found that only 

Fortum 2001 contained actual emissions test data. The Fortum study is discussed further in 

Section II.B of this memorandum.

The Swedish EPA 2004 report documents Sweden’s national GHG inventory but does 

not include actual emissions test data. The N2O emission factor for spent pulping liquor was 

confirmed in the reference documentation, but the CH4 value of 30 kg/TJ was not. It appears that 

the same CH4 emission factor for wood waste was used for spent pulping liquor. Appendix B

provides the emission factor tables from the Swedish EPA report.

 

inventory report 2004 – Submitted under the United National Convention on Climate

Change. Stockholm: Swedish Environmental Protection Agency.

http://www.internat.naturvardsverket.se/documents/pollutants/climate/climate/fcccdata/N

IR.pdf (27 October 2004).

4 Fortum Power and Heat Oy (Fortum). 2001. Methane and nitrous oxide emissions in the 

Finnish energy production. Fortum, Finland: Fortum Power and Heat Oy, Technology.

5 European Environment Agency (EEA). 2004. EMEP/CORINAIR Emission Inventory 

Guidebook - Third edition, September 2004 Update. Copenhagen: European Environment

Agency. http://reports.eea.eu.int/EMEPCORINAIR4/en (27 October 2004).
4

The EEA 2004 reference is an update of the EMAP/CORINAIR Emissions inventory 

guidebook – Third edition. We did not locate the 2004 version of this document, but found that it 

was replaced with a 2006 version (and a 2007 version was available). We were unable to locate 

the 2004 emission factors using the newer document but we note that the EEA 2004 emission 

factor range (as referenced in the WRI/WBCSD protocol) is nearly the same as the range of 

emission factors provided in the 2006 Intergovernmental Panel on Climate Change (IPCC) 

Guidelines (IPCC 2006).

6 The table from IPCC 2006 that contains the spent pulping liquor 

emission factors is reproduced in Appendix C1. The IPCC 2006 emission factors for spent 

pulping liquor are:

• 1 to 18 kg CH4/TJ (0.001 to 0.019 kg CH4/MMBtu) with a recommended default of 3 kg 

CH4/TJ (0.0032 kg CH4/MMBtu), and 

• 1 to 21 kg N2O/TJ (0.001 to 0.022 kg N2O/MMBtu) with a recommended default of 2 kg 

N2O/TJ (0.002 kg N2O/MMBtu)

The IPCC 2006 report refers back to the 1996 IPCC Reference Manual as the source of the 

default emission factors included in IPCC 2006 Table 2.3 for the manufacturing and construction 

industries. However, as shown in Appendix C2, the 1996 Reference Manual does not include 

emission factors for spent puling liquor combustion. We were unable to determine the basis for 

the range of emission factors for spent pulping liquor in either EEA 2004 or IPCC 2006. No 

emissions test data were available in either document. 

B. Recovery Furnace Emissions Test Data

As mentioned previously, the only reference we located with spent pulping liquor CH4

and N2O emissions test data was Fortum 2001. The Fortum report provides emission factors 

derived from Fourier Transform Infrared Spectroscopy (FTIR) and non-dispersive infrared 

(NDIR) testing of two recovery furnaces located at a pulp mill in Finland. One of the furnaces 

was tested twice (once with spent liquor derived from softwood furnish and once with hardwood 

furnish). Appendix D contains the Fortum study. It appears that each test included only one 

measurement (e.g., one test run). The CH4 and N2O emissions averages from all three tests were 

less than or equal to 1 milligram per megajoule (mg/MJ) (0.0011 kg/MMBtu). 

The most commonly referenced compilations of pulp mill emission factors in the U.S. 

include EPA’s AP-42 Section 10.2 on Chemical Wood Pulping (dated September 1990), 7 and

more recent NCASI Technical Bulletins 973 (February 2010) and 884 (August 

2004). 8, 9 However, no CH4 or N2O emission factors are available in these documents for 

recovery furnace spent pulping liquor combustion.

 6

2006 Intergovernmental Panel on Climate Change (IPCC) Guidelines for National Greenhouse 

Gas Inventories. Intergovernmental Panel on Climate Change. Accessed at http://www.ipccnggip.iges.or.jp/public/2006gl/index.html

7

AP 42, Fifth Edition, Volume I Chapter 10: Wood Products Industry. Section 10.2 – Chemical 

Wood Pulping. September 1990. Available at 

http://www.epa.gov/ttn/chief/ap42/ch10/final/c10s02.pdf

8 NCASI. Compilation of ‘Air Toxic’ and Total Hydrocarbon Emissions Data for Pulp and Paper 

Mill Sources – A Second Update. Technical Bulletin 973. February 2010. 
5

The recent NCASI Technical Bulletin 998 submitted by petitioners contains FTIR testing 

of eight recovery furnaces using ASTM 6348-03.10 The U.S. EPA reference method for FTIR 

emissions testing is Method 320 (Vapor Phase Organic & Inorganic Emissions by Extractive 

FTIR) in Appendix A to 40 CFR Part 63.11 The ASTM D6348-03 method NCASI used for the 

CH4 and N2O testing is incorporated by reference into 40 CFR 63.14(b) as an approved 

alternative to Method 320 under two national emission standards for hazardous air pollutants 

(NESHAP) affecting the forest products industry.

Technical Bulletin 998 documents emissions testing from three non-direct contact 

evaporator (NDCE) recovery furnaces and five direct contact evaporator (DCE) recovery 

furnaces. All of the recovery furnaces tested processed spent pulping liquor derived from kraft 

pulping of hardwood or softwood feedstock. None of the furnaces processed any spent liquor 

derived from bagasse, bamboo, or straw. The kraft process is the most commonly used pulping 

process in the U.S. No chemical recovery combustion units (CRCU) found at sulfite and 

semichemcial pulp mills were included in Technical Bulletin 998. Under the GHGRP, the Table 

AA-1 CH4 and N2O emissions factors for kraft pulping are used to estimate emissions for spent 

pulping liquor in CRCU because no other information is available. 

Table 2 summarizes the results of the recovery furnace tests from Technical Bulletin 998. 

The number of valid CH4 and N2O test runs ranged from three to 10. Consistent with EPA 

emission factor development procedures, values one half of the method detection limit (MDL)

were used in test averages when some of the test run results were non-detect (ND) but others 

were detected.

Although it might be expected that DCE recovery furnaces could have greater CH4

emissions than NDCE furnaces due to contact of the hot flue gases with incoming pulping liquor 

in the DCE, the ranges of CH4 and N2O emissions reported in Technical Bulletin 998 overlap for 

the NDCE and DCE recovery furnaces. Therefore, it is reasonable for the GHGRP to continue to 

make no distinction between DCE and NDCE recovery furnaces and to consider test data from 

both types of furnaces together in a consolidated emission factor. Similarly, the ranges of the test 

results overlapped for liquor derived from hardwood and softwood feedstocks, and across air 

pollution control device types (wet bottom electrostatic precipitator [WBESP] and dry bottom 

electrostatic precipitator [DBESP]).

 9 NCASI. Compilation of Criteria Air Pollutant Emissions Data for Sources at Pulp and Paper 

Mills Including Boilers, Technical Bulletin 884. August 2004.

10 ASTM D6348-03, Standard Test Method for Determination of Gaseous Compounds by 

Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy.

11EPA Method 320. Vapor Phase Organic & Inorganic Emissions by Extractive FTIR. EPA’s 

CFR-promulgated air emissions measurement methods are available at 

http://www.epa.gov/ttn/emc/promgate.html 
Table 2. Summary of Recovery Furnaces Tested in Technical Bulletin 998

CH4, kg/MMBtu N2O, kg/MMBtu

ID

Mill 

type

RF 

type

Spent 

liquor 

feedstock

Other 

fuels Control

No. 

runs

No. 

ND 

runs Min Max Average

No. 

runs

No. 

ND 

runs Min Max Average

BRF5 kraft NDCE softwood DBESP 3 1 0.00039 0.001 0.00093 5 0 0.00062 0.0011 0.00082

DRF1 kraft NDCE softwood DBESP 8 7 0.000034 0.000047 0.000042 7 3 0.00012 0.00018 0.00015

ERF1 kraft NDCE softwood ESP 10 0 0.000065 0.0057 0.0031 10 7 0.000099 0.00065 0.00034

ARF3 kraft DCE softwood

No. 6 

oil DBESP 10 1 0.00008 0.00068 0.0002 9 0 0.00013 0.00043 0.00027

FRF1 kraft DCE unspecified WBESP 6 0 0.002 0.016 0.01 6 0 0.00044 0.00085 0.00065

FRF3 kraft DCE unspecified WBESP 9 0 0.00026 0.0021 0.0011 9 0 0.00034 0.00076 0.00049

GRF1 kraft DCE hardwood DBESP 6 5 0.0001 0.00015 0.00011 6 0 0.00012 0.00031 0.0002

GRF2 kraft DCE hardwood WBESP 5 0 0.0001 0.00016 0.00013 6 0 0.000092 0.00033 0.00019

The average was based on 1/2-MDL values for 

ND runs. Average: 0.00195 0.00039

min 0.000042 0.00015

max 0.01 0.00082

median 0.000565 0.000305
Only one of the eight furnaces tested burned a small amount of fossil fuel during the 

tests. Thus, the emission factors in Technical Bulletin 998 are representative of the biogenic CH4

and N2O emissions from recovery furnaces. Fossil fuel emissions from recovery furnaces are 

estimated separately using equations and emission factors under Subpart C of the GHGRP. 

The petitioners requested that EPA replace the current GHGRP Table AA-1 CH4 and 

N2O emission factors with the average factors from Technical Bulletin 998, specifically 0.0019 

kg CH4/MMBtu and 0.00042 kg N2O/MMBtu. [We note that the petitioners’ recommendation of 

0.00042 kg N2O/MMBtu does not exactly match the average N2O emission factor of 0.00039 kg 

N2O/MMBtu calculated in Table 2, likely due to rounding of the average emission factors from 

each test when they were reported in technical Bulletin 998.] Based upon the literature we 

reviewed, Technical Bulletin 998 appears to be the most recent and comprehensive source of 

U.S. recovery furnace CH4 and N2O emission factors available to date. 

The Fortum 2001 test data (the only other actual emissions data we located) compare 

fairly well with the data in NCASI Technical Bulletin 998. If the Fortum 2001 tests were 

included with the NCASI Technical Bulletin 998 data, the resultant emission factors would be 

0.0018 kg CH4/MMBtu and 0.00052 kg N2O/MMBtu as shown in Appendix E. Inclusion of the 

Fortum 2001 tests would have little effect of the petitioners’ suggested emission factors, but

continued application for the Fortum 2001 data for U.S. pulp mill recovery furnaces is 

questionable in light of more recent test data obtained by NCASI from repeated measurements of 

recovery furnaces at U.S. mills. Table 3 compares the emission factors in the GHGRP to those 

derived considering the Technical Bulletin 998 test data with and without the Fortum 2001 data. 

Table 3. Emission Factors for Spent Liquor Combustion in the GHGRP Table AA-1 

Compared to Emission Factors Derived from Available Emissions Test Data

Reference CH4, kg/MMBtu N2O, kg/MMBtu

GHGRP Table AA-1 0.03 0.005

Revised emission factors 

suggested by petitioners (TB 

998)

0.0019 0.000421

Average of all available data 

(TB 998 and Fortum 2001 as 

shown in Appendix E)

0.0018 0.00052

1. Calculated as 0.00039 in Table 2 of this memorandum, likely due to rounding. 
8

III. Wood and Wood Residuals Combustion CH4 and N2O Emission Factors

A. Wood and Wood Residuals Literature Review

The CH4 and N2O emission factors for combustion of solid biomass are provided in 

GHGRP Table C-2. Table C-2 contains one row for “Biomass Fuels-Solid (All fuel types listed 

in Table C-1).” Table C-1 of the GHGRP provides separate default higher heating values and 

carbon dioxide (CO2) emission factors for each type of solid biomass (wood and wood residuals, 

agricultural byproducts, peat, and solid byproducts). 

The existing Table C-2 emission factors are based on the Tier 1 emission factors for 

wood and wood waste in IPCC 2006. Appendix C1 of this memorandum contains the table from 

IPCC 2006 (Table 2-3) that was the source of the GHGRP Table C-2 solid biomass emission 

factors. The IPCC Tier 1 emission factors ranged from 10 to 100 kg CH4/TJ (0.011 to 0.11 kg 

CH4/MMBtu) and 1.5 to 15 kg N2O/TJ (0.0016 to 0.016 kg N2O/MMBtu). The default emission 

factors recommended by IPCC 2006 were 30 kg CH4/TJ (0.032 kg CH4/MMBtu) and 4 kg 

N2O/TJ (0.0042 kg N2O/MMBtu) on a net caloric value basis.

RTI traced the source of the IPCC 2006 Tier 1 emission factors back to the 1996 

Reference Manual. Relevant excerpts and the reference list from the 1996 Reference Manual are 

provided in Appendix C2 of this memorandum. The 1996 Reference Manual emission factors for 

many different fuels were based on, “the CORINAIR90 database, the CORINAIR 1994 default 

emission factors, the EDGAR Version 2.0 database, National Communications to the FCCC, 

Berdowski, et al. (1993a and 1993b), Radian Corporation (1990) and US EPA (1995).” RTI was 

able to obtain three of these references (National Communications to the FCCC, Radian 

Corporation 1995, and US EPA 1995), but did not find any actual emissions test data in the 

references. RTI was unable to locate the other references from the IPCC Reference Manual. The 

IPCC Reference Manual states that “additional research will need to be undertaken to further 

improve the quality of the emission factors.” The 1996 Reference Manual contained a Tier 2 

emission factor for CH4 of 15 kg CH4 /TJ (0.016 kg CH4/MMBtu) in addition to the Tier 1 

default factors adopted in the GHGRP. The Tier 2 emission factor was based on US EPA 1995.

The 2005 WRI/WBCSD protocol recommended an emission factor of 12 kg CH4/TJ 

(0.012 kg CH4/MMBtu) and 4 kg N2O/TJ (0.0042 kg CH4/MMBtu) based on the median of 

emission factors from various studies, including the IPCC Tier 1 and Tier 2 emission factors. 

Table 4 lists the biomass combustion CH4 and N2O emission factor references from the 

WRI/WBCSD protocol.
9

Table 4. References for the Biomass Emission Factors 

Included in the WRI/WBCSD Protocol

Abbreviated reference 

from WRI/WBCSD

protocol

Full reference

EEA 2004 European Environment Agency (EEA). 2004. EMEP/CORINAIR 

Emission inventory guidebook - Third edition, September 2004 Update. 

Copenhagen: European Environment Agency. 

IPCC 1997 Intergovernmental Panel on Climate Change (IPCC). 1997c. Revised 1996 

IPCC guidelines for national greenhouse gas inventories: Reference manual 

(Vol. 3). IPCC National Greenhouse Gas Inventory Program.

USEPA 2001 United States Environmental Protection Agency (USEPA). 2001. AP-42 

emission factors for wood residue combustion in boilers – Supplement G, July 

2001. Washington, DC: United States Environmental Protection Agency.

Fortum 2001 Fortum Power and Heat Oy (Fortum). 2001. Methane and nitrous oxide 

emissions in the Finnish energy production. Fortum, Finland: Fortum Power 

and Heat Oy, Technology.

NCASI 1980 National Council for Air and Stream Improvement, Inc. (NCASI). 1980. A 

study of wood residue fired power boiler total gaseous non-methane organic 

emissions in the Pacific Northwest. Air Quality Technical Bulletin No.109. 

Research Triangle Park, NC: National Council for Air and Stream 

Improvement, Inc.

NCASI 1985 National Council for Air and Stream Improvement, Inc. (NCASI). 1985. 

Volatile organic carbon emissions from wood residue fired power boilers in 

the Southeast. Technical Bulletin No.455. Research Triangle Park, NC: 

National Council for Air and Stream Improvement, Inc.

JPA 2002 Japan Paper Association (JPA). 2002. Various personal communications 

between JPA and Reid Miner of NCASI. Tokyo: Japan Paper Association.

AEA Tech. 2001 AEA Technology. 2001. UK greenhouse gas inventory 1990-1999: Annual 

report for submission under the Framework Convention on Climate Change. 

Oxfordshire, England: National Environmental Technology Centre.

Swedish EPA 2004 Swedish Environmental Protection Agency (Swedish EPA). 2004. Sweden’s 

national inventory report 2004 – Submitted under the United National 

Convention on Climate Change. Stockholm: Swedish Environmental 

Protection Agency.

The WRI/WCBSD protocol compared the emission factors from the above references to 

the emission factor range presented in EEA 2004. The EEA 2004 reference was not used in 

calculating the WRI/WBCSD-recommended median CH4 and N2O emission factors for woody 

biomass combustion. Appendix A1 contains a reproduction of the CH4 and N2O emission factor 

summary table from the WRI/WBCSD protocol and Appendix A2 contains other relevant pages 

from the WRI/WBCSD protocol.

RTI was unable to locate any formal documentation of the JPA 2002 reference from the 

WRI/WBCSD protocol. We successfully located the remaining references, and concluded that 

only USEPA 2001, Fortum 2001, NCASI 1980, and NCASI 1985 contained actual emissions test 

data. These studies are discussed further in Section III.B of this memorandum.
10

Appendix F presents the table containing emission factors for wood from the AEA 

Technology 2001 report

12 and indicates that the AEA Technology 2001 emission factors were 

based on CORINAIR (1992) and IPCC (1997). Emission factors for “Wood – Other Industry” 

appear to be the source of the emission factors included in the WRI/WBCSD protocol (although

for CH4 our conversions yielded an emission factor an order of magnitude lower than that 

reported in the WRI/WBCSD protocol). Using 20 GJ/t of dry solids, we calculated emission 

factors of 2.4 kg CH4/TJ and 3.5 kg N2O/TJ as opposed to the 24 kg CH4/TJ and 3.4 kg N2O/TJ 

provided in the WRI/WBCSD protocol. Either we were unable to identify the exact emissions 

factors used from the AEA Technology 2001 report, or possibly there was a decimal place typo 

in the WRI/WBCSD CH4 emission factor. The AEA Technology 2001 report did not contain any 

actual emissions test data for woody biomass CH4 and N2O. 

The Swedish EPA 2004 report documents Sweden’s national GHG inventory and did not 

include emissions testing. Appendix B of this memo provides the emission factor tables from the 

Swedish EPA report.

B. Wood and Wood Residuals Emissions Test Data

The only sources of actual emissions test data for CH4 or N2O RTI was able to locate to 

date include EPA’s AP-42 (USEPA 2001), Fortum 2001, NCASI 1980, NCASI 1985 and the 

new test data (new testing and boiler MACT data) used in NCASI Technical Bulletin 998. Tables 

6A and 6B in this section present the test results from each of these references.

The EPA’s AP-42 Chapter 1.6 contains a CH4 emission factor based on four emissions 

tests and an N2O emission factor based on two tests. The 1998 Industrial Combustion 

Coordinated Rulemaking (ICCR) data base was the source of the four CH4 tests. The N2O tests 

were conducted prior to 1993 and referenced from a prior AP-42 report. 

Fortum 2001 is a Finnish study that contains CH4 and N2O emissions testing for six

biomass boilers. Three of the boilers were tested with different fuel mixtures, for a total of nine 

fuel mixture test scenarios. The average of the results for the nine tests was reported in the 

WRI/WBCSD protocol. Review of Fortum 2001 reveals that only five of the tests involved

woody biomass, and three of these tests were for boilers burning 50 percent or more of peat. The 

other four tests were for boilers burning peat or a combination of peat and sludge (which was not 

described as industrial or municipal sludge so we interpreted this sludge to likely differ from 

forest products wastewater treatment residuals). Peat is turf resulting from an accumulation of 

partially decayed vegetation and is arguably different from woody biomass. Table C-1 in the 

GHGRP distinguishes peat from wood and wood residuals. The IPCC 2006 guidelines treat peat 

as fossil carbon due to the long length of time it takes to replace harvested peat.13

 12 http://uk-air.defra.gov.uk/library/reports?report_id=8

13IPCC 2006, p. G.3. http://www.ipccnggip.iges.or.jp/public/2006gl/pdf/0_Overview/V0_2_Glossary.pdf
11

The Fortum 2001 study does not specify the number of measurements (test runs) 

performed during each of the tests, so it is unclear if a three-run test was performed as is 

customary in the U.S. for stack testing. Table 5 below presents the results of the Fortum 2001

testing converted to kg/MMBtu. Poor combustion (e.g., high carbon monoxide emissions) was 

noted for one of the bark boiler tests (BFB2). This test was excluded from the WRI/WBCSD 

protocol. The three tests where at least 50 percent woody biomass was burned are included in the 

summary Tables 6A and 6B later in this section. The BFB2 CH4 test was also included in Table 

6A because the results are the same order of magnitude as two other tests noted in Technical 

Bulletin 998 (also noted for poor combustion). It is reasonable to expect that similar poor 

combustion could occur in some U.S. boilers (as evidenced by the two high CH4 tests in the 

boiler MACT data set documented in Technical Bulletin 998).

Table 5. Fortum 2001 Results from Emission Testing of Biomass Boilers in Finland

Unit Fuel CH4, kg/TJ

CH4, 

kg/MMBtu N2O, kg/TJ

N2O, 

kg/MMBtu

Circulating Fluidised Bed Boilers

CFB1 peat 1 0.0011 < 2 0.0021

CFB1

peat, wood 

(15%) 1 0.0011 4 0.0042

CFB2

peat, wood 

(20%) 1 0.0011 3 0.0032

CFB3 peat < 1 0.0011 26 0.0274

CFB3 bark 1 0.0011 10 0.0105

CFB 

Average 1 0.0011 9.0 0.0095

Bubbling Fluidised Bed Boilers

BFB1 peat 2 0.0021 < 1 0.0011

BFB2 bark * 72 0.0759 < 2 0.0021

BFB3

peat, bark 

(50%) < 1 0.0011 < 2 0.0021

BFB3 peat, sludge 3 0.0032 < 2 0.0021

BFB 

Average 19.5 0.017 3.2 0.0034

Overall 

average 0.0097 0.0061

*Poor combustion conditions.

As mentioned previously, the emission factors reported in the WRI/WBCSD protocol 

from the two NCASI technical bulletins, TB 109 (NCASI 1980) and TB 455 (NCASI 1985) are 

based on actual emissions testing of multiple boilers so the emission factors from the two 

technical bulletins were included in Table 6A. Technical Bulletin 109 contains volatile organic 

carbon (VOC) emissions testing for four boilers, and Technical Bulletin 455 contains VOC 

testing for six boilers. RTI reviewed these technical bulletins and found CH4 concentration data. 

CH4 is usually measured as part of the total organic compounds in a gas, but is not a VOC. CH4
12

is sometimes reported separately if measured in conjunction with VOC. No flow rate data were 

reported with the concentration measurements in the two technical bulletins so we were unable to 

verify the emission factors reported in the WRI/WBCSD protocol or to extract boiler-specific 

CH4 test results from the technical bulletins. The emission factors provided in Table 6A are the 

aggregated emission factors provided in the WRI/WBCSD protocol. 

The 2012 NCASI Technical Bulletin 998 submitted by petitioners contains FTIR testing 

of CH4 and N2O emissions from five pulp mill boilers using ASTM 6348-03. At least 90 percent

of the boiler heat input was from biomass during testing. In addition, NCASI Technical Bulletin 

998 provides results from a review of EPA Method 18 CH4 test data contained in EPA’s boiler 

maximum achievable control technology (MACT) data base for boilers firing more than 80 

percent of heat input as biomass. Predominantly woody biomass boilers of various designs 

(stoker, fluidized bed, fuel cell, dutch oven) firing wood, bark, or wastewater treatment (WWT) 

sludge were studied. 

RTI downloaded the boiler MACT data base referenced by the petitioners14 to determine 

if additional CH4 and N2O tests were available for major or area sources firing predominantly 

woody biomass. Consistent with Technical Bulletin 998, 19 methane tests (using EPA Method 

18) for major source boilers were identified in the data base. The units of measure in the data 

base were parts per million rather than kg/MMBtu. A code-breaker and more information (e.g., 

gas flow rates) would be needed to map the 19 tests in the data base to the 19 tests listed in 

Technical Bulletin 998. We suspect that NCASI used the original boiler MACT test reports to 

assemble the information in Technical Bulletin 998 as opposed to the information directly from 

the data base. No N2O tests were found in the data base (consistent with NCASI Technical 

Bulletin 998 which did not tabulate N2O data from the MACT testing). No additional CH4 or 

N2O tests were identified in the data base for area sources. From this we can infer that all of the 

available biomass CH4 data from the boiler MACT emissions testing data base was used in 

Technical Bulletin 998 (i.e., that tests were not chosen selectively). The control devices used on 

the biomass boilers included particulate matter controls (cyclone or multiclone, electrified filter 

bed [EFB], electrostatic precipitator [ESP], fabric filter) and other controls with unknown (or 

unpredictable) effect on methane (dry sorbent injection followed by an ESP or fabric filter, spray 

dryer and fabric filter, and wet scrubbers).

The new CH4 and N2O emissions test data provided in Technical Bulletin 998 and test 

data from other references are summarized in Tables 6A and 6B. The data shown in these tables 

represent measurements from combustion of various woody biomass fuels in different types of 

boilers. Poor combustion conditions were reported in three of the boilers tested for CH4. 

Combustion conditions can vary from boiler to boiler. For example, it has been documented that 

poor combustion leads to higher CH4 emissions, and fluidized bed combustors may operate 

within a range of combustion temperatures that favors formation of N2O.

15, 16 In addition, other 

 14 May 30, 2012 Boiler MACT Draft Emissions and Survey Results Databases. Available at: 

http://www.epa.gov/ttn/atw/boiler/boilerpg.html

15 Intergovernmental Panel on Climate Change (IPCC). 1997c. Revised 1996 IPCC guidelines for 

national greenhouse gas inventories: Reference manual (Vol. 3). IPCC National Greenhouse Gas 

Inventory Program.
13

wood-fired combustion sources with differing conditions (e.g., direct wood fired dryers) may use 

the GHGRP wood and wood residuals emission factors developed in this memo. Therefore, it 

seems reasonable to retain in Table 6A the tests where poor combustion was suspected as leading 

to higher CH4 emissions in order to account for variability and avoid underestimation of GHG 

emissions from wood-fired combustors. Similarly, given that some of the woody biomass boilers 

that report under the GHGRP are fluidized bed boilers, it seems reasonable to retain the Fortum 

data for fluidized bed boilers in the N2O data set in order to avoid underestimation of N2O 

emissions.

 16 Fortum Power and Heat Oy (Fortum). 2001. Methane and nitrous oxide emissions in the 

Finnish energy production. Fortum, Finland: Fortum Power and Heat Oy, Technology.
14

Table 6A. Methane Emissions Test Data from Technical Bulletin 998 and Other References

Count Data Source Source ID Test Date APCD

CH4, 

kg/MMBtu Min run Max run No. runs note

1

TB 998 -NCASI 

Testing ABB2 7/8/2008 wet scrubber 0.0011 0.00044 0.0016 4 stoker-bark

2 CCB4 12/2/2008 ESP 0.0031 0.0004 0.0077 6 stoker-bark, no. 6 oil

3 DBB1 2/18/2009 ESP 0.00028 0.00017 0.00047 10 stoker-bark

4 FBB1 3/23/2009

2 boilers with 

common wet 

scrubber 0.041 0.017 0.078 10

poor combustion; 2 wood 

stokers

5 GCB3 6/10/2009 Wet scrubber 0.00068 0.00054 0.00099 6 stoker-bark, no. 6 oil

6 TB 998 -MACT HCB1 7/15/2009 Not Reported 0.00012 0.00011 0.00012 3 [all ND] bark, resin wood

7 ICB1 7/14/2009 Not Reported 0.0018 0.0016 0.002 3 hog fuel, MSW, gas

8 JCB2 7/1/2009 Not Reported 0.0076 0.0037 0.01 3 bark, TDF, oil

9 KCB2 8/4/2009 Not Reported 0.00043 0.00029 0.00061 3 bark

10 LCB1 8/13/2009 Not Reported 0.00072 0.00037 0.00092 3 wood/bark

11 MCB3 8/6/2009 Not Reported 0.00032 0.00022 0.00048 3 wood waste

12 NCB1 8/6/2009 Not Reported 0.001 0.0005 0.0014 3 bark

13 OCB4 8/11/2009 Not Reported 0.00023 0.00015 0.00031 2

bark, oil, gas; 1 run omitted 

(0.00371 kg/mmbtu)

14 PCB4 8/5/2009 Not Reported 0.00018 0.00016 0.00021 3 bark, WWT sludge, TDF

15 QCB8 7/29/2009 Not Reported 0.0007 0.00064 0.00076 3 WWT sludge, bark

16 RCB1 9/2/2009 Not Reported 0.0016 0.00046 0.0036 3 bark

17 SCB1 8/14/2009 Not Reported 0.0022 0.00078 0.0047 3

bark, cross ties, gas, WWT 

sludge

18 TCB1 8/11/2009 Not Reported 0.0015 0.00053 0.0024 3 wood

19 UCB2 6/24/2009 Not Reported 0.0027 0.00075 0.005 3

wood/bark, WWT sludge, 

OCC rejects, gas

20 VCB2 8/6/2009 Not Reported 0.0012 0.00055 0.0023 3

bark, WWT sludge, cross 

ties, gas

21 WCB1 7/30/2009 Not Reported 0.0012 0.00093 0.0014 3

bark, OCC rejects, gas, 

WWT sludge

22 XCB1 8/13/2009 Not Reported 0.0052 0.003 0.0056 3 bark

23 YCB1 8/6/2009 Not Reported 0.046 0.032 0.056 3 poor combustion; bark, gas

24 ZCB1 10/8/2009 Not Reported 0.0048 0.0034 0.0046 3 bark

25 AACB1 7/29/2009 Not Reported 0.0048 0.00091 0.011 3 wood/bark

26 ABCB1 7/23/2009 Not Reported 0.0007 0.00063 0.00084 3 bark/wood

27 ACCB1 7/29/2009 Not Reported 0.00051 0.00014 0.00096 3 bark
15

Count Data Source Source ID Test Date APCD

CH4, 

kg/MMBtu Min run Max run No. runs note

28 NCASI 1980 pre-1980 None 0.0086 Avg EF

Pre-1980 stoker ahead of 

control device

29 NCASI 1985 pre-1985 Wet Scrubber 0.0028 Avg EF

Pre-1980 stoker after 

scrubber

30 Fortum 2001 CFB3 pre-2001 None1 0.0011 FB-bark

31 BFB2 pre-2001 None1 0.0759 FB-bark; poor combustion

32 BFB3 pre-2001 None1 0.0011 FB-peat, bark (50%); ND

33 AP-42, Ch 1.6 B109 9/24/1996 Wet Scrubber 0.020 0.037 0.053 3 Bark/Wet Wood

34 B47 6/1/1995 Fabric Filter 0.0030 0.0055 0.0090 3

Wet Wood. B47 & B48 are 

dual stacks on the same 

boiler.

35 B48 6/1/1995 Fabric Filter 0.0052 0.00016 0.025 3

Wet Wood. B47 & B48 are 

dual stacks on the same 

boiler.

36 B49 12/22/1994 ESP 0.0091 0.010 0.032 3 Wet Wood

NCASI Min 0.00012

TB 998 Max 0.046

Average 0.0049

Stdev 0.011

Median 0.0012

All Min 0.00012

Max 0.076

Average 0.0072

Stdev 0.016

Median 0.0016

All but Min 0.00012

Fortum Max 0.046

Average 0.0055

Stdev 0.011

Median 0.0016

Current GHGRP Table C-2 Factor 0.032

1. The report stated that all tests were completed with no limestone feed. 
16

Table 6B. N2O Emissions Test Data from Technical Bulletin 998 and Other References

Count Data Source Source ID Test Date APCD

N2O, 

kg/MMBtu Min run Max run No. runs note

1

TB 998 -NCASI 

Testing ABB2 7/8/2008 wet scrubber 0.0027 0.0014 0.004 5 stoker-bark

2 CCB4 12/2/2008 ESP 0.0015 0.0012 0.0019 6 stoker-bark, no. 6 oil

3 DBB1 2/18/2009 ESP 0.0011 0.00062 0.0013 10 [2 ND] stoker-bark

4 FBB1 3/23/2009

2 boilers with 

common wet 

scrubber 0.00073 0.00028 0.0023 10 [2 ND]

poor combustion; 2 

wood stokers

5 GCB3 6/10/2009 Wet scrubber 0.0034 0.002 0.0048 6 stoker-bark, no. 6 oil

6 Fortum 2001 CFB3 pre-2001 None1 0.0105 FB- bark

7 BFB2 pre-2001 None1 0.0021 FB-bark; ND

8 BFB3 pre-2001 None1 0.0021

FB- peat, bark (50%); 

ND

9 AP-42, Ch 1.6 pre-1993 Not Reported 0.010 FBC-Wet Wood

10 pre-1993 Not Reported 0.0020 Stoker-Wet Wood

NCASI Min 0.00073

TB 998 Max 0.0034

Average 0.0019

Stdev 0.0011

Median 0.0015

All Min 0.00073

Max 0.011

Average 0.0036

Stdev 0.004

Median 0.0021

All but Min 0.00073

Fortum Max 0.010

Average 0.0031

Stdev 0.0032

Median 0.0020

Current GHGRP Table C-2 Factor 0.0042

1. The report stated that all tests were completed with no limestone feed. 
17

Based upon the literature reviewed, Technical Bulletin 998 appears to be the most recent 

and comprehensive source of wood-fired boiler CH4 and N2O emission factors available to date. 

The data presented in Technical Bulletin 998 could be used alone or in conjunction with older 

emissions test data to add a row to the GHGRP Table C-2 with emission factors for wood and 

wood residuals. Table 7 summarizes the current solid biomass emission factors in Table C-2, the 

revised emission factors requested by petitioners based on NCASI TB 998, and other alternatives 

incorporating older emissions test data. The current GHGRP Table C-2 factors are not limited to 

woody biomass and apply for “Biomass Fuels-Solid (All fuel types listed in table C-1).” 

However, the test data presented in Tables 6A and 6B are based primarily on boilers firing wood 

and wood residuals. Therefore, EPA could add a row to Table C-2 for “wood and wood 

residuals” similar to the current Table C-1, and leave the existing Table C-2 biomass factors for 

other forms of solid biomass.

Table 7. Emission factors for Wood and Wood Residuals Derived from the Available Data

Reference CH4, kg/MMBtu N2O, kg/MMBtu

GHGRP (based on IPCC 

2006)

0.032 0.0042

Revised emission factors 

suggested by petitioners (TB 

998)

0.0049 0.0019

Average of all available data 0.0072 0.0036

Average of available data 

without Fortum 2001

0.0055 0.0031

 

IV. Summary and Conclusions

RTI performed a literature review to document the basis for the existing GHGRP CH4

and N2O emission factors in Subpart AA for spent pulping liquor and in Subpart C for solid 

biomass fuels (specifically wood and wood residuals). The purpose of the literature review was 

to locate additional emission testing results that could be compared to new information (NCASI 

Technical Bulletin 998) supplied through a November 2012 petition for rulemaking. RTI found 

that few of the previously referenced sources of CH4 and N2O emission factors were based on 

actual emission test data, and that the few references containing test data were dated and/or based 

on emissions sources outside of the U.S. The information provided in NCASI Technical Bulletin 

998 appears to be the more robust than previous references due to the number and variety of U.S. 

emission sources for which recent test data are provided. The EPA can use the summary 

information presented in this memorandum to consider whether to adopt the emission factors 

suggested by the petitioners based on NCASI Technical Bulletin 998 or to combine the new data 

with previously available emission test data in order to revise the CH4 and N2O emission factors 

in Table AA-1 and C-2. 
Appendix A

Excerpts from the WRI/WBCSD Protocol, Calculation Tools for Estimating Greenhouse 

Gas Emissions from Pulp and Paper Mills, Version 1.1, July 8, 2005

Appendix A1: Biomass Combustion CH4 and N2O Emission Factor Summary Table from the 

WRI/WBCSD Protocol

Appendix A2: Additional Excerpts from the WRI/WBCSD Protocol

Available at: 

http://www.wbcsd.org/web/projects/forestry/pulp-and-paper-tool-guidance.pdf
F - 4 Version 1.1 

July 8, 2005 

Table 8. Emission Factors for CH4 and N2O from Biomass Combustion 

Emission Factor Description 

kg 

CH4/TJ 

kg 

N2O/TJ Reference 

Wood waste-fired boilers 

Wood, wood waste, and other biomass and 

wastes 

30 4 Tier 1 – IPCC 1997c 

Uncontrolled emissions from wood-fired 

stoker boilers 

15 - Tier 2 – IPCC 1997c 

Average for wood residue combustion 9.5* 5.9* USEPA 2001 

Average for circulating fluidized bed boilers 

burning peat or bark 

1 8.8 Fortum 2001 

Average for bubbling fluidized bed boilers 

burning peat or bark 

2** <2 Fortum 2001 

Pre-1980 wood residue-fired stoker boilers 

sampled ahead of control devices 

8.2* - NCASI 1980 

Pre-1980 wood residue-fired stoker boilers 

sampled after wet scrubbers 

2.7* - NCASI 1985 

Wood fired boiler 41λ

 3.1λ JPA 2002 

Wood as fuel 24 λ

 3.4 λ AEA Tech. 2001 

Wood waste 30 5 Swedish EPA 2004 

Median emission factors for wood waste 12 4 

 1 – 40 1.4 – 75 EEA 2004 

Recovery furnaces 

Recovery furnace <1 <1 Fortum 2001 

Recovery furnace – black liquor 2.5 Ω - JPA 2002 

Black Liquor 30 5 Swedish EPA 2004 

Median emission factors for black liquor 2.5 2 

1 –17.7 1 – 21.4 EEA 2004 

* converted from GCV to NCV assuming a 5% difference 

** excludes one very high number associated with low oxygen-high carbon monoxide conditions 

λ

 based on heat content of 20 GJ/t dry solids 

Ω based on liquor heat content of 13.3 GJ/t dry solids 

A1-1
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July 8, 2005 

Calculation Tools for 

Estimating

Greenhouse Gas 

Emissions 

from Pulp and Paper Mills

Version 1.1 

July 8, 2005 

A Project of

The Climate Change Working Group of 

The International Council of Forest and Paper 

Associations (ICFPA) 

with special contributions from 

Paper Manufacturers Association of South Africa 

Japan Paper Association 

Forest Products Association of Canada 

Confederation of European Paper Industries 

Chilean Forest and Industry Association 

Australian Paper Industry Council 

American Forest and Paper Association 

Prepared by: National Council for Air and Stream Improvement, Inc. (NCASI) 

Research Triangle Park, NC, USA 

Questions or comments on this material can be directed to 

Brad Upton, NCASI, PO Box 458, Corvallis, OR, USA 97339-0458 

phone + 541-752-8801, fax + 541-752-8806, e-mail BUpton@ncasi.org 

A2-1
Version 1.1 

July 8, 2005 

CALCULATION TOOLS FOR ESTIMATING GREENHOUSE GAS EMISSIONS 

FROM PULP AND PAPER MILLS – Version 1.1 

EXECUTIVE SUMMARY

This report contains Version 1.1 of the Calculation Tools for Estimating Greenhouse Gas 

Emissions from Pulp and Paper Mills, developed for the International Council of Forests and 

Paper Associations by the National Council for Air and Stream Improvement, Inc. (NCASI). 

The differences between this version of the tools and Version 1.0, issued in 2001, are 

described in Annex G to this report. It is intended that these industry-specific tools be used 

in conjunction with a greenhouse gas (GHG) accounting protocol such as the “Greenhouse 

Gas Protocol” issued by the World Resources Institute/World Business Council for 

Sustainable Development (WRI/WBCSD), the “Climate Leaders Greenhouse Gas Inventory 

Protocol Core Module Guidance” issued by the United States Environmental Protection 

Agency (USEPA), the “Challenge Registry Guide to Entity and Facility-Based Reporting” 

issued by the Voluntary Challenge and Registry (VCR), or other protocol for corporate GHG 

inventories. 

These tools reflect many of the features of well-known and widely accepted protocols. In 

addition, they anticipate a number of questions that pulp and paper mills must address when 

preparing facility-level or company-level inventories. A special effort has been made to 

ensure that the tools are consistent with guidance issued by the Intergovernmental Panel on 

Climate Change (IPCC) and the WRI/WBCSD. 

These tools estimate CO2 emissions from fossil fuel combustion based on the carbon content 

of the fuel (or a comparable emission factor) and the amount burned. Carbon dioxide 

emissions from biomass combustion are not counted as GHG emissions, a convention 

common to most of the protocols examined in this review, but if a company elects to do so it 

can report them separately. Companies that wish to comply with the WRI/WBCSD GHG 

Protocol should include these biomass combustion CO2 emissions, and they should be 

reported separately from direct GHG emissions. Regardless of the reporting approach 

chosen, it is important to clearly separate estimates of CO2 emissions from fossil fuel 

combustion from emissions of CO2 from biomass combustion. Methane and nitrous oxide 

emissions from combustion processes, both fossil fuel and biomass, are estimated using fuelbased emission factors and activity data. Methods are presented for estimating the fossilCO2, methane, and nitrous oxide emissions from kraft mill lime kilns and calciners. 

Greenhouse gas emissions from landfills and wastewater treatment plants are estimated using 

methods derived from those suggested by IPCC, as are emissions from vehicles and other 

fossil fuel-fired equipment. In all cases, however, companies may use site-specific 

information where it yields more accurate estimates of GHG emissions than the tools 

outlined in this report. 

Using these tools, indirect emissions related to imports of electricity or steam are included in 

the inventory results but are tracked separately from direct emissions. Emissions attributable 

to exports of electricity or steam, which are a subset of direct emissions, are explicitly 

delineated in order to demonstrate that at some facilities a portion of the direct emissions are 

associated with energy streams that are exported to other end users. Emissions from 

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July 8, 2005 

combined heat and power (CHP) plants are allocated using the WRI/WBCSD “efficiency 

method.” 

The calculation tools allow companies to develop corporate inventories that include all direct 

emission sources from within the organizational boundaries–e.g., company-owned truck 

fleets–as well as indirect emission sources outside the organizational boundaries–e.g., 

emissions from electricity, heat, and steam purchased and consumed–and on-site pulp and 

paper making operations outside the organizational boundaries. It is understood, however, 

that companies will include indirect emission sources that are best suited to the objectives of 

the inventory. For most mills, the GHG profile will be dominated by stationary fossil fuel 

combustion emissions and emissions attributable to purchases of power and steam, emissions 

that are discussed in Sections 8 and 12. 

For inventories which consider CO2 emissions only (i.e., CH4 and N2O emissions are not 

included in the emissions inventory), it may be appropriate to estimate emissions based 

solely on facility-level fuel consumption activity data and CO2 emission factors. In certain 

situations, CH4 and N2O emissions may be estimated adequately using facility-level activity 

data as well. 

To aid in interpreting the results of the inventory, these tools recommend that the results 

include a description of the operational boundaries of the inventory and a list of emission 

factors used to estimate emissions. The format suggested for presenting the results of the 

inventory allows a company to report direct emissions (those from sources owned or 

controlled by the company) separately from indirect emissions (those that are a consequence 

of the activities of the company, but occur from sources owned or controlled by another 

company). The company is free to select a method for determining the ownership of 

emissions, but the method should be explained in the inventory results. The user is directed 

to the WRI/WBCSD GHG Protocol for guidance on how to determine ownership of 

emissions from partly-owned or partly-controlled sources. 

An Excel® workbook is available to assist in performing the calculations described in this 

report. 

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CONTENTS 

1.0 INTRODUCTION ............................................................................................................1 

2.0 FOREST PRODUCTS INDUSTRY GREENHOUSE GAS EMISSIONS IN 

PERSPECTIVE.................................................................................................................2 

3.0 RELATIONSHIP OF THESE CALCULATION TOOLS TO OTHER 

GREENHOUSE GAS PROTOCOLS...............................................................................2 

4.0 OVERVIEW OF THE CALCULATION TOOLS...........................................................4 

4.1 Steps Involved in Applying the Calculation Tools..................................................4 

4.2 Data Quality.............................................................................................................6 

4.3 Units.........................................................................................................................7 

5.0 DETERMINING THE ORGANIZATIONAL BOUNDARIES OF THE 

INVENTORY ...................................................................................................................9 

6.0 IDENTIFYING PULP AND PAPER OPERATIONS TO BE INCLUDED 

WITHIN THE INVENTORY.........................................................................................10 

7.0 MATERIALITY AND INSIGNIFICANT EMISSIONS ...............................................11 

8.0 GREENHOUSE GAS EMISSIONS FROM STATIONARY FOSSIL FUEL 

COMBUSTION ..............................................................................................................14 

8.1 Carbon Dioxide......................................................................................................14 

8.2 Methane and Nitrous Oxide...................................................................................16 

9.0 EMISSIONS FROM KRAFT MILL LIME KILNS AND CALCINERS......................22 

10.0 CARBON DIOXIDE EMISSIONS FROM MAKE-UP CHEMICALS ........................25 

10.1 Emissions from Make-up Carbonates Used in the Pulp Mill ................................25 

10.2 Emissions from Limestone or Dolomite Used in Flue Gas Desulfurization 

(FGD) Systems.......................................................................................................26 

11.0 EMISSIONS FROM STATIONARY COMBUSTION OF BIOMASS FUELS...........27 

11.1 Releases of Biomass-Derived Carbon Dioxide from Burning Biomass Fuels ......27 

11.2 Methane and Nitrous Oxide Emissions from Burning Biomass Fuels ..................28 

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12.0 EMISSIONS ATTRIBUTABLE TO IMPORTS AND EXPORTS OF 

ELECTRICITY AND STEAM.......................................................................................30 

12.1 Emission Factors for Purchased Power and Steam................................................31 

12.2 Electricity Imports .................................................................................................31 

12.3 Electricity Exports .................................................................................................32 

12.4 Steam Imports ........................................................................................................33 

12.5 Steam and Hot Water Exports................................................................................33 

12.6 Allocating Emissions from Combined Heat and Power (CHP) Systems ..............33 

13.0 GREENHOUSE GAS EMISSIONS FROM VEHICLES AND 

MISCELLANEOUS FOSSIL FUEL-FIRED EQUIPMENT.........................................37 

13.1 Greenhouse Gas Emissions from On-Road Vehicles ............................................37 

13.2 Greenhouse Gas Emissions from Off-Road Vehicles and Equipment ..................37 

14.0 GREENHOUSE GAS EMISSIONS FROM WASTE IN LANDFILLS........................39 

14.1 Using Data from Landfill Gas Collection Systems................................................40 

14.2 Estimating Methane Emissions at Landfills without Gas Collection Data............41 

15.0 GREENHOUSE GAS EMISSIONS FROM ANAEROBIC TREATMENT OF 

WASTEWATER OR SLUDGE .....................................................................................45 

15.1 Anaerobic Treatment Operations where Off-Gases are Captured .........................45 

15.2 Anaerobic Treatment Operations where Off-Gases are Released to the 

Atmosphere............................................................................................................45 

16.0 PRESENTING THE RESULTS OF THE INVENTORY..............................................46 

REFERENCES ........................................................................................................................57 

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ANNEXES 

A GREENHOUSE GAS EMISSIONS FROM KRAFT MILL LIME KILNS AND 

CALCINERS .................................................................................................................A1 

B ALLOCATING GREENHOUSE GAS EMISSIONS FROM COMBINED HEAT 

AND POWER (CHP) SYSTEMS: RECOMMENDED GUIDANCE AND 

REVIEW OF METHODS..............................................................................................B1 

C GREENHOUSE GASES FROM VEHICULAR TRAFFIC AND MACHINERY: 

OVERVIEW OF METHODS IN EXISTING PROTOCOLS.......................................C1 

D GREENHOUSE GASES FROM WASTE MANAGEMENT AT PULP AND 

PAPER MILLS: RECOMMENDED APPROACH AND REVIEW OF 

EXISTING METHODS.................................................................................................D1 

E CARBON DIOXIDE FROM BIOMASS COMBUSTION........................................... E1 

F TABLES OF GREENHOUSE GAS EMISSION FACTORS....................................... F1 

G SUMMARY OF SIGNIFICANT REVISIONS TO VERSION 1.0 ..............................G1 

H REFERENCES FOR ANNEXES A THROUGH G......................................................H1 

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TABLES

Table 1. Emission Factor Ranges Useful in Identifying Significant and Insignificant 

Sources of GHGs ...................................................................................................13 

Table 2. IPCC Default CO2 Emission Factors for Fossil Fuels ...........................................15 

Table 3. Recommended Correction Factors for Unoxidized Carbon from Various 

Guidance Documents.............................................................................................15 

Table 4. IPCC Tier 1 CH4 and N2O Emission Factors for Stationary Combustion.............18 

Table 5. IPCC Tier 2 Uncontrolled CH4 and N2O Emission Factors for Industrial 

Boilers....................................................................................................................18 

Table 6. Emission Factors for Kraft Mill Lime Kilns and Calciners...................................24 

Table 7. Emissions from Calcium Carbonate and Sodium Carbonate Make-up in the 

Pulp Mill ................................................................................................................25 

Table 8. Emission Factors for CH4 and N2O from Biomass Combustion ...........................29 

Table 9. Emission Factors for Non-Road Mobile Sources and Machinery .........................38 

Table 10. Recommended Default Values for k and L0 for Estimating Landfill Methane 

Emissions ...............................................................................................................42 

Table 11. Example of a Table to Report Operational Boundaries of the Inventory ..............48 

Table 12. Example of a Table to Report GHG Inventory Results – Direct Emissions..........49 

Table 13. Example of a Table to Report GHG Inventory Results – Indirect Emissions .......50 

Table 14. Example of a Table to Report Emission Factors Used to Prepare the 

Inventory................................................................................................................51 

Table 15. Example GHG Inventory Results – Operational Boundaries of the Inventory .....52 

Table 16. Example GHG Inventory Results – Direct Emissions...........................................54 

Table 17. Example GHG Inventory Results – Indirect Emissions ........................................55 

Table 18. Example GHG Inventory Results – Emission Factors Used to Prepare the 

Inventory................................................................................................................56 

FIGURES 

Figure 1. Schematic for Example Inventory Results.............................................................53 

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4.3.2 Heat Content of Fuels – GCV vs. NCV 

Some countries measure fuel according to its gross calorific value (GCV) or higher heating 

value (HHV), while other countries use net calorific value (NCV) or lower heating value 

(LHV). The distinction between GCV and NCV arises from the different physical states 

(liquid or gaseous) water may be in following combustion. The GCV includes the latent 

energy of condensation of water following combustion. The NCV is computed for product 

water in the gaseous state (i.e., not condensed). The latent energy of vaporization of water is 

deducted from the GCV. When a moist fuel is combusted, two sources of product water 

exist–the moisture present in the fuel and the water formed from the hydrogen in the fuel 

during combustion. 

The NCV of a fuel at any moisture content can be determined as (Kitana and Hall 1989, 

p. 883): 

NCV )[1( GCVM HM )]9( −= wet solids − λ dry + (Eq. 1) 

where: NCV = net calorific value at any moisture content 

GCVsolids = gross calorific value of dry fuel (zero moisture content) 

λ = latent heat of vaporization of water (2.31 MJ/kg at 25°C) 

Mwet = moisture content of fuel on a wet basis (expressed as a fraction) 

Mdry = moisture content of fuel on a dry basis (expressed as a fraction) 

H = mass fraction of hydrogen in dry fuel (expressed as a fraction) 

If the NCV is to be expressed in terms of dry fuel (e.g., corresponding to the dry solids in the 

fuel) it can be determined from the GCV of the dry fuel (GCVsolids): 

NCVsolids = GCVsolids − 9λH (Eq. 2)

where: NCVsolids = net calorific value of dry fuel (zero moisture content) 

A commonly accepted approximation is that NCV is 95% of GCV for coal and oil and 90% 

of GCV for natural gas (IPCC 1997c). IPCC does not provide a relationship between NCV 

and GCV for biomass fuels, presumably because the moisture content of biomass fuels can 

vary extensively. However, in most instances the forest products industry characterizes the 

energy content of biomass fuels (e.g., spent pulping liquors, hogged fuels, etc.) in terms of 

the energy in the dry solids of the biomass. Therefore, Equation 2 can be used to develop a 

relationship between NCG and GCV for biomass fuels on a dry basis. A hydrogen content 

value representative of many wood species is approximately 6% (based on dry wood, 

expressed as the fraction 0.06) (Browning 1975, Table VI, p. 74). A typical NCVsolids value 

for wood is 20 MJ/kg (IPCC 1997c). Therefore: 

= dry wood MJ/kg 20 = − × MJ/kg 31.2(9 water)×(0.06) NCVsolids GCVsolids

∴

dry wood MJ/kg 25.21

dry wood MJ/kg 20 MJ/kg 31.2(9 water) (0.06)

=

GCVsolids = ×+ ×

 (Eq. 3)

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July 8, 2005 

An approximate relationship between NCVsolids and GCVsolids can be developed using this 

result: 

95.094.0

25.21

20

∴ ≅==

solids

solids

GCV

NCV (Eq. 4)

It is important to realize that the relation above is only valid when the energy content (in 

terms of both GCV and NCV) are expressed in terms of the dry fuel (i.e., energy expressed in 

terms of biomass solids, such as 20 GJ NCV per tonne dry wood). 

In this report, NCV (LHV) is used. In some cases, the emission factors have been converted 

from GCV (HHV) units as listed in the sources for the factors, using the approximations 

described above. In the Annexes, energy-related parameters are expressed in the units used 

by the authorities or countries that developed the information. Except where noted, the 

Annexes use NCV (LHV).

5.0 DETERMINING THE ORGANIZATIONAL BOUNDARIES OF THE 

INVENTORY 

Organizational boundaries define the company for the purpose of accounting for GHG 

emissions. There are a large number of possible ownership arrangements, making it difficult 

to provide specific instructions on how to derive organizational boundaries. Perhaps the 

most thorough discussion of methods for determining organizational boundaries is contained 

in the WRI/WBCSD GHG Protocol (WRI 2004a). Companies whose organizational 

boundaries include partially-owned or partially-controlled sources will want to obtain that 

document. The approach outlined in the GHG Protocol is summarized herein. 

Where the allocation of GHGs is specified contractually, that allocation is to be used. 

Otherwise the WRI/WBCSD GHG Protocol suggests that allocation be done in one of two 

ways: according to control or according to equity share. Of course, if the reporting company 

owns all of the operations considered in the inventory the organizational boundaries will be 

the same when determined by either approach. The GHG Protocol also outlines different 

selection criteria that will facilitate the choice of approach, including the consistency with 

financial accounting (WRI 2004a). 

After the organizational boundaries of the company have been determined, operational 

boundaries then categorize direct and indirect emissions, using the approach chosen under 

organizational boundaries (either ownership or control). The situation is usually 

straightforward for the consumption of purchased electricity or steam, because the emissions 

are usually from sources outside the company’s ownership and control and are, therefore, 

indirect. 

Companies using these calculation tools may encounter situations where the inventory 

includes emission sources from which only a portion of the emissions will be reported (or 

“consolidated”) as direct emissions at the corporate level, as they are from operations or 

companies jointly owned or controlled. In other cases (e.g., outsourced operations that are 

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Non-condensable gases (NCGs) consist of reduced sulfur compounds and other organic 

compounds that are formed during the kraft pulping process. These gases are often collected 

and burned in boilers, lime kilns, or incinerators as a pollution abatement procedure. 

Because the carbon in NCGs originated in wood, the CO2 generated during combustion of 

NCGs is of biomass origin and is, therefore, not included in a tabulation of direct GHG 

emissions. The quantities of NCGs combusted at kraft mills are very low relative to 

quantities of spent pulping liquors and other wood residuals fuels. There are no data on 

methane or nitrous oxide generation from combustion of NCGs. 

11.2 Methane and Nitrous Oxide Emissions from Burning Biomass Fuels 

Although CO2 from biomass burning is almost universally excluded from GHG inventories, 

CH4 and N2O from biomass burning are sometimes included because these gases do not 

participate in the atmospheric CO2 sequestration-recycling process explained in Section 11.1. 

Therefore, calculation tools are provided to assist in estimating these emissions. 

If a company has reliable site-specific data allowing it to estimate CH4 and N2O emissions 

from biomass combustion, it should use those data. Otherwise, it will be necessary to use the 

most appropriate emission factors available. Unfortunately, there are few data on CH4 and 

N2O emissions from biomass combustion. 

IPCC’s Revised 1996 Inventory Guidelines used emission factors developed by EPA. This is 

also true for a number of countries. EPA has since revised these factors. Even the updated 

EPA factors, however, are based on very few data. Table 8 provides a summary of the 

available information on methane and nitrous oxide emissions from biomass boilers. The 

IPCC Tier 1 emission factors for combustion of “wood, wood residuals, and other biomass 

and wastes” are also shown in Table 8. The many individual country factors that are based 

on IPCC or EPA factors are not shown. The variability in the data reflects the many different 

types and ages of boilers tested, operating conditions, control equipment, and fuel 

characteristics. As discussed in Section 11.1, there are no data on methane or nitrous oxide 

emissions from combustion of NCGs generated during the kraft pulping process. 

Where an emission factor shown in Table 8 was developed for circumstances that match 

conditions at a mill, the company may want to select that emission factor for estimating 

emissions. For instance, companies with fluidized bed boilers may want to use the Fortum 

emission factors because they were developed on fluidized bed boilers while the other 

emission factors were developed on stoker boilers or on boilers of an unspecified design. In 

many cases, however, because of the ranges in emission factors and the limited ability at this 

time to match emission factors to boiler designs, operating conditions, and fuels, it is 

reasonable to use the median emission factors shown in the table to characterize emissions 

from boilers. These median emission factors fall within the ranges cited in the CORINAIR 

emissions inventory (ranges also shown in the table) (EEA 2004). For wood-fired 

combustion equipment other than boilers, it may be most appropriate to use the IPCC Tier 1 

emission factors shown in Table 4. In some cases, a facility may choose to base emission 

estimates on facility-level fuel consumption data in conjunction with the Tier 1 emission 

factors. 

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Table 8. Emission Factors for CH4 and N2O from Biomass Combustion 

Emission Factor Description 

kg 

CH4/TJ 

kg 

N2O/TJ Reference 

Wood waste-fired boilers 

Wood, wood waste, and other biomass and 

wastes 

30 4 Tier 1 – IPCC 1997c 

Uncontrolled emissions from wood-fired 

stoker boilers 

15 - Tier 2 – IPCC 1997c 

Average for wood residue combustion 9.5* 5.9* USEPA 2001 

Average for circulating fluidized bed boilers 

burning peat or bark 

1 8.8 Fortum 2001 

Average for bubbling fluidized bed boilers 

burning peat or bark 

2** <2 Fortum 2001 

Pre-1980 wood residue-fired stoker boilers 

sampled ahead of control devices 

8.2* - NCASI 1980 

Pre-1980 wood residue-fired stoker boilers 

sampled after wet scrubbers 

2.7* - NCASI 1985 

Wood fired boiler 41λ

 3.1λ JPA 2002 

Wood as fuel 24 λ

 3.4 λ AEA Tech. 2001 

Wood waste 30 5 Swedish EPA 2004 

Median emission factors for wood waste 12 4 

 1 - 40 1.4 – 75 EEA 2004 

Recovery furnaces 

Recovery furnace <1 <1 Fortum 2001 

Recovery furnace – black liquor 2.5 Ω - JPA 2002 

Black Liquor 30 5 Swedish EPA 2004 

Median emission factors for black liquor 2.5 2 

1 –17.7 1 – 21.4 EEA 2004 

* Converted from GCV to NCV assuming a 5% difference 

** Excludes one very high number associated with low oxygen-high carbon monoxide conditions 

λ

 Based on heat content of 20 GJ/t dry solids 

Ω Based on liquor heat content of 13.3 GJ/t dry solids 

11.2.1 Combination Fuel-Fired Boilers Burning Biomass and Fossil Fuels 

As discussed in Section 8.2.1, methane and nitrous oxide releases from boilers are sensitive 

to combustion conditions, especially combustion temperature. In most cases, the combustion 

conditions in combination fuel boilers are more like those in biomass-fired boilers than fossil 

fuel-fired boilers. Methane and nitrous oxide emissions are often more directly related to 

combustion conditions than to fuel type. Because of the high moisture content of most 

wood-based fuels, a reasonable default is to assume that the combustion conditions in 

combination fuel-fired boilers reflect the impact of the wood residual fuels. Therefore, 

unless data are available from site-specific testing on similar boilers burning a comparable 

mix of fuels, or unless the combustion conditions in the combination fuel-fired boiler are 

more like fossil fuel-fired boilers than wood residual fuel boilers, it is recommended that the 

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emissions from combination fuel-fired boilers be estimated from the total heat input to the 

boiler and CH4 and N2O emission factors for biomass. 

In some cases, a facility may operate a combination fuel boiler where fossil fuel comprises a 

major portion of the total fuel to the boiler. Although estimating CH4 and N2O emissions 

using the approach outlined in the previous paragraph is appropriate in these cases, it is also 

valid to estimate these emissions based on consumption rates of each fossil fuel multiplied by 

the fuel’s emission factors, plus the consumption rate of biomass fuel multiplied by the 

biomass fuel’s emission factors. 

Example Calculation: Mill with a bark boiler. 

A mill has a 250,000 kg steam/hour (550,000 pound/hr) circulating fluidized bed (CFB) bark 

boiler. In a year, the boiler burns approximately 6.9 x 106 GJ of bark and 0.8 x 106 GJ of 

residual fuel oil. Because the boiler receives supplemental fossil fuel, it is necessary to 

estimate the CO2 from the fossil fuel use and the CH4 and N2O emissions based on the total 

firing rate. The mill decides to use the IPCC emission factor for residual oil (76.6 t CO2/TJ, 

after correcting for 1% unoxidized carbon) and to estimate CH4 and N2O emissions based on 

the total firing rate and the emission factors developed by Fortum on CFB boilers. The 

average emission factors found by Fortum, shown in Table 8, are 1 kg 

CH4/TJ and 8.8 kg N2O/TJ. 

CO2 emissions from fossil fuel: 

• (0.8 x 106 GJ/y) = (0.8 x 103 TJ/y) 

• (0.8 x 103 TJ/y) x (76.6 t CO2/TJ) = 61,300 t CO2/y 

CH4 emissions: 

• total heat input = (6.9 x 106 GJ/y) + (0.8 x 106 GJ/y) = 7.7 x 106 GJ/y = 7.7 x 103 TJ/y 

7.7 x 103 TJ/y x 1 kg CH4/TJ = 7,700 kg CH4/y = 7.7 t CH4/y 

Using the IPCC warming potential of 21, this equates to 162 t CO2-eq./y. 

N2O emissions: 

• total heat input = 7.7 x 103 TJ/y 

• 7.7 x 103 TJ/y x 8.8 kg N2O/TJ = 67,800 kg N2O/y = 67.8 t N2O/y 

Using the IPCC warming potential of 310, this equates to 21,000 t CO2-eq./y 

Total CO2 equivalents emitted = 61,300 + 162 + 21,000 = 82,500 t CO2-equivalents/y 

12.0 EMISSIONS ATTRIBUTABLE TO IMPORTS AND EXPORTS OF 

ELECTRICITY AND STEAM 

The consumption of power or steam (or hot water) purchased from another company usually 

results in the generation of indirect emissions–i.e., “emissions that are a consequence of 

activities of the reporting company, but occur from sources owned or controlled by another 

company” (WRI 2004a). Of course, virtually every raw material, energy source, and service 

used by a company has an indirect emissions impact. Many GHG accounting protocols, 

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REFERENCES 

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Birdsey, R.A. 1996. Chapter 1 – Carbon storage for major forest types and regions in the 

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Browning, B.L. (ed.). 1975. The chemistry of wood. New York: Robert E. Krieger 

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Environment Canada. 2004. Canada’s greenhouse gas inventory 1990-2002. Ottawa: 

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European Environment Agency (EEA). 2004. EMEP/CORINAIR Emission inventory 

guidebook - Third edition, September 2004 Update. Copenhagen: European Environment 

Agency. http://reports.eea.eu.int/EMEPCORINAIR4/en (27 October 2004). 

Fortum Power and Heat Oy (Fortum). 2001. Methane and nitrous oxide emissions in the 

Finnish energy production. Fortum, Finland: Fortum Power and Heat Oy, Technology. 

Georgia-Pacific Corporation (GP). 2002. Protocol for the inventory of greenhouse gases in 

Georgia-Pacific Corporation. Atlanta, GA: Georgia-Pacific Corporation. 

http://www.gp.com/enviro/strategy/protocol.pdf (30 October 2004). 

Intergovernmental Panel on Climate Change (IPCC). 1996. Climate change 1995, the 

science of climate change. New York: Cambridge University Press 

Intergovernmental Panel on Climate Change (IPCC). 1997a. Revised 1996 IPCC guidelines 

for national greenhouse gas inventories: Reporting instructions (Vol. 1). IPCC National 

Greenhouse Gas Inventory Program. 

http://www.ipcc-nggip.iges.or.jp/public/gl/invs4.htm (30 October 2004). 

Intergovernmental Panel on Climate Change (IPCC). 1997b. Revised 1996 IPCC guidelines 

for national greenhouse gas inventories: Workbook (Vol. 2). IPCC National Greenhouse 

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Intergovernmental Panel on Climate Change (IPCC). 1997c. Revised 1996 IPCC guidelines 

for national greenhouse gas inventories: Reference manual (Vol. 3). IPCC National 

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Greenhouse Gas Inventory Program. 

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Intergovernmental Panel on Climate Change (IPCC). 2000a. Good practice guidance and 

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Intergovernmental Panel on Climate Change (IPCC). 2000b. IPCC special report on land 

use, land-use change, and forestry. Cambridge University Press. 375 pp. 

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Intergovernmental Panel on Climate Change (IPCC). 2001. Third assessment report (TAR), 

climate change 2001: The scientific basis. Working Group 1 Report, Technical 

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Intergovernmental Panel on Climate Change (IPCC). 2003. Good practice guidance for 

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Japan Paper Association (JPA). 2002. Various personal communications between JPA and 

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Lewandowski, D.A. 2000. Design of thermal oxidation systems for volatile organic 

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Matthews, R. 1996. The influence of carbon budget methodology on assessments of the 

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National Council for Air and Stream Improvement, Inc. (NCASI). 1980. A study of woodresidue fired power boiler total gaseous non-methane organic emissions in the Pacific 

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Northwest. Air Quality Technical Bulletin No.109. Research Triangle Park, NC: 

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National Council for Air and Stream Improvement, Inc. (NCASI). 1985. Volatile organic 

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National Council for Air and Stream Improvement, Inc. (NCASI). 1999. Evaluation of the 

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for estimating greenhouse gas emissions from wood products manufacturing facilities. 

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Skog, K.E., and Nicholson, G.A. 1998. Carbon cycling through wood products: The role of 

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Swedish Environmental Protection Agency (Swedish EPA). 2004. Sweden’s national 

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United States Environmental Protection Agency (USEPA). 1996. AP-42 emission factors 

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United States Environmental Protection Agency (USEPA). 1998a. AP-42 emission factors 

for natural gas combustion – Supplement D, July 1998. Washington, DC: United States 

Environmental Protection Agency. 

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for bituminous and subbituminous coal combustion – Supplement E, September 1998. 

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for municipal solid waste landfills – Supplement E, November 1998. Washington, DC: 

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for wood residue combustion in boilers – Supplement G, July 2001. Washington, DC: 

United States Environmental Protection Agency. 

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World Resources Institute (WRI) and World Business Council for Sustainable Development 

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calculation worksheets version 1.1. Washington, DC: World Resources Institute. 

http://www.ghgprotocol.org/standard/tools.htm (30 October 2004). 

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ANNEX F 

TABLES OF GREENHOUSE GAS EMISSION FACTORS 

These tables are copied from the main body of this report. Table numbers are consistent with 

numbering in the main text. 

Table 2. IPCC Default CO2 Emission Factors for Fossil Fuels (after IPCC 1997b) 

Fossil Fuel Uncorrected Emission Factor

kg CO2/TJ* 

Corrected Emission Factor 

kg CO2/TJ 

Crude oil 73,300 72,600 

Gasoline 69,300 68,600 

Kerosene 71,900 71,200 

Diesel oil 74,100 73,400 

Residual fuel oil 77,400 76,600 

LPG 63,100 62,500 

Petroleum coke 100,800 99,800 

Anthracite coal 98,300 96,300 

Bituminous coal 94,600 92,700 

Sub-bituminous coal 96,100 94,200 

Lignite 101,200 99,200 

Peat 106,000 104,900 

Natural gas 56,100 55,900 

* These factors assume no unoxidized carbon. To account for unoxidized carbon, 

IPCC suggests multiplying by these default factors: coal = 0.98, oil = 0.99, and 

gas = 0.995. 

Table 3. Recommended Correction Factors for Unoxidized Carbon 

from Various Guidance Documents 

Source Coal Oil Natural Gas 

IPCC (1997c) 98% 99% 99.5% 

Environment Canada (2004)* 99% 99% 99.5% 

EPA Climate Leaders (USEPA 2003) 99% 99% 99.5% 

DOE 1605b (USDOE 1994) 99% 99% 99% 

EPA AP-42 (USEPA 1996, 1998a,b,c) 99% 99% 99.9% 

* The emission factors presented in VCR (2004) do not specify correction factors for unoxidized 

carbon, however all emission factors presented in VCR (2004) are drawn from Environment 

Canada 2004 

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Table 4. IPCC Tier 1 CH4 and N2O Emission Factors for Stationary Combustion 

(from IPCC 1997c) 

 CH4 Emission Factors 

kg/TJ 

N2O Emission Factors 

kg/TJ 

Coal 10 1.4

Natural gas 5 0.1 

Oil 2 0.6 

Wood/wood residuals 30 4 

Table 5. IPCC Tier 2 Uncontrolled CH4 and N2O Emission Factors 

for Industrial Boilers (IPCC 1997c) 

Fuel Technology Configuration kg CH4/TJ kg N2O/TJ

Bituminous coal Overfeed stoker 

boilers 

 1.0 1.6 

Sub-bituminous coal Overfeed stoker 

boilers 

 1.0 1.6 

Bituminous coal Underfeed stoker 

boilers 

 14 1.6 

Sub-bituminous coal Underfeed stoker 

boilers 

 14 1.6 

Bituminous coal Pulverized Dry bottom, wall fired 0.7 1.6 

Bituminous coal Pulverized Dry bottom, tang. fired 0.7 0.5 

Bituminous coal Pulverized Wet bottom 0.9 1.6 

Bituminous coal Spreader Stoker 1.0 1.6 

Bituminous coal Fluidized bed Circulating or bubbling 1.0 96 

Sub-bituminous coal Fluidized bed Circulating or bubbling 1.0 96 

Anthracite 10* 1.4* 

Residual oil 3.0 0.3 

Distillate oil 0.2 0.4 

Natural gas Boilers 1.4 0.1* 

Natural gas Turbines 0.6 0.1* 

Natural gas Int. comb. engine 2-cycle lean burn 17 0.1* 

Natural gas Int. comb. engine 4-cycle lean burn 13 0.1* 

Natural gas Int. comb. engine 4-cycle rich burn 2.9 0.1* 

* These are IPCC Tier 1 generic emission factors for coal and natural gas. Tier 2 emission factors are 

not available. 

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Table 8. Emission Factors for CH4 and N2O from Biomass Combustion 

Emission Factor Description 

kg 

CH4/TJ 

kg 

N2O/TJ Reference 

Wood waste-fired boilers 

Wood, wood waste, and other biomass and 

wastes 

30 4 Tier 1 – IPCC 1997c 

Uncontrolled emissions from wood-fired 

stoker boilers 

15 - Tier 2 – IPCC 1997c 

Average for wood residue combustion 9.5* 5.9* USEPA 2001 

Average for circulating fluidized bed boilers 

burning peat or bark 

1 8.8 Fortum 2001 

Average for bubbling fluidized bed boilers 

burning peat or bark 

2** <2 Fortum 2001 

Pre-1980 wood residue-fired stoker boilers 

sampled ahead of control devices 

8.2* - NCASI 1980 

Pre-1980 wood residue-fired stoker boilers 

sampled after wet scrubbers 

2.7* - NCASI 1985 

Wood fired boiler 41λ

 3.1λ JPA 2002 

Wood as fuel 24 λ

 3.4 λ AEA Tech. 2001 

Wood waste 30 5 Swedish EPA 2004 

Median emission factors for wood waste 12 4 

 1 – 40 1.4 – 75 EEA 2004 

Recovery furnaces 

Recovery furnace <1 <1 Fortum 2001 

Recovery furnace – black liquor 2.5 Ω - JPA 2002 

Black Liquor 30 5 Swedish EPA 2004 

Median emission factors for black liquor 2.5 2 

1 –17.7 1 – 21.4 EEA 2004 

* converted from GCV to NCV assuming a 5% difference 

** excludes one very high number associated with low oxygen-high carbon monoxide conditions 

λ

 based on heat content of 20 GJ/t dry solids 

Ω based on liquor heat content of 13.3 GJ/t dry solids 

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ANNEX H 

REFERENCES FOR ANNEXES A THROUGH G

Australian Greenhouse Office (AGO). 2004. Factors and Methods Workbook, August 2004. 

Australian Greenhouse Office, Canberra, Australia. 

http://www.greenhouse.gov.au/challenge/tools/index.html (27 October 2004). 

AEA Technology. 2001. UK greenhouse gas inventory 1990-1999: Annual report for 

submission under the Framework Convention on Climate Change. Oxfordshire, England: 

National Environmental Technology Centre. 

http://www.aeat.co.uk/netcen/airqual/reports/ghg/ghg2.html (29 October 2004) 

Environment Canada. 2004. Canada’s greenhouse gas inventory 1990-2002. Ottawa: 

Environment Canada. http://www.ec.gc.ca/pdb/ghg/inventories_e.cfm (28 October 

2004). 

European Environment Agency (EEA). 2004. EMEP/CORINAIR Emission inventory 

guidebook - Third edition, September 2004 Update. Copenhagen: European Environment 

Agency. http://reports.eea.eu.int/EMEPCORINAIR4/en (27 October 2004). 

Finland Ministry of the Environment. 2004. Greenhouse gas emissions in Finland 1990–

2002, National Inventory Report. Helsinki: Finland Ministry of the Environment. 

http://www.ymparisto.fi/download.asp?contentid=11372&lan=en (28 October 2004). 

Fortum Power and Heat Oy (Fortum). 2001. Methane and nitrous oxide emissions in the 

Finnish energy production. Fortum, Finland: Fortum Power and Heat Oy. 

Georgia-Pacific Corporation (GP). 2002. Protocol for the inventory of greenhouse gases in 

Georgia-Pacific Corporation. Atlanta, GA: Georgia-Pacific Corporation. 

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States Environmental Protection Agency. 

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for natural gas combustion – Supplement D, July 1998. Washington, DC: United States 

Environmental Protection Agency. 

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(WBCSD). 2004c. Calculating CO2 emissions from the combustion of standard fuels and 

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calculation worksheets version 1.1. Washington, DC: World Resources Institute. 

http://www.ghgprotocol.org/standard/tools.htm (30 October 2004). 

A2-24
Appendix B

Emission Factor Tables from Swedish EPA 2004

Available at: 

http://s3.amazonaws.com/zanran_storage/www.lansstyrelsen.se/ContentPages/70817864.pdf
CH4

stationary combustion

Power plants, district heating and industry

Resident and other consumption

01, 21 Eldningsolja 1, Dieselolja Gas/diesel oil 0,001 0,00202, 03 Eldningsolja 2-5 Residual fuel oil 0,002 0,00304 Propan och butan LPG 0,001 0,00105 Stadsgas Gas works gas 0,001 0,00106 Naturgas Natural Gas 0,001 0,00107 Koksugnsgas Coke oven gas 0,001 -08 Masugnsgas Blast furnace gas 0,001 -09 LD-gas Steel converter gas 0,001 -10 Kol Coking coal, other bituminous coal 0,002 0,00411 Koks Coke 0,002 0,00412 Trädbränsle Wood, wood waste 0,03 0,2513 Torv Peat 0,02 0,0314 Sopor Municipal Solid Waste 0,02 -15 Avlutar Black liquor 0 -16 Tallolja Tall oil 0,002 0,00320 Fotogen Kerosene 0,001 0,00223 Deponigas Landfill gas 0,001 0,00124 Petroleumkoks Petroleum coke 0,002 0,00491 Övriga biobränslen Other biomass 0,03 0,2592 Övriga petroleumbränslen Other petroleum fuels 0,001 0,00193 Övriga fasta fossila bränslen Other solid fuels 0,001 0,00194 Övriga ospecifierade bränsle Other not specified fuels 0,001 0,00195 Raffinaderigaser Refinery gases 0,001 0,001 - = Not occuringSource: Swedish EPA, IPCC, IVL Environmental Research Institute Ltd

Fuel type

kg CH4/GJ by area of consumption

Kod Bränsleslag

Appendix 16 Emission factors and ther
N2O

stationary combustion

kod Bränsleslag Fuel type kg N2O/GJ

01, 21 Eldningsolja 1, Dieselolja Gas/diesel oil 0,00202, 03 Eldningsolja 2-5 Residual fuel oil 0,00504 Propan och butan LPG 0,00205 Stadsgas Gas works gas 0,00206 Naturgas Natural Gas 0,00207 Koksugnsgas Coke oven gas 0,00208 Masugnsgas Blast furnace gas 0,00209 LD-gas Steel converter gas 0,00210 Kol Coking coal, other bituminous coal 0,0211 Koks Coke 0,0212 Trädbränsle Wood, wood waste 0,00513 Torv Peat 0,0114 Sopor Municipal Solid Waste 0,00515 Avlutar Black liquor 0,00516 Tallolja Tall oil 0,00520 Fotogen Kerosene 0,00223 Deponigas Landfill gas 0,00224 Petroleumkoks Petroleum coke 0,0291 Övriga biobränslen Other biomass 0,00592 Övriga petroleumbränslen Other petroleum fuels 0,00293 Övriga fasta fossila bränslen Other solid fuels 0,00294 Övriga ospecifierade bränsle Other not specified fuels 0,00295 Raffinaderigaser Refinery gases 0,002Source: Swedish EPA, IPCC, IVL Environmental Research Institute Ltd

Appendix 16 Emission factors and ther
Appendix C

IPCC Emission Factor Documentation

Appendix C1: Portion of 2006 IPCC Guidance Document Table 2.3, Default Emission Factors 

for Stationary Combustion in the Manufacturing Industries and Construction.

Available at: http://www.ipccnggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_2_Ch2_Stationary_Combustion.pdf

Appendix C2: Excerpts from the Revised 1996 IPCC Guidelines for National Greenhouse Gas 

Inventories Reference Manual (Volume 3), Chapter 1 – Energy.

Available at: http://www.ipcc-nggip.iges.or.jp/public/gl/invs6a.html
 Chapter 2: Stationary Combustion 

2006 IPCC Guidelines for National Greenhouse Gas Inventories 2.19 

TABLE 2.3 (CONTINUED) 

DEFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN MANUFACTURING INDUSTRIES AND CONSTRUCTION

(kg of greenhouse gas per TJ on a Net Calorific Basis) 

CO2 CH4 N2O 

Fuel Default 

Emission 

Factor 

Lower Upper 

Default 

Emission 

Factor 

Lower Upper 

Default 

Emission 

Factor 

Lower Upper 

Municipal Wastes (non-biomass fraction) n 91 700 73 300 121 000 30 10 100 4 1.5 15 

Industrial Wastes n143 000 110 000 183 000 30 10 100 4 1.5 15 

Waste Oils n 73 300 72 200 74 400 30 10 100 4 1.5 15 

Peat 106 000 100 000 108 000 n 2 0.6 6 n 1.5 0.5 5 

Wood / Wood Waste n 112 000 95 000 132 000 30 10 100 4 1.5 15 

Sulphite lyes (Black Liquor)a n 95 300 80 700 110 000 n 3 1 18 n 2 1 21 

Other Primary Solid Biomass n 100 000 84 700 117 000 30 10 100 4 1.5 15 

Solid Biofuels 

Charcoal n 112 000 95 000 132 000 200 70 600 4 1.5 15 

Biogasoline n 70 800 59 800 84 300 r 3 1 10 0.6 0.2 2 

Biodiesels n 70 800 59 800 84 300 r 3 1 10 0.6 0.2 2 

Liquid Biofuels 

Other Liquid Biofuels n 79 600 67 100 95 300 r 3 1 10 0.6 0.2 2 

Landfill Gas n 54 600 46 200 66 000 r 1 0.3 3 0.1 0.03 0.3 

Sludge Gas n 54 600 46 200 66 000 r 1 0.3 3 0.1 0.03 0.3 

Gas Biomass 

Other Biogas n 54 600 46 200 66 000 r 1 0.3 3 0.1 0.03 0.3 

Other non-fossil fuels 

Municipal Wastes (biomass 

fraction) n100 000 84 700 117 000 

 

30 10 100 4 1.5 15 

(a) Includes the biomass-derived CO2 emitted from the black liquor combustion unit and the biomass-derived CO2 emitted from the kraft mill lime kiln. 

n indicates a new emission factor which was not present in the 1996 Guidelines 

r indicates an emission factor that has been revised since the 1996 Guidelines 
Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual

C HAPTER 1

E NERGY

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Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual 1.33

gas and 1 per cent for peat used for electricity generation. In addition, the following

assumptions (from Summers, 1993) are recommended:

• For stoker-fired industrial boilers an average value for carbon unoxidised is 5 per

cent. If countries believe that their operation and maintenance procedures achieve

maximum efficiency, a 2 per cent carbon loss is suggested. If these procedures are

believed to lead to very poor efficiency, then a 10 per cent carbon loss is

recommended.

• In those cases when coal is used in the commercial or residential sectors, the

assumption for unoxidised carbon should be 5 per cent.

Clearly, much additional research needs to be done in this area. These adjustments are

suggested as initial default values. As more work is done, countries are encouraged to

report any additional information they may have to refine understanding of the amount of

carbon unoxidised in various applications.

Fuels used for international transport

The exclusion from national totals of emissions from (bunker) fuels used for international

marine and air transport has been discussed in Section 1.4.1.1, Reference Approach. As

in that approach, the emissions from international bunkers should not be omitted entirely

but reported separately on the worksheet. The definitions of national and international

movements for ships and aircraft are covered under the “Definition of Source

Categories” (Energy) in Volume 1, Reporting Instructions.

Combustion of biofuels

CO2 emissions from the combustion of biomass fuels are not to be included in the total

national CO2 emissions but should be reported separately on the worksheet.

Fuel use for mobile sources and stationary plant in the Agriculture/Forestry/

Fisheries sector

The separation of fuel combustion between the two types of combustion sources in this

sector has been introduced to permit the aggregation of CO2 emissions from them with

the emissions of the non-CO2 gases. Whatever methods are used for estimating the

quantities of fuels used by these two types when calculating the non-CO2 emissions from

this sector should be used for CO2. Delivery statistics do not usually distinguish between

combustion plant types in any economic activity sector.

1.4.2 Non-CO 2 Emissions

1.4.2.1 M ETHANE (CH 4 ) E MISSIONS FROM F UEL

C OMBUSTION

The contribution of fuel combustion to global emissions of methane is minor and the

uncertainty is high. For these reasons, an aggregated fuel/sector split is sufficient for a

Tier 1 approach, although exact product detail needs to be determined for CH4 from

biomass combustion. Fuel wood, charcoal, agricultural residues, agricultural waste and

municipal waste combustion is by far the major contributor to CH4 emissions within the

fuel combustion group. Traditional charcoal making, which is a typical smouldering

process, is a large source of methane which should be reported under Fugitive Emissions

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1.34 Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual

from Energy. Consequently, CH4 emissions from developing countries with large biomass

consumption could be significant.

Methane is produced in small quantities from fuel combustion due to incomplete

combustion of hydrocarbons in fuel. The production of methane is dependent on the

temperature in the boiler/stove. In large, efficient combustion facilities and industrial

applications, the emission rate is very low, with utility emission rates being less than I per

cent of average rates for residential coal combustion. In smaller combustion sources,

emission rates are higher, particularly when smouldering occurs. The highest rates of

methane emissions from fuel combustion occur in residential applications (small stoves

and open burning).

The CH4 emissions from mobile sources are a function of the methane content of the

motor fuel, the amount of hydrocarbons passing unburnt through the engine, the engine

type, and any post-combustion controls. In uncontrolled engines the proportion of

methane emissions is highest at low speeds and when the engine is idle. Poorly tuned

engines may have a particularly high output of CH4.

The general method for estimating CH4 can be described as:

Emissions = ∑ (EFab x Activityab)

where:

EF = Emission Factor (kg/TJ);

Activity = Energy Input (TJ);

a = Fuel type; and

b = Sector-activity.

The following default emission factors have been developed by the IPCC based on the

CORINAIR90 database, the CORINAIR 1994 default emission factors, the EDGAR

Version 2.0 database, National Communications to the FCCC, Berdowski, et al. (1993a

and 1993b), Radian Corporation (1990) and US EPA (1995). Additional research will

need to be undertaken to further improve the quality of the emission factors.

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Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual 1.35

TABLE 1-7

CH4 DEFAULT (UNCONTROLLED) EMISSION FACTORS (IN KG/TJ)

Coal(a) Natural

Gas

Oil Wood/

Wood Waste

Charcoal Other Biomass

and Wastes(c)

Energy Industries 1 1 3 30(b) 200(b) 30

Manufacturing Industries and

Construction

10 5 2 30 200 30

Transport Aviation(d) 0.5

Gasoline Diesel

Road 50 20(e) 5

Railways 10 5

Navigation 10 5

Other Commercial/Institutional 10 5 10 300 200 300

Sectors Residential 300 5 10 300 200 300

Agriculture/

Forestry/

Stationary 300 5 10 300 200 300

Fishing Mobile 5 5

Note: These factors are considered as the best available global default factors to date.

(a) The emission factors for brown coal may be several times higher than those for hard coal.

(b) These factors are for fuel combustion in the energy industries. For charcoal production, please refer to Table 1-14, Default Non-CO2 Emission Factors for Charcoal

Production.

(c) Includes dung and agricultural, municipal and industrial wastes.

(d) In the cruise mode CH4 emissions are assumed to be negligible (Wiesen et al., 1994). For LTO cycles only (i.e., below an altitude of 914 metres (3000 ft.)) the

emission factor is 5 kg/TJ (10% of total VOC factor) (Olivier, 1991). Since globally about 10% of the total fuel is consumed in LTO cycles (Olivier, 1995), the resulting

fleet averaged factor is 0.5 kg/TJ.

(e) Emission factors for 2-stroke engines may be three times higher than those for 4-stroke engines.

1.4.2.2 N ITROUS O XIDE ( N 2 O) E MISSIONS FROM

F UEL C OMBUSTION

As with methane, the contribution of fuel combustion to global emissions of N2O is

minor and the uncertainty is high. Reliable emission factors are not yet available for all

sources. For these reasons, an aggregated fuel/sector split is sufficient for a Tier 1

approach.

Nitrous oxide is produced directly from the combustion of fossil fuels. It has been

determined that lower combustion temperatures (particularly below 1200 K) cause

higher N2O emissions with a maximum of N2O production occurring around 1000 K.

For combustion temperatures below 800 K or over 1200 K the emissions of N2O are

negligible (de Soete, 1993). Compared to emissions from conventional stationary

combustion units, emissions of nitrous oxides from fluidised bed combustion are relatively

high (Rentz et al., 1992). Nitrous oxide is formed by different catalytic reduction

processes. For more detailed information on N2O chemistry see de Soete (1993). The

mechanisms of N2O chemistry seem to be relatively well understood, but experimental

data are limited.

N2O emissions from vehicles have only recently been studied in detail. Global emissions

from this source are still thought to be small relative to total anthropogenic emissions,

but may be substantially higher when emission controls (especially catalysts on road

vehicles) are used.

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1.36 Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual

Published emission rates for non-commercial fuel combustion, in particular fuelwood,

charcoal, agricultural wastes and dung are few and it is uncertain whether they are

representative for global application (Olivier, 1993).

The general method for estimating N2O can be described as:

Emissions = ∑ (EFab x Activityab)

where:

EF = Emission Factor (kg/TJ);

Activity = Energy Input (TJ);

a = Fuel type; and

b = Sector-activity.

The following default emission factors have been developed by the IPCC based on the

CORINAIR90 database, the CORINAIR 1994 default emission factors, Radian

Corporation (1990), the EDGAR Version 2.0 database, National Communications to the

FCCC and de Soete (1993). Additional research will need to be undertaken to further

improve the quality of the emission factors.

TABLE 1-8

N2O DEFAULT (UNCONTROLLED) EMISSION FACTORS (IN KG/TJ)

Coal(a) Natural

Gas

Oil Wood/

Wood Waste

Charcoal Other Biomass

and Wastes(c)

Energy Industries 1.4 0.1 0.6 4(b) 4(b) 4

Manufacturing Industries and

Construction

1.4 0.1 0.6 4 4 4

Transport Aviation 2

Gasoline Diesel

Road 0.1 0.6(d) 0.6

Railways 1.4 0.6

Navigation 1.4 0.6

Other Commercial/Institutional 1.4 0.1 0.6 4 1 4

Sectors Residential 1.4 0.1 0.6 4 1 4

Agriculture/

Forestry/

Stationary 1.4 0.1 0.6 4 1 4

Fishing Mobile 0.1 0.6

Note: These factors are considered as the best available global default factors to date.

(a) Brown coals may produce less N2O than bituminous coals; some measurements have shown that N2O emissions by hard coal combustion in power plants may be

negligible. N2O emissions from FBC are generally about 10 times higher than from boilers.

(b) These factors are for fuel combustion in the energy industries. For charcoal production, please refer to Table 1-14, Default Non-CO2 Emission Factors for Charcoal

Production.

(c) Includes dung and agricultural, municipal and industrial wastes.

(d) When there is a significant number of cars with 3-way catalysts in the country, road transport emission factors should be increased accordingly. Emission factors for 2-

stroke engines may be three times higher than those for 4-stroke engines.

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Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual 1.47

1 . 5 D e t a i l e d Met h od s (T i e r s 2 a n d 3 ) f or F u e l

Combustion

1.5.1 Overview

Identification and quantification of greenhouse gas emissions by source category and

economic sector, together with a sound understanding of plant combustion conditions,

are essential for the study of abatement procedures and the formulation of abatement

policy options. Equally, assessment of the effects of emissions on the atmosphere and

climate requires detailed data on the magnitude and spatial distribution of pollutant

emissions. Both sets of requirements are served by the estimation of emissions from

combustion activities categorised by plant types at a level of detail for which an emission

factor can be reasonably narrowly specified. Studies of the products of combustion from

many types of plant under different operating conditions have resulted in a growing

database of emission factors linking the emission rate to the activity. Estimation

methodologies using these emission factors are described and discussed in this section.

In what follows, the emission sources are grouped into stationary and mobile sources and

representative emission factors for them are assembled for use in a simple formula

common to the majority of cases. The distinction between Tier 1 methods and those of

Tiers 2 and 3 rests mainly on the reliance of the first on widely available fuel supply data

which, by its nature, takes no account of the combustion technology to which the fuel is

delivered. Distinguishing between Tiers 2 and 3 is less easily done as there is a steadily

increasing degree of refinement and detail in the emissions estimation process as the

methods are developed from one tier to another. However, Tier 2 methods may be

regarded as those dividing fuel consumption on the basis of sample or engineering

knowledge between technology types which are sufficiently homogenous to permit the

use of representative emission factors. Tier 3 methods generally estimate emissions from

activity figures (kilometre travelled or tonne-kilometre carried, not fuel consumption) and

specific fuel efficiency or fuel rates or, alternatively, using an emission factor or factors

expressed directly in terms of a unit of activity.

A new methodology, developed from that used by CORINAIR, has been introduced for

the estimation of emissions from aircraft. Revised emission factors are also given for

emissions from many types of stationary combustion and road transport in the United

States and Europe.

Estimating CO2

It follows from the arguments given above for the construction of detailed emission

estimates that a country will also benefit from the estimation of CO2 emissions in parallel

with the calculation of non-CO2 inventories despite the existence of Tier 1 methods for

CO2 estimation. The Overview to this Chapter also emphasises this point. Most of the

tables of emission factors for mobile sources, but few of the tables for stationary sources,

have figures for CO2. In cases where CO2 emission factors are not given the carbon

emission factors provided for the fuel types listed for the Tier 1 methods will suffice. If

different fuel qualities are used in different applications national experts may wish to vary

the emission factors accordingly.

Where CO2 emission factors are given in this Chapter they include all carbon based

molecule emissions from the process. This ensures that CO2 totals constructed by

summing the results of the detailed estimation of emissions (the “bottom-up” approach)

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1.48 Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual

will be comparable with the IPCC Reference Approach described under Tier 1 methods

above. The Reference Approach provides a simple transparent and verifiable means of

accounting for all of the carbon in fuels which could be emitted to the atmosphere.

Because of the complexity of covering all sources of fuel combustion and obtaining the

related data it does not automatically follow that summing emissions from the many

detailed sources will result in a figure close to that obtained from the Reference

Approach. Consequently, verification of CO2 totals against the Reference Approach is an

obligation of the IPCC reporting system.

Use of carbon emission factors based on the fuel’s carbon content also implies that

adjustments may be needed (depending on the combustion process under consideration)

for any carbon unoxidised. Carbon remaining unoxidised after combustion is discussed in

Section 1.4.1.1. Where emission estimates are prepared by plant type the general

information given in the section cited may be used when more specific carbon unoxidised

factors are not available. At the level of process detail implicit in Tiers 2 and 3, quantities

of fuel combusted should be known or fairly well estimated and quantities delivered for

the manufacture of non-energy products identified and excluded. Where this is not the

case estimates of carbon stored in manufactured products will need to be made in

collaboration with national experts preparing estimates of emissions from Industrial

Processes to ensure that there is no double counting of emissions.

D ATA S OURCES

National experts working on detailed emission of non-CO2 GHGs (particularly the

indirect gases) and SO2 should consult the extensive literature on emission factors and

other estimation procedures which has been developed by other inventory programmes

outside of the framework of the IPCC/OECD/IEA programme. These data generally

contain more technology detail, and are further broken down by size of the various

technologies. For mobile sources, data generally contain more vehicle and control

technology detail, and are further broken down by operating conditions (e.g., catalyst

vintages, driving cycles). The nature of these control assumptions should be known and

carefully matched with actual conditions in the country when selecting the specific factors

to be used.

Some key examples of data sources are:

• Default Emission Factors Handbook (European Environment Agency Task Force,

Bouscaren, 1992)

• CORINAIR Working Group on Emission Factors for Calculating 1990 Emissions

from Road Traffic, Volume 1: Methodology and Emission Factors (Eggleston, et al.,

1992)

• CORINAIR Working Group on Emission Factors for Calculating 1990 Emissions

from Road Traffic, Volume 2: COPERT Model, Users Manual (Andrias, et al., 1992)

• Atmospheric Emission Inventory Guidebook (Joint EMEP/CORINAIR, European

Environment Agency, 1996)

• US EPA's Compilation of Air Pollutant Emissions Factors (AP-42), 4th Edition 1985,

(US EPA, 1985a and 1985b), 5th Edition 1995 (US EPA, 1995) and Supplement F,

(US EPA, 1993b)

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Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual 1.49

• US EPA's MOBILE5a (US EPA 1994a). Contact Terry Newell, US EPA Office of

Mobile Sources, 2565 Plymouth Road, Ann Arbor MI 48105, USA; tel: (313) 668-

4462, Email: Newell.Terry@epamail.epa.gov or access the latest information on

mobile sources on the world wide web at

http://www.epa.gov/OMSWWW/omshome.htm.

• Criteria Pollutant Emission Factors for the 1985 NAPAP Emissions Inventory

(Stockton and Stelling, 1987)

• Proceedings of the TNO/EURASAP Workshop (TNO, 1993)

• EMEP and CORINAIR Emission Factors and Species Profiles for Organic

Compounds. (Veldt, 1991)

• Transport Statistics for Europe (UN ECE, 1989)

• World Road Statistics (International Road Federation, 1990)

• Other compilations of emission factors include

- Netherlands Bakkum, et al., 1987, Okken, 1989

- Norway Statens forurensningstilsyn, 1990

- Germany Brieda and Pakleppa, 1989, Fritsche, 1989, Rentz et al.,

1988,

Walbeck, et al., 1988

- Japan JAERI, 1988

- United Kingdom Eggleston and McInnes, 1987

- UNEP Country Studies

- US Country Studies, US CSP, 1996

- National Communications to the FCCC

1.5.2 Stationary Combustion

1.5.2.1 O VERVIEW

This section considers emissions of NOx, N2O, CO, CH4, SO2 and NMVOCs from

stationary combustion plant. Estimation of CO2 emissions at the level of detail of Tiers 2

and 3 is described in Section 1.5.1.

The section focuses on emissions from the combustion of commercial fuels, which include

virtually all fossil fuels and biomass fuels traded commercially and used in large combustion

plants. Non-CO2 emissions from combustion of biomass are estimated in exactly the

same manner as fossil fuel combustion emissions.14.

Emissions of non-CO2 greenhouse gases across activities (sectors and subsectors) will depend

upon fuel, technology type and pollution control policies. Emissions will also vary with the

size and vintage of the combustion technology, its maintenance, and its operation. Most of a

country’s NOx emissions arise from stationary fuel combustion. As defined here (i.e.,

excluding "traditional" small scale use of biomass), this category generally contributes a smaller

but still significant share of national emissions of CO and NMVOC, and, to a lesser extent, of

N2O and CH4. These two gases are nonetheless discussed in some detail because of their

priority status within the IPCC/OECD/IEA programme.

 

 14 See Section 1.4.3 for a discussion of CO2 emissions from biomass combustion.

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A section on SO2 has been added to the Tier 1 methodology. In the more detailed Tier 2

approach the same basic formula should be applied to more detailed fuel information.

1.5.2.2 R ECOMMENDED M ETHODOLOGY

General Method

Estimation of emissions from stationary sources can be described using the following basic

formula:

Emissions = ∑ (EFabc x Activityabc)

where:

EF = Emission Factor (kg/TJ);

Activity = Energy Input (TJ);

a = Fuel type;

b = Sector-activity; and

c = Technology type.

Total emission for a particular country is the sum across activities, technologies and fuels

of the individual estimates.

Emission estimation is based on at least three distinct sets of assumptions or data:

1) emission factors; 2) energy activities; and 3) relative share of technologies in each of

the main energy activities. Sources of the emission factors and energy activity data that

are relevant internationally are described briefly below and suggestions on appropriate

use of such data are made.

Technology share or technology splits for each of the various energy activities are needed

at least on a national level for non-CO2 greenhouse gas estimation since emission levels

are affected by the technology type. Unfortunately, there is no complete international

source of data on technology splits and, as a result, each country will need to develop its

own technology splits for each energy activity.

The main steps in the inventory method can be summarised as follows:

1 Determine the source and form of the best available, internationally verifiable,

national (or sub-national) energy activity data.

2 Based on a survey of national energy activities, determine the main categories of

emission factors.

3 Compile best available emission factor data for the country, preferably from national

sources. If no national sources are available, select from the options described here.

Selection among the options should be based on the similarity of the country to the

source of original measurements for types of technology and operating conditions

across main energy activities. The selection should also consider the extent to

which control technologies may be in place and requires the ability to clearly

separate and understand control policy assumptions that may be embedded in the

emission factor data.

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Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual 1.51

4 Based on the form of the selected emission factors, identify the technology

categories to be used in the national inventory.15

5 Using these assumptions on technology categories, develop estimates for each of the

greenhouse gases for each main activity.

6 Sum the individual activity estimates to arrive at the national inventory total for each

of the greenhouse gases.

Technology Splits for Energy Data

National data or assumptions on the technology shares of each of the main source sector

categories which have been identified as important in each country are necessary to

create the linkage between national energy balances and the emission factors. Again, this

may be based on "bottom-up" data collection at as detailed a level as individual sources,

or it may be more of a “top-down” allocation based on statistical sampling, or engineering

judgement. The objective is to match up fuel use, by fuel type, with specific technologies

or classes of technologies, for which credible emission factors for non-CO2 gases can be

provided.

Emission Factor Data

Emission factors for all non-CO2 greenhouse gases from combustion activities vary to

lesser or greater degrees with:

• fuel type

• technology

• operating conditions

• maintenance and vintage of technology

and so represent the average emission performance of similar technologies.

They are therefore technology specific, but may still represent a wide distribution of

possible values because of the influence of the other three factors above. When available,

the standard deviation of the emission factor should be used to show the range of

possible emission factors, and hence emissions, for each particular energy activity.16

1.5.2.3 E MISSION F ACTORS

Some tables of representative emission factors for NOx,

17 CO, CH4, N2O and NMVOCs

by main technology and fuel types (based on Radian, 1990) were presented in the

preliminary methodology manual (OECD, 1991) distributed by the IPCC. This information is

still useful in showing the range and variation of sources and emission rates, and it is

 

 15 This may also require assumptions about the control technologies in place.

 16 Unfortunately, the standard deviation of emission factors is rarely reported with

emission factor data. One study shows that when considered, variation of emission

factors within an energy activity vary widely, from 20 to more than 50 per cent (Eggleston

and McInnes, 1987).

 17 The convention in this document is that NOx emissions from fossil fuel combustion

are expressed on a full molecular basis assuming that all NOx emissions are emitted as

NO2.

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TABLE 1-16

INDUSTRIAL BOILER PERFORMANCE

Emission Factors (kg/TJ energy input)

Basic Technology Configuration CO CH4 NOx N2O NMVOCs

Coal

Bit./Sub-bit. Overfeed Stoker Boilers 110 1.0 130 1.6 NAV

Bit./Sub-bit. Underfeed Stoker Boilers 190 14 170 1.6 NAV

Bit./Sub-bit. Hand-fed Units 4800 87 160 1.6 NAV

Bituminous/Sub-bituminous Pulverised Dry Bottom, wall fired 9 0.7 380 1.6 NAV

Dry Bottom, tangentially fired 9 0.7 250 0.5 NAV

Wet Bottom 9 0.9 590 1.6 NAV

Bituminous Spreader Stokers 87 1.0 240 1.6 NAV

Bit./Sub-bit. Fluidised Bed Combustor Circulating Bed 310 1.0 68 96 NAV

Bubbling Bed 310 1.0 270 96 NAV

Anthracite Stokers 10 NAV 160 NAV NAV

Anthr. Fluidised Bed Combustor Boilers 5.2 NAV 31 NAV NAV

Anthracite Pulverised Coal Boilers NAV NAV 310 NAV NAV

Oil

Residual Fuel Oil Boilers 15 3.0 170 0.3 NAV

Distillate Fuel Oil Boilers 16 0.2 65 0.4 NAV

Small Waste Oil Boilers <0.1MW 15 NAV 58 NAV NAV

LPG Boilers Propane 17 NAV 96 NAV NAV

Butane 16 NAV 97 NAV NAV

Small Stationary Internal Comb. Engines Gasoline <250hp (186 kW) 27 NAV 0.7 NAV NAV

Diesel <600hp (447 kW) 0.4 NAV 1.9 NAV NAV

Large Stationary Diesel Engines >600hp (447 kW) 0.3 0.0 1.3 NAV NAV

Natural Gas

Large Boilers >100 MBtu/h (293 MW) 18 1.4 250 NAV NAV

Small Boilers 10-100 MBtu/h (29.3-293 MW) 16 1.4 64 NAV NAV

Heavy Duty Nat. Gas Compressor Eng. Turbines 2.0 0.6 4.1 NAV NAV

2-Cycle Lean Burn 4.7 17 33 NAV NAV

4-Cycle Lean Burn 5.1 13 39 NAV NAV

4-Cycle Rich Burn 20 2.9 28 NAV NAV

Wood

Fuel Cell/Dutch Oven Boilers 290 NAV 17 NAV NAV

Stoker Boilers 590 15 65 NAV NAV

FBC Boilers 61 NAV 87 NAV NAV

Bagasse/Ag. Waste Boilers NAV NAV 68 NAV NAV

MSW

MSW Boilers Mass Burn Waterwall 22 NAV 170 NAV NAV

Mass Burn Rotary Waterwall 36 NAV 110 NAV NAV

Mass Burn Rotary Refrac. Wall 64 NAV 120 NAV NAV

Modular, Excess Air NAV NAV 120 NAV NAV

Modular, Starved Air 14 NAV 150 NAV NAV

Refuse Derived Combustors 90 NAV 240 NAV NAV

Source: US EPA (1995).

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Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual 1.55

TABLE 1-17

KILNS, OVENS, AND DRYERS SOURCE PERFORMANCE

Emission Factors (kg/TJ energy input)(a)

Industry Source CO CH4 NOx N2O NMVOCs

Cement, Lime Kilns - Natural Gas 83 1.1 1,111 NAV NAV

Cement, Lime Kilns - Oil 79 1.0 527 NAV NAV

Cement, Lime Kilns - Coal 79 1.0 527 NAV NAV

Coking, Steel Coke Oven 211 1 35(b) NAV 16(b)

Chemical Processes, Wood, Asphalt,

Copper, Phosphate

Dryer - Natural Gas 11 1.1 64 NAV NAV

Chemical Processes, Wood, Asphalt,

Copper, Phosphate

Dryer - Oil 16 1.0 168 NAV NAV

Chemical Processes, Wood, Asphalt,

Copper, Phosphate

Dryer - Coal 179 1.0 226 NAV NAV

Source: Radian, 1990.

(a) Values were originally based on gross calorific value; they were converted to net calorific value by assuming that net calorific

values were 5 per cent lower than gross calorific values for coal and oil, and 10 per cent lower for natural gas. These

percentage adjustments are the OECD/IEA assumption on how to convert from gross to net calorific values.

(b) Joint EMEP/CORINAIR (1996).

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1.136 Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual

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Fortum 2001 - 

Methane and nitrous oxide emissions in the Finnish energy production.
Report 1 (36)

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Fortum Power and Heat Oy, Technology

Rajatorpantie 8, Vantaa, P.O.Box 20, 00048 Fortum, Finland

Tel. +358 10 4511 Fax +358 10 45 34902 www.fortum.com

Domicile Helsinki Business ID FI 01091602

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Distribution Checked by, Date

Approved by, Date

Replaces

Keywords

METHANE AND NITROUS OXIDE EMISSIONS IN THE FINNISH ENERGY

PRODUCTION

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EXECUTIVE SUMMARY

The objective of the present study is to gather and analyse existing information on the

formation of methane and nitrous oxide emissions from combustion processes and to

produce more reliable measurement data on the emissions of these gases from the

energy production in Finland. These data will be used for evaluating the emission

factors that are presently in use in reporting of Finland's national greenhouse gas

inventory.

Measurements were made at 13 plants, including three CFB boilers, three BFB

boilers, two recovery (RB) boilers, two pulverised coal firing (PC) boilers, two

combined cycle gas turbine-plants (GTCC) and one heavy oil firing boiler.

Measurements were focused (six of 13) on the fluidised bed combustion boilers, as

these technologies are reported to produce significantly more N2O than the

corresponding conventional technologies. In overall, the measured plants present quite

well the Finnish energy production both by the technology, plant size and the fuel

used.

A total of 21 different process condition situations were measured. The results of

nitrous oxide and methane measurements fit well with the theories. Methane emission

is a result of incomplete combustion. Measurements show that methane emission only

occurs with a simultaneous and relatively high carbon monoxide concentration. In

normal process conditions, emissions were <1...3 mg/MJ.

The N2O emission level was under the confidence limit (<2 ppm i.e. <3 mg/MJ) in the

PC boilers, recovery boilers, heavy oil boiler and the GTCC plants. The SCR system

did not increase the N2O emission level, according to these measurements. In fluidised

bed combustion, there was a clear difference between the BFB and the CFB

technique. In the BFB boilers, the N2O emission level was under the confidence limit.

The N2O emission level was above the confidence limit only in the CFB boilers. The

emission level varies between <2 mg/MJ and 26 mg/MJ. The main reason for the N2O

emission seems to be the low combustion temperature. Temperature sensitivity of the

nitrous oxide emission means that, in CFB combustion, it is in its minimum at full

load, and the emission increases as the load decreases. Also fuel properties (rank and

nitrogen content) have influence on the N2O emission as alleged. For these reasons the

fixed emission factors do not work well in CFB boilers. The emission factor in CFB

boilers has to be such that it considers both the boiler load and the fuel.

Measured N2O and CH4 emissions from different combustion techniques were

compared to national and IPCC's emission factors. The biggest difference between the

measured N2O emission and the national factor was in BFB boilers. Also the factors

for CFB boilers seemed to be too high. The CH4 emission factors for CFB and BFB

boilers seemed equally to be too high.

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FOREWORD

Methane and Nitrous Oxide Emissions in Finnish Energy Production project has been

executed by Fortum Technology.

Mr Pekka Järvinen of Fortum Tech has acted as the maneger of the project. Ms Sirpa

Korhonen, Mr Marko Fabritius and Mr Heikki Hoffren have acted as the project

engineers.

The members of the Management Group have been: Ms Anu Karessuo, Finnish Forest

Industries Federation, Dr Pia Kilpinen, Åbo Academi, Dr Riitta Pipatti, VTT Energy,

Mr Kari Grönfors, Statistics Finland, Mr Matti Hiltunen, Foster Wheeler Energia Oy

and Mr Ari Tamminen, Kvearner Pulping Oy. The Chairman of the Management

Group has been Mr Jukka Leskelä, Finnish Energy Industries Federation.

This project has been financed by: Finnish Energy Industries Federation and Finnish

Forest Industries Federation.

May, 2001

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CONTENTS

EXECUTIVE SUMMARY...............................................................................................................................................2

1 INTRODUCTION ...................................................................................................................................................5

2 OFFICIAL ESTIMATES OF GREENHOUSE GAS EMISSIONS IN FINLAND ...........................................6

3 FORMATION OF METHANE EMISSIONS IN THE COMBUSTION SYSTEMS........................................7

4 NITROUS OXIDE EMISSIONS............................................................................................................................8

4.1 GENERAL...............................................................................................................................................................8

4.2 N2O EMISSIONS FROM FLUIDISED BED BOILERS ...................................................................................................10

4.3 N2O EMISSION FROM SNCR AND SCR................................................................................................................13

4.4 N2O MEASUREMENT TECHNIQUES .......................................................................................................................13

5 MEASUREMENTS...............................................................................................................................................16

5.1 SCOPE..................................................................................................................................................................16

5.2 PROCESSES AND CONDITIONS ..............................................................................................................................16

5.3 MEASUREMENT METHODS ( QUALITY CONTROL )................................................................................................18

5.4 RESULT OF MEASUREMENTS................................................................................................................................22

5.5 EVALUATION.......................................................................................................................................................28

6 DISCUSSION.........................................................................................................................................................29

REFERENCES................................................................................................................................................................30

APPENDIX 1: N2O AND CH4 EMISSION FACTORS...............................................................................................33

APPENDIX 2: N2O AND CH4 EMISSION FACTORS ACCORDING IPCC ..........................................................36

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1 INTRODUCTION

In the Kyoto protocol, the parties to the UN Framework Convention on Climate

Change (FCCC) agreed to reduce the emissions of six greenhouse gases: carbon

dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs),

perfluorocarbons (PFCs) and sulphur hexafluoride (SF6). The emissions of the last

three gases are negligible in the Finnish energy sector.

The most important anthropogenic greenhouse gas is CO2. In 1998, the total CO2

emissions from the Finnish energy production and industry were estimated to be

63.9 Tg. The carbon dioxide emissions from fuel combustion were 57.4 Tg (Ministry

of the Environment 2000).

The magnitude of the Finnish CH4 and N2O emissions is considerably lower than the

CO2 emissions, but they are very effective greenhouse gases. The total methane

emissions were estimated to be 197.6 Gg and the nitrous oxide emissions 25.6 Gg. As

converted to CO2 equivalents, the Finnish emissions of CH4 and N2O were 4.1 Tg and

7.9 Tg, respectively, in 1998 (Ministry of the Environment 2000).

The CH4 emissions from the energy sector are relatively small. The methane

emissions from the fuel combustion were estimated to be 21.8 Gg in 1998, which

represent 11 per cent of the total estimated anthropogenic methane emissions in

Finland. N2O emissions from the energy sector are more significant in Finland,

8.0 Gg, i.e. about one third of the total anthropogenic N2O emissions came from the

fuel consumption in 1998 (Ministry of the Environment 2000).

The N2O emissions are estimated to grow, due to the increased use of fluidized bed

combustion and catalytic converters in the energy sector. These otherwise

environmentally friendly technologies are reported to produce significantly more N2O

than the corresponding conventional technologies. It has been estimated that, in 2010,

about 50 per cent of the Finnish N2O emissions will be due to the energy sector.

In 1990, this share was about 20 per cent (Lehtilä and Tuhkanen 1999).

CO2 emissions from combustion systems can be reliably calculated on the basis of

fuel data (carbon content and mass flow). Many more uncertainties are associated

with the estimates of the methane and nitrous oxide emissions from the energy

production, due to the nature of the emission sources. Methane emission is almost

solely dependent on the combustion conditions, whereas the nitrous oxide emission is

varyingly dependent on both the combustion conditions and the properties of the fuel

(Saviharju 1992).

The objective of the present study is to gather and analyse existing information on the

formation of methane and nitrous oxide emissions from combustion processes and to

produce more reliable measurement data on the emissions of these gases from the

energy production in Finland. These data will be used for evaluating the emission

factors that are presently in use in reporting of Finland's national greenhouse gas

inventory.

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In addition to this, secondary measurements, such as CO measurement for the

methane and combustion temperature measurement for nitrous oxide are to be

suggested for the prediction of these emissions.

2 OFFICIAL ESTIMATES OF GREENHOUSE GAS EMISSIONS IN FINLAND

The recent inventories on CH4 and N2O have been estimated in accordance with the

Intergovernmental Panel on Climate Change (IPCC) methodologies with some minor

deviations (Pipatti 1998, Ministry of the Environment 1997).

The inventories of greenhouse gas emissions from fuel combustion activities have

been estimated by using the Air Emission Calculation Model, ILMARI. This model

was developed by Statistics Finland in 1992-1994 to calculate air emissions from

Finland's fuel consumption for various purposes; statistics, research, decision-making

and international air emission reporting. Under this system, emissions can be

examined by type of process, industrial sector, and fuel, or partly by region, according

to needs. The system includes emissions of particles and sulphur, nitrogen oxides,

carbon dioxide, carbon monoxide, methane and other hydrocarbons, and nitrous

oxide. The data are updated annually, and data on the year's emissions are available in

the autumn of the following year (Ministry of the Environment 1997, Pipatti 1998).

The main source of data for the model is the VAHTI database maintained by the

Finnish Environment Centres. The database contains the data in the obligatory annual

air emission reports of the establishments. Emission and fuel data are thus obtained at

establishment and at subprocess levels. Extra information is received from the data

sources of the annual Energy Statistics, for example, energy production and fuel

consumption surveys carried out by Statistics Finland and associations in the energy

branch.

CO2 emissions are calculated based on the amount of fuel used in each boiler or

process. CO, CH4, N2O and NMVOC emissions are calculated using the fuel

consumption data from the VAHTI database, and emission factors obtained from

various sources, particularly from a database of emission factors of the different types

of boilers and processes, taking into account the installed emission reduction

equipment. The database includes emission factors for approximately 200 different

types of boiler or process (Ministry of the Environment 1997).

The summary of the emission factors for methane and nitrous oxide emission factors

used in Finland's emission inventory is presented in Appendix 1 (Lehtilä & Tuhkanen,

1999). This collection of emission factors is based on the ILMARI calculation system.

In comparison, in Appendix 2, IPPC's factors for CH4 and N2O are presented.

According to Pipatti (1998), most of these emission factors used in the national

inventories are the same as in Boström (et al. 1992; 1994) calculations. The reliability

of these factors cannot be considered high. The emissions of both gases are very

dependent on the combustion conditions, and, even if the combustion technology and

energy sources (fuels) are accounted for in the inventory, the actual operating

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conditions (combustion temperature, oxygen content, etc.) are not known (Ministry of

the Environment 1997).

The N2O factors in Boström (et al. 1992) are based on estimates presented at experts'

workshop held in 1990 (LNETI 1990). There was little measurement to support those

factors, because some of the older measurements have been proved false, due to the

wrong measurement technique. The emission factors for CH4 are based on the factors

for total hydrocarbon presented by Hupa et al. (1988).

The uncertainties associated with the methane and nitrous oxide emission estimates

are largely due to the nature of the emission sources. Current statistics cannot provide

all the input data needed in the estimates. This situation will improve within the

coming years, but will not reach the same level of reliability as the input data used in

the calculation of carbon dioxide emissions in the energy sector. The methodologies

in the IPCC Guidelines (1995) are also still tentative and under development, where

methane and nitrous oxide inventories are concerned, and the results of more recent

research data have therefore been used in the estimates when deemed essential

(Ministry of the Environment 1997).

3 FORMATION OF METHANE EMISSIONS IN THE COMBUSTION SYSTEMS

Unburned gases from combustion can be divided into two main groups: carbon

monoxide (CO) and hydrocarbons (CxHy) such as methane (CH4).

The thermodynamic equilibrium levels of hydrocarbons are low at the equivalence

ratios, at which practical combustion systems are normally operated, and the oxidation

reactions are fast. Hydrocarbons can escape destruction, if poor mixing allows very

fuel-rich gases to persist in the combustor exhaust or if the oxidation reactions are

quenched early in the combustion process (Flagan & Seinfeld 1988). CO is a stable

compound even at a high temperature, if there is no oxygen present. Hydrocarbons, on

the contrary, are decomposed and form soot in high temperatures in an oxygen-poor

atmosphere (Saviharju 1990). Combustion conditions that result in low carbon

monoxide emission will generally yield low exhaust concentrations of unburned

hydrocarbons (Flagan & Seinfeld 1988), i.e. unburned hydrocarbons only occur with a

simultaneous and relatively high carbon monoxide concentration.

With some simplification, it can be said that hydrocarbon emissions will be generated,

when a low combustion zone temperature and inefficient mixing of fuel and air occur

simultaneously (Fig. 1). Such conditions are rare in large furnaces, but are the more

common in the smallest combustion devices, such as heating stoves, open fireplaces

etc. (Boström et al. 1991).

This kind of small-scale wood combustion is estimated to result in nearly half of the

methane emissions by the energy sector in Finland, even though it is less than 3% of

the energy production (Ministry of the Environment 1997). Transportation causes less

than a third of the CH4 emissions of the energy sector. The role of fugitive emissions

from the natural gas distribution is also minor (Pipatti 1998). Noncombustion sources,

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such as fuel or lubricant evaporation, are frequently major contributors to hydrocarbon

emissions (Flagan & Seinfeld 1988).

The composition and quantity of hydrocarbons in exhaust gases depend on the nature

of the fuel and on the process that limits oxidation. The range of hydrocarbon species

that are emitted from combustion systems is broad (Flagan & Seinfeld 1988). Gaseous

hydrocarbon emissions from energy production chiefly consist of methane, CH4, and

other simple hydrocarbon compounds (Boström et al. 1991).

Mixing

Poor Good

Low High

Temp

e

r

a

tu

r

e

1. 2.

3. 4.

CO high 

CxHy low

CO low 

CxHy low

CO high 

CxHy high

CO low 

CxHy low

Figure1. Formation of CO and hydrocarbon emissions (Kilpinen 1999).

4 NITROUS OXIDE EMISSIONS

4.1 General

Nitrous oxide is still a very new object of study. It became classified as an emission

component in the fluidised bed combustion only in the late '80s. The discovery of the

emission of N2O led to a vivid research activity that improved essentially the general

understanding of conversion of fuel nitrogen to nitrogen oxides NOx, N2O and

molecular nitrogen N2 (Kilpinen 1999, Leckner 1998).

However, the reaction paths for NOx and N2O formation and reduction are

complicated (see Fig. 2) and not yet fully understood, and it is often difficult to

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explain the variation in NOx and N2O emissions observed in different operating

conditions and with different fuel types. The emission of N2O is a balance between

formation and destruction. The relative importance of homogeneous and

heterogeneous decomposition or reduction of N2O and the heterogeneous reduction of

NOx depends on the operating conditions, especially the temperature, and the catalytic

activity of char and mineral matter (Johnsson et al. 1999).

In most combustion processes, the temperature of the combustion zone is usually

more than 950 °C, which results in negligible N2O emissions. Fluidized bed

combustion is an exception, and the nitrous oxide emissions can be significant. In

circulating fluidised bed (CFB) boilers, the combustion zone temperature is usually

relatively low (800-900 °C). These temperatures promote formation of N2O during the

combustion process. (Kilpinen 1995, Lin et al.1999).

Some NOx-reduction measures like urea addition (selective non-catalytic reduction

SNCR) can also increase the amount of nitrous oxide emitted from the combustion

processes (Kilpinen 1995, Lin et al.1999).

In the following chapters, the formation and influencing factors of N2O emission from

the fluidised bed combustion and SNCR are reviewed briefly.

Nfuel

Nchar

1

Nvol

2

NH3

3

NH3

5

HCN4

N2 9

N2 6

NO10 NO 8N2O7

N2

15

NO13

N2O14

N2

16

N2O12

N2

11

NO Nchar NH3 HCN N2O

Figure 2. Fuel-N conversion routes in coal firing FBC (Kilpinen 1999).

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4.2 N2O emissions from fluidised bed boilers

Fluidised bed combustion (FBC) has emerged as an environmentally attractive

combustion method mainly due to the possibility to control SOx and NOx emissions

without any expensive equipment. Combustion is stable in spite of wide variations in

the particle size, moisture content and heating value of the fuel.

In principal, there are two types of fluidised bed. The first one is based on the

bubbling fluidised bed (BFB) technology and the other on the circulating fluidised bed

(CFB) technology. Both types are characterised by the bed material (typically sand).

In BFB, the height of the bed is 0.5...0.8 m when fluidised. The bed temperature is

kept at 800...950 °C. The combustion temperature above the bed will rise clearly

over 1000 °C. Bubbling fluidised bed combustion is suitable for reactive and wet fuels

like peat, biomasses and sludges.

In CFB, the fluidisation velocity is higher, and the bed particle size is smaller than in

BFB. Because of that, part of the bed material flows out from the furnace with flue

gases. Bed particles are separated from flue gases by a separator (normally cyclone)

and returned back into the lower part of the furnace. Due to bed material circulation,

the furnace temperature (800...950 °C) is lower and more even than in BFB. The low

operating temperature results in low NOx emissions and optimum conditions for SOx

removal with the addition of limestone or dolomite. The low combustion temperature,

however, allows formation of N2O. Circulating fluidised bed combustion is suitable

for reactive fuels and also for less reactive and high-heating-value fuels like coal.

During combustion, nitrogen oxides in are formed from the nitrogen present in the air

and in the fuel. At fluidised bed combustion temperatures, both NOx and N2O

emissions are derived almost solely from the nitrogen present in the fuel (Lin et al.

1999, Wójtowicz et al. 1994). Upon being fed into the fluidized bed, the fuel particles

quickly heat up, mix with bed materials and release volatiles. During devolatilization,

the originally bound fuel nitrogen is partitioned into volatile nitrogen and charnitrogen. In the volatiles, the major nitrogen intermediates are ammonia, NH3, and

cyano-species, such as hydrogen cyanide, HCN. When the fuel volatiles are oxidised

in the gas phase at the fluidized bed temperatures, NH3 is predominantly converted

into NO, whereas HCN is an important volatile source of N2O. NOx and N2O will also

be produced during the char burnout stage (Kilpinen 1995, Leckner 1998). The

manner of conversion of char-N to N2O is not clear. The share of char-N in the

formation of N2O is often considered to be small, although no general agreement

exists.

Both the formation and destruction of N2O in a fluidized bed combustor are more or

less catalytically affected by the bed material, including char, calcium oxides, calcium

sulphates, ash and sand. N2O can be effectively reduced by hydrogen radicals, carbon

monoxide, thermal decomposition and char. (Liu & Gibbs 1999).

The factors affecting the production of N2O (as well as NOx) can be broadly

categorized into those originating from the fuel type, and those brought about by the

combustor design and operating conditions. A review of the literature identifies these

latter factors as the combustion temperature, excess air, limestone feed, pressure, air

staging and boiler load. Except for the bed temperature, the effects of these operating

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conditions on NOx and N2O in FBC are often contradictory. The contradictions are

believed to be due to the different FBC technologies employed; that is, bubbling,

circulating, and pressurised beds, as well as combustor size (laboratory to commercial

scales), and the complex chemistry of the formation and destruction of N2O (Lin et al.

1999). Affecting factors to N2O emissions are summarized in Table 1.

The combustion temperature is, undoubtedly, the single most important parameter

affecting the rates of formation and destruction of N2O and NO. Most studies report

that N2O emissions decrease with an increase in the bed temperature, and NO exhibits

an opposite trend (Lin et al. 1999). Conversion of HCN to N2O is very sensitive to

temperature and decreases, when the temperature increases. If the temperature is more

than 950 °C, N2O is not formed, instead HCN is converted mainly to NO. Also, the

increasing temperature accelerates the destruction of already formed N2O (Kilpinen

1995). The N2O emissions could be reduced, in principle, by adjusting the combustion

temperature conditions, but, in that case, other emissions tend to increase (Lin et al.

1999). Fig. 3 shows how the furnace temperature at the over fire air (OFA) level

affects the nitrous oxide and nitrogen oxide emission in the Viikki lab-scale BFBcombustion unit.

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.00

180.00

200.00

21.11.2000 0:00 21.11.2000 0:30 21.11.2000 1:00 21.11.2000 1:30 21.11.2000 2:00 21.11.2000 2:30 21.11.2000 3:00

N2O (dry), NO and NOx (wet) ppm

800

820

840

860

880

900

920

940

960

980

1000

Furnace temperature in OFA level /°C

NO

NOx

N2O

Temp

Figure 3. Effect of temperature on the nitrous oxide emission in the Viikki 200 kW labscale BFB-combustion unit. Fuel was peat (moist. 55%), the stoichiometric ratio in

the secondary air region was 0.90 and the total air ratio 1.25.

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The temperature profile is quite uniform in the combustion chamber of the circulating

fluidised bed boiler, whereas in the bubbling fluidised bed boiler, the zone near the

secondary air level is distinctly hotter than the dense bed. Thus the N2O emission is

considered to be lower in the BFB boiler than in the CFB boiler. The highest N2O

emissions are reported from the coal firing circulating fluidised bed boilers.

According to Leckner (1998), the emission of N2O depends on the fuel in a

descending scale from coal, to lignite, peat and wood. The emission of N2O from a

boiler burning wood is negligible. Different fuels give different nitrogen compound

flows into volatiles and char. The small nitrogen content of wood, for instance, would

go mostly with the volatiles to produce ammonia and NO. Very little of N2O is

formed in this case (Leckner 1998). According to the literature (Kilpinen 1995), the

fuel rank and nitrogen content of the fuel are important factors to determining the

relative concentrations of N2O and NO evolved from different fuels. On the other

hand, Aho (1998) found that the ratio fuel-O/fuel-N is an important fuel factor

determining the formation of N2O and NO from volatile fuel-N. According to Aho,

the emissions of N2O decrease with an increasing fuel-O/fuel-N ratio, because the

ratio of HCN/NH3 in pyrolysis gases decreases.

N2O emission can also be affected by excess-air ratio. N2O formation is decreased

with lowering the excess air ratio (Leckner 1998, Moritomi et al.1999). A strong

decrease in excess oxygen will, however, increase the CO emission and result in a

decreased combustion efficiency.

The temperature range in fluidised bed combustion is suitable for addition of sorbent

into the bed to reduce SO2 emissions. Limestone addition usually results in a lower

N2O emission, and this is most pronounced at high molar ratios of Ca/S. Suggested

reasons for the often-observed decrease in N2O emissions are principally three: first of

all, limestone/CaO catalyses the decomposition of N2O. Secondly, the reduced SO2

level in the combustor results in an increase in the pool of H, OH and/or O radicals,

which can effectively destroy N2O. Thirdly, the oxidation of HCN, the major N2O

precursor from volatile-N, over limestone has a high selectivity for NOx formation

and a low selectivity for N2O formation under FBC conditions. Finally,

limestone/CaO catalyses the conversion of HCN to NH3, which in turn results in a

reduced N2O (Kilpinen 1995).

Air staging is a technique used to reduce NOx levels, but its effect on N2O emission is

unclear. In some studies, no significant change in the N2O level was observed. In

others, a decrease in N2O was reported together with an NOx reduction (Wójtowich et

al. 1994). Hiltunen et al. (1991) reported that air staging and air ratio have an

insignificant effect on N2O emission.

In the literature, there has been reported 10 - 150 ppmv N2O emission (corresponding

specific emission 5-100 mg/MJ) for fluidised bed combustion of coal (Kilpinen 1995).

In Ahlstrom pyroflow CFB boilers, it has been reported that 10-30 ppm

(corresponding 5-15 mg/MJ) is a typical N2O emission in wood, peat and oilshale

combustion and 30-120 ppm (3% O2 dry, corresponding 15-60 mg/MJ) in coal

combustion (Hiltunen et al. 1991). N2O emission for Foster Wheeler's Compact CFB

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boiler is reported to be 5 mg/MJ in bark/woodwaste firing (Kostamo & Niemelä

1997).

Rautanen et al. (1997) reported 20 mg/MJ emission in the 196 MWth Kvaerner's

Cymic (CFB) boiler firing biofuel and 35 mg/MJ, when firing coal.

Table 1. Summary of factors affecting on N2O emissions.

Factor Effect on N2O emission

Increasing combustion temperature (<950 °C) Decrease

Increasing fuel rank Increase

Increasing nitrogen content Increase

Increasing excess-air ratio Increase

Increasing Ca-based sorbent addition Decrease

Increasing air staging Not clear

4.3 N2O emission from SNCR and SCR

Injection of ammonia (NH3) or urea (CO(NH2)2) is one of the measures for reducing

NOx emissions; this technique is often termed as selective non-catalytic reduction

(SNCR). In general, SNCR involves a NOx reduction to N2 and H2O in the

temperature region of 900 - 1100 °C. A similar method of NOx abatement combines

ammonia injection into the flue gas with the use of a solid catalyst. The process is

known as selective catalytic reduction (SCR) and is normally carried out in the

temperature range of 300 - 400 °C.

A detrimental effect of SNCR on N2O emission has been reported. In general, the

increase in N2O depends on the temperature, the additive used and the feed rate, the

location of the injection point, and the efficiency of NOx reduction. The increase in

the N2O emission due to SNCR is roughly correlated with the amount of NOx reduced

by this process. The value of the ratio has been reported at between 5 and 50%

(Wójtowicz 1994 et al.). The N2O formation issue is more prevalent in urea-based

systems than in ammonia-based systems (Kilpinen 1995).

There has been concern about possible formation of N2O due to SCR, but the

available commercial-scale data show that this does not occur (Wójtowicz et al.

1994).

4.4 N2O measurement techniques

The development of continuous emission monitors (CEMs) has been intensive during

the last few years, especially of N2O, which had great problems e.g. with sampling

earlier.

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The N2O measurements from combustion sources have primarily been made by

collecting gas samples into glass or stainless steel containers or e.g. Tedlar bags, prior

to the gas chromatografic (GC) analysis. The most common GC methods are based on

the use of the thermal conductivity detector (GC/TCD) or the electron capture detector

(GC/ECD). The results of these primary tests indicated significant N2O concentrations

from the stationary sources, i.e. different types of boilers and combustion processes.

The potential error in the measurement method was observed in the late ‘80s (Muzio

et al.1989). The grab samples containing NO, SO2 and condensed H2O were found to

form N2O as an artefact in the sample container only after few hours. The chemical

reactions leading to the formation of N2O are shown in Figure 4. In the sample

container, the NO is oxidised to NO2. NO2 and SO2 in the gas phase are taken to be in

equilibrium with the aqueous phase. In the aqueous phase, the NO2 and SO2

ultimately form N2O and H2SO4. It was also shown that N2O production occurred,

when the aqueous phase was in a low pH.

Figure 4. Overall chemical path leading to N2O formation in the sample flasks (Muzio

et al.1989).

The chemical kinetic model was also used to investigate parametrically the formation

of N2O in the sample containers. Figure 5 shows the calculated effect of SO2

concentration on the formation of N2O in the sample containers ́ SO2 levels up to

2000 ppm. In the conclusions, it was suggested that some changes to the sampling

protocols, e.g. the gas sample should be dried or that SO2 should be scrubbed of the

sample gas before the sample container (Muzio et al.1989).

These findings led to the fact that many of the primary N2O measurements in the

combustion sources were regarded as more or less inaccurate with too high N2O

concentrations.

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The manual sampling method was besides time and labour consuming, so there was

an obvious need for a continuous analysing method, so the development work on the

continuous N2O analysers began then, over a decade ago.

Figure 5. Calculated effect of SO2 on the N2O formation in the sample containers

(Muzio et al.1989).

N2O is a chemically inert and stable gas and has characteristics, which make it ideal to

measure with sensitive optical methods. Such measuring techniques as Tunable Diode

Laser System (TDLS), Fourier Transform Infrared (FTIR) spectroscopy and NonDispersive Infrared (NDIR) technique were already then capable of measuring low

N2O concentrations in the flue gases. The development of the two last-mentioned has

been the strongest, and nowadays analysers based on these techniques are sharing the

markets.

N2O has strong infrared absorbencies at 4.5, 7.8 and 17.0 microns, from which the

main band of 4.5 micron is commonly being used in the NDIR analysers. In this

region, other oxides of nitrogen (NO, NO2) have no significant cross-interferences,

but water vapour, carbon dioxide and carbon monoxide have an effect on the N2O

measurement. They have infrared absorbances in the same region as N2O, thus they

have an overlap with the N2O absorbance, as is shown in Figure 6. These overlaps

cause both positive and negative cross-sensitivities, depending on the gas. In the

modern N2O analysers, these effects are minimised by the optical interference filters

and other technical solutions, which were not at this high level about ten years ago,

when the first models came to the market. It is possible that they gave too high

measuring values, because of the insufficient sample handling and the insensitive

optical filtration.

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Figure 6. The spectra of CO2 (left), CO (top and right), N2O (centre) and a typical IR

filter (bottom) used for the GFC measurement of trace N2O (Bruce and Middleton

1999).

5 MEASUREMENTS

5.1 Scope

The scope of these measurements was to obtain independent and reliable data of the

non-CO2 greenhouse gases, N2O and CH4, from the modern combustion processes in

the energy production industry and in the pulp and paper industry. With the new

sophisticated analysing techniques, a better and more accurate estimation of the target

gas concentrations would be given.

In addition, the effect of the different measuring principle of the N2O analyser

concerning to the results will be found with comparison measurements. In this

measurement, the conventional NDIR technique will be measured parallel with the

FTIR technique.

5.2 Processes and conditions

Measurements were made at 13 plants, including three CFB boilers, three BFB

boilers, two recovery (RB) boilers, two pulverised coal firing (PC) boilers, two

combined cycle gas turbine-plants (GTCC) and one heavy oil firing boiler.

Measurements were focused (six of 13) on the fluidised bed combustion boilers, as

these technologies are reported to produce significantly more N2O than the

corresponding conventional technologies. In overall, the measured plants present quite

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well the Finnish energy production both by the technology, plant size and the fuel

used. Plant data and information of the measured runs are in Tables 2-7.

Table 2. Data from measured circulating fluidised (CFB) boilers.

CFB1 CFB2 CFB3

Category Municipal CHP plant Industrial CHP plant Industrial CHP plant

Nominal effect MWth 299 97.5 185

Steam flow kg/s 111/99 33+17 69

Design fuel peat 100% 

coal 100%

peat 100% bark 100% 

coal 100%

Fuels in use peat and biomass peat and biomass peat and biomass

In operation since 1990 1995 1996

deSOx limestone injection limestone injection limestone injection

Measurement 1, fuel peat peat and wood(20%) peat

Load 100 % 100 % 75 %

Measurement 2, fuel peat and wood(15%) bark

Load 100 % 75 %

Table 3. Data from measured bubbling fluidised bed (BFB) boilers.

BFB1 BFB2 BFB3

Category Municipal CHP plant Industrial CHP plant Industrial CHP plant

Nominal effect MWth 260 115 78

Steam flow kg/s 110 40 28

Design fuel peat and biomass bark peat and biomass

Fuels in use peat and biomass bark peat and biomass

In operation since 1993 1994 1996

Remarks retrofitted to BFB from 

pulverised peat boiler 

in 1993

retrofitted to BFB 

from grate boiler in 

1994

Measurement 1, fuel peat bark peat and bark(50%)

Load 100 % 65 % 75 %

Measurement 2, fuel Peat and sludge

Load 75 %

Table 4. Data from measured recovery boilers.

RB1 RB2

Category Industrial CHP plant Industrial CHP plant

Capacity tds/d 2600 3000

Nominal steam flow kg/s 105 120

In operation since 1990 1996

Measurement 1 soft wood soft wood

Load 100 % 100 %

Measurement 2 hard wood

Load 100 %

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Table 5. Data from measured PC boilers.

PC1 PC2

Category Municipal CHP plant Condensing power 

plant

MWfuel 430 1300

Power MWe 160 560

Type tangential-firing boxer-firing

In operation since 1984 1993

deNOx OFA-system 

(modernization in '90s)

Low NOx burners 

+OFA and SCR

deSOx spray dry scrubber wet FGD

Measurement 1 OFA off before SCR

Load 100 % 100 %

Measurement 2 OFA on after SCR

Load 100 % 100 % EMBED

Table 6. Data from measured GTCC plants.

GTCC1 GTCC2

Category Municipal CHP plant Industrial CHP plant

MWfuel 363

Nominal effect MWth 327 113

In operation since 1991 1993

Remarks two gas turbines and 

one heat recovery 

steam generator

possibility to 

supplementary and 

fully firing

Measurement 1, load 50 % 100 %

Measurement 2 supplement 20 MW

Load 115 %

Table 7. Data from measured heavy oil boiler.

OB1

Nominal effect MWth 65

Steam flow kg/s 30

In operation since 1983

Measurement 1, load 50 %

Measurement 2, load 75 %

5.3 Measurement methods ( quality control )

The measurement period at all power plants was agreed beforehand with the person in

charge to be 6 hours, during which the process was operated in normal stable

conditions with no remarkable changes in the load. Due to the exceptionally mild

winter, it was not possible to arrange a maximum load at every plant.

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Measurement arrangements

In this project, the following flue gas analyser and devices were used in the

measurements:

N2O: with Servomex Xentra 4900 analyser, based on infrared absorption and gas filter

correlation technique. The measuring range was 0 - 50/500 ppm. The reported

confidence limit was agreed to 2 ppm.

Total hydrocarbons (TOC): with Signal Model 3000 analyser, based on the flame

ionisation detector (FID). The measuring range was 0-1000 ppm CH4. The reported

confidence limit was agreed to 2 ppm.

NOx: with Monitor Labs 9841A analyser, based on the chemiluminescense principle.

Measuring range 0 - 1000 ppm.

SO2: with Monitor Labs 9850 analyser, based on the UV-fluorescence principle.

Measuring range 0 - 1000 ppm. The reported confidence limit was agreed to 5 ppm.

O2: with M&C PMA 25 analyser, based on paramagnetism of oxygen. Measuring

range 0 - 25%.

CO and CO2: with Hartmann & Braun Uras 10 E analyser, based on infrared

absorption. Measuring ranges 0- 2000/5000 CO and 0 - 20% CO2.

The sample handling of gaseous compounds was arranged as follows: the NOx and the

SO2 analyser were connected to dilution probe EPM 797. This method gives the

results on a wet basis.

The total hydrocarbon analyser took the gas sample through a heated particle filter

and a heated sample line, which was maintained at the temperature of 150 °C. Results

are given on a wet basis.

N2O, O2, CO and CO2 analysers were connected to Teflon sample lines to sample gas

cooler Hartmann & Braun SCC, which removed the moisture from the sample gas

flow.

The continuous emission monitors were calibrated (zero and span calibration) with

calibration gases before and after the measurement period. The possible drift has been

corrected in the results. The calibration of the analysers was made with the certified

calibration gases, manufactured by Messer Griesheim GmbH. The concentrations of

the calibration gases were as follows:

N2O 39.1 ppm

TOC 931 ppm (CH4)

NO 299 ppm

SO2 203 ppm

O2 4.91 %

CO 199 ppm

CO2 15.0 %

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All the gases were balanced in nitrogen except CH4, which was balanced in synthetic

air. The moisture content of the flue gas was measured with the condensation method

(with ice bath and silicagel). The flue gas flow rate was measured with Pitot tube and

with a micromanometer according to standard SFS 3866. The measurement

arrangements are described in Figure 7.

 SAMPLE

GAS

COOLER

O2, CO, CO2

DILUTION

CONTROL

 NOx 

 SO2 

 N2 O 

 TOC 

DATA

LOGGER PC

CALIBRATION GASES

ZERO GAS

∆p

t

H2O

dilution probe

heated sample line

Figure 7. The arrangement of the flue gas measurements.

N2O analyser Servomex Xentra 4900

The function of the analyser is based on the monitoring of changes at this

characterised wavelength, due to molecular absorption. A more detailed description of

the operation is shown in Figure 8, where the same idea of NO analyser is presented.

Broad band IR radiation from a hot element source passes alternately through one of

two gas filters mounted on a chopper wheel. One contains nitrogen and the other

contains gas of interest, NO for NO analyser and N2O for N2O analyser, respectively.

When the nitrogen gas filter is in position, no absorbance takes place. When the NO

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gas filter is in position, absorption takes place reducing the IR intensity in the beam

characteristic wavelengths for NO.

The temporally spaced beams then pass through a narrow band pass filter, which

limits the IR region to a specific part of the absorption spectrum and further into the

sample cell. When radiation that has passed through the nitrogen gas filter passes

through a gas sample containing NO in the sample cell, absorption occurs according

to Beer's law and produces a reduction in this "nitrogen" detector signal. This signal is

effectively a measurement signal.

In contrast, radiation that has passed through the NO gas filter has had the intensity at

the characteristic NO wavelengths already significantly reduced, and so any further

absorption in the sample cell is small, resulting in a fairly constant "target gas " signal.

The energy that is transmitted makes a reference signal, as it has exactly the same

spectral distribution as the "nitrogen" signal. Therefore the resulting "nitrogen" and

"target gas" detector signals are effective measure and reference signals, and they are

electronically balanced out under zero gas conditions (e.g. with nitrogen in the sample

cell) to set the zero output (Bruce and Middleton 1999).

Calibration of the N2O analyser was made in the laboratory of Fortum Technology

with the dynamic gas calibrator Environics model 2000. The test included checking

the linearity of the analyser, the detection limit, the response time and the cross

interferences of other main flue gas compounds. All the measured values remained

under the limits given by the manufacturer in the technical specifications.

Figure 8. Function principle of a gas analyser based on the gas filter correlation

infrared technique (GFC/IR).

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Multicomponent FTIR analyser Gasmet

This gas analyser was used in the comparison measurements of the different

measuring principles of N2O. The analyser was operated at the power plant by a

person from the Research Centre of Stora Enso. The analyser consists of a

spectrometer, which utilises the Fourier Transform Infrared technique in the

measurements and measures the entire infrared spectrum of the gas sample. Many of

the gases of interest will be measured simultaneously, and the results will be

calculated from the stored reference spectra library with the analysis software.

Hydrocarbon analyser Signal Model 3000

The analyser is based on the flame ionisation detection technique. In the analyser, the

sample gas is conducted along the heated sample line to the detector, where the

hydrocarbons are ionised into electrons and positive ions in the hydrogen/helium

flame. The detector consists of a combustion chamber and a burner. The

hydrogen/helium mixture is conducted through the burner nozzle and the combustion

air through a hole around the nozzle into the combustion chamber. The ions and

electrons are collected using the collector electrode placed near the flame. The

combustion nozzle serves as one of the electrodes, and the ionisation current between

the electrodes is amplified and converted to the measurement signal. The analyser is

capable of measuring also other hydrocarbons than methane by using the inbuilt

catalyst. In that mode, the analyser switches the sample flow periodically through to

the detector and through the catalyst, which removes other hydrocarbons than

methane from the sample gas. This means that, with the analyser, the total

concentration of hydrocarbons, the concentration of non-methane hydrocarbons and

the concentration of only methane can be measured. In these measurements, only the

"total" mode was used.

5.4 Result of measurements

Process conditions and emissions from the CFB boiler measurements are in Table 8.

All emission measurements in the CFB boilers were made without limestone feeding.

In CFB1 boiler with peat firing, the nitrous oxide emission was below the confidence

limit, and, with a peat/wood-mixture, the level was 4 mg/MJ. Emission level increase

could be explained lower temperature in upper furnace with than with peat. With

peat/wood-mixture firing, the combustion temperature in the upper furnace was lower

than with peat firing. The methane emission level of 1 mg/MJ was low in both

measurements. In CFB2 with a peat/wood mixture, the nitrous oxide emission level

was 3 mg/MJ and the methane emission 1 mg/MJ.

The highest nitrous oxide emissions were measured from the CFB3 boiler. In peat

combustion, the emission was 26 mg/MJ and, with bark, 10 mg/MJ. The difference

between peat and bark could be explained by the different fuel properties. The

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methane emission was below the confidence limit in peat combustion. With bark, the

firing emission was 1 mg/MJ.

Table 8. Process conditions and emissions from CFB boilers.

Boiler CFB1 CFB1 CFB2 CFB3 CFB3

Main fuel peat peat peat peat bark

Secondary fuel and share none wood (15%) wood (20%) none none

Capacity MWth 294 297 94 138 138

Load 98 % 99 % 96 % 75 % 75 %

Bed °C 865 846 867 865 838

Upper furnace °C 901 887 746 768

After separator °C 905 894 867 860 796

O2, dry % 6.1 6.2 5.5 6.5 7.1

CO2, dry % 13.8 13.7 14.4 13.1 13

CO, dry ppm 14 9 34 4 24

NOx, as NO2 dry 6% O2 mg/m3

n 174 159 316 331 313

NOx, as NO2 mg/MJ 68 62 122 128 123

SO2, dry 6% O2 mg/m3

n 394 286 241 381 < 20

SO2 mg/MJ 153 113 93 147 < 8

N2O, dry ppm < 2 5 4 33 12

N2O, dry 6% O2 mg/m3

n < 4 10 8 68 25

N2O mg/MJ < 2 4 3 26 10

CH4, wet ppm 4 4 3 < 2 2

CH4, dry 6% O2 mg/m3

n 2 2 2 < 2 2

CH4 mg/MJ 1 1 1 < 1 1

The process conditions and emissions from the BFB boiler measurements are in Table

9. In all measurements, the nitrous oxide emission was below the confidence limit. In

BFB3 boiler methane emission level was <1...3 mg/MJ and in BFB1 level was

2 mg/MJ.

In the BFB2 boiler, the methane emission was 72 mg/MJ. The reason for the high

methane and CO emission levels was too low an air ratio (average oxygen content

after furnace about 3%). During the measurement, the power plant’s own CO-analyser

was in malfunction, and the lack of emission information meant that only the

efficiency was optimised. For that reason, the measurement does not represent a

normal situation. On the other hand, this measurement fits with the theory of CH4

emission, i.e. unburned hydrocarbons only occur with a simultaneous and relatively

high carbon monoxide concentration.

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Table 9. Process conditions and emissions from BFB boilers.

Boiler BFB1 BFB2 BFB3 BFB3

Main fuel Peat Bark Peat Peat

Secondary fuel and share none none bark (50%) sludge

Capacity MWth 260 73 60 58

Load 96 % 64 % 76 % 74 %

Bed °C 817 853 897 831

O2, dry % 4.9 8.9 6.4 5.4

CO2, dry % 14.5 10.9 13.5 14.4

CO, dry ppm 179 769 38 113

NOx, as NO2 dry 6% O2 mg/m3

n 353 187 315 337

NOx, as NO2 mg/MJ 136 73 124 136

SO2, dry 6% O2 mg/m3

n 940 < 23 101 300

SO2 mg/MJ 362 < 9 40 121

N2O, dry ppm < 2 < 2 < 2 < 2

N2O, dry 6% O2 mg/m3

n < 4 < 5 < 4 < 4

N2O mg/MJ < 1 < 2 < 2 < 2

CH4, wet ppm 5 166 < 2 10

CH4, dry 6% O2 mg/m3

n 2 155 < 2 8

CH4 mg/MJ 2 72 < 1 3

The process conditions and emissions from the recovery boiler measurements are in

Table 10. In all measurements, the nitrous oxide emission was below the confidence

limit. Also the methane emission level was low.

The process conditions and emissions from the PC boiler measurements are in

Table 11. In both measurements, the N2O and CH4 emissions were below the

confidence limit. The OFA system caused an about 30% reduction in the NOx

emission. The N2O emission level in the PC2 boiler was below the confidence limit

both before and after the SCR unit. The NOx reduction in the SCR was about 55%.

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Table 10. Process conditions and emissions from recovery boilers.

Boiler RB1 RB1 RB2

Liquor from soft wood hard wood soft wood

Capacity kg/s 103 100 125.3

Load 98 % 95 % 104 %

Furnace °C 1038 1068

O2, dry % 4.4 4.3 3.4

CO2, dry % 14.9 15 15.5

CO, dry ppm 195 25 5

NOx, as NO2 dry 6% O2 mg/m3

n 218 202 163

NOx, as NO2 mg/MJ 86 79 60

SO2, dry 6% O2 mg/m3

n < 15 < 15 < 15

SO2 mg/MJ < 6 < 6 < 6

N2O, dry ppm < 2 < 2 < 2

N2O, dry 6% O2 mg/m3

n < 4 < 4 < 3

N2O mg/MJ < 1 < 1 < 1

CH4, wet ppm 3 < 2 < 2

CH4, dry 6% O2 mg/m3

n 5 < 5 < 2

CH4 mg/MJ 1 < 1 < 1

Table 11. Process conditions and emissions from PC boilers.

Boiler PC1 PC1 PC2 PC2

Capacity MWth 453 453 565 565

Load 105 % 105 % 100 % 100 %

O2, dry % 5.9 5.9 4.4 4.4

CO2, dry % 13 13

CO, dry ppm 17 17 1 1

NOx, as NO2 dry 6% O2 mg/m3

n 633 442

NOx, as NO2 mg/MJ 224 156 138 59

SO2, dry 6% O2 mg/m3

n 208 185

SO2 mg/MJ 74 66

N2O, dry ppm < 2 < 2 < 2 < 2

N2O, dry 6% O2 mg/m3

n < 4 < 4 < 4 < 4

N2O mg/MJ < 1 < 1 < 1 < 1

CH4, wet ppm < 2 < 2

CH4, dry 6% O2 mg/m3

n < 2 < 2

CH4 mg/MJ < 1 < 1

Remarks OFA off OFA on before SCR after SCR

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The process conditions and emissions from the GTCC plant measurements are in

Table 12. In all measurements, the N2O emission was below the confidence limit. The

methane emission was below the confidence limit. The only exception to this was the

supplementary firing measurement, in which the emission level was 26 mg/MJ. This

indicates that there were some mixing problems in the supplementary firing system,

i.e. a small portion of the natural gas goes unreacted through the burner zone.

Table 12. Process conditions and emissions from CCGT plants.

Plant GTCC1 GTCC2 GTCC2

Capacity MWth 155 120 138

Load 47 % 100 % 115 %

Supplementary firing MWfuel 21

O2, dry % 14.7 14.9 13.9

CO2, dry % 3.5 3.1 3.6

CO, dry ppm 7 64 122

NOx, as NO2 dry 6% O2 mg/m3

n 201 192 137

NOx, as NO2 mg/MJ 70 67 48

N2O, dry ppm < 2 < 2 < 2

N2O, dry 6% O2 mg/m3

n < 10 < 10 < 8

N2O mg/MJ < 3 < 3 < 3

CH4, wet ppm < 2 < 2 45

CH4, dry 6% O2 mg/m3

n < 2 < 3 74

CH4 mg/MJ < 1 < 1 26

The process conditions and emissions from the heavy oil boiler measurements are in

Table 13. In both measurements, the N2O and CH4 emissions were below the

confidence limit.

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Table 13. Process conditions and emissions from a heavy oil firing boiler.

Boiler OB1 OB1

Capacity kg/s 15 22

Load 50 % 73 %

O2, dry % 4.6 4

CO2, dry % 12.3 12.8

CO, dry ppm 8 9

NOx, as NO2 dry 6% O2 mg/m3

n 384 396

NOx, as NO2 mg/MJ 135 139

SO2, dry 6% O2 mg/m3

n 1102 1097

SO2 mg/MJ 387 385

N2O, dry ppm < 2 < 2

N2O, dry 6% O2 mg/m3

n < 4 < 3

N2O mg/MJ < 1 < 1

CH4, wet ppm < 2 < 2

CH4, dry 6% O2 mg/m3

n < 2 < 2

CH4 mg/MJ < 1 < 1

The comparison measurement with NDIR and FTIR was carried out at the CFB3 plant

under a normal operating load and condition. The purpose of the measurement was to

find out, how much the measurement results depended on the measuring method. Two

different N2O analysers were connected to a common heated sampling line. This was

done for practical reasons and, in this way, also the possible differences in sample

handling were compensated. Both analysers were calibrated with the same calibration

gas before and after the measurement period.

Based on these measurements, no differences between the results of these two

analysers/analysing methods could be observed, and the results were identical in

practise as shown in Figure 9.

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CFB3 5.9.2000

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

9:15 9:45 10:15 10:45 11:15 11:45 12:15 12:45 13:15

N2O concentration, ppm, dry

 N2O ppm, FTIR

 N2O ppm, IR GFC

N2O average 19 ppm, FTIR

N2O average 17 ppm, IR GFC

Figure 9. Comparison of FTIR and IR GFC N2O measurements in the CFB3 boiler.

5.5 Evaluation

The results of the nitrous oxide measurements fit quite well with the theories. The

emission level was above the confidence limit only in the CFB boilers. The main

reason for the N2O emission seems to be the low combustion temperature. The highest

measured emission level was in the CFB3 boiler in peat combustion. At this

measurement point, the temperature of the upper part of the furnace was the lowest. In

bark combustion, the emission level was clearly lower than with peat firing with the

same load, but, on the other hand, at this measurement point, the temperature was

22 °C higher. In any case, the fuel properties (rank and nitrogen content) have an

influence on the N2O emission as alleged. The temperature sensitivity of the nitrous

oxide emission means that, in CFB combustion, it is in its minimum at full load. So it

could be claimed that the smaller load the higher the N2O emission level, until it finds

its maximum value. An indication of that was found in the CFB3 boiler measurements

with peat firing. After the measurement period, the boiler load was dropped to 65%.

At that load, the N2O emission increased to the level of 36 mg/MJ. For that reason, it

is unfair to compare the CFB3 boiler nitrous emission level at 75% load to the CFB1

and CFB2 boilers at full load.

The size of the boiler does not have any influence on the N2O emission in this size

class. Unfortunately, none of the measured boilers burned coal. So its influence on

the N2O emission remained unclear. The catalytic effect of limestone feeding on the

N2O emission remained also unclear.

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6 DISCUSSION

The measurements were carried out successfully at all 13 plants and a total of 21

different situations were measured. The results from the nitrous oxide and methane

measurements fit well with the theories. The methane emission is a result of

incomplete combustion. The measurements show that the methane emission only

occurs with a simultaneous and relatively high carbon monoxide concentration. In

normal situations, the emissions were below 3 mg/MJ.

The N2O emission level was under the confidence limit in the PC boilers, recovery

boilers, heavy oil boiler and in the GTCC plants. The SCR system did not increase the

N2O emission level, according to these measurements. In fluidised bed combustion,

there was a clear difference between the BFB and the CFB technique. In the BFB

boilers, the N2O emission level was under the confidence limit.

The N2O emission level was above the confidence limit only in the CFB boilers. The

main reason for the N2O emission seems to be the low combustion temperature. The

temperature sensitivity of the nitrous oxide emission means that, in CFB combustion,

it is in its minimum at full load, and the emission increases as the load decreases.

Also, fuel properties (rank and nitrogen content) have an influence on the N2O

emission as alleged. Unfortunately, none of the measured CFB boilers burned coal. So

its influence on the N2O emission remained unclear. For these reasons, the fixed

emission factors do not work well in CFB boilers. The emission factor has to be such

that it considers both the boiler load and the fuel.

The measured N2O and CH4 emissions from the different combustion techniques are

compared with the national and IPCC's emission factors in Table 14. The biggest

difference between the measured N2O emission and the national factor was in the

BFB boilers. Also, the factors for the CFB boilers seemed to be too high. The CH4

emission factors for the CFB and BFB boilers seemed equally to be too high.

Table 14. Comparison of the measured N2O and CH4 emissions with the national and

the IPCC's emission factors. Parenthesis indicates abnormal process conditions.

CFBboilersBFB-boilers PCboilersGas turbine 

plants

Recovery 

boilers

Heavy oil 

boiler

N2O national factor mg/MJ 30 - 39 27 - 30 2 1 1.4 2

N2O IPCC- factor mg/MJ 4 4 1.4 0.1 4 0.6

N2O measured mg/MJ <2...26 <2 <1 <3 <1 <1

CH4 national factor mg/MJ 11.1 - 22.4 14.5 - 21.3 4 3 1 8

CH4 IPCC- factor mg/MJ 30 30 1 1 30 3

CH4 measured mg/MJ 1 1 - 3 (72) <1 <1 (26) 1 <1

The N2O measurement based on the IR-technique has its own difficulties, due to the

cross-interferences of other components, but the comparison measurement showed

that both the NDIR and the FTIR methods gave reliable results.

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REFERENCES

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Boström, S., Backman, R. and Hupa, M. "Greenhouse gas emissions related to energy

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Boström, S. Greenhouse gas inventory in Finland base on IPCC Draft Guidelines:

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Hiltunen, M., Kilpinen, P. Hupa, M. Lee, Y. Y. N2O emissions from CFB boilers:

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Hupa, M. and Matinlinna, J. (eds.) Liekki 2, combustion and gasification research

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D-30
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Kostamo, M. and Niemelä, K. Breakthrough for Foster Wheeler's Compact CFB

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of Mechanical Engineers, 1999.

Liu, H. and Gibbs, B. M. The influence of limestone and alumina on NOx and N2O

emissions from char combustion in a fluidized bed combustor. In: Reuther, R.B. (Ed.).

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fluidized bed combustors. In: Reuther, R.B. (Ed.). Proceedings of the 15th

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K. Errors in Grab Sample Measurements of N2O from Combustion Sources. Journal

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D-31
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Rautanen, M., Kinni, J. and Kokko, A. Experience with multifuel industrial scale BFB

and Cymic boilers. In: The future of fluidized bed combustion. VGB technical

scientific report. Report TW212e. Essen, Germany: VGB-Kraftwerkstechnik GmbH,

1997.

Saviharju, Kari. "Polttotekniikan näkymät päästöjen vähentämisessä". In: Päästöjen

lähteet, vaikutukset ja vähentämisen kustannukset. 16-17.10.1990. Hotelli Rantasipi,

Aulanko, Finland. Insinöörien Koulutuskeskus, 1990.

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Programme. Study number: IEA/91/OE 9, Study Completed February 1992.

D-32
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APPENDIX 1: N2O AND CH4 EMISSION FACTORS

Table 1. Emission factors for central electricity production (Lehtilä and Tuhkanen

1999).

Production category Fuel CH4

(t/TJ)

CH4

(mg/MJ)

N2O

(t/TJ)

N2O

(mg/MJ)

Coal condensing power,

PF, new

Coal 0.0040 4.0 0.0020 2.0

Coal condensing power,

PF, old

Coal 0.0040 4.0 0.0029 2.9

Oil condensing power Heavy and Light

Fuel Oil

0.0080 8.0 0.0020 2.0

Gas condensing power Natural Gas 0.0030 3.0 0.0010 1.0

Peat condensing power Peat 0.0020 2.0 0.0020 2.0

Natural Gas CombinedCycle

Natural gas, Light

Fuel Oil

0.0030 3.0 0.0010 1.0

Pressurised Fluidised

Bed Combustion

Coal 0.0040 4.0 0.0300 30.0

Integrated Gasification

Combined-Cycle

Coal 0.0040 4.0 0.0020 2.0

Diesel block power Heavy Fuel Oil,

Natural Gas

0.0020 2.0 0.0310 31.0

Gas turbine power Natural gas 0.0030 3.0 0.0010 1.0

Gas turbine power Light Fuel Oil 0.0080 8.0 0.0010 1.0

Gas engine Biogas 0.0020 2.0 0.0310 31.0

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Table 2. Emission factors for industrial energy production (Lehtilä and Tuhkanen

1999).

Production category/

Combustion technique

Fuel CH4

(t/TJ)

CH4

(mg/MJ)

N2O

(t/TJ)

N2O

(mg/MJ)

Process condensing power

/ All

Peat

Waste wood

Coal

HFO, LFO

Natural gas

Other gases

0.0020

0.0500

0.0040

0.0080

0.0030

0.0030

2.0

50.0

4.0

8.0

3.0

3.0

0.0020

0.0020

0.0020

0.0020

0.0010

0.0010

2.0

2.0

2.0

2.0

1.0

1.0

Back pressure power

PF

PF

CFBC

BFBC

Grate

Soda recovery boiler

Diesel + Waste Heat Boiler

GT + Waste Heat Boiler

GT + Waste Heat Boiler

NGCC

IGCC

IGCC

Steam Boiler

Grate/Burner

Steam boiler, FBC

Coal, Peat

Oil, Gases

Coal, Peat, Wood

Coal, Peat, Wood

Black liquor

HFO, Natural gas

POK

Gases

Natural gas

Peat, wood

Waste liquor

0.0035

0.0039

0.0224

0.0213

0.0213

0.0010

0.0020

0.0080

0.0030

0.0030

0.0040

0.0040

0.0187

0.0058

3.5

3.9

22.4

21.3

21.3

1.0

2.0

8.0

3.0

3.0

4.0

4.0

18.7

5.8

0.0031

0.0014

0.0390

0.0270

0.0027

0.0014

0.0310

0.0010

0.0010

0.0010

0.0020

0.0021

0.0039

0.0300

3.1

1.4

39.0

27.0

2.7

1.4

31.0

1.0

1.0

1.0

2.0

2.1

3.9

30.0

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Table 3. Emission factors for district heat and power production (Lehtilä and

Tuhkanen 1999).

Production category/

Combustion technique

Fuel CH4

(t/TJ)

CH4

(mg/MJ)

N2O

(t/TJ)

N2O

(mg/MJ)

CHP power plant

PF, big

PF, small

All

All

CFBC

BFBC

PF, big

PF or Grate, small

All

GT + WHB

GT + WHB

NGCC

Diesel + WHB

Gas Engine

PFBC

IGCC

Coal

Coal

HFO

Natural Gas

Coal, Peat, Wood

Coal, Peat, Wood, REF

Peat

Peat, Wood

Municipal Solid Waste

LFO

Natural gas

Natural gas

LFO, Natural gas

Biogas

Coal, Peat

Coal, Peat, Wood

0.0040

0.0040

0.0080

0.0030

0.0111

0.0145

0.0020

0.0050

0.0119

0.0080

0.0030

0.0030

0.0020

0.0020

0.0040

0.0040

4.0

4.0

8.0

3.0

11.1

14.5

2.0

5.0

11.9

8.0

3.0

3.0

2.0

2.0

4.0

4.0

0.0020

0.0020

0.0020

0.0010

0.0300

0.0300

0.0020

0.0300

0.0300

0.0010

0.0010

0.0010

0.0310

0.0310

0.0300

0.0020

2.0

2.0

2.0

1.0

30.0

30.0

2.0

30.0

30.0

1.0

1.0

1.0

31.0

31.0

30.0

2.0

District heat boiler

FBC

FBC

Others

Others

Coal, Peat, Wood

Coal, Natural Gas

HFO, Peat, Wood

HFO, LFO, Gases

0.0099

0.0033

0.0138

0.0371

9.9

3.3

13.8

37.1

0.0370

0.0013

0.0038

0.0017

37.0

1.3

3.8

1.7

D-35
Report 36 (36)

S. Korhonen, M. Fabritius and H. Hoffren 15 May 2001 TECH-4615

Fortum Power and Heat Oy, Technology

Copyright 2001 Fortum

k:\t&k\y-pooli\non-co2-raportti.doc

APPENDIX 2: N2O AND CH4 EMISSION FACTORS ACCORDING TO IPCC

Table 1. CH4 Emission factors (IPCC Reference manual).

Table 2. N2O Emission factors (IPCC Reference manual).

D-36
Appendix E

Emission Factor Data from Fortrum 2001 Combined with 

NCASI Technical Bulletin 998 Data
Appendix E. Emission Factor Data from Fortrum 2001 Combined with NCASI Technical Bulletin 998 Data

(The Fortrum 2001 data are shaded.)

CH4, kg/MMBtu N2O, kg/MMBtu

ID

Mill 

type

RF 

type

Spent 

liquor 

feedstock

Other 

fuels Control

No. 

runs

No. 

ND 

runs Min Max Average

No. 

runs

No. 

ND 

runs Min Max Average

BRF5 kraft NDCE softwood DBESP 3 1 0.00039 0.001 0.00093 5 0 0.00062 0.0011 0.00082

DRF1 kraft NDCE softwood DBESP 8 7 0.000034 0.000047 0.000042 7 3 0.00012 0.00018 0.00015

ERF1 kraft NDCE softwood ESP 10 0 0.000065 0.0057 0.0031 10 7 0.000099 0.00065 0.00034

ARF3 kraft DCE softwood

No. 6 

oil DBESP 10 1 0.00008 0.00068 0.0002 9 0 0.00013 0.00043 0.00027

FRF1 kraft DCE unspecified WBESP 6 0 0.002 0.016 0.01 6 0 0.00044 0.00085 0.00065

FRF3 kraft DCE unspecified WBESP 9 0 0.00026 0.0021 0.0011 9 0 0.00034 0.00076 0.00049

GRF1 kraft DCE hardwood DBESP 6 5 0.0001 0.00015 0.00011 6 0 0.00012 0.00031 0.0002

GRF2 kraft DCE hardwood WBESP 5 0 0.0001 0.00016 0.00013 6 0 0.000092 0.00033 0.00019

RB1 unspecified softwood unspecified unspecified

RB1 unspecified hardwood unspecified 0.0011 unspecified 0.0011

RB2 unspecified softwood unspecified 0.0011 unspecified 0.0011

The average was based on 1/2-MDL values for 

ND runs. Average: 0.0018 0.00052

min 0.000042 0.00015

max 0.01 0.00105

median 0.00099 0.00042
Appendix F

Wood Emission Factors from AEA Technology 2001

Available at: http://uk-air.defra.gov.uk/library/reports?report_id=8
AEAT/R/ENV/0524 Issue 1

AEA Technology A2.9

Table 3 Emission Factors for Combustion of Solid Fuels (kg/t)

C CH4 N2O NOx CO NMVOC SO2

Anthracite Domestic 813.4n2

o

0.14w1.6b45f1.7o14.0aa

Coke Agriculture 795.4n0.011p0.144g4.0b4.1p0.05p19ab

Coke Coke Production;

SSF Production

820n0.011p0.221w4.8b4.1p0.05p19ab

Coke Domestic 803.6n5.8p0.111w1.33b45q4.9p16ab

Coke I&S (Sinter Plant) 795.4n0.011p0.221w4.13b115ae 0.05p19ab

Coke I& S (Combustion) Other

Industry

795.4n0.011p0.221w4.8b4.1p0.05p19ab

Coke Railways 795.4n0.011p0.144g4.8b4.1p0.05p19ab

Coke Miscellaneous; Public Service 795.4n0.011p0.144g4.0b4.1p0.05p19ab

Petro-Coke Refineries 800a0.0127p0.256w6.9z2.57z0.0577p42.5z

SSF Agriculture; Miscellaneous;

Public Service

766.3n0.011p0.143g3.96b4.1p0.05p19ab

SSF Domestic 774.2n5.8p0.112w1.32b45q4.9p16ab

SSF Other Industry 766.3n0.011p0.218w4.75b4.1p0.05p19ab

Straw Agriculture 418g4.28g0.057g1.43g71.3g8.56g0

Wood Domestic 264g3.61b0.0388g0.722b99.3g5.42b0.037m

Wood Other Industry 470g0.482b0.069g3.21b7.1g0.803b0.037m

F-1
AEAT/R/ENV/0524 Issue 1

AEA Technology A2.11

Footnotes to Tables 1 to 4

a UKPIA (1989)

b CORINAIR (1992)

b+ Derived from CORINAIR(1992) assuming 30% of total VOC is methane

c Methane factor estimated as 12% of total hydrocarbon emission factor taken

from EMEP/CORINAIR(1996) based on speciation in IPCC (1997c).

d Based on operators data : Terra Nitrogen(2000), Kemira(2000)

e As gas oil

f USEPA (1977)

g IPCC (1997c)

h EMEP (1990)

i Walker et al (1985)

j As fuel oil.

k NMVOC emission factor estimated as 98.75% of total hydrocarbon emission

factor taken from USEPA (1977).

l USEPA(1997) estimated from total VOC factor and the methane factor given

m USEPA(1997)

n British Coal (1989)

o Brain et al, (1994)

p As coal

q As anthracite

r British Gas (1992)

s As natural gas

t EMEP/CORINAIR(1996)

u Powergen (1997), National Power (1997)

v Emission factor derived from emissions reported in the PI. Environment 

Agency (2000)

w Fynes et al (1994)

x as coke

y British Gas (1994)

z UKPIA (2000), Emission factor for 1999 derived from data supplied

by UKPIA

aa Emission factor for 1999 based on data provided by RJB(2000), Scottish 

Coal(2000), Celtic Energy (2000), Tower (2000), Betwys(2000)

ab Munday (1990)

ac Powergen (1994)

ae Factor derived from British Steel (2000) emissions data.

ad EMEP/CORINAIR (1999)

af UKPIA (2000)

ag LPG factor assumes an 80/20 mixture of propane/butane by weight.

F-2