### Date: January 9
, 201 3
Subject: Kraft Pulping Liquor and Woody Biomass Methane (CH 4 

### ) and Nitrous Oxide (N 2 

### O) 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 (A WC) petitioned the U.S. Environmental Protection Agency ( EPA ) to

r econsider and revise the m ethane (CH 4 

### ) and nitrous o xide (N 2 

### O) 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 Stre am Improvement (NCASI), Technical Bulletin 998, which contains new CH 4 

### and N 2 

### O 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 R ecommended CH 4 

### and N 2 

### O Emission F actors

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 CH 4 

### and N 2 

### O emissions test data provided in NCASI Technical Bulletin 998 with previously avail able

### 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 CH 4 

### and N 2 

### O Emission Factors

A. Recovery Furnace Literature Review

The CH 4 

### and N 2 

### O emission factors for kraft pulping liquor combustion in pulp mill recovery furnaces are provided in Table AA

- 1 of 40 CFR part 98 S ubpart AA. Table AA

- 1 is reproduced in Exhibit 1 below.

The CH 4 

### and N 2 

### O 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 A 1 contains a reproduction of the CH 4 

### and N 2 

### O emission facto r summary table from the WRI/WB C S D p rotocol and Appendix A2 contains other relevant pages from the WRI/WBCSD protocol. As shown in Appendix A 1
, four international references were cited in the WRI/WB C S D 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 Cha nge Working Group of The International Council of Forest and Paper Associations (ICFPA). http://www.wbcsd.org/web/projects/forestry/pulp

- and

paper

- 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 Liq uor Emissions Factors for Biomass

- Based CO 2 

### , CH 4 

### , and N 2 

### O

Wood furnish Biomass

- based emissions factors (kg/mmBtu HHV)

CO 2 

### a CH 4 

### N 2 

### O

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 CH 4 

### emission factors recommended in the WRI/WBCSD protocol (0.0025 kg/MMBtu) , and the median of two studies was the basis for the recommended N 2 

### O emission factor (0.002 kg/MMBtu)

. The second reference (JPA 2002) did not have an N 2 

### O factor and therefore could not be used in calculating the WRI/WBCSD

recommended median N 2 

### O emission factor. The fourth reference (EEA 2004) was mentioned in the WRI/WBCSD protocol for comparison, but was not used in calculating the WRI/WBCSD

recommended median CH 4 

### and N 2 

### O emission factors

.
Given that the WRI/WBCSD CH 4 

### and N 2 

### O 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 conservat ive measure . The highest values chosen from the WRI/WBCSD protocol for Table AA

- 1 were 30 kilograms (kg) of CH 4 

### per terajoule (TJ) which converts to 0.030 kg CH 4 

### per million British thermal units [MMBtu] and 5 kg N 2 

### O/TJ (0.005 kg/MMBtu)

. These emis sion factors originated from the Swedish EPA report. The 0.030 kg CH 4 

### /MMBtu and 0.005 kg N 2 

### O/MMBtu emission factors were included in the original greenhouse gas reporting rule ( 74 FR 16448, April 10 2009 ).

I n their November 2012 petition for rulemaking, the petitioners stated that the current Table AA

- 1 emission factors (0.030 kg CH 4 

### /MMBtu and 0.005 kg N 2 

### O/MMBtu) are overly conservative , especially in light of the new information submitted in NCASI Technical Bulletin 998. To investigate the petitioners’ conce rns, 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 d oes not include actual emissions test data

. The N 2 

### O emission factor for spent pulping liq uor was confirmed in the reference documentation, but the CH 4 

### value of 30 kg/TJ was not

. It appears that the same CH 4 

### emission factor for wood waste was used for spent pulping liquor

. Ap pendix 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 ( IPC C 2006 )

. 6 

### The table from IPCC 2006 that contains the spent pulping liquor emission factor s is reproduced in Appendix C1

. The IPCC 2006 emission factors for spent pulping liquor are:

• 1 to 18 kg CH 4 

### /TJ (0.001 to 0.019 kg CH 4 

### /MMBtu) with a recommended default of 3 kg CH 4 

### /TJ (0.0032 kg CH 4 

### /MMBtu), and

• 1 to 21 kg N 2 

### O /TJ (0.001 to 0.022 kg N 2 

### O /MMBtu) with a recommended default of 2 kg N 2 

### O /TJ (0.002 kg N 2 

### O /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 pr eviously, the only reference we located with spent pulping liquor CH 4 

### and N 2 

### O emissions test data was Fortum 2001. The Fortum report provides emission factors derived fr om Fourier Transform Infrared Spectroscopy (FTIR) and n o n

- d ispersive 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 CH 4 

### and N 2 

### O emissi ons averages from all three tests were less than or equal to 1 mil ligram 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 200 4 ). 8

, 9 

### However, n o CH 4 

### or N 2 

### O 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.ipcc

nggip.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 Pap er 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 6 348

- 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 CH 4 

### and N 2 

### O 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 (NES H AP) affecting the forest products industry.

Technical Bulletin 998 documents emissi ons 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 combu stion units (CRCU) found at sulfite and semichemcial pulp mills were included in Technical Bulletin 998. Under the GHGRP, the Table AA

- 1 CH 4 

### and N 2 

### O 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 CH 4 

### and N 2 

### O 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 CH 4 

### emissions than NDCE furnaces due to contact of the hot flue gases with incoming pulping liquor in the DCE, the ranges of CH 4 

### and N 2 

### O 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 a nd 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 T est Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy. 11 

### EPA 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 T ested in Technical Bulletin 998

CH 4 , kg/MMBtu N 2 O , kg/MMBtu

ID Mill type RF type Spent liquor feedstock Other fuels C ontrol 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
ER F1 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
FR F1 kraft DCE unspecified WBESP 6 0 0.002 0.016 0.01 6 0 0.00044 0.00085 0.00065
FR F3 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
GR F2 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 N D 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 test s . Thus, the emission factors in Technical Bulletin 998 are representative of the biogenic CH 4 

### and N 2 

### O 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 CH 4 

### an d N 2 

### O emission factors with the average factors from Technical Bulletin 998 , specifically 0.0019 kg CH4/MMBtu and 0.00042 kg N 2 

### O /MMBtu

. [We note that the petitione r s’ recommen dation of 0.00042 kg N 2 

### O/MMBtu does not exactly match the average N 2 

### O emission factor of 0.00039 kg N 2 

### O/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 up on the literature we reviewed , Technical Bulletin 998 appears to be the most recent and comprehensive sour ce of U.S. recovery furnace CH 4 

### and N 2 

### O 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 99 8. If the Fortum 2001 tests were included with the NCASI Technical Bulletin 998 data, the resultant emission factors would be 0.0018 kg CH 4 

### /MMBtu and 0.00052 kg N 2 

### O/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 m easurements 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.

T able 3. Emission F act ors for Spent Liquor Combustion in the GHGRP Table AA

- 1 C ompared to Emission Factors Derived from Available Emissions Test Data Reference CH 4 

### , kg/MMB tu N 2 

### O, kg/MMB tu GHGRP Table AA

- 1 0.03 0.005 Revised emission factors suggested by petitioners (TB 998) 0.0019 0.00042 1



### Average of all available data (TB 998 and Fortum 2001 as shown in Appendix E) 0.0018 0.00052

1. Calculated as 0.0 0 039 in Table 2 of this memorandum, likely due to rounding.

### 8 

### III. Wood and Wood Residuals Combustion CH 4 

### and N 2 

### O Emission Factors

A. Wood and Wood Residuals Literature Review

The CH 4 

### and N 2 

### O 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 (CO 2 

### ) emission factors for each type of solid biomass ( wood and wood residuals, agricultural byproducts, peat, and solid byproduc ts)

.
The existing Table C

- 2 emissi on factors are base d 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 e mission factors ranged from 10 to 100 kg CH 4 

### /TJ (0.011 to 0.11 kg CH 4 

### /MMBtu) and 1.5 to 15 kg N 2 

### O/TJ (0.0016 to 0.016 kg N 2 

### O/MMBtu)

. The default emission factors recommended by IPCC 2006 were 30 kg CH 4 

### /TJ (0.032 kg CH4/MMBtu) and 4 kg N 2 

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

RTI traced th e 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 memorand um

. The 1996 Reference M anual 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 w as unable to locate the other references from the IPCC Reference M anual

. 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 CH 4 

### of 15 kg CH 4 

### /TJ (0.016 kg CH 4 

### /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/W BCSD protocol recommended an emission factor of 12 kg CH 4 

### /TJ (0.012 kg CH 4 

### /MMBtu) and 4 kg N2O/TJ (0.0042 kg CH 4 

### /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 CH 4 

### and N 2 

### O 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 Gr eenhouse 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 . Washi ngton, DC: United States E nvironmental 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: Nationa l 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 T riangle 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 E nvironmental 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 E nvironmental Protection Agency.



### The WRI/WCBSD protocol compared t he 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 CH 4 

### and N 2 

### O emission factors for woody biomass combustion

. Appendix A1 contains a reproduction of the CH 4 

### and N 2 

### O emission facto r summary table from the WRI/WB C S D 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 fro m 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 st udies are discussed further in Section III.B of this memor andum.

### 10 

### Appendix F presents the table containing emission factors for wood from the AEA Technology 2001 repo r t 12 

### and indicates that the AEA T echnology 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 i ncluded in the WRI/WBCSD protocol ( al though for CH 4 

### 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 CH 4 

### /TJ and 3.5 kg N 2 

### O/TJ as opposed to the 24 kg CH 4 

### /TJ and 3.4 kg N 2 

### O /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 CH 4 

### emission factor

. T he AEA Technology 2001 report did not contain any actual emissions test data for woody biomass CH 4 

### and N 2 

### O.

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 CH 4 

### or N 2 

### O 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 bo iler 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 CH 4 

### emission factor based on four emissions tests and an N 2 

### O emission factor based on two tests. The 1998 Industrial Combustion Coordinated Rulemaking (ICCR) data base was the source of the four CH 4 

### tests. The N 2 

### O tests were conducted prior to 1993 and referenced from a prior AP

- 42 report.

Fortum 2001 is a Finnish study that contains CH 4 

### and N 2 

### O emissions testing for six biomass boilers

. Three of the boilers were tested with different fuel mixtures, for a total of nine fuel mixture test s cenarios . The average of the results for the nine test s was reported in the WRI/WBCSD protocol

. Review of Fortum 2001 reveals that only fi ve of the test s involved woody biomass, and thre e 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 partial ly decayed vegetation and is arguably different from woody biomass

. Table C

- 1 in the GHGRP distinguishes peat from woo d and wood residuals. T he IPCC 2006 guidelines treat peat as fossil carbon due to the long length of time it takes to replace harvested pe at. 13

12 

### http://uk

- air.defra.gov.uk/library/reports?report_id=8 13 

### IPCC 2006, p. G.3. http://www.ipcc

nggip.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/MM Btu. 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 Table s 6A and 6B later in this section

. The BFB2 CH 4 

### test was also included in Table 6A because the results are the same order of magnitud e as two other tests noted in Technical Bulletin 998 (also noted for po or combustion). It is reasonable to expect that similar poor combustion could occur in some U.S. boilers (as evidenced by the two high CH 4 

### tests in the boiler MACT d ata set documented in Technical Bulletin 998).

Table 5. Fortum 2001 Results from Emission Testing of B iomass B oilers in Finland

Unit Fuel CH 4 

### , kg/TJ CH 4 

### , kg/MMB tu N 2 

### O, kg/TJ N 2 

### O, kg/MMB tu 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 fr om the two technical bulletins were included in Table 6A

. Technical B ulletin 109 contains volatile organic carbon (VOC) emissions testing for four boilers, and Technical Bulletin 455 contains VOC test ing for six boilers. RTI reviewed these technical bulletins and found CH 4 

### concentration data. CH 4 

### is usually measured as part of the total organic compounds in a gas, but is not a VOC . CH 4

### 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 CH 4 

### test results from the technical bulle tins. 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 CH 4 

### and N 2 

### O 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 CH 4 

### test data contained in EPA’s boiler maximum achievable c ontrol technology ( MACT ) data base for boilers firing more than 80 percent of heat input as biomass. P redominantly woody biomass boilers of various designs (stoker, fluidized bed, fuel cell, dutch oven) firing wood, bark, or wastewater treatment (WWT) slud ge were studied.

RTI downloaded the boiler MACT data base referenced by the petitioners 14 

### to determine if additional CH 4 

### and N 2 

### O tests were available for major or area sources firin g predominantly woody biomass. Consistent with Technical Bulletin 998, 19 methane tests (using EPA Method 18) for major source boilers wer e identified in the data base. The units of measure in the data base were par ts per million rather than kg/MM Btu. A code

- breaker and more information (e.g., gas flow rates) would be n eeded 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 informatio n directly from the data base. No N 2 

### O tests were found in the data base (consistent with NCASI Technical Bulletin 998 which did not tabulate N 2 

### O data from the MACT testing). No additional CH 4 

### or N 2 

### O tests were identified in the data base for area sources. From this we can infer that all of the available biomass CH 4 

### data from the boiler MACT emissions testing data base was used in Technical Bulletin 998 (i.e., that tests were not chosen selectively). T he control devices used on the biomass boilers included p articulate matter c ontrols (cyclone or multiclone, electrified filter bed [EFB]
, electrostatic precipitator [ ESP ] , fabric filter) and other controls with unknown (or unpredictable) effect on methane (dry sorbent in jection followed by an ESP or fabric filte r , spray dryer and fabric filter, and wet scrubbers).

The new CH 4 

### and N 2 

### O emissions test da ta provided in Technical Bulletin 998 and test data from other references are summarized in Table s 6A and 6B

. The data shown in these tables represent measurements from combustion of various woody biomass fuels in different types of boilers. P oor combustion condi tions were reported in three o f the boilers tested for CH 4 

### . Combustion conditions can vary from boiler to boiler

. For example, it has been documen t ed that poor combustion leads to higher CH 4 

### emissions, and fluidized bed combustors may operate within a range of combustion temperatures that favors formation of N 2 

### O

. 15
, 16 

### In addition, o ther

14 

### May 30, 2012 Boiler MACT Draft Emissions and Survey Results Databases. Available at: http://www.epa.gov/ttn/atw/boiler/boile rpg.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 diff ering 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 CH 4 

### emissions in ord er 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 dat a for fluidized bed boilers in the N 2 

### O data set in order to avoid underestimation of N 2 

### O 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

. Me thane Emissions Test Data from T echnical Bulletin 998 and Other References

Count Data Source Source ID Test Date APCD CH 4 , kg/MMB tu 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 CH 4 , kg/MMB tu 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 None 1 0.0011 FB

- bark 31 BFB2 pre

- 2001 None 1 0.0759 FB

- bark; poor combustion 32 BFB3 pre

- 2001 None 1 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

. N 2 

### O Emissions Test Data from T echnica l Bulletin 998 and Other Refere nces

Count Data Source Source ID Test Date APCD N 2 O, kg/MMB tu 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 None 1 0.0105 FB

- bark 7 BFB2 pre

- 2001 None 1 0.0021 FB

- b ark; ND

8 BFB3 pre

- 2001 None 1 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 up on the literature reviewed , Technical Bulletin 998 appears to be the most recent and comprehensive source of wood

- fired boiler CH 4 

### and N 2 

### O 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. Tab le 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. The refore, 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 CH 4 

### , kg/MMBtu N 2 

### O, kg/MMBtu GHGRP (based on IPCC 2006) 0.032 0.0042

Revised emission factors suggested by petitioners (TB 998) 0.0049 0.0019

Average o f all available data 0.0072 0.0036 Averag e of available data without Fortum 200 1 0.0055 0.0031

IV. Summary and Conclusions

RTI performed a literature review to document the basis for the existing GHGRP CH 4 

### and N 2 

### O emission factors in Subpart AA for spent pulping liquor and in Subpart C for solid biomass fuels (specifically wood and wood r esiduals). The purpose of the literature review was to locate additional emission testing results that could be compared to new information (NCASI T echnical Bulletin 998) supplied through a November 2012 petition for rulemaking. RTI found that few of the previously referenced sources of CH 4 

### and N 2 

### O 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 rob ust 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 w hether 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 CH 4 

### and N 2 

### O emission factors in Table AA

- 1 and C

- 2.

### Appendi x 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 CH 4 

### and N 2 

### O Emission Facto r Summary Table from the WRI/WB C S D Protocol
Appendix A2: Addi tional Excerpts from the WRI/WB C S D Protocol

Available at: http://www.wbcsd.org/web/projects/forestry/pulp

- and

- paper

- tool

- guidance.pdfF - 4 Version 1.1 July 8, 2005 

### Table 8. 

### Emission Factors for CH 4 

### and N 2 

### O from Biomass Combustion

Emission Factor Description kg CH 4 

### /TJ kg N 2 

### O/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 41 λ 

### 3.1 λ 

### 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 solidsVersion 1.1 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 Associ ation 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.orgVersion 1.1 July 8, 2005 

### CALCULATION TOOLS FOR ESTIMATI NG 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 Ai r 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 repor t. 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 th e United States Environmental Protection Agency (USEPA), the “Challenge Registry Guid e to Entity and Facility-Based Reporting” issued by the Voluntary Challenge and Registry (VCR), or other prot ocol 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 invent ories. A special effort has been made to ensure that the tools are consistent with gui dance issued by the Intergovernmental Panel on Climate Change (IPCC) and the WRI/WBCSD.

These tools estimate CO 2 

### 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 CO 2 

### emissions, and they should be reported separately from direct GHG emissi ons. Regardless of the reporting approach chosen, it is important to cl early separate estimates of CO 2 

### emissions from fossil fuel combustion from emissions of CO 2 

### 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. Me thods are presented for estimating the fossilCO 2 

### , methane, and nitrous oxide emissions from kraft mill lime kilns and calciners. Greenhouse gas emissions from landfills and wastew ater 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 case s, 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 emi ssions 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 em issions, are explicitly delineated in order to demonstrat e that at some facilities a por tion of the direct emissions are associated with energy streams that are expor ted to other end users. Emissions fromVersion 1.1 July 8, 2005 

### combined heat and power (CHP) plants are allocated using the WRI/WBCSD “efficiency method.”
The calculation tools allow compan ies to develop corporate inventories that include all direct emission sources from within the organi zational 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 indi rect emission sources that are be st 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 CO 2 

### emissions only (i.e., CH 4 

### and N 2 

### O 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 CO 2 

### emission factors. In certain situations, CH 4 

### and N 2 

### O emissions may be estimated adequately using facility-level activity data as well.
To aid in interpreting the resu lts of the inventory, these tool s 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 i ndirect 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 th e inventory results. The user is directed to the WRI/WBCSD GHG Prot ocol for guidance on how to determine ownership of emissions from partly-owned or partly-controlled sources.

An Excel ® 

### workbook is available to assist in perfo rming the calculations described in this report.Version 1.1 July 8, 2005 

### CONTENTS

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

2.0 FOREST PRODUCTS INDUSTRY GREENHOUSE GAS EMISSIONS IN PERSPECTIVE.................................................................................................................2

3.0 RELATIONSHIP OF THESE CA LCULATION 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 ORGANIZA TIONAL BOUNDARIES OF THE INVENTORY ...................................................................................................................9

6.0 IDENTIFYING PULP AND PAPER OPERATIONS TO BE INCLUDED WITHIN THE INVENTORY.........................................................................................10

7.0 MATERIALITY AND INSI GNIFICANT 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 Emissi ons from Burning Biomass Fuels ..................28Version 1.1 July 8, 2005 

### 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 La ndfills 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 ........................................................................................................................57Version 1.1 July 8, 2005 

### ANNEXES

A GREENHOUSE GAS EMISSIONS FROM KRAFT MILL LIME KILNS AND CALCINERS .................................................................................................................A1

B ALLOCATING GREENHOUSE GAS EMI SSIONS FROM COMBINED HEAT AND POWER (CHP) SYSTEMS: RECOMMENDED GUIDANCE AND REVIEW OF METHODS..............................................................................................B1

C GREENHOUSE GASES FROM VEHICU LAR 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 RE VISIONS TO VERSION 1.0 ..............................G1

H REFERENCES FOR ANNEXES A THROUGH G......................................................H1Version 1.1 July 8, 2005 

### TABLES
Table 1. Emission Factor Ranges Useful in Identifying Significant and Insignificant Sources of GHGs ...................................................................................................13

Table 2. IPCC Default CO 2 

### Emission Factors for Fossil Fuels ...........................................15

Table 3. Recommended Correction Factor s for Unoxidized Carbon from Various Guidance Documents.............................................................................................15

Table 4. IPCC Tier 1 CH 4 

### and N 2 

### O Emission Factors for Stationary Combustion.............18

Table 5. IPCC Tier 2 Uncontrolled CH 4 

### and N 2 

### O 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 CH 4 

### and N 2 

### O from Biomass Combustion ...........................29

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

Table 10. Recommended Default Values for k and L 0 

### for Estimating Landfill Methane Emissions ...............................................................................................................42
Table 11. Example of a Table to Report Op erational 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 Inventor y 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.............................................................538 Version 1.1 July 8, 2005 

### 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 ca lorific value (NCV) or lower heating value (LHV). The distinction between GCV and NCV arises from the diffe rent physical states (liquid or gaseous) water may be in followi ng combustion. The GCV includes the latent energy of condensation of water following co mbustion. The NCV is computed for product water in the gaseous state (i.e., not condensed). The latent ener gy of vaporization of water is deducted from the GCV. When a moist fuel is combusted, two s ources of product water exist–the moisture present in the fuel and th e 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):


### )]9( )[1( HM GCVM NCV dry solids wet 

### +

− −= λ (Eq. 1)

where: NCV = net calorific value at any moisture content GCV solids 

### = gross calorific value of dry fuel (zero moisture content) λ = latent heat of vaporization of water (2.31 MJ/kg at 25 ° 

### C) M wet 

### = moisture content of fuel on a wet basis (expressed as a fraction) M dry 

### = 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 (GCV solids 

### ):

H GCV NCV solids solids 

### λ 

### 9

− = (Eq. 2)

where: NCV solids 

### = 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 rela tionship between NCV and GCV for biomass fuel s, presumably because the moisture content of biomass fuels can vary extensively. However, in most instances the forest products i ndustry characterizes the energy content of biomass fuels (e.g., spent pul ping 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) (Browni ng 1975, Table VI, p. 74). A typical NCV solids 

### value for wood is 20 MJ/kg (IPCC 1997c). Therefore:
(0.06) water) MJ/kg 31.2(9 dry wood MJ/kg 20 × ×

− = = solids solids 

### GCV NCV

∴ 

### dry wood MJ/kg 25.21 (0.06) water) MJ/kg 31.2(9 dry wood MJ/kg 20

= × ×+ = solids 

### GCV (Eq. 3)Version 1.1 9 July 8, 2005 

### An approximate relationship between NCV solids 

### and GCV solids 

### can be developed using this result:

95.094.0 25.21

20 ≅== ∴

solids solids 

### GCV NCV (Eq. 4)

It is important to realize th at the relation above is only va lid when the energy content (in terms of both GCV and NCV) are expressed in te rms 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-relate d parameters are expressed in the units used by the authorities or countries that develope d the information. Except where noted, the Annexes use NCV (LHV).

5.0 DETERMINING THE ORGANIZA TIONAL BOUNDARIES OF THE INVENTORY


### Organizational boundaries define the compa ny for the purpose of accounting for GHG emissions. There are a large number of possi ble ownership arrangements, making it difficult to provide specific instructions on how to derive organizational boundaries. Perhaps the most thorough discussion of me thods for determining organiza tional boundaries is contained in the WRI/WBCSD GHG Prot ocol (WRI 2004a). Companies whose organizational boundaries include partially-owned or partially-c ontrolled sources will want to obtain that document. The approach outlined in the GHG Protocol is summarized herein.
Where the allocation of GHGs is specified contra ctually, that allocati on is to be used. Otherwise the WRI/WBCSD GHG Pr otocol suggests that allocation be done in one of two ways: according to control or according to equi ty 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 boundari es of the company have be en determined, operational boundaries then categorize direct and indirect emissions, usin g 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 cor porate level, as they are from operations or companies jointly owned or controlled. In ot her cases (e.g., outsourced operations that are28 Version 1.1 July 8, 2005 

### Non-condensable gases (NCGs) consist of reduced sulfur compounds and other organic compounds that are formed during the kraft pulpi ng process. These gases are often collected and burned in boilers, lime kilns, or incinera tors as a pollution abatement procedure. Because the carbon in NCGs originated in wood, the CO 2 

### generated during combustion of NCGs is of biomass origin and is, therefor e, not included in a ta bulation of direct GHG emissions. The quantities of NCGs combusted at kraft mills are very low relative to quantities of spent pulping liquors and other wo od residuals fuels. There are no data on methane or nitrous oxide genera tion from combustion of NCGs.
11.2 Methane and Nitrous Oxide Emissions from Burning Biomass Fuels


### Although CO 2 

### from biomass burning is almost univers ally excluded from GHG inventories, CH 4 

### and N 2 

### O from biomass burning are sometimes included because these gases do not participate in the atmospheric CO 2 

### 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-spe cific data allowing it to estimate CH 4 

### and N 2 

### O emissions from biomass combustion, it should use those data . Otherwise, it will be necessary to use the most appropriate emission factors availabl e. Unfortunately, there are few data on CH 4 

### and N 2 

### O emissions from biomass combustion.
IPCC’s Revised 1996 Inventory Guidelines used em ission factors developed by EPA. This is also true for a number of countries. EPA has si nce 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 ma ny individual country factors that are based on IPCC or EPA factors are not shown. The vari ability 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 gene rated 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 fluidi zed bed boilers may want to use the Fortum emission factors because they were develope d on fluidized bed boile rs while the other emission factors were developed on stoker boilers or on boilers of an unspecified design. In many cases, however, because of th e ranges in emission factors and the limited ability at this time to match emission factors to boiler de signs, 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 ci ted 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.Version 1.1 29 July 8, 2005 

### Table 8. 

### Emission Factors for CH 4 

### and N 2 

### O from Biomass Combustion

Emission Factor Description kg CH 4 

### /TJ kg N 2 

### O/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 41 λ 

### 3.1 λ 

### 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 num ber 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. Becau se 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 imp act 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 conditi ons in the combination fuel-fired boiler are more like fossil fuel-fired boilers than wood re sidual fuel boilers, it is recommended that the30 Version 1.1 July 8, 2005 

### emissions from combination fuel-fired boilers be estimated from the total heat input to the boiler and CH 4 

### and N 2 

### O emission factors for biomass.
In some cases, a facility may operate a combin ation fuel boiler where fossil fuel comprises a major portion of the total fuel to the boiler. Although estimating CH 4 

### and N 2 

### O emissions using the approach outlined in the previous paragr aph 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 consum ption 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 boile r burns approximately 6.9 x 10 6 

### GJ of bark and 0.8 x 10 6 

### GJ of residual fuel oil. Because th e boiler receives supplemental fo ssil fuel, it is necessary to estimate the CO 2 

### from the fossil fuel use and the CH 4 

### and N 2 

### O emissions based on the total firing rate. The mill decides to use the IP CC emission factor for residual oil (76.6 t CO 2 

### /TJ, after correcting for 1% unoxidi zed carbon) and to estimate CH 4 

### and N 2 

### O emissions based on the total firing rate and the emission factor s developed by Fortum on CFB boilers. The average emission factors found by Fort um, shown in Table 8, are 1 kg

CH 4 

### /TJ and 8.8 kg N 2 

### O/TJ.

CO 2 

### emissions from fossil fuel:

• 

### (0.8 x 10 6 

### GJ/y) = (0.8 x 10 3 

### TJ/y)

• 

### (0.8 x 10 3 

### TJ/y) x (76.6 t CO 2 

### /TJ) = 61,300 t CO 2 

### /y

CH 4 

### emissions:

• 

### total heat input = (6.9 x 10 6 

### GJ/y) + (0.8 x 10 6 

### GJ/y) = 7.7 x 10 6 

### GJ/y = 7.7 x 10 3 

### TJ/y 7.7 x 10 3 

### TJ/y x 1 kg CH 4 

### /TJ = 7,700 kg CH 4 

### /y = 7.7 t CH 4 

### /y
Using the IPCC warming potential of 21, this equates to 162 t CO 2 

### -eq./y.

N 2 

### O emissions:

• 

### total heat input = 7.7 x 10 3 

### TJ/y

• 

### 7.7 x 10 3 

### TJ/y x 8.8 kg N 2 

### O/TJ = 67,800 kg N 2 

### O/y = 67.8 t N 2 

### O/y Using the IPCC warming potential of 310, this equates to 21,000 t CO 2 

### -eq./y

Total CO 2 

### equivalents emitted = 61,300 + 162 + 21,000 = 82,500 t CO 2 

### -equivalents/y

12.0 EMISSIONS ATTRIBUTABLE TO IMPORTS AND EXPORTS OF ELECTRICITY AND STEAM


### The consumption of power or steam (or hot wa ter) purchased from another company usually results in the generation of i ndirect emissions–i.e., “emissions that are a consequence of activities of the reporting comp any, but occur from sources ow ned or controlled by another company” (WRI 2004a). Of course, virtually ev ery raw material, energy source, and service used by a company has an indirect emissi ons impact. Many GHG accounting protocols,Version 1.1 57 July 8, 2005 

### REFERENCES


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Apps, M.J., Kurz, W.A., Beukema, S.J., and Bhatti, J.S. 1999. Carbon budget of the Canadian forest product sector. 25-41 in Environmental Science and Policy No. 2. Elsevier Science Ltd.
Birdsey, R.A. 1996. Chapter 1 – Carbon storag e for major forest types and regions in the conterminous United States. Forests and global change – Vol. 2: Forest management opportunities for mitigating carbon emissions . Sampson, N., and Hair, D. (eds.). Washington, DC: American Forests.
Browning, B.L. (ed.). 1975. The chemistry of wood . New York: Robert E. Krieger Publishing Company.

Environment Canada. 2004. Canada’s greenhouse gas inventory 1990-2002 . Ottawa: Environment Canada. http://www.ec.gc. ca/pdb/ghg/inventories_e.cfm (30 October 2004).
European Environment Agency (EEA). 2004. EMEP/CORINAIR Emission inventory guidebook - Third editio n, September 2004 Update . Copenhagen: European Environment Agency. http://reports.eea.eu.int/E MEPCORINAIR4/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/publ ic/gl/invs4.htm (30 October 2004).
Intergovernmental Panel on Climate Change (IPCC). 1997b. Revised 1996 IPCC guidelines for national greenhouse gas inven tories: Workbook (Vol. 2) . IPCC National Greenhouse Gas Inventory Program. http://www.ipcc-ngg ip.iges.or.jp/public/gl/invs5.htm (30 October 2004).
Intergovernmental Panel on Climate Change (IPCC). 1997c. Revised 1996 IPCC guidelines for national greenhouse gas inventori es: Reference manual (Vol. 3) . IPCC National58 Version 1.1 July 8, 2005 

### Greenhouse Gas Inventory Program. http://www.ipcc-nggip.iges.or.jp/publ ic/gl/invs6.htm (30 October 2004).
Intergovernmental Panel on Climate Change (IPCC). 2000a. Good practice guidance and uncertainty management in na tional greenhouse gas inventories . IPCC National Greenhouse Gas Inventory Program . http://www.ipcc-nggip.iges. or.jp/public/gp/english/ (30 October 2004).
Intergovernmental Panel on Climate Change (IPCC). 2000b. IPCC special report on land use, land-use change, and forestry . Cambridge University Press. 375 pp. http://www.grida.no/climate/ip cc/land_use/ (30 October 2004).
Intergovernmental Panel on Climate Change (IPCC). 2001. Third assessment report (TAR), climate change 2001: The scientific basis . Working Group 1 Report, Technical Summary. IPCC National Greenhou se Gas Inventory Program. http://www.ipcc.ch/activity/tar.htm (30 October 2004).
Intergovernmental Panel on Climate Change (IPCC). 2003. Good practice guidance for land use, land use change and forestry . IPCC National Greenhouse Gas Inventory Program. http://www.ipcc-nggip.iges.or.jp/ public/gpglulucf/gpgluluc f.htm (30 October 2004).
Japan Paper Association (JPA). 2002. Various personal communications between JPA and Reid Miner of NCASI . Tokyo: Japan Paper Association.
Kitana, O., and Hall, C.W. (eds.). 1989. Biomass handbook . New York: Gordon and Breach Science Publishers.
Lewandowski, D.A. 2000. Design of thermal oxidation systems for volatile organic compounds . p. 27. Boca Raton, FL: CRC Press.
Loreti, C.P., Foster, S.A., and Obbagy, F.E. 2001. An overview of greenhouse gas emissions verification issues . Cambridge, MA: A.D. Little. http://www.pewclimate.org/globalwarming-in-depth/all_reports/emissions_ve rification_issues/index.cfm (30 October 2004).
Loreti, C.P., Wescott, W.F., and Isenberg, M.A. 2000. An overview of greenhouse gas emissions inventory issues . Cambridge, MA: A.D. Little. http://www.pewclimate.org/docUploads/ greenhouse%2Epdf (30 October 2004).
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National Council for Air and Stream Improvement, Inc. (NCASI). 1980. A study of woodresidue fired power boiler to tal gaseous non-methane organic emissions in the PacificVersion 1.1 59 July 8, 2005 

### Northwest . Air Quality Technical Bulletin No .109. Research Triangle Park, NC: National Council for Air and Stream Improvement, Inc.
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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.
National Council for Air and Stream Improvement, Inc. (NCASI). 1999. Evaluation of the EPA-recommended approach to predicting air emissions from pulp and paper landfills

. Technical Bulletin No.790. Research Triangle Park, NC: Nationa l Council for Air and Stream Improvement, Inc.
National Council for Air and Stream Improvement, Inc. (NCASI). 2004. Calculation tools for estimating greenhouse gas emissions fr om wood products manufacturing facilities

. Research Triangle Park, NC: National Council for Air and Stream Improvement, Inc. http://www.ncasi.org/support/downloa ds/default.aspx (30 October 2004)
Skog, K.E., and Nicholson, G.A. 1998. Ca rbon cycling through wood products: The role of wood and paper products in carbon sequestration. Forest Products Journal 48(7/8).
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. Washington, DC: United States Department of Energy. http://www.eia.doe.gov/pub/oiaf/1605/cdrom/ pdf/gg-app-tables.pdf (30 October 2004)
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### United States Environmental Protec tion Agency (USEPA). 1998a. AP-42 emission factors for natural gas combustion – Supplement D, July 1998 . Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/ttn/chief/ap42/ch01/ final/c01s04.pdf (30 October 2004).
United States Environmental Protection Agency (USEPA). 1998b. AP-42 emission factors for bituminous and subbituminous coal combustion – Supplement E, September 1998

. Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/ttn/chief/ap42/ch01/ final/c01s01.pdf (30 October 2004).

United States Environmental Protec tion Agency (USEPA). 1998c. AP-42 emission factors for fuel oil combustion – Supplement E, September 1998 . Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/ttn/chief/ap42/ch01/ final/c01s03.pdf (30 October 2004).
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. Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/climateleaders/ protocol.html (30 October 2004).
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### World Resources Institute (WRI) and World Bu siness Council for Sustainable Development (WBCSD). 2004b. Calculating CO 2 

### emissions from the combustion of standard fuels and from electricity/steam purchase - Guide to calculation worksheets (February 2004) v2.0

. Washington, DC: World Resources Institute. http://www.ghgprotocol.org/standard /tools.htm (11 September 2004).
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### emissions from the com bustion of standard fuels and from electricity/steam purchase - Calc ulation worksheets (February 2004) v2.0

. Washington, DC: World Resources Institute. http://www.ghgprotocol.org/standard /tools.htm (11 September 2004).
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### emissions from mobile sources - Guide to calculation worksheets version 1.1 . Washington, DC: World Resources Institute. http://www.ghgprotocol.org/standard /tools.htm (30 October 2004).Version 1.1 F - 1 July 8, 2005 

### ANNEX F

TABLES OF GREENHOUSE GAS EMISSION FACTORS


### These tables are copied from the main body of th is report. Table numbers are consistent with numbering in the main text.

Table 2. 

### IPCC Default CO 2 

### Emission Factors for Fossil Fuels (after IPCC 1997b)
Fossil Fuel Uncorrected Emission Factor kg CO 2 

### /TJ* Corrected Emission Factor kg CO 2 

### /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 car bon. 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 Fact ors 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 (USE PA 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 2004F - 2 Version 1.1 July 8, 2005 

### Table 4 

### . IPCC Tier 1 CH 4 

### and N 2 

### O Emission Factors for Stationary Combustion (from IPCC 1997c)
CH 4 

### Emission Factors kg/TJ N 2 

### O 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 CH 4 

### and N 2 

### O Emission Factors for Industrial Boilers (IPCC 1997c) Fuel Technology Configuration kg CH 4 

### /TJ kg N 2 

### O/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 be d 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.F - 4 Version 1.1 July 8, 2005 

### Table 8. 

### Emission Factors for CH 4 

### and N 2 

### O from Biomass Combustion

Emission Factor Description kg CH 4 

### /TJ kg N 2 

### O/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 41 λ 

### 3.1 λ 

### 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 solidsVersion 1.1 H - 1 July 8, 2005 

### ANNEX H

REFERENCES FOR ANN EXES A THROUGH G



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

. Australian Greenhouse Offi ce, Canberra, Australia. http://www.greenhouse.gov.au/challenge/to ols/index.html (27 October 2004).
AEA Technology. 2001. UK greenhouse gas inventory 1990-1999: Annual report for submission under the Framewor k 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 editio n, September 2004 Update . Copenhagen: European Environment Agency. http://reports.eea.eu.int/E MEPCORINAIR4/en (27 October 2004).
Finland Ministry of th e 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: Fort um 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. http://www.gp.com/enviro/strategy/ protocol.pdf (30 October 2004).
Hough, G. 1985. Chemical recovery in the alkaline pulping processes . Atlanta, GA: TAPPI 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/publ ic/gl/invs4.htm (30 October 2004).
Intergovernmental Panel on Climate Change (IPCC). 1997b. Revised 1996 IPCC guidelines for national greenhouse gas inven tories: Workbook (Vol. 2) . IPCC National Greenhouse Gas Inventory Program. http://www.ipcc-ngg ip.iges.or.jp/public/gl/invs5.htm (30 October 2004).
Intergovernmental Panel on Climate Change (IPCC). 1997c. Revised 1996 IPCC guidelines for national greenhouse gas inventori es: Reference manual (Vol. 3) . IPCC NationalH - 2 Version 1.1 July 8, 2005 

### Greenhouse Gas Inventory Program. http://www.ipcc-nggip.iges.or.jp/publ ic/gl/invs6.htm (30 October 2004).
Intergovernmental Panel on Climate Change (IPCC). 2000. Good practice guidance and uncertainty management in na tional greenhouse gas inventories . IPCC National Greenhouse Gas Inventory Program . http://www.ipcc-nggip.iges. or.jp/public/gp/english/ (30 October 2004).
Japan Paper Association (JPA). 2001. Various personal communications between Masao Taniguchi of JPA and Reid Miner of NCASI . Tokyo: Japan Paper Association.
Japan Paper Association (JPA). 2002. Various personal communications between JPA and Reid Miner of NCASI . Tokyo: Japan Paper Association.
Miner, R., and Upton, B. 2002. Methods for estimating greenhouse gas emissions from lime kilns at kraft pulp mills. Energy 27(8):729-738.
National Council for Air and Stream Improvement, Inc. (NCASI). 1980. A study of woodresidue fired power boiler to tal 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.
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.
National Council for Air and Stream Improvement, Inc. (NCASI). 1999. Evaluation of the EPA-recommended approach to predicting air emissions from pulp and paper landfills

. Technical Bulletin No. 790. Research Tr iangle Park, NC: Nationa l Council for Air and Stream Improvement, Inc.
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. http://www.internat.naturvardsverket.se/docum ents/pollutants/climat e/climate/fcccdata/N IR.pdf (27 October 2004).

Technical Research Center of Finland. 2001. Greenhouse gas emissions and removals in Finland . Espoo: Technical Research Center of Finland. http://www.vtt.fi/inf/pdf/tiedott eet/2001/T2094.pdf (28 October 2004).
United States Department of Energy (USDOE). 1994. Voluntary Reporting of Greenhouse Gases Program – General guidelines and supporting documents establishing the Voluntary Reporting of Greenhouse Ga ses Program, Appendix B, Table B1

. Washington, DC: United States Department of Energy. http://www.eia.doe.gov/pub/oiaf/1605/cdrom/ pdf/gg-app-tables.pdf (30 October 2004)Version 1.1 H - 3 July 8, 2005 

### United States Environmental Protection Agency (USEPA). 1993. Anthropogenic methane emissions in the United States: Es timates for 1990, Report to Congress . EPA 430-R-93- 003. Washington, DC: United States Environmental Protection Agency.
United States Environmental Protection Agency (USEPA). 1996. AP-42 emission factors for anthracite coal combustion – Supplement B, October 1996 . Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/ttn/chief/ap42/ch01/ final/c01s02.pdf (30 October 2004).

United States Environmental Protec tion Agency (USEPA). 1998a. AP-42 emission factors for natural gas combustion – Supplement D, July 1998 . Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/ttn/chief/ap42/ch01/ final/c01s04.pdf (30 October 2004).
United States Environmental Protection Agency (USEPA). 1998b. AP-42 emission factors for bituminous and subbituminous coal combustion – Supplement E, September 1998

. Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/ttn/chief/ap42/ch01/ final/c01s01.pdf (30 October 2004).

United States Environmental Protec tion Agency (USEPA). 1998c. AP-42 emission factors for fuel oil combustion – Supplement E, September 1998 . Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/ttn/chief/ap42/ch01/ final/c01s03.pdf (30 October 2004).
United States Environmental Protection Agency (USEPA). 1998d. AP-42 emission factors for municipal solid waste landf ills – Supplement E, November 1998 . Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/ttn/chief/ap42/ch02/ final/c02s04.pdf (30 October 2004).

United States Environmental Protec tion Agency (USEPA). 2001a. Inventory of U.S. greenhouse gas emissions and sinks: 1990-1999 . EPA 236-R-01-001. Washington, DC: United States Environmental Protection Agency. http://yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHG EmissionsUSEmissionsInventory2004.html (30 October 2004).
United States Environmental Protection Agency (USEPA). 2001b. AP-42 emission factors for wood residue combustion in boilers – Supplement G, July 2001 . Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/ttn/chief/ap42/ch01/ final/c01s06.pdf (30 October 2004).
United States Environmental Protection Agency (USEPA). 2003. Climate leaders greenhouse gas inventory protocol co re module guidance – Draft June 2003

. Washington, DC: United States Environmental Protection Agency. http://www.epa.gov/climateleaders/ protocol.html (30 October 2004).
United States Environmental Protection Agency (USEPA). 2004. Inventory of U.S. greenhouse gas emissions and sinks: 1990-2002 . EPA 430-R-04-003. Washington, DC: United States Environmental Protection Agency.H - 4 Version 1.1 July 8, 2005 

### http://yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHG EmissionsUSEmissionsInventory2004.html (27 October 2004).
Voluntary Challenge and Registry (VCR). 2004. Canadian GHG Challenge Registry, Guide to Entity & Facility-Based Reporting – Canada’s Climate Change Voluntary Challenge & Registry Inc., Version 3.0 July 2004 . Ottawa: Canada’s Climate Change Voluntary Challenge and Registry Inc. http://cha llenge.vcr-mvr.ca/index_e.cfm (27 Oct 2004).
World Resources Institute (WRI) and World Bu siness Council for Sustainable Development (WBCSD). 2001. The Greenhouse Gas Protocol: A corporate accounting and reporting standard . Washington, DC: World Resources Institute. http://www.ghgprotocol.org/standa rd/ghg.pdf (30 October 2004).
World Resources Institute (WRI) and World Bu siness Council for Sustainable Development (WBCSD). 2004a. The greenhouse gas protocol: A corporate accounting and reporting standard, Revised edition . Washington, DC: World Resources Institute. http://www.ghgprotocol.org/standa rd/index.htm (30 October 2004).
World Resources Institute (WRI) and World Bu siness Council for Sustainable Development (WBCSD). 2004b. Calculating CO 2 

### emissions from the combustion of standard fuels and from electricity/steam purchase - Guide to calculation worksheets (February 2004) v2.0

. Washington, DC: World Resources Institute. http://www.ghgprotocol.org/standard /tools.htm (11 September 2004).
World Resources Institute (WRI) and World Bu siness Council for Sustainable Development (WBCSD). 2004c. Calculating CO 2 

### emissions from the com bustion of standard fuels and from electricity/steam purchase - Calc ulation worksheets (February 2004) v2.0

. Washington, DC: World Resources Institute. http://www.ghgprotocol.org/standard /tools.htm (11 September 2004).
World Resources Institute (WRI) and World Bu siness Council for Sustainable Development (WBCSD). 2004d. Calculating CO 2 

### emissions from mobile sources - Guide to calculation worksheets version 1.1 . Washington, DC: World Resources Institute. http://www.ghgprotocol.org/standard /tools.htm (30 October 2004).

### Appendix B

Emission Factor Tables from Swedish EPA 2004

Available at: http://s3.amazonaws.com/zanran_storage/www.lansstyrelsen.se/ContentPages/70817864.pdfCH4stationary combustionPower plants, districtheating and industryResident and otherconsumption01, 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 LtdFuel typekg CH4/GJ by area of consumptionKod BränsleslagAppendix 16 Emission factors and thermal values Energy.xls stat CH4 2004-03-25N2Ostationary combustionkod BränsleslagFuel typekg N2O/GJ01, 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 LtdAppendix 16 Emission factors and thermal values Energy.xls stat N2O 2004-03-25

### 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.ipcc

nggip.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.htmlChapter 2: Stationary Combustion

2006 IPCC Guidelines for National Greenhouse Gas Inventories 2.19 T ABLE 2.3 ( CONTINUED ) D EFAULT EMISSION FACTORS FOR STATIONARY COMBUSTION IN MANUFACTURING INDUSTRIES AND CONSTRUCTION (kg of greenhouse gas per TJ on a Net Calorific Basis)

CO 2 CH 4 N 2 O

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 n 143 000 110 000 183 000 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 15Solid 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 2LiquidBiofuels

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 0.3GasBiomass

Other Biogas n 54 600 46 200 66 000 r 1 0.3 3 0.1 0.03 0.3Othernon-fossilfuels Municipal Wastes (biomass fraction) n 100 000 84 700 117 000 30 10 100 4 1.5 15

(a) Includes the biomass-derived CO 2 emitted from the black liquor combus tion unit and the biomass-derived CO 2 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 GuidelinesRevised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual 

## C HAPTER 

# 1 

# E NERGY

## 1 E NERGY

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

CO 2 emissions from the combustion of biomass fuels are not to be included in the total national CO 2 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 CO 2 emissions from them with the emissions of the non-CO 2 gases. Whatever methods are used for estimating the quantities of fuels used by these two types when calculating the non-CO 2 emissions from this sector should be used for CO 2 . 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 CH 4 from biomass combustion. Fuel wood, charcoal, agricultural residues, agricultural waste and municipal waste combustion is by far the major contributor to CH 4 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

## E NERGY

1.34 Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual from Energy. Consequently, CH 4 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 CH 4 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 CH 4 . The general method for estimating CH 4 can be described as:

Emissions = ∑ (EF ab x Activity ab )

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.

## 1 E NERGY

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

### 1.35 T ABLE 1-7 CH 4 D EFAULT (U NCONTROLLED ) E MISSION F ACTORS ( 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-CO 2 Emission Factors for Charcoal Production. (c) Includes dung and agricultural, municipal and industrial wastes. (d) In the cruise mode CH 4 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 N 2 O 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 N 2 O emissions with a maximum of N 2 O production occurring around 1000 K. For combustion temperatures below 800 K or over 1200 K the emissions of N 2 O 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 N 2 O chemistry see de Soete (1993). The mechanisms of N 2 O chemistry seem to be relatively well understood, but experimental data are limited.

N 2 O 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.

## E NERGY

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 N 2 O can be described as:

Emissions = ∑ (EF ab x Activity ab )

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.

T ABLE 1- 8 N 2 O D EFAULT (U NCONTROLLED ) E MISSION F ACTORS ( 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 N 2 O than bituminous coals; some measurements have shown that N 2 O emissions by hard coal combustion in power plants may be negligible. N 2 O 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-CO 2 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. E mission factors for 2- stroke engines may be three times higher than those for 4-stroke engines.

## 1 E NERGY

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 CO 2 It follows from the arguments given above for the construction of detailed emission estimates that a country will also benefit from the estimation of CO 2 emissions in parallel with the calculation of non-CO 2 inventories despite the existence of Tier 1 methods for CO 2 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 CO 2 . In cases where CO 2 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 CO 2 emission factors are given in this Chapter they include all carbon based molecule emissions from the process. This ensures that CO 2 totals constructed by summing the results of the detailed estimation of emissions (the “bottom-up” approach)

## E NERGY

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 CO 2 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-CO 2 GHGs (particularly the indirect gases) and SO 2 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)

## 1 E NERGY

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 NO x , N 2 O, CO, CH 4 , SO 2 and NMVOCs from stationary combustion plant. Estimation of CO 2 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-CO 2 emissions from combustion of biomass are estimated in exactly the same manner as fossil fuel combustion emissions. 14

. Emissions of non-CO 2 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 NO xemissions 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 N 2 O and CH 4 . 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 CO 2 emissions from biomass combustion.

## E NERGY

1.50 Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual A section on SO 2 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 = ∑ (EF abc x Activity abc )

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-CO 2 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-CO 2 gases can be provided.

Emission Factor Data
Emission factors for all non-CO 2 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 NO x , 17 CO, CH 4 , N 2 O 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 NO x emissions from fossil fuel combustion are expressed on a full molecular basis assuming that all NO x emissions are emitted as NO 2 .

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1.54 Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual T ABLE 1-16 I NDUSTRIAL B OILER P ERFORMANCE Emission Factors (kg/TJ energy input) Basic Technology Configuration CO CH 4 NO x N 2 O 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 T ABLE 1-17 K ILNS , O VENS , AND D RYERS S OURCE P ERFORMANCE Emission Factors (kg/TJ energy input) (a)
Industry Source CO CH 4 NO x N 2 O 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 

## 1.10 References
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### 1.139 GOB (Government of Bangladesh) (1987), Bangladesh Energy Planning Project (BEPP), Final Report, Vol. I-VII, Sir Halcrow and Partners, Motor Columbus Consulting Engineering Inc., Petronus Consultants SA in association with TSL and PSL. Grubb, M.J. (1989), On Coefficients for Determining Greenhouse Gas Emissions From Fossil Fuel Production and Consumption. Energy and Environmental Programme, Royal Institute of International Affairs, London, UK, April. Prepared for IEA/OECD Expert Seminar on Energy Technologies for Reducing Emissions of Greenhouse Gases
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## 1 E NERGY

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

### 1.143 Seiler, W. (1984), "Contribution of biological processes to the global budget of CH 4 in the atmosphere." In: Current Perspectives in Microbial Ecology , American Society for Microbiology, Washington, DC, USA. Seltzer, H. and W. Zittel (1990), Emissions of Methane Gas Affecting the Climate: An Investigation of Global Methane Emissions from the Use of Fossil Fuels, Waste Incineration, Agriculture, and the Earth , LBST-Report No. 10/90, Ottobrunn, Germany. Smith, I.M. and L.L. Sloss (1992), Methane Emissions from Coal: IEA Perspectives . IEAPER/04, London, UK, November 1992. Smith, K.R. and J. Ramakrishna (1990), Biomass Fuels and Health , in: Lamptey et al. (1990), Bioenergy , Wiley Eastern Ltd, IDRC, Ottawa, Canada. Smith, K.R., M.A.K. Khalil, R.A. Rasmussen, S.A. Thornloe, F. Manegdeg and M. Apte (1993), Greenhouse Gas Emissions from Biomass and Fossil Fuel Stoves in Developing Countries: a Manila pilot study , Chemosphere 26:1-4, pp. 479-505. Southern California Gas Company (SOCAL) (1992), Unaccounted for Gas Project Summary Volume SOCAL Research & Development, Los Angeles, CA, USA. Statens forurensningstilsyn (1990), Klimagass Regnskap for Norge . Oslo, Norway. Stockton, M.B. and J. Stelling (1987), Criteria Pollutant Emission Factors for the 1985 NAPAP Emissions Inventory . EPA-600/7-87-015. Office of Research and Development, US EPA, Washington, DC, USA. Summers, G. (1993), Personal communication on behalf of the Coal Industry Advisory Board, Global Climate Committee, 22nd July.
Susuki, M., M. Nakazawa, T. Hidaka and M. Kaneko (1992): “Study on N 2 O emission from motor vehicles” . Proc. of the 33 rd Annual meeting of the Japan Society of Air Pollution
, 347, Osaka, Japan, 1992. TNO (1993), Proceedings of the TNO/EUROSAP Workshop , Delft, June 1993. TNO, Institute of Environmental Sciences, Petten, The Netherlands. UK Offshore Operators Association Ltd (1993), Methane Emissions From Offshore Oil & Gas Exploration & Production Activities . Submitted to The Watt Committee on Energy. UN (1996), 1994 Energy Statistics Yearbook . United Nations, New York, USA. UN ECE (1989), Annual Bulletin of Transport Statistics for Europe: Volume XXXIX . United Nations, New York, USA. US CSP (1996), Greenhouse Gas Emission Inventories. Interim results from the US Country Studies Program . Environmental Science and Technology Library 9. Kluwer Acad. Publishers, UK. US DOE/EIA (1992), Analysis of the Relationship Between the Heat and Carbon Content of US Coals . Energy Information Administration, Department of Energy, USA, September. US EPA (1985a), “Compilation of Air Pollutant Emission Factors ”, Vol. I, Stationary Point and Area Sources, AP-42, 4 th Edition 1985; Suppl. A/1986, Suppl. B/1988, Suppl. C/1990. Environmental Protection Agency, USA. US EPA (1985b), “Compilation of Air Pollutant Emission Factors” : Highway Mobile Sources . AP-42, Fourth Edition, Ann Arbor, Michigan, USA.

## E NERGY

1.144 Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual US EPA (1992), Procedures for Emission Inventory Preparation , Vol. IV: Mobile Sources, EPA-450/4-81-026d. US EPA (1993a). Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to the US Congress , US Environmental Protection Agency, Office of Air and Radiation, Washington, DC, USA. US EPA (1993b), “Compilation of Air Pollutant Emission Factors” , Vol. I, Stationary Point and Area sources, AP-42, Supplement F. US Environmental Protection Agency, USA. US EPA (1993c), Global Anthropogenic Methane Emissions: Estimates for 1990, Report to the US Congress , , US Environmental Protection Agency, Office of Policy, Planning and EvaluationWashington, DC, USA. US EPA (1994a), User's Guide to Mobile5 (Mobile Source Emission Factor Model , EPA-AAAQAB-94-01, US Environmental Protection Agency, Office of Mobile Sources, , Ann Arbor, MI, USA. US EPA (1994b), International Anthropogenic Methane Emissions, Estimates for 1990 (Report to Congress). EPA 230-R-93-010, , US Environmental Protection Agency, Office of Policy Planning and EvaluationWashington, DC, USA. US EPA (1995), Compilation of Air Pollutant Emission Factors . Vol. I: Stationary Point and Area Sources, 5th Edition, AP-42; US Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, USA. US GS (1993), personal communication. US Office of Environment and Energy (1991), FAA Aircraft Emission Database User’s Manual. Veldt, C. (1991), Development of EMEP and CORINAIR Emission Factors and Species Profiles for emissions of Organic C ompounds. IMET-TNO Report 91-299. Veldt, C. and J.J.M. Berdowski (1995), GEIA-note on the combustion of biomass fuels (Emission factors for CO, CH 4 and NMVOC), TNO-MW-R94/218, Delft, the Netherlands. Vernon, J.L. (1990), “Coal and Environmental Quality Throughout the 1990s and Sulphur Emissions Worldwide”, Energy Business Review , 1(2), pp. 35-60 (Oct-Dec 1990). Venon, J.L. and T. Jones (1993), Sulphur and Coal , IEA Coal Research, IEACR/57, London, UK. Weaver, C.S. (1988), Feasibility and Cost-Effectiveness of Controlling Emissions from Diesel Engines Used in Rail, Marine, Construction, Farm, and Other Mobile Off-Highway Equipment . Report under EPA Contract No. 68-01-7288, Radian Corporation, Sacramento, CA, USA. Wiesen, P., J. Kleffmann, R. Kortenbach and K.H. Becker (1994 ), Nitrous Oxide and Methane Emissions from Aero Engines , Geophys. Res. Lett. 21:18 2027-2030. Williams, A. and C. Mitchell (1992), Methane Emissions from Coal Mining , Department of Fuel and Energy, The University of Leeds, Leeds, UK. Wuebbles, D.J., S.L. Baughcum, M. Metwally and R.K. Seals Jr. (1993) Emissions Scenario Development , Emissions scenarios committee report in: Stolarski, R.S. and H.L. Wesoky (1993), The Atmospheric Effects of Stratospheric Aircraft : a third program report. NASA, Reference Publication RP-1313

.

## 1 E NERGY

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

### 1.145 Zeedijk, H. (1986), “Emissions by Combustion of Solid Fuels in Domestic Stoves”. Proc. 7 th World Clean Air Congress , Sydney, Australia, H.F. Hartmann (ed.)., Vol. IV, pp. 78-85. Zimmermeyer, G. (1989), Methane Emissions and Hard Coal Mining , Glückaufhaus, Essen, Germany, Gesamtverband des deutschen Steinkohlenbergbaus, personal communication.

### Appendix D

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 Copyright 2001 Fortum k:\t&k\y-pooli\non-co2-raportti.doc Distribution Checked by, Date

Approved by, Date

Replaces

Keywords



### METHANE AND NITROUS OXIDE EMISSIONS IN THE FINNISH ENERGY PRODUCTION

### Report 2 (36)

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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 N 2 

### O 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 N 2 

### O 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 N 2 

### O 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 N 2 

### O emission level was under the confidence limit.
The N 2 

### O 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 N 2 

### O 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 N 2 

### O 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 N 2 

### O and CH 4 

### emissions from different combustion techniques were compared to national and IPCC's emission factors. The biggest difference between the measured N 2 

### O emission and the national factor was in BFB boilers. Also the factors for CFB boilers seemed to be too high. The CH 4 

### emission factors for CFB and BFB boilers seemed equally to be too high.

### Report 3 (36)

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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

### Report 4 (36)

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Fortum Power and Heat Oy, Technology Copyright 2001 Fortum k:\t&k\y-pooli\non-co2-raportti.doc 

### 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 G ENERAL ...............................................................................................................................................................8 4.2 N 2 O EMISSIONS FROM FLUIDISED BED BOILERS ...................................................................................................10 4.3 N 2 O EMISSION FROM SNCR AND SCR................................................................................................................13 4.4 N 2 O MEASUREMENT TECHNIQUES .......................................................................................................................13

5 MEASUREMENTS.................................................................................................................. .............................16
5.1 S COPE

............................................................................................................................... ...................................16 5.2 P ROCESSES AND CONDITIONS ..............................................................................................................................1 6 5.3 M EASUREMENT METHODS ( QUALITY CONTROL )................................................................................................18 5.4 R ESULT OF MEASUREMENTS

............................................................................................................................... .22 5.5 E VALUATION

............................................................................................................................... ........................28

6 DISCUSSION.................................................................................................................... .....................................29

REFERENCES..................................................................................................................... ...........................................30

APPENDIX 1: N 2 O AND CH 4 EMISSION FACTORS...............................................................................................33

APPENDIX 2: N 2 O AND CH 4 EMISSION FACTORS ACCORDING IPCC ..........................................................36

### Report 5 (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 (CO 2 

### ), methane (CH 4 

### ), nitrous oxide (N 2 

### O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulphur hexafluoride (SF 6 

### ). The emissions of the last three gases are negligible in the Finnish energy sector. The most important anthropogenic greenhouse gas is CO 2 

### . In 1998, the total CO 2 

### 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 CH 4 

### and N 2 

### O emissions is considerably lower than the CO 2 

### 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 CO 2 

### equivalents, the Finnish emissions of CH 4 

### and N 2 

### O were 4.1 Tg and 7.9 Tg, respectively, in 1998 (Ministry of the Environment 2000).
The CH 4 

### 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. N 2 

### O emissions from the energy sector are more significant in Finland, 8.0 Gg, i.e. about one third of the total anthropogenic N 2 

### O emissions came from the fuel consumption in 1998 (Ministry of the Environment 2000).
The N 2 

### O 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 N 2 

### O than the corresponding conventional technologies. It has been estimated that, in 2010, about 50 per cent of the Finnish N 2 

### O emissions will be due to the energy sector. In 1990, this share was about 20 per cent (Lehtilä and Tuhkanen 1999).
CO 2 

### 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 CH 4 

### and N 2 

### O 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.
CO 2 

### emissions are calculated based on the amount of fuel used in each boiler or process. CO, CH 4 

### , N 2 

### O 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 CH 4 

### and N 2 

### O 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 N 2 

### O 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 CH 4 

### 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 (C x 

### H y 

### ) such as methane (CH 4 

### ). 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 CH 4 

### emissions of the energy sector. The role of fugitive emissions from the natural gas distribution is also minor (Pipatti 1998). Noncombustion sources,

### Report 8 (36)

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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, CH 4 

### , and other simple hydrocarbon compounds (Boström et al. 1991).



# Mixing Poor GoodLow HighTemperature 

# 1. 2.

3. 4. CO high
C x 

# H y 

# low CO low
C x 

# H y 

# low

CO high
C x 

# H y 

# high CO low
C x 

# H y 

# 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 N 2 

### O led to a vivid research activity that improved essentially the general understanding of conversion of fuel nitrogen to nitrogen oxides NO x 

### , N 2 

### O and molecular nitrogen N 2 

### (Kilpinen 1999, Leckner 1998). However, the reaction paths for NO x 

### and N 2 

### O formation and reduction are complicated (see Fig. 2) and not yet fully understood, and it is often difficult to

### Report 9 (36)

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### explain the variation in NO x 

### and N 2 

### O emissions observed in different operating conditions and with different fuel types. The emission of N 2 

### O is a balance between formation and destruction. The relative importance of homogeneous and heterogeneous decomposition or reduction of N 2 

### O and the heterogeneous reduction of NO x 

### 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 N 2 

### O 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 N 2 

### O during the combustion process. (Kilpinen 1995, Lin et al. 1999).
Some NO x 

### -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 N 2 

### O emission from the fluidised bed combustion and SNCR are reviewed briefly.

N fuel 

### N char 1 

### N vol 2 

### NH 3 3 

### NH 3 5


### HCN 4 

### N 2 9 

### N 2 6 

### NO 10 

### NO 8 

### N 2 

### O 7 

### N 2 15



### NO 13 

### N 2 

### O 14 

### N 2 16



### N 2 

### O 12



### N 2 11 

### NO N char 

### NH 3 

### HCN N 2 

### O



### Figure 2. Fuel-N conversion routes in coal firing FBC (Kilpinen 1999).

### Report 10 (36)

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### 4.2 N 2 

### O emissions from fluidised bed boilers Fluidised bed combustion (FBC) has emerged as an environmentally attractive combustion method mainly due to the possibility to control SO x 

### and NO x 

### 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 NO x 

### emissions and optimum conditions for SO x 

### removal with the addition of limestone or dolomite. The low combustion temperature, however, allows formation of N 2 

### O. 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 NO x 

### and N 2 

### O 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, NH 3 

### , and cyano-species, such as hydrogen cyanide, HCN. When the fuel volatiles are oxidised in the gas phase at the fluidized bed temperatures, NH 3 

### is predominantly converted into NO, whereas HCN is an important volatile source of N 2 

### O. NO x 

### and N 2 

### O will also be produced during the char burnout stage (Kilpinen 1995, Leckner 1998). The manner of conversion of char-N to N 2 

### O is not clear. The share of char-N in the formation of N 2 

### O is often considered to be small, although no general agreement exists.
Both the formation and destruction of N 2 

### O in a fluidized bed combustor are more or less catalytically affected by the bed material, including char, calcium oxides, calcium sulphates, ash and sand. N 2 

### O can be effectively reduced by hydrogen radicals, carbon monoxide, thermal decomposition and char. (Liu & Gibbs 1999). The factors affecting the production of N 2 

### O (as well as NO x 

### ) 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

### Report 11 (36)

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### conditions on NO x 

### and N 2 

### O 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 N 2 

### O (Lin et al

. 1999). Affecting factors to N 2 

### O emissions are summarized in Table 1. The combustion temperature is, undoubtedly, the single most important parameter affecting the rates of formation and destruction of N 2 

### O and NO. Most studies report that N 2 

### O emissions decrease with an increase in the bed temperature, and NO exhibits an opposite trend (Lin et al. 1999). Conversion of HCN to N 2 

### O is very sensitive to temperature and decreases, when the temperature increases. If the temperature is more than 950 °C, N 2 

### O is not formed, instead HCN is converted mainly to NO. Also, the increasing temperature accelerates the destruction of already formed N 2 

### O (Kilpinen 1995). The N 2 

### O 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) levelaffects 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 3:00N2O (dry), NO and NOx (wet) ppm

800 820 840 860 880 900 920 940 960 980 1000Furnace 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 N 2 

### O emission is considered to be lower in the BFB boiler than in the CFB boiler. The highest N 2 

### O emissions are reported from the coal firing circulating fluidised bed boilers. According to Leckner (1998), the emission of N 2 

### O depends on the fuel in a descending scale from coal, to lignite, peat and wood. The emission of N 2 

### O 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 N 2 

### O 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 N 2 

### O 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 N 2 

### O and NO from volatile fuel-N. According to Aho, the emissions of N 2 

### O decrease with an increasing fuel-O/fuel-N ratio, because the ratio of HCN/NH 3 

### in pyrolysis gases decreases.
N 2 

### O emission can also be affected by excess-air ratio. N 2 

### O 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 SO 2 

### emissions. Limestone addition usually results in a lower N 2 

### O emission, and this is most pronounced at high molar ratios of Ca/S. Suggested reasons for the often-observed decrease in N 2 

### O emissions are principally three: first of all, limestone/CaO catalyses the decomposition of N 2 

### O. Secondly, the reduced SO 2 

### level in the combustor results in an increase in the pool of H, OH and/or O radicals, which can effectively destroy N 2 

### O. Thirdly, the oxidation of HCN, the major N 2 

### O precursor from volatile-N, over limestone has a high selectivity for NO x 

### formation and a low selectivity for N 2 

### O formation under FBC conditions. Finally, limestone/CaO catalyses the conversion of HCN to NH 3, 

### which in turn results in a reduced N 2 

### O (Kilpinen 1995). Air staging is a technique used to reduce NO x 

### levels, but its effect on N 2 

### O emission is unclear. In some studies, no significant change in the N 2 

### O level was observed. In others, a decrease in N 2 

### O was reported together with an NO x 

### reduction (Wójtowich et al. 1994). Hiltunen et al. (1991) reported that air staging and air ratio have an insignificant effect on N 2 

### O emission. In the literature, there has been reported 10 - 150 ppmv N 2 

### O 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 N 2 

### O emission in wood, peat and oilshale combustion and 30-120 ppm (3% O 2 

### dry, corresponding 15-60 mg/MJ) in coal combustion (Hiltunen et al. 1991). N 2 

### O 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 MW th 

### Kvaerner's Cymic (CFB) boiler firing biofuel and 35 mg/MJ, when firing coal.

Table 1. Summary of factors affecting on N 2 

### O emissions.
Factor Effect on N 2 

### O 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 N 2 

### O emission from SNCR and SCR Injection of ammonia (NH 3 

### ) or urea (CO(NH 2 

### ) 2 

### ) is one of the measures for reducing NO x 

### emissions; this technique is often termed as selective non-catalytic reduction (SNCR). In general, SNCR involves a NO x 

### reduction to N 2 

### and H 2 

### O in the temperature region of 900 - 1100 °C. A similar method of NO x 

### 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 N 2 

### O emission has been reported. In general, the increase in N 2 

### O depends on the temperature, the additive used and the feed rate, the location of the injection point, and the efficiency of NO x 

### reduction. The increase in the N 2 

### O emission due to SNCR is roughly correlated with the amount of NO x 

### reduced by this process. The value of the ratio has been reported at between 5 and 50% (Wójtowicz 1994 et al .). The N 2 

### O formation issue is more prevalent in urea-based systems than in ammonia-based systems (Kilpinen 1995). There has been concern about possible formation of N 2 

### O due to SCR, but the available commercial-scale data show that this does not occur (Wójtowicz et al. 1994).

4.4 N 2 

### O measurement techniques The development of continuous emission monitors (CEMs) has been intensive during the last few years, especially of N 2 

### O, which had great problems e.g. with sampling earlier.

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### The N 2 

### O 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 N 2 

### O 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, SO 2 

### and condensed H 2 

### O were found to form N 2 

### O as an artefact in the sample container only after few hours. The chemical reactions leading to the formation of N 2 

### O are shown in Figure 4. In the sample container, the NO is oxidised to NO 2 

### . NO 2 

### and SO 2 

### in the gas phase are taken to be in equilibrium with the aqueous phase. In the aqueous phase, the NO 2 

### and SO 2 

### ultimately form N 2 

### O and H 2 

### SO 4 

### . It was also shown that N 2 

### O production occurred, when the aqueous phase was in a low pH.

Figure 4. Overall chemical path leading to N 2 

### O formation in the sample flasks (Muzio et al.1989)

.

The chemical kinetic model was also used to investigate parametrically the formation of N 2 

### O in the sample containers. Figure 5 shows the calculated effect of SO 2 

### concentration on the formation of N 2 

### O in the sample containers ́ SO 2 

### 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 SO 2 

### 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 N 2 

### O measurements in the combustion sources were regarded as more or less inaccurate with too high N 2 

### O 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 N 2 

### O analysers began then, over a decade ago.

Figure 5. Calculated effect of SO2 on the N 2 

### O formation in the sample containers (Muzio et al.1989).
N 2 

### O 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 DiodeLaser System (TDLS), Fourier Transform Infrared (FTIR) spectroscopy and NonDispersive Infrared (NDIR) technique were already then capable of measuring low N 2 

### O 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.
N 2 

### O 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, NO 2 

### ) have no significant cross-interferences, but water vapour, carbon dioxide and carbon monoxide have an effect on the N 2 

### O measurement. They have infrared absorbances in the same region as N 2 

### O, thus they have an overlap with the N 2 

### O absorbance, as is shown in Figure 6. These overlaps cause both positive and negative cross-sensitivities, depending on the gas. In the modern N 2 

### O 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 CO 2 

### (left), CO (top and right), N 2 

### O (centre) and a typical IR filter (bottom) used for the GFC measurement of trace N 2 

### O (Bruce and Middleton 1999).

5 MEASUREMENTS
5.1 Scope The scope of these measurements was to obtain independent and reliable data of the non-CO 2 

### greenhouse gases, N 2 

### O and CH 4 

### , 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 N 2 

### O 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 N 2 

### O 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 MW th 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 MW th 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 MW fuel 430 1300 Power MW e 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 MW fuel 363 Nominal effect MW th 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 MW th 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:
N 2 

### O: 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 CH 4 

### . The reported confidence limit was agreed to 2 ppm.
NO x 

### : with Monitor Labs 9841A analyser, based on the chemiluminescense principle. Measuring range 0 - 1000 ppm.
SO 2 

### : 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

. O 2 

### : with M&C PMA 25 analyser, based on paramagnetism of oxygen. Measuring range 0 - 25%.
CO and CO 2 

### : with Hartmann & Braun Uras 10 E analyser, based on infrared absorption. Measuring ranges 0- 2000/5000 CO and 0 - 20% CO 2 

### . The sample handling of gaseous compounds was arranged as follows: the NO x 

### and the SO 2 

### 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.
N 2 

### O, O 2 

### , CO and CO 2 

### 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:
N 2 

### O 39.1 ppm TOC 931 ppm (CH 4 

### ) NO 299 ppm SO 2 

### 203 ppm O 2 

### 4.91 % CO 199 ppm CO 2 

### 15.0 %

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### All the gases were balanced in nitrogen except CH 4 

### , 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 O 2 , CO, CO 2

DILUTION CONTROL NO x SO 2

N 2 O TOC

DATA LOGGER PC

CALIBRATION GASES ZERO GAS



### ∆ p

t

H 2 

### O dilution probe

heated sample line



### Figure 7. The arrangement of the flue gas measurements.

N 2 

### O 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 N 2 

### O for N 2 

### O 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 N 2 

### O 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 N 2 

### O. 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 MW th 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
O 2 , dry % 6.1 6.2 5.5 6.5 7.1
CO 2 , dry % 13.8 13.7 14.4 13.1 13 CO, dry ppm 14 9 34 4 24
NO x , as NO 2 dry 6% O 2 mg/m 3 n 174 159 316 331 313
NO x , as NO 2 mg/MJ 68 62 122 128 123
SO 2 , dry 6% O 2 mg/m 3 n 394 286 241 381 < 20
SO 2 mg/MJ 153 113 93 147 < 8

N 2 O, dry ppm < 2 5 4 33 12

N 2 O, dry 6% O 2 mg/m 3 n < 4 10 8 68 25

N 2 O mg/MJ < 2 4 3 26 10 CH 4 , wet ppm 4 4 3 < 2 2
CH 4 , dry 6% O 2 mg/m 3 n 2 2 2 < 2 2 CH 4 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 CH 4 

### 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 MW th 260 73 60 58 Load 96 % 64 % 76 % 74 % Bed °C 817 853 897 831
O 2 , dry % 4.9 8.9 6.4 5.4

CO 2 , dry % 14.5 10.9 13.5 14.4 CO, dry ppm 179 769 38 113
NO x , as NO 2 dry 6% O 2 mg/m 3 n 353 187 315 337
NO x , as NO 2 mg/MJ 136 73 124 136
SO 2 , dry 6% O 2 mg/m 3 n 940 < 23 101 300
SO 2 mg/MJ 362 < 9 40 121

N 2 O, dry ppm < 2 < 2 < 2 < 2
N 2 O, dry 6% O 2 mg/m 3 n < 4 < 5 < 4 < 4

N 2 O mg/MJ < 1 < 2 < 2 < 2
CH 4 , wet ppm 5 166 < 2 10

CH 4 , dry 6% O 2 mg/m 3 n 2 155 < 2 8 CH 4 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 N 2 

### O and CH 4 

### emissions were below the confidence limit. The OFA system caused an about 30% reduction in the NO x 

### emission. The N 2 

### O emission level in the PC2 boiler was below the confidence limit both before and after the SCR unit. The NO x 

### 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 O 2 , dry % 4.4 4.3 3.4 CO 2 , dry % 14.9 15 15.5 CO, dry ppm 195 25 5

NO x , as NO 2 dry 6% O 2 mg/m 3 n 218 202 163 NO x , as NO 2 mg/MJ 86 79 60

SO 2 , dry 6% O 2 mg/m 3 n < 15 < 15 < 15 SO 2 mg/MJ < 6 < 6 < 6 N 2 O, dry ppm < 2 < 2 < 2

N 2 O, dry 6% O 2 mg/m 3 n < 4 < 4 < 3 N 2 O mg/MJ < 1 < 1 < 1 CH 4 , wet ppm 3 < 2 < 2
CH 4 , dry 6% O 2 mg/m 3 n 5 < 5 < 2 CH 4 mg/MJ 1 < 1 < 1



### Table 11. Process conditions and emissions from PC boilers.

Boiler PC1 PC1 PC2 PC2 Capacity MW th 453 453 565 565 Load 105 % 105 % 100 % 100 % O 2 , dry % 5.9 5.9 4.4 4.4 CO 2 , dry % 13 13 CO, dry ppm 17 17 1 1

NO x , as NO 2 dry 6% O 2 mg/m 3 n 633 442 NO x , as NO 2 mg/MJ 224 156 138 59

SO 2 , dry 6% O 2 mg/m 3 n 208 185 SO 2 mg/MJ 74 66 N 2 O, dry ppm < 2 < 2 < 2 < 2

N 2 O, dry 6% O 2 mg/m 3 n < 4 < 4 < 4 < 4 N 2 O mg/MJ < 1 < 1 < 1 < 1 CH 4 , wet ppm < 2 < 2
CH 4 , dry 6% O 2 mg/m 3 n < 2 < 2 CH 4 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 N 2 

### O 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 MW th 155 120 138 Load 47 % 100 % 115 % Supplementary firing MW fuel 21 O 2 , dry % 14.7 14.9 13.9 CO 2 , dry % 3.5 3.1 3.6 CO, dry ppm 7 64 122

NO x , as NO 2 dry 6% O 2 mg/m 3 n 201 192 137
NO x , as NO 2 mg/MJ 70 67 48
N 2 O, dry ppm < 2 < 2 < 2
N 2 O, dry 6% O 2 mg/m 3 n < 10 < 10 < 8
N 2 O mg/MJ < 3 < 3 < 3
CH 4 , wet ppm < 2 < 2 45
CH 4 , dry 6% O 2 mg/m 3 n < 2 < 3 74
CH 4 mg/MJ < 1 < 1 26



### The process conditions and emissions from the heavy oil boiler measurements are in Table 13. In both measurements, the N 2 

### O and CH 4 

### emissions were below the confidence limit.

### Report 27 (36)

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Fortum Power and Heat Oy, Technology Copyright 2001 Fortum k:\t&k\y-pooli\non-co2-raportti.doc 

### Table 13. Process conditions and emissions from a heavy oil firing boiler.

Boiler OB1 OB1 Capacity kg/s 15 22 Load 50 % 73 % O 2 , dry % 4.6 4 CO 2 , dry % 12.3 12.8 CO, dry ppm 8 9
NO x , as NO 2 dry 6% O 2 mg/m 3 n 384 396

NO x , as NO 2 mg/MJ 135 139
SO 2 , dry 6% O 2 mg/m 3 n 1102 1097
SO 2 mg/MJ 387 385
N 2 O, dry ppm < 2 < 2
N 2 O, dry 6% O 2 mg/m 3 n < 4 < 3

N 2 O mg/MJ < 1 < 1
CH 4 , wet ppm < 2 < 2
CH 4 , dry 6% O 2 mg/m 3 n < 2 < 2
CH 4 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 N 2 

### O 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.

### Report 28 (36)

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Fortum Power and Heat Oy, Technology Copyright 2001 Fortum k:\t&k\y-pooli\non-co2-raportti.doc 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 13:15N2O 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 N 2 

### O 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 N 2 

### O 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 N 2 

### O 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 N 2 

### O 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 N 2 

### O 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 N 2 

### O emission in this size class. Unfortunately, none of the measured boilers burned coal. So its influence on the N 2 

### O emission remained unclear. The catalytic effect of limestone feeding on the N 2 

### O emission remained also unclear.

### Report 29 (36)

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Fortum Power and Heat Oy, Technology Copyright 2001 Fortum k:\t&k\y-pooli\non-co2-raportti.doc 

### 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 N 2 

### O 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 N 2 

### O 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 N 2 

### O emission level was under the confidence limit.
The N 2 

### O emission level was above the confidence limit only in the CFB boilers. The main reason for the N 2 

### O 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 N 2 

### O emission as alleged. Unfortunately, none of the measured CFB boilers burned coal. So its influence on the N 2 

### O 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 N 2 

### O and CH 4 

### 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 N 2 

### O emission and the national factor was in the BFB boilers. Also, the factors for the CFB boilers seemed to be too high. The CH 4 

### emission factors for the CFB and BFB boilers seemed equally to be too high.

Table 14. Comparison of the measured N 2 

### O and CH 4 

### emissions with the national and the IPCC's emission factors. Parenthesis indicates abnormal process conditions.

CFBboilers BFB-boilers PCboilers Gas turbine plants Recovery boilers Heavy oil boiler N 2 O national factor mg/MJ 30 - 39 27 - 30 2 1 1.4 2 N 2 O IPCC- factor mg/MJ 4 4 1.4 0.1 4 0.6 N 2 O measured mg/MJ <2...26 <2 <1 <3 <1 <1 CH 4 national factor mg/MJ 11.1 - 22.4 14.5 - 21.3 4 3 1 8 CH 4 IPCC- factor mg/MJ 30 30 1 1 30 3 CH 4 measured mg/MJ 1 1 - 3 (72) <1 <1 (26) 1 <1



### The N 2 

### O 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.

### Report 30 (36)

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Fortum Power and Heat Oy, Technology Copyright 2001 Fortum k:\t&k\y-pooli\non-co2-raportti.doc 

### REFERENCES Aho, M. Effects of fuel properties, temperature, and pressure on fuel reactivity, formation and destruction of nitrogen oxides, and release of alkalis. In: Hupa, M. and Matinlinna, J. (eds.) Liekki 2, combustion and gasification research programme. Technical Review 1993-1998. Åbo, Finland: Åbo Akademi, 1998. Boström, S., Backman, R. and Hupa, M. Greenhouse gas emissions in Finland in 1988 and 1990. Turku, Finland: Prosessikemia Ky, 1992. Boström, S., Backman, R. and Hupa, M. "Greenhouse gas emissions related to energy production and consumption in Finland. Ministry of Trade and Industry, Energy Department, Research Reports D:197. Helsinki, 1991. Boström, S. Greenhouse gas inventory in Finland base on IPCC Draft Guidelines: Energy and industry. Turku, Finland: Prosessikemia Ky, 1994. Bruce, S. H., The Big Three- On-line Monitoring of Greenhouse gases. Proceedings of the International Conference on Emission Monitoring. Coventry, UK, 1999. Flagan, R.C. & Seinfeld, J.H. Fundamentals of air pollution engineering. New Jersey, USA: Prentice Hall, 1988. Hiltunen, M., Kilpinen, P. Hupa, M. Lee, Y. Y. N 2 

### O emissions from CFB boilers: Experimental results and chemical interpretation. In: Anthony, E. J. (ed.). Proceedings of the International conference on fluidised bed combustion. New York, USA: The American Society of Mechanical Engineers, 1991. Hupa, M., Boström, S. and Nermes, M.: Total emissions from energy production in Finland (in Finnish). Prosessikemia Ky, Ministry of the Trade and Industry Energy Department. Series D:162, Helsinki, 1988. Johnsson, J. E., Jensen, A. and Nielsen, J. S. Kinetics of heterogeneous NO and N 2 

### O reduction of N 2 

### O and NO. In: Reuther, R.B. (Ed.). Proceedings of the 15th International Conference of Fluidised Bed Combustion. Savannah, Georgia, USA. May 16-19,1999. New York, USA: The American Society of Mechanical Engineers, 1999. Kilpinen, P. "Gaseous emissions", lecture notes at the course on "Chemistry in combustion processes", Part I, 18-24 March, Åbo Akademi University, Åbo/Turku, 1999.Kilpinen, P. Formation and decomposition of nitrogen oxides. In: Raiko, R., KurkiSuonio, I., Saastamoinen, J. & Hupa, M. (eds.). Combustion and burning. Jyväskylä, Finland: International Flame Research Foundation (IFRF), Finnish national department, 1995. Pp. 239-279. (In Finnish). Kilpinen, P. and Hupa, M. Nitrogen chemistry in combustion and gasification. In: Hupa, M. and Matinlinna, J. (eds.) Liekki 2, combustion and gasification research programme. Technical Review 1993-1998. Åbo, Finland: Åbo Akademi, 1998.

### Report 31 (36)

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Fortum Power and Heat Oy, Technology Copyright 2001 Fortum k:\t&k\y-pooli\non-co2-raportti.doc 

### Kostamo, M. and Niemelä, K. Breakthrough for Foster Wheeler's Compact CFB Technology. In: The future of fluidized bed combustion. VGB technical scientific report. Report TW212e. Essen, Germany: VGB-Kraftwerkstechnik GmbH, 199 7. Leckner, B. Fluidized bed combustion: Mixing and pollutant limitation. Progress in Energy and Combustion Science. Vol. 24, No 1, pp 31-63, 1998. Lehtilä, A. and Tuhkanen, S. Integrated cost-effectiveness analysis of greenhouse gas emission abatement. The case of Finland. Espoo, Finland: Technical Research Centre of Finland, 1999. 113 p. (VTT Publications 374). Lin, M., Kulasekaran, S., Ignowski, J. M., Linjewile, T. M. and Agarwal, P. K. Emissions of N 2 

### O in fluidised bed combustion of coal. In: Reuther, R.B. (Ed.). Proceedings of the 15th International Conference of Fluidised Bed Combustion. Savannah, Georgia, USA. May 16-19,1999. New York, USA: The American Society of Mechanical Engineers, 1999. Liu, H. and Gibbs, B. M. The influence of limestone and alumina on NO x 

### and N 2 

### O emissions from char combustion in a fluidized bed combustor. In: Reuther, R.B. (Ed.). Proceedings of the 15th International Conference of Fluidised Bed Combustion. Savannah, Georgia, USA. May 16-19,1999. New York, USA: The American Society of Mechanical Engineers, 1999. LNETI 1990. European Workshop on N 2 

### O. Lisbon. June 6-8,1990. Laboratorio Nacional de Engenharioa e Tecnologia Industrial, Unites States Environmental Protection Agency, Institute Francais du Petrole, 1990. Ministry of the Environment. Finland's annual inventory report on greenhouse gases to the UN's Framework Convention on Climate Change, Common Reporting Format (CFR): 1990 and 1998.Helsinki, Finland, 14th April 2000. Ministry of the Environment. Finland's second report under the framework convention on climate change. Helsinki, Finland: Helsinki University Printing House, 1997. Moritomi, H., Shimizu, T., Suzuki, Y., Ninomiya, Y., Naruse, I, Ono, N. and Harada, M. Measurement of N 2 

### O emission from commercial scale and bench-scale coal-fired fluidized bed combustors. In: Reuther, R.B. (Ed.). Proceedings of the 15th International Conference of Fluidised Bed Combustion. Savannah, Georgia, USA. May 16-19,1999. New York, USA: The American Society of Mechanical Engineers, 1999. Muzio, L., Montgomery T. and Samuelsen G., Continuous Infrared Analysis of N 2 

### O in Combustion Products. Journal of Air Pollution and Control Association, Vol. 39, 1989 Muzio, L., Teague, M.E., Kramlich, J. C., Cole, J. A., McCarthy, J. M. and Lyon, R. K. Errors in Grab Sample Measurements of N 2 

### O from Combustion Sources. Journal of Air Pollution and Control Association, Vol. 39, 1989 Pipatti, R. Emission estimates for some acidifying and greenhouse gases and options for their control in Finland. Doctoral thesis. VTT Publications 340. Espoo, Finland: Technical Research Centre of Finland, 1998.

### Report 32 (36)

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Fortum Power and Heat Oy, Technology Copyright 2001 Fortum k:\t&k\y-pooli\non-co2-raportti.doc 

### 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, 199 7. Saviharju, Kari. "Polttotekniikan näkymät päästöjen vähentämisessä". In: Päästöjen lähteet, vaikutukset ja vähentämisen kustannukset. 16-17.10.1990. Hotelli Rantasipi, Aulanko, Finland. Insinöörien Koulutuskeskus, 1990. Wójtowicz, M.A., Pels, J.R and Moulijn, J.A. N 2 

### O emission control in coal combustion. Fuel,1994. Vol.73, Nr 9, pp. 1416-1422.
The Characterisation of Carbon Dioxide and other Greenhouse Gas releases from a Natural Gas Fired Combined Cycle Power Plant. IEA Greenhouse Gas R&D Programme. Study number: IEA/91/OE 9, Study Completed February 1992.

### Report 33 (36)

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Fortum Power and Heat Oy, Technology Copyright 2001 Fortum k:\t&k\y-pooli\non-co2-raportti.doc 

### APPENDIX 1: N 2 

### O AND CH 4 

### 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

### Report 34 (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 

### 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

### Report 35 (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 

### 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

### 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: N 2 

### O AND CH 4 

### EMISSION FACTORS ACCORDING TO IPCC

Table 1. CH 4 

### Emission factors (IPCC Reference manual)

.

Table 2. N 2 

### O Emission factors (IPCC Reference manual)

.

### 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

. )

CH 4 , kg/MMBtu N 2 O , kg/MMBtu

ID Mill type RF type Spent liquor feedstock Other fuels C ontrol 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 Factor s from AEA Technology 2001

Available at: http://uk

- air.defra.gov.uk/library/reports?report_id=8AEAT/R/ENV/0524 Issue 1

AEA Technology A2. 9 

### Table 3 Emission Factors for Combustion of Solid Fuels (kg/t)

C CH 4 

### N 2



### O NO
x 

### CO NMVOC SO 2 

### Anthracite Domestic 813.4 n 

### 2

o 

### 0.14

w 

### 1.6

b 

### 45

f 

### 1.7

o 

### 14.0 aa 

### Coke Agriculture 795.4 n 

### 0.011 p 

### 0.144 g 

### 4.0

b 

### 4.1 p 

### 0.05 p 

### 19

ab


### Coke Coke Production;

SSF Production 820 n 

### 0.011 p 

### 0.221 w 

### 4.8 b 

### 4.1 p 

### 0.05 p 

### 19

ab



### Coke Domestic 803.6 n 

### 5.8

p 

### 0.111 w 

### 1.33 b 

### 45

q 

### 4.9

p 

### 16

ab


### Coke I&S (Sinter Plant) 795.4 n 

### 0.011 p 

### 0.221 w 

### 4.13 b 

### 115

ae 

### 0.05

p 

### 19

ab


### Coke I& S (Combustion) Other

Industry 795.4 n 

### 0.011 p 

### 0.221 w 

### 4.8 b 

### 4.1 p 

### 0.05 p 

### 19

ab



### Coke Railways 795.4 n 

### 0.011 p 

### 0.144 g 

### 4.8

b 

### 4.1 p 

### 0.05 p 

### 19

ab


### Coke Miscellaneous; Public Service 795.4 n 

### 0.011 p 

### 0.144 g 

### 4.0

b 

### 4.1 p 

### 0.05 p 

### 19

ab


### Petro-Coke Refineries 800 a 

### 0.0127

p 

### 0.256

w 

### 6.9

z 

### 2.57

z 

### 0.0577

p 

### 42.5

z 

### SSF Agriculture; Miscellaneous;

Public Service 766.3 n 

### 0.011 p 

### 0.143 g 

### 3.96

b 

### 4.1 p 

### 0.05 p 

### 19

ab



### SSF Domestic 774.2 n 

### 5.8

p 

### 0.112

w 

### 1.32

b 

### 45

q 

### 4.9

p 

### 16

ab


### SSF Other Industry 766.3 n 

### 0.011 p 

### 0.218 w 

### 4.75

b 

### 4.1 p 

### 0.05 p 

### 19

ab


### Straw Agriculture 418 g 

### 4.28

g 

### 0.057

g 

### 1.43

g 

### 71.3

g 

### 8.56

g 

### 0 Wood Domestic 264 g 

### 3.61 b 

### 0.0388 g 

### 0.722

b 

### 99.3

g 

### 5.42

b 

### 0.037 m



### Wood Other Industry 470 g 

### 0.482

b 

### 0.069

g 

### 3.21 b 

### 7.1 g 

### 0.803 b 

### 0.037

mAEAT/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 B ritish 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.