TNO-report R 2002/174 emission factors for fuels in …...TNO-report TNO-MEP − R 2002/174 5 of 42 2. Approach Two research steps have been taken to evaluate the documentation and

Nederlandse Organisatie voor toegepast-natuurwetenschappelijk onderzoek / Netherlands Organisation for Applied Scientific Research

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TNO-report R 2002/174

CO2 emission factors for fuels in the Netherlands

Date April 2002 Authors Drs. A.K. van Harmelen

Ing. W.W.R. Koch Order no. 32498 Keywords CO2 emission factor

Carbon emission factor Fuel

Intended for Novem

Ministry of VROM Project group CO2 monitoring

All rights reserved. No part of this publication may be reproduced and/or published by print, photoprint, microfilm or any other means without the previous written consent of TNO. In case this report was drafted on instructions, the rights and obligations of contracting parties are subject to either the Standard Conditions for Research Instructions given to TNO, or the relevant agreement concluded between the contracting parties. Submitting the report for inspection to parties who have a direct interest is permitted. © 2002 TNO

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Table of content

1. Introduction................................................................................................3

2. Approach....................................................................................................5

3. Present emission factors and prioritisation ................................................7 3.1 Interpretation of emission factors ...............................................7 3.2 Overview of present emission factors ........................................8 3.3 Sources and quality of present IPCC EFs.................................10 3.4 Sources and quality of present national EFs.............................11

3.4.1 Solid fossil fuels (primary and secondary)................11 3.4.2 Liquid fossil fuels (primary and secondary) .............14 3.4.3 Gaseous fossil fuel ....................................................15

3.5 Priority setting ..........................................................................16

4. Analysis of new information on fuels ......................................................18 4.1 Consistency of CO2 calculations ..............................................18

4.1.1 Measurements and factors.........................................18 4.1.2 Criteria for adoption of new CO2 emission

factors........................................................................19 4.2 Primary solid fossil fuels ..........................................................20 4.3 Secondary fuels from solid fossil fuels.....................................25 4.4 Primary liquid fossil fuels.........................................................26 4.5 Secondary fuels from liquid fossil fuels ...................................28 4.6 Primary Gaseous fossil fuels ....................................................30 4.7 Other fuels ................................................................................33

5. Conclusions & recommendations ............................................................34

6. References................................................................................................38

7. List of Abbreviations ...............................................................................41

Appendix A The IPCC CO2 methodology Appendix B Oil data

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1. Introduction

In 1999 a start has been made to improve the quality of existing emission invento-ries of greenhouse gases and to determine and minimise the uncertainties. The main reasons for improving the quality of the existing emission inventories are rooted in the following international developments: − The adoption of new reporting guidelines and the Common Reporting Format

under the Framework Convention on Climate Change; − The Kyoto protocol: development of guidelines for the ‘national system’ (art.

5), ‘supplemental information’ (art. 7) and ‘review’ (art. 8) 1; − IPCC: development of ‘Good practice guidance’ for emission inventories2.

The IPCC has put it in very concrete terms: when countries use local values of CO2 emission factors instead of default IPCC emission factors, they should note the dif-ferences from the default values and provide to the IPCC documentation support-ing the values used in the national inventory calculations.

Moreover, the intensified national climate policy as described in the Implementa-tion note on Climate Change policy Part 1 (in Dutch: ‘Uitvoeringsnota Klimaat-beleid, deel 1’) requires an improvement of the quality of the emission inventory of greenhouse gases.

In the autumn of 1999 two national workshops were held in the Netherlands in or-der to determine the state of affairs concerning the monitoring of greenhouse gas emissions and sinks and to determine points of improvement. As a result of these workshops the Working group monitoring of greenhouse gas emissions (in Dutch: ‘Werkgroep Emissiemonitoring Broeikasgassen - WEB’) was founded to coach and monitor the process to improve the monitoring of greenhouse gas emissions in the Netherlands. Representatives of relevant ministries and research institutes (Statistics Netherlands CBS, National Institute of Public Health and the Environment RIVM, Netherlands Organization for Applied Scientific Research TNO) are seated in this working group. The working group established a project group on CO2 monitoring that is responsible for determining and improving the uncertainties in the process of CO2 emission monitoring in the Netherlands. This project group initiated the present study on the determination and documentation of 1 As a result of the Kyoto Protocol each party shall have in place, no later than one

year prior to the start of the first commitment period, a national system for the es-timation of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not controlled by the Montreal Protocol (article 5). Besides this, each party is obliged to incorporate the necessary supplementary informa-tion for the purposes of ensuring compliance with Article 3 of the Kyoto Protocol (article 7). Furthermore it is stated in the Kyoto Protocol that each Party shall be reviewed as part of the annual compilation and accounting of emissions invento-ries and assigned amounts (article 8).

2 In the framework of the Intergovernmental Panel on Climate Change (IPCC) it is compulsory to include an uncertainty discussion in the inventory submission. To do so it is necessary to have insight in the quality of the a set of emission factors.

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tiated the present study on the determination and documentation of CO2 emission factors of fuels in the Netherlands.

The set of CO2 emission factors for fuels used in the Netherlands is presently only applied by parties in the Netherlands involved in the greenhouse gas emission in-ventory directly or indirectly under the umbrella of FCCC, viz. research institutes, governments and (smaller) companies that do not measure their emissions directly. Most large companies measure their emissions on the spot, present them in Envi-ronmental reports and provide their emission estimations to the national Pollutant Emission Register. These companies are not obliged to use standard emission fac-tors.

The objective of this study is to evaluate the documentation and validity of the pre-sent national set of CO2 emission factors and to analyse the currently available in-formation in the literature and at companies in order to make recommendations for the adoption, maintenance and further improvement of reliable, well-founded and documented CO2 emission factors for fuels used in the Netherlands. If information on uncertainty of the data is available, these are presented. However, uncertainty is not an explicit aim in this study, but the main subject of a separate study on the un-certainty of greenhouse gases by IVM and ICIS that is currently being executed (report forthcoming).

The results presented in this report have been reported and discussed with the pro-ject group CO2 monitoring. The recommendations for further actions on the adop-tion, maintenance and further improvement of the set of emission factors are di-rected to the project group on CO2 monitoring that is responsible for implementa-tion of the recommendations.

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2. Approach

Two research steps have been taken to evaluate the documentation and validity of the present national set of CO2 emission factors in order to make recommendations for a reliable, well-founded and documented set of CO2 emission factors for fuels used in the Netherlands: 1. Exploration and prioritisation; 2. Collection of new information and recommendations for improvement of na-

tional CO2 emission factors.

The objective of the first step was to analyse the foundation and documentation of the set of CO2 emission factors presently in use in the Netherlands, to determine the available sources of information and to establish priorities for updating documenta-tion and calculation of Dutch CO2 emission factors. The results of step 1 are de-scribed in section 3. Present emission factors and prioritisation.

The prioritisation takes place on the basis of: − The reliability and validity of the emission factor; − The quality and age of the documentation; − The contribution of specific fuels to national CO2 emissions; − The difference with the default IPCC CO2 emission factor.

The contribution to national CO2 emissions has been assessed by consulting the Dutch Pollutant Emission Register (PER), also called the Emission Inventory Sys-tem (EIS), which contains the emissions to air, water, soil and waste both from all industrial and non-industrial sources. The emission inventory of 1998 has been analysed to indicate the importance of different fossil fuels in terms of their contri-bution to the national CO2 emission. Together with a quality assessment of the na-tional CO2 emission factors presently in use and a comparison of default IPCC CO2 emission factors, this resulted in a priority setting in terms of fuels that are impor-tant for more thorough investigation in step 2.

Closer examination of the emission inventory generated additional information on the individual sources of the CO2 emission and hence gave insight in the compa-nies and institutes to be approached for more specific data in step 2.

The second step analyses new, recent information and makes recommendations for the improvement of CO2 emission factors for the Netherlands. The results of this step are described in section 4. Analysis of new information on fuels.

Step 2 started with approaching the selected companies and institutes with a re-quest for cooperation to collect the latest specific data. This resulted in specific in-formation on the composition and use of the selected fuels and fuel types in use during (years of) the last decade in the Netherlands. Special attention has been paid

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to the source of the received emission information and the reliability in qualitative or preferably quantitative terms. This information has been expressed in a CO2 emission factor for each fuel, possibly accompanied with (an indication of) a con-fidence interval. This new CO2 emission factor has been compared with the pres-ently used national CO2 emission factor and the default IPCC CO2 emission factor. Also, an indication of the impact of adoption of the new emission factor on the na-tional CO2 emission has been given for the year 1998.

According to IPCC, the use of a country specific CO2 emission factor is to be pre-ferred above the use of IPCC default values. A documentation of the national emis-sion factor is only obligatory in case of a significant difference. Approximately 2% is mentioned as being significant. Only if a difference larger than 2% cannot be ex-plained and documented, the default IPCC value has to be used. In this report, the principle is adopted that all country specific CO2 emission factors have to be ex-plained and documented, also the ones within a range of 2% of the IPCC default values.

It is useful to point out the difference between two IPCC approved methods for CO2 emission estimation, viz. the Reference Approach and the Detailed Technol-ogy based approach (see Appendix A for a more detailed description). The Refer-ence Approach only provides aggregated estimates of emissions by fuel type dis-tinguishing between primary and secondary fuels. The Detailed Technology-based Approach allocates these emissions by source category. The Reference Approach directly uses national CO2 emission factors, based on either national values or de-fault IPCC values. The Reference approach only distinguishes extracted, imported and exported fuels. This means that secondary fuels that are being converted within the country and remain within the country are not viewed in this approach. For the Netherlands it concerns fuels such as petrocokes, refinery gas, blast furnace gas, cokes gas and chemical residue gas.

The large majority of the CO2 emissions of these fuels are calculated in the De-tailed Technology based approach on the basis of a carbon mass balance method or locally measured carbon contents. Thus, national emission factors are not being used for these fuels. The national emission factors for these fuels are used in con-trol calculations and other analyses by scientific institutes.

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3. Present emission factors and prioritisation

3.1 Interpretation of emission factors

Before analysing the set of CO2 emission factors presently used in the Netherlands, some general remarks on the definition and thus proper interpretation of emission factors in this study have to be made.

The CO2 emission factors assessed in this project are based upon Net Calorific Values and carbon contents, which are related to the composition of fuels. No dis-tinction is made between the different types of fuel use; this means the possible storage of C in a (semi finished) product is not taken into account. This issue is ad-dressed in a separate study on emissions from feedstocks currently conducted by ECN and the University of Utrecht.

In the present study, like the IPCC, only CO2 emissions directly related to the fuel use are taken into account. Indirect effects in terms of upstream losses are not in-cluded in the presented emission factors.

When fuels are burned, most carbon is emitted as CO2 immediately during the combustion process. Some carbon is released as CO, CH4, or non-methane hydro-carbons, which oxidise to CO2 in the atmosphere within a period from a few days to 10-11 years. The IPCC methodology accounts for all of the carbon from these emissions in the total for CO2 emissions1.

CO2 emission factors in fact concern carbon emission factors. This means that the (differences in) oxidation fractions of carbon in the fuel combustion process are not taken into account in the factor. Or in other words: it has been assumed that the carbon in fuel will completely oxidise during combustion. The different combus-tion circumstances in locally applied technology are not taken into account in the assessment of emission factors. Also, fixation of carbon in products is not taken into account in emission factors. This IPCC definition of emission factors is fol-lowed in this report. However, the complete IPCC methodology does take oxida-tion and fixation into account. After the estimation of the CO2 emissions using the carbon emission factors, a correction is made for unoxidised carbon and fixed car-bon (see Appendix A for a short overview of the complete IPCC CO2 metho-dology).

1 It is important to note that there is an intentional double counting of carbon emit-

ted from combustion. The IPCC format treats the non-CO2 gases as a subset of CO2 emissions and ensures that the CO2 emission estimates reported by each country represent the entire amount of carbon that would eventually be present in the atmosphere as CO2.

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In this report, the number of decimals does not indicate the reliability of a value. In most cases, decimals are being used for presentation purposes and to show the number exactly as it is presented in other literature.

3.2 Overview of present emission factors

Table 3.1 shows the default values of the Carbon Emission Factors (CEF) as pre-sented in the Revised 1996 IPCC Guidelines for National Greenhouse Gas Invento-ries Workbook in ton C / TJ and ton CO2 / TJ. The latter values are the result of conversion and have been rounded off to 3 significant numbers. The CO2 Emission Factors presently in use in the Netherlands are also presented in ton CO2 per TJ.

In order to show the relative importance of the emission factors for fuels, the CO2 emissions of fuels in the Netherlands have been calculated for the year 1998. Sub-sequently, the contribution to national CO2 emissions is presented for each fuel in terms of the share in national CO2 emissions. Since the fuel mix did not change drastically over the last years, these figures are expected to give a representative picture of the relative importance of emissions per fuel in the Netherlands and thus indicate the relative importance of high quality emission factors. For all fuels, the CO2 emission factors presently used in the Netherlands have been applied. This means that the shares do not necessarily reflect the CO2 emissions as reported in the Common Reporting Format exactly. This approach has been chosen to be able to compare with the situation where IPCC default CO2 emission factors are used. The last column shows the difference in terms of the relative contribution to the to-tal national CO2 emission in the Netherlands as a result of the use of IPCC factors instead of country specific emission factors. This indicates the priority on high quality documentation of the particular emission factor

Some country specific fuels that are not distinguished by the IPCC are listed at the lower part of the table as ‘non-IPCC fuels’. Also, some categories additional to IPCC standard fuel types are being distinguished, for example anthracite for differ-ent sectors since in the Netherlands different emission factors are being used for these sectors.

In the next paragraphs, the CO2 emission factors and their foundation will be dis-cussed for each fuel type with reference to table 3.1. After summarising the back-ground of IPCC factors briefly, the Dutch emission factors are being discussed. In a paragraph on prioritisation, a selection will be made of fuel types for which an update of the national CO2 emission factor is important, considering the criteria as described in section 2. Approach.

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Table 3.1 Overview of default IPCC and Dutch national CO2 emission factors, contributions to the national CO2 emissions using national emission factors and the impact of the use of IPCC emission factors.

Fuels (translation in Dutch in italic) IPCC CO2 emission factor [ton C/TJ]

IPCC CO2 emission factor [t CO2/TJ]

Present national EFs [t CO2/TJ]

Share 1998 national CO2 emission based on pre-sent EFs [%]

Difference CO2 emission by national – IPCC EFs [%] (c)

Primary liquid fuels 1) Crude oil (ruwe olie) 20.0 73.3 73 28.5 (sum 4-18) 1.29 (sum 4-18) 2) Orimulsion (-) 22.0 80.7 n/a 3) Natural gas liquids (aardgascondensaat) 17.2 63.1 n/a Secondary liquid fuels / products 4) Gasoline [for transport] (benzine) 18.9 69.3 73 [72.3] 8.8 -0.37 5) Jet Kerosene (kerosine luchtvaart) 19.5 71.5 73 0.36 -0.007 6) Other Kerosene (kerosene overig) 19.6 71.9 n/a 7) Shale Oil (leisteenolie) 20.0 73.3 n/a

8) Gas/ Diesel oil [transport] (diesel, petro-leum, H.B.O. I en II) 20.2 74.1 73 [73.3] 13.13 0.14

9) Residual Fuel Oil (zware stookolie) 21.1 77.4 77 1.17 0.01 10) LPG [for transport] (LPG) 17.2 63.1 66 [66.4] 1.26 -0.06 11) Ethane (ethaan) 16.8 61.6 n/a 12) Naphtha (nafta) 20.0 (a) 73.3 n/a 13) Bitumen (bitumen) 22.0 80.7 n/a 14) Lubricants (smeermiddelen) 20.0 (a) 73.3 n/a 15) Petroleum Coke (petrokooks) 27.5 100.8 100 0.26 0.002 16) Refinery Feedstock’s (-) 20.0 (a) 73.3 n/a 17) Refinery gas (raffinaderijgas) 18.2 (b) 66.7 46 3.5 1.58 18) Other Oil (overige olieproducten) 20.0 (a) 73.3 n/a Primary solid fuels 19) Anthracite (steenkool) 26.8 98.3 15.06 0.69 Anth. Metal industry (st.k. basismetaal) 101 Anth. Other industry (st.k. overige ind.) 94 Anth. Power gen. (st.k. elektr.prod.) 93.8 Anthracite Other (st.k. overige afnemers) 103 20) Coking Coal (kookskolen) 25.8 94.6 103 21) Other Bit. Coal (bit. kolen) 25.8 94.6 n/a 22) Sub-bit. Coal (subbit. kolen) 26.2 96.1 n/a 23) Lignite (bruinkool) 27.6 101.2 n/a 0.01 0 Lignite powder (bruinkoolpoeder) 100.7 Lignite briquettes (bruinkoolbriketten) 101.1 Lignite average (bruinkool gemiddeld) 101 24) Oil Shale (-) 29.1 106.7 n/a 25) Peat (turf) 28.9 106 n/a Secondary solid fuels 26) BKB & Patent Fuel (briketten, eierkolen) 25.8 (a) 94.6 n/a 27) Coke Oven / Gas coke (kooks) 29.5 108.2 101 28) Coke Oven Gas (kooksgas) 13.0 (b) 47.7 44 0.15 0.013 29) Blast Furnace Gas (hoogovengas) 66.0 (b) 242 200 0.92 0.19

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Fuels (translation in Dutch in italic) IPCC CO2 emis-sion fac-tor [ton C/TJ]

IPCC CO2 emission factor [t CO2/TJ]

Present national Efs [t CO2/TJ]

Share 1998 national CO2 emission based on pre-sent EFs [%]

Difference CO2 emission by national – IPCC EFs [%] (c)

Gaseous fuels 30) Natural Gas, Dry (aardgas, droog) 15.3 56.1 56 49.87 0.089 Information entries 31) Solid Biomass (biomassa, vast) 29.9 109.6 n/a 32) Liquid Biomass (biomassa, vloeibaar) 20.0 (a) 73.3 n/a 33) Gas Biomass (biomassa, gasvormig) 30.6 (a) 112.2 n/a Total IPCC fuels 94.49 2.28 Non-IPCC fuels Chemical residue gases (chemisch restgas) 46 3.33 Other solid fuels (overige vaste brandstof) 0.23 TPA Tar, Pitch, Asphalt (teer, asfalt) 1.17 Wood (hout, niet duurzaam) 104 0.00 Kerosene / Aviation Gasoline (benzine luchtv.) 0.14 Unknown (onbekend) 0.64 Total Non-IPCC 5.51 TOTAL 100 2.28

(a) This value is a default value until a fuel specific CEF is determined. For Gas biomass, the CEF is based on the assumption that 50% of the carbon in the biomass is converted to methane and 50% is emitted as CO2. The CO2 emissions from biogas should not be included in national inventories. If biogas is released and not combusted, 50% of the carbon content should be included as methane.

(b) For use in the sector calculations. (c) The difference in CO2 emission shares as a result of the use of IPCC default EF instead of national

EF is calculated by the formula IPCC EF ( ————— – 1 ) * share 1998 national CO2 emission national EF

3.3 Sources and quality of present IPCC EFs

The IPCC Reference Approach relies primarily on the emission factors from Grubb (1989) with additions from other studies, to estimate total carbon content. The sug-gested carbon emission factors are listed in table 3.1.

The carbon emission factors for the fuels are average values based on net calorific values (NCV). This approach has been recommended by the IPCC because it re-duces the variation in carbon content by weight and enables the comparison of dif-ferent fuels in terms of their use in terms of producing energy.

The approach used by Grubb to estimate carbon emission factors is very similar to Marland and Rotty (1984), but based on more recent research. All carbon emission factors were originally reported on a gross calorific value basis, but are converted by Grubb to a net calorific value basis. He provides carbon factors for methane, ethane, propane, and butane and using data from Marland and Rotty (1984), esti-mates an average emission factor for natural gas of 15.3 t C/TJ +/- 1 per cent. It is

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based upon samples of natural gas representing the ‘average’ natural gas in 1976. For oil and some refined petroleum products the estimates are based on literature data.

The carbon emission factor of coal, excluding anthracite, was defined as:

EF = 32.15 - 0.234 * Hv

where EF is the carbon emission factor in t C/TJ and Hv is the gross calorific value of the coal when the calorific value is from 31 to 37 TJ / kiloton on a dry mineral matter free (dmf) basis. Anthracites fall outside this range and a value of 26.8 t C/TJ or 98.3 ton CO2/TJ is used.

Since the publication of the original OECD Background Document (OECD 1991), additional information has been made available on carbon emission factors. At an IPCC sponsored workshop in October 1992 (IPCC/OECD, 1993), experts recom-mended several revised emission factors based on national inventory submissions to the OECD. Additional emission factors were also made available based on the work of the expert group on GHG Emissions from Fuel Combustion during Phase II of the IPCC/OECD/IEA Programme on National GHG Inventories in 1996.

3.4 Sources and quality of present national EFs

The CO2 emission factors presently in use in the Netherlands for different types of fuels are based on different publications. Per fuel type the scientific foundation and source of the EF will be discussed in order to estimate the quality and validity of the national EF.

3.4.1 Solid fossil fuels (primary and secondary)

Primary solid fuels The CO2 emission factor for coal can vary over a wide range according to the type of coal. In the Netherlands all coal is being imported. This means that it is not easy to assess the typical coal that is being used in the Netherlands. The types of coal are being differentiated to types of consumers or sectors. Different types of anthra-cite and thus different emission factors are therefore used for different sectors in the Netherlands. The main consumers of anthracite are the power companies (ap-proximately 25 Mton CO2) and the iron & steel industry (Corus, responsible for CO2 emissions in the order of 5 Mton). The latter also exports self-produced cokes in significant amounts (in the order of 1 Mton CO2).

In 1988 van der Kooij [KEMA] presented an analysis of 55 hard coal samples rep-resenting coal used in Dutch power stations over the period 1981-1988. He showed

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that the variation in carbon content was correlated to the net calorific value (NCV in MJ / kg) as follows:

C-content (mass %) = 2.35 * NCV + 5.62

Since:

C-content (mass %) / 100 EF [ton C / TJ] =

NCV [MJ / kg] / 1000

this can be reformulated into:

( 2.35 * NCV + 5.62 ) EF [ton C / TJ] =

NCV [MJ / kg] / 10

or:

EF [ton C / TJ] = 23.5 + 56.2 / NCV

Since the average net calorific value was 26.9 MJ / kg at that time, the CO2 emis-sion factor was 93.8 ton / TJ. This relation is graphically presented in figure 3.1 where the square indicates this average situation. Also, the relation found by Grubb for the IPCC and the IPCC EF for coal as described in the previous paragraph, are depicted in the figure.

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20

25

30

35

92 93 94 95 96 97 98 99CO2 emission factor [ton/TJ]

NCV [MJ/kg]

Coking coal / Sub-bit.

Anthracite

Coking coal / Other bit.

IPCC

Dutch coal

Figure 3.1 The relation between net calorific value and the CO2 emission factors based

upon 55 hard coal samples representing coal consumed in Dutch power sta-tions from 1981 to 1988 [van der Kooij – KEMA 1988] and the analysis for the IPCC by Grubb 1 [Grubb, 1989].

The CO2 emission factor of 93.8 is used in a rounded form for the industry, except for the iron & steel industry. The iron & steel industry used a factor of 101 ton/TJ for its metallurgical coal. This is reported in Okken (1989) but the basis is unclear. To our knowledge, this emission factor has also been used for cokes.

The anthracite combusted in households had an average carbon content of 90% ac-cording to the Note on Coal (in Dutch Kolennota, Appendix C, Dutch Parliament 1979-1980). Assuming a net calorific value of 32 MJ / kg, a CO2 emission factor of 103 ton / TJ was calculated. These values are not very accurate, but the present use of coal in households is very limited.

The emission factors of lignite powder (Building materials) and lignite briquettes have been based on an analysis by Rheinische Braunkohlenwerke (Koln) in 1987. The emission factor for lignite powder is 100.7 and for briquettes 101.1 ton CO2 / TJ. The average value is 101 ton CO2 / TJ.

The use of lignite is very limited in the Netherlands. In 1998 only in the sector in-dustry (building materials, pottery and glass) and the building sector (extraction of other non-energy carriers) a limited amount of 132 TJ brown coal is used, resulting

1 Assuming a factor 0.93 between Gross Calorific Value and Net Calorific Value.

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in 14 kton CO2. Since this is negligible in the national balance, it is not investigated further.

Coke oven gas and blast furnace gas On the basis of data of the PER of individual companies (1983-1985) an emission factor for blast furnace gas of 200 ton CO2 / GJ and for coke oven gas of 44 ton / TJ was adopted. The composition of especially blast furnace gas can vary substan-tially.

3.4.2 Liquid fossil fuels (primary and secondary)

Crude oil The estimation of the CO2 emission factor for crude oil is based upon estimation by Olivier et al. (2000) that did not include measurements. The national CO2 emission as calculated by the Reference approach, serving as a control calculation, uses the crude oil emission factor. A sensitivity analysis has been executed for four (hypo-thetical) sets of carbon contents for crude oil, showing that the national emissions may vary on average over the last 10 years with 1.6%. The Reference calculation is quite sensitive to the emission factor for crude oil since the amounts of crude oil being refined in the Netherlands are high due to the high export of oil products. It should be noted here that the national CO2 emission estimation following the bot-tom-up method is not relying on the crude oil emission factor.

Liquid oil products On basis of the composition of crude oil ((CH2)n) and the literature consulted (a.o. Polyenergy-pocketbook (in Dutch)) the amount of carbon is estimated to be 85.7% (which is exactly the carbon content of the heavier alkanes n>200). Net calorific values of 41 GJ / ton for residual fuel oil, 42 to 43 GJ / ton for lighter oil products such as gas and diesel oil, and 44 GJ / ton for gasoline and kerosene have been as-sumed. On this basis, the following emission factors are calculated: for residual fuel oil 77 kg CO2 / GJ, for lighter products 73 to 74 (to be exact 73.3) ton CO2 / TJ and for gasoline and kerosene 72 (to be exact 72.3) ton / TJ [Spakman et al., 1997]. The value of residual fuel oil is also used for Tar, Peat and Asphalt. Since the fuel composition of gasoline, kerosene and gas/diesel oil can vary substantially, one emission factor of 73 kg CO2 / GJ has been chosen. However, for calculation of emissions in the transport sector, the exact values with one decimal are being used (presented within brackets in table 3.1). This is reported in Klein et al. [2002].

LPG In 1987, the composition mentioned in the Polyenergy-pocketbook was according to Okken [Okken et al. 1989] 58% propane, 27% butane, 10% propene and 5% bu-tene, resulting in a corresponding emission factor of 65.6 g/MJ. On basis of litera-ture consulted (a.o. Polyenergy-pocketbook (in Dutch)) the amount of carbon in LPG is estimated to be 82%. The net calorific value is estimated to be 45 – 46

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GJ/ton (based on the same literature). This leads to an emission factor of 66 kg CO2/GJ [Spakman et al., 1997]. Like with diesel and gasoline, the exact value of 66.4 is being used in the emission estimation for transport only (Klein et al. [2002]). It is not known how country specific these values are.

Refinery gas and chemical residue gas On basis of some samples of chemical residue gas and refinery gas taken during the data collection in the framework of the PER (1983-1985) an emission factor of 46 kg CO2 / GJ was calculated. The composition of these gases can vary a lot (ranging from high CO2 contents to high hydrogen contents), therefore, the emission factor of 46 kg CO2 / GJ is probably not robust over the years.

Petroleum Coke Petroleum coke is a black solid residue feedstock, obtained mainly by cracking and distillation of crude oil. Except for the production of silicium carbide, petrocoke is used as an intermediary fuel in the cracking process. The compositions of petro-leum cokes highly depend on feedstock and types of processes used. In general pe-troleum cokes contain some portions of all the elements, which existed in the origi-nal feedstock.

This emission factor for the Netherlands is based on the assumption that the petro-leum cokes contain 99% carbon, diminished with 5% of hydrogen. This leads to an emission factor of 100 kg CO2/GJ.

3.4.3 Gaseous fossil fuel

The natural gas from Dutch origin is being excavated and purified by the Dutch Pe-troleum Company (NAM) and sold to the N.V. Nederlandse Gasunie, which was the sole gas trading and transmission company in the Netherlands before the recent gas market liberalisation.

The presented emission factor of 56 ton CO2 / TJ for natural gas is based upon measurements by Gasunie of the gas quality from different gas wells in the Nether-lands. One national average value has been calculated for the different gas qualities in order to avoid a situation where natural gas consumers have to monitor the com-position of the consumed gas. This mean value is accurate up to a range of plus or minus 1%. Although the measurements took place more than 20 years ago, the data are still valid according to Gasunie [Personal communication K. Dijkstra of Gas-unie].

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3.5 Priority setting

Priority setting is based upon the contribution to the Dutch national emissions, the quality and age of the present documentation as well as the expected sources and quality of possible new information. Furthermore the amount of deviation from the IPCC standard EF is taken into account.

A quick look at table 3.1 learns that the combustion of natural gas, anthracite (in-cluding coking coal) and gas/diesel oil and gasoline deliver the most voluminous contribution to the total Dutch emission of CO2. Together, these sources account for almost 90% of national CO2 emissions. For the CO2 Reference approach, the contribution of crude oil is very important as well.

Adoption of the default IPCC emission factor for anthracite (including coking coal) would theoretically lead to an increase of national CO2 emissions of 0.69%, which is a relatively large proportion given the limited share of coal in the national bal-ance (15%).

The choice for the default set of IPCC CO2 emission factors for several light oil products would decrease national emissions with only a small proportion of 0.3%. However, the distribution over different fuel types and sectors is quite different when IPCC values are used.

Adoption of the IPCC value for natural gas will hardly affect national emissions (0.089%) because the values of the national emission factor and the IPCC emission factor are close together. Nevertheless, the investigation of the emission factor of natural gas receives priority since natural gas accounts for half the CO2 emissions in the Netherlands.

Theoretically, a large impact can be expected from the shift towards the IPCC de-fault CO2 emission factors for refinery gas and blast furnace gas. National emis-sions would increase with more than 1.5% respectively almost 0.2%. However, in practice, these emission factors are not used for the national emission inventory, since the refineries and iron & steel company deliver their emissions based upon a carbon balance calculation. In fact, also the emission factor for coal is not used for the national inventory since the central purchasing office for the electricity compa-nies (Gemeenschappelijk Kolenbureau Elektriciteitsproductiebedrijven) has meas-ured the carbon content and heating value of the coal purchased for the power companies annually.

Adoption of the default IPCC CO2 emission factors would therefore only in theory lead to an increase of 2.3% of present CO2 emission estimations in the Netherlands. This would only be the case if all parties presently submitting their CO2 emission estimations to the national PER used the presented national set of CO2 emission factors. However, if CO2 emissions that are estimated without the use of a national

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emission factor, are left out of the comparison, the impact of using default CO2 emissions would be a decrease of 0.2%. This is current practice.

Based upon the previous discussion, it was agreed upon in discussion with the pro-ject group CO2 monitoring that natural gas, anthracite (including coking coal) and gas/diesel oil and gasoline (oil products and crude oil) deserve specific research, analysis and documentation. This is presented in the next section 4. Analysis of new information on fuels. In addition, other fuels are sometimes discussed with re-spect to aspects such as the application of the national emission factor.

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4. Analysis of new information on fuels

In the following paragraphs new information is presented, analysed and compared with the presently used EF of the Netherlands and IPCC. The focus is on the most important fuels with respect to CO2 as selected in the previous section. After a short introduction concerning the application of the fuel, the new information re-garding the EF is discussed and eventually expressed in the form of a possible new EF. After this a comparison is made between the IPCC, the old and the new emis-sion factor. This comparison includes the implications for the emission of CO2. Fi-nally, recommendations for the improvement of the quality or accessibility of in-formation are made.

Before this fuel specific analysis, a general discussion of the requirements for con-sistent CO2 emission calculation is presented. It concerns the consistent application of CO2 measurements, emission factors, emission calculations and procedures for the adoption of national CO2 emission factors.

4.1 Consistency of CO2 calculations

4.1.1 Measurements and factors

A CO2 emission factor as defined by IPCC in terms of ton CO2 per TJ of fuel can-not be measured directly. In fact, the carbon content (in weight %) has to be meas-ured or calculated from the chemical composition. Furthermore, the heating value (in terms of Net Calorific Value, NCV) is necessary to express the amount of fuel in terms of energy instead of mass.

Preferably, the assessment of a national emission factor would consist of an accu-rate combined measurement of a representative sample of fuels in terms of both carbon content and heating value. However, this is only the correct approach if it is consistent with national statistics.

The units to measure amounts of fuels in Dutch statistics are not energy units. Natural gas is measured in standardized m3 of gas (at 0 °C and 1013 mbar), coal and oil products in weight units (ton). The conversion to energy units is performed with standard conversion factors. Up to now, the exception is coal, from which the heating value was measured each year by GKE. However, due to the electricity market liberalisation, GKE will stop per 1 July 2002 the central purchase of coal for the electricity production companies. It is not clear who will measure the coal quality in the future and if these data will continue to be available.

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The use of standard conversion factors has as a consequence that changes in energy consumption due to changes in calorific values are not registered in the national energy statistics. In relation to this, making changes in a national emission factor as a result of a change in calorific value over time introduces an error in the national emission estimation. The only way to avoid both limitations is to use the real (an-nually measured) heating value in both emission factors and national statistics. As long as the national statistics do not use the actual heating values, national emission factors should preferably be calculated using the standard conversion factors as be-ing used in national statistics in order to calculate the correct national emission.

The same holds for local application of the national emission factor. If the local en-ergy consumption has been calculated with a locally measured heating value, the use of a national emission factor in terms of ton CO2 per TJ results in wrong CO2 estimations. In fact it means that in this situation as in the Netherlands, the carbon content is the most accurate, measurable indicator of CO2 emissions, combined with data on the amount of fuel. Therefore, it is recommended that the presentation of CO2 emission factors in terms of ton CO2 per TJ (as recommended by IPCC) is supplemented with carbon contents (weight %) and perhaps standard national net calorific values as used in the national statistics in order to make the background of CO2 calculations transparent and facilitate the proper application of emission fac-tors.

In the early eighties, when the first set of Dutch emission factors were adopted, it has been chosen to adopt rounded numbers since this was in accordance with the uncertainty of the numbers. However, it appears that there is a tendency among in-stitutes or companies to use more accurate numbers, maybe as a result of an in-creasing importance of CO2 emissions within the Netherlands. For instance the CO2 emissions of the transport sector are being calculated with the EF values with one decimal. This is reported only recently in Klein et al. (2002). It is concluded that the present set of emission factors and the application of it is not transparent. Therefore it is recommended to use numbers with one decimal that will be used by all parties. In addition to this, it can be concluded that thorough communication on the good and consistent application of the set of national emission factors is of high importance. Therefore the recommendation is made to draw up a set of guidelines that accompany the set of CO2 emission factors on the proper application of these factors. This last updated version of this set of emission factors, as well as the guidelines, should be communicated broadly. An Internet site is a highly suited way to realise this.

4.1.2 Criteria for adoption of new CO2 emission factors

After analysis of new information and literature sources, eventually leading to a proposition for different value of the CO2 emission factor, it still remains to be de-cided whether the national emission factor will be updated or not. In other words,

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what criteria for adoption of (new) CO2 emission factors have to be used? It is rec-ommended to adopt explicit criteria for adoption of national CO2 emission factors.

The IPCC states in its guidelines that in case a national emission factor has a weak foundation or is based upon obsolete information, the IPCC default value has to be adopted while in the other cases the national value is preferred. According to IPCC, only differences larger than 2% between the national and the default IPCC emis-sion factor have to be explained by documentation.

It is the view of the authors that deviations within a range of 2% of the default IPCC value also have to be explained. This procedure is more correct since unsub-stantiated adjustments downward are being avoided. In other words, all national emission factors have to be documented.

If the new data lead to an insignificant adjustment of the emission factor, the factor presently in use will be kept. Here, an explicit decision has to be made on the de-viation that is being considered as insignificant. Given the different properties of fuels and the different uncertainties ranges attached to the emission factors of fuels, this adjustment range can be very well fuel specific.

Furthermore, in our opinion it is practical not to change emission factors to often. The resulting emission estimation will be more consistent and probably more accu-rate.

In case of a methodological change or drastic variation over time of the CO2 emis-sion factor, recalculation has to take place for historic time series. Recalculation is not presented in the present report.

4.2 Primary solid fossil fuels

Introduction The main consumers of anthracite are the electricity companies and the metal in-dustry (Corus) that produce CO2 emissions in the order of 25 Mton respectively 5 Mton CO2. The electricity companies obtained their anthracite from GKE (NV Gemeenschappelijk Kolenbureau Electriciteitsproduktiebedrijven) a central pur-chase office which supplied from 1987 to 2000 all coal used for electricity genera-tion by the Dutch generating companies. It concerned coal from 6 different conti-nents. From 2001, EON (former EZH) and Electrabel Netherlands (former Epon) withdrew from the central purchase after market liberalisation. Per 1 July 2002, GKE will stop the central purchase of coal. Thus, in the future, information on the national coal quality is only available at the power companies themselves. Because of the increased market competition, it is very well possible that this information is less freely available than in the past for the whole sector.

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Corus Steel (IJmuiden) uses anthracite (metallurgical coal, also called coking coal) for the production of pig iron and imports anthracite from five different countries (USA, Canada, Australia, Poland and Venezuela). A part of the coal is transformed into cokes and cokesoven gas. The cokes are exported in significant amounts (sev-eral tenths of Mton CO2) and the blast furnace gas is sold in amounts equivalent to 1 Mton CO2 to an external power plant (UNA).

Results Power generation The Technical Laboratory Rotterdam takes over 1000 samples annually from coal supplied to power generation in the Netherlands and analyses the coal with respect to calorific value and carbon and sulphur content (among other things) [source: Breman of GKE].

The information provided by the GKE is presented in table 4.1 and 4.2. The last two columns in table 4.1 present the emission factors for CO2 and SO2 respectively, assuming that all carbon and sulphur are oxidised. The data on carbon content and thus CO2 emission factors are only available for the last 3 years. However, we used the relation between carbon content and lower heating value that has been assessed for Dutch coal in the eighties by van der Kooij [KEMA, 1988] to estimate the 1990 carbon content (see also section 3).

The standard deviation of the individual carbon content measurements of the last year was 4.2%. Assuming a standard normal distribution, it can be concluded that the 95% confidence interval of the mean carbon content with 1270 samples is +/-0.4% or a carbon content ranging from 62.4 to 62.9%. The standard deviation of the sulphur content is 1.1%, resulting in a 95% confidence interval of the mean sulphur content of +/-6.7% or a sulphur content ranging from 0.84 to 0.96%.

Looking at all the data on the quality of coal used in power generation, a switch to lower quality coal can be observed over the last decade. In 1990 the net calorific value was considerably higher while the sulphur content was lower compared with the coal used in 2000. One of the reasons is that the abatement technology avail-able is effective in terms of removal efficiency and costs to meet SO2 emission standards and allows for the purchase of cheaper coal.

However, the CO2 emission factor does not follow this development directly. The emission factor merely jumps up and down in a margin around the average value. This is illustrated in figure 4.1, where the relation of van der Kooij on coal of the eighties, our assumption to apply it also on 1990 and the values of GKE for the pe-riod 1998-2000 are presented together in one graph. Clearly, it can be seen that the emission factors of the last years are placed in a range next to the van der Kooij re-lation. Or to put it in other words, the relation assessed by van der Kooij is not ap-plicable at the end of the century because the coal quality and mix has changed completely. The annual fluctuation of the emission factor is sometimes more than the 0.4% deviation of the carbon content.

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The changes in coal are illustrated once more in table 4.2 that presents for each supplier country the shares in total coal supply to the Dutch power generation from 1990 to 2000. The table clearly shows that over the last decade South Africa and Indonesia have taken the place as major coal supplier from Australia and USA.

Table 4.1 The quantity, quality and CO2 and SO2 emission factors of coal supplied to the Dutch power generation sector over the years, under the assumption that oxidation of C and S is complete and not taking into account end-of-pipe abatement technology [source GKE / TLR].

Year Supply C-content S-content Net calorific

value

CO2 emission

factor

SO2 emission

factor

[PJ] [mass-%] [mass-%] [MJ/kg] [ton CO2/TJ] [ton SO2/TJ]

1990 237 67.0 1 0.67 26.60 93.8 1 0.503 1995 238 n.a. 0.66 26.16 n.a. 0.504 1998 225 63.2 0.65 24.24 95.6 0.535 1999 187 64.4 0.81 24.90 94.8 0.650 2000 201 62.6 0.90 24.25 94.7 0.741

1 The carbon content has been derived with the formula by van der Kooij [KEMA 1988] assuming the coal quality and mix in 1988 was similar to those of 1990 (see also figure 4.1).

53

58

63

68

73

92 93 94 95 96 97CO2 emission factor [ton/TJ]

C-content [mass-%]

20

22

24

26

28

30NCV [MJ/kg]

2000

1990

19991998

Figure 4.1 The CO2 emission factors of Dutch coal for the power generation in 1998-

2000 [GKE 2001] presented in combination with the relation between carbon content and net calorific value resulting in CO2 emission factors based upon 55 hard coal samples representing coal consumed in Dutch power stations from 1981 to 1988 [van der Kooij – KEMA 1988].

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Table 4.2 The shares in total coal supply to the Dutch power generation presented by supplier country from 1990 to 2000 [source: GKE].

Supplier country Share of total supply 1990 1995 1998 1999 2000

USA 27 27 2 11 14 Australia 45 22 23 24 8 Colombia 15 16 17 16 16 South Africa 16 22 18 28 Indonesia 2 8 21 17 26 Poland 10 6 11 6 3 China 1 4 Other 1 1 4 8 5 Total 100 100 100 100 100

As has been explained in section 3.1 Interpretation of emission factors, the CO2 emission factors here are in fact carbon emission factors, assuming full combustion of carbon. After calculation of gross CO2 emissions, a correction has to be made for unoxidised carbon in e.g. fly and ground ashes. The reader is referred to Ap-pendix A. In this respect it is interesting to mention the use of biomass (wood chips) in coal fired power plants which is one of the measures to reduce CO2 emis-sions in the Netherlands. Although the CO2 emission factor of this wood is as-sumed to be 0 (since this wood is produced under sustainable conditions), the in-fluence of biomass on the combustion of coal is not known. In this study it is as-sumed to be negligible.

All new coal fired power stations in the Netherlands are fitted with flue gas desul-phurisation units using the wet gypsum process. In this process limestone (CaCO3) is used as flue gas desulphurisation agent. During this process CO2 is generated:

CaCO3 + SO2 -> CaSO4 + CO2

This means that for each molecule of removed SO2 one molecule of CO2 is gener-ated [Okken, ECN 1989]. Since the ratio of molecular masses of CO2 and SO2 is 44/64.1, the emission of 0.741 ton SO2 / TJ in the year 2000 results by flue gas de-sulphurisation with an efficiency of 90% into the following:

Additional CO2 emission factor = 0.741 * 44/64.1 * 0.90 = 0.46 ton / TJ

Accordingly, the coal with lower sulphur content in the year 1990 had a lower ad-ditional CO2 emission factor due to flue gas desulphurisation of 0.3 ton / TJ.

1 Other countries are among others Russia, Venezuela, The Netherlands, Belgium,

Germany, Spitsbergen, Egypt, Nigeria and New Zealand.

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This type of indirect CO2 emission is not taken into account in the emission factor. The same applies for the changes in efficiency of power generation due to flue gas desulphurisation.

Results Iron & steel Also the iron & steel sector measures its solid fuels in terms of carbon. It has ISO certification to do so since the supply and price is related to the amount of carbon in the coal, which is used as reduction substance in the process.

The CO2 emission factors and the underlying data of solid fuels used in the iron & steel sector in the Netherlands are presented in table 4.3. It concerns CO2 emissions in the order of 5 Mton CO2, which is approximately one fifth of the CO2 emissions produced by all solid fuels. Since the data in table 4.3 are for the year 2000 only, the variability of the EF over the years is not deducible from this table.

Table 4.3 The carbon content, Net Calorific Value and resulting CO2 emission factor of solid fuels used by the iron & steel sector in the Netherlands in 2000 [source: Corus and Statistics Netherlands].

Fuel Carbon content NCV 1 CO2 EF

[mass-%] [MJ/kg] [ton / TJ]

coking coal 81.8% 32.304 92.8 injection coal 76.9% 30.248 93.2 cokes 87.8% 28.50 2 113.0 2

1 The Net Calorific Value and carbon content are presented on a dry basis; It should be noted that coal data often refer to wet coal.

2 The NCV was not measured by Corus; the presented value is the standard Dutch NCV from Statistic Netherlands.

The CO2 emission factor of the coal used in the iron & steel is relatively low com-pared to the coal used in Dutch power generation. The coking coal consumption is 3 times that of the injection coal, resulting in an average CO2 emission factor for coal used in the iron & steel sector of 92.9 ton CO2 / TJ. This is also much lower than the present EF of 101 ton CO2 / TJ.

The emission factor of cokes could only be calculated by assuming a Net Calorific Value of 28.5, the value of Dutch cokes in international statistics (source: IEA / OECD 1998). Although this data set is probably not consistent in the sense that in reality the coal does not have this emission factor, it is the correct value for application (see for a more detailed explication and discussion section 4.7 Measurements and factors). The high national value of 113 ton CO2 / TJ indicates together with the default IPCC value of 108 ton / TJ that the present value that is used for cokes, the factor of metallurgical coal of 101 ton / TJ, is too low for cokes. It is more correct to apply a specific factor for cokes, all the more since cokes is ex-ported in significant quantities (approximately equal to one Mton CO2).

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Conclusions The coal mix and quality have changed considerably from year to year. The CO2 emission factor varied also from year to year. It was also significantly different in the power generation and the iron & steel sectors.

The CO2 emission factors in power generation varied from 93.8 to 95.6 ton CO2 / TJ while it was in the iron & steel sector 92.9 ton CO2 / TJ in 2000. The difference from the standard IPCC value of 98.3 is rather large (around 3%).

The changes in supplier countries provide not enough foundation for a quantitative estimation of the change in emission factor. It can only be assessed by regular measurements, such as GKE performs annually. GKE stops as a result of market liberalisation, which means that either the companies themselves or another central body should be made responsible for regular measurements of the coal quality and use this to decide each year whether the CO2 emission factor has to change.

The use of the coal emission factor for cokes is not an accurate proxy of the CO2 emission factor for cokes. Actual measurement of the carbon content in the year 2000 resulted in a national factor for cokes of 113 ton CO2 per TJ. The carbon con-tent is measured continuously by the company itself. These data should be made available on an annual basis.

4.3 Secondary fuels from solid fossil fuels

One iron & steel company (Corus) exists in the Netherlands. It produces coke oven gas and blast furnace gas. Coke oven gas is produced in the coking factory where cokes are produced to feed in the blast furnace. The blast furnace produces pig iron and blast furnace gas. The blast furnace reduces iron ore into iron using the carbon in the coke (combinations with other fuels such as coal or oil injection are possi-ble). A small part of the carbon is mixed with the reduced iron forming pig iron. Relatively large amounts of carbon leave the blast furnace as blast furnace gas (containing carbon monoxide and carbon dioxide in more or less equal quantities). In a next production step, pig iron is converted into primary crude steel where most of the carbon leaves the pig iron in the form of blast oxygen furnace gas (contain-ing high levels of carbon monoxide).

The complexity of this production process already indicates that the composition of these gases can vary substantially. The present documentation of the national emis-sion factor for cokes gas and blast furnace gas is old and not valid anymore. The impact on national emissions of new national emission factors for these energy car-riers is negligible since the emission reporting to the PER of the iron & steel com-pany is based upon a carbon mass balance. This is the most accurate way to esti-mate the CO2 emissions for the sector.

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The CO2 emission factors for these energy carriers are not needed for the Reference approach. However, blast furnace gas (and to a lesser extend cokes gas) is supplied to the UNA power plant in substantial volumes (equivalent to almost 5 Mton CO2). These gas flows are monitored continuously, but the company is reluctant to pro-vide emission factors since it is afraid to be confronted with inaccurate alternative CO2 emission estimates for the company. It is recommended for reasons of trans-parency, however, that the company publishes the measured and applied EF each year.

4.4 Primary liquid fossil fuels

Introduction The Netherlands imports crude oil form all over the world with Norway, Saudi Arabia and United Kingdom being the three largest suppliers, together responsible for more than 60% of the imported oil (see Appendix B). The Netherlands has a number of refineries producing oil products for both the Dutch and foreign market.

Results The IPCC describes a method to estimate the carbon content of crude oil, based upon some properties of crude oil, API gravity and sulphur content, that are gener-ally measured and known of traded crude oils. Therefore and because of their physical and chemical relationship with carbon content, these characteristics can be used to estimate the carbon content of a specific crude.

API is an arbitrary scale designating an oil's specific gravity, or the ratio of the weights of equal volumes of oil and pure water; it is the standard specific gravity scale of the petroleum industry. The API scale has the advantage of allowing hy-drometers, which measure specific gravity, to be calibrated linearly. As volume is dependent on temperature and pressure, these must be specified. In the United States they are generally 60 degrees F (16 degrees C) and one atmosphere (101.3 kPa) pressure. The API gravity scale, whose units are degrees API, does not vary linearly with the specific gravity or its related properties (e.g. viscosity). High spe-cific gravity (SG) values give low API gravity values using the relationship:

SG at 60 degrees F and 1 atmosphere = 141.5 / (degrees API + 131.5)

Water with a specific gravity of 1 has an API gravity of 10 degrees.

The following formula is based on the analyses of 182 crude oil samples and may be used to estimate the carbon content of crude oil (Source: USDOE/EIA. URL: http://www.eia.doe.gov/oiaf/ 1605/gg98rpt/ appendixb.html):

Carbon Content = 76.99 + (10.19 * SG) - (0.76 * Sulphur Content)

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The carbon content (measured in percent weight) is calculated with these formulae for different types of crude oil (e.g. Iranian light, Iranian heavy, Arab medium) by their API values (specific gravities) and sulphur contents.

84,0

84,2

84,4

84,6

84,8

85,0

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000

year

[% carbon content]

72,5

72,6

72,7

72,8

72,9

73,0

EF [ton CO2 / TJ]C-contentEF

Figure 4.2 The carbon content and the CO2 emission factor of crude oil imported in the

Netherlands in the period 1990 to 2000. The CO2 emission factor is calcu-lated with the API method using the standard net calorific value of 42.71 MJ/kg as applied by Statistics Netherlands and monthly data on carbon con-tent [IEA 2002].

Figure 4.2 presents the inferred carbon content and the implied CO2 emission factor of average crude oil imports in the Netherlands in the period 1990 to 2000. The sta-tistics register crude oil in ton. The heating value is not monitored annually. In-stead, the standard NCV applied by the Dutch statistic of 42.71 MJ/kg is used. The emission factor varies within a small band of 0.15 ton CO2 per TJ around an aver-age value of 72.73 ton CO2 per TJ. This is slightly lower than the rounded value of 73 that has been used for Dutch imported crude oil in the Reference emission cal-culation. The effect on national emissions can be in the order of 0.1%. The underlying data are presented in table 4.4.

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Table 4.4 API degrees, sulphur content, inferred carbon content, CO2 emission factor and standard deviation of the EF based upon the monthly measurements of the carbon content [IEA 2002].

Year API S-content 1 C-content EF 2 Standard

[degrees] [%] [%] [ton CO2 / TJ] deviation

1990 33.19 1.35 84.72 72.73 0.009 1991 32.94 1.35 84.73 72.74 0.005 1992 32.89 1.35 84.74 72.75 0.007 1993 32.58 1.35 84.75 72.76 0.004 1994 32.82 1.45 84.66 72.68 0.027 1995 33.20 1.32 84.74 72.75 0.016 1996 33.26 1.27 84.78 72.78 0.011 1997 33.43 1.34 84.71 72.73 0.024 1998 33.32 1.44 84.64 72.67 0.018 1999 33.91 1.36 84.67 72.69 0.017 2000 33.89 1.25 84.76 72.76 0.022

1 Due to a lack of data the average sulphur content value of the period 1994-2000 has been used for the period 1990-1993.

2 Calculated using a NCV = 42.71 MJ/kg.

The import mix of the Netherlands has an average carbon content of 84.7%, which is in the lower part of the international spectrum (see Appendix B for the inferred carbon content of average crude oil imports in 1998 by selected countries listed in Annex II of the UNFCCC. However, it should be noted that measured values may differ from this stylised relation.

Over the years 1999 and 2000, the countries that supplied oil to the Netherlands have changed (see also Appendix B) considerably. As table 4.4 has illustrated, the change in oil quality was not very large: the sulphur content of imported oil in the Netherlands and the gravity of the oil have in general counter balancing effects on the carbon content, which remains more or less constant.

4.5 Secondary fuels from liquid fossil fuels

Light oil products Light oil products are subject to a large number of specifications and are accord-ingly measured in a large number of ways. However, it is not common practice to measure the carbon content and the NCV on a regular basis. This makes it difficult to estimate national CO2 emission factors for light oil products directly.

The specifications for gasoline for example concern among other things the maxi-mum weight % of aromates (after 2004 lowered from 42% to 35%) and olefins (18%), the maximum fuel boiling point (210 °C) and the density (720-775 kg/m3). Especially the density is a property that is a useful indicator for the carbon content. In principle, a producer would like to reduce the density as much as possible in or-der to sell as much liters as possible. In practice, however, over summer and winter

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the density of distilled products changes and can vary over the full range. It is con-sidered to be confidential information since it touches upon the competitiveness of refineries [source: J.C.D. Boot of VNPI].

These ranges of specifications are being declared at EU level and are becoming more specific over time, herewith narrowing down the variation in oil products in general and their carbon contents in particular. This seems to be confirmed by the CO2 emission factors used in other countries. The Dutch emission factors are in general closer to the EU average values than to the Annex I average values (see ta-ble 4.5 and for more data also Appendix B). The Dutch emission factors are gener-ally higher than the EU values, while the EU values are higher than the average Annex I values. The Dutch country specific values are closer to the EU average values than the IPCC default values. This could be viewed as an indication that the Dutch country specific values are a better proxy for CO2 emission factors within the EU than the IPCC default values.

Table 4.5 Comparison of Dutch, EU average, Annex I average and IPCC default CO2 emission factors of oil products for 1999 [source: CRF 2001 of Annex I countries].

Party Aviation Gasoline

Diesel Oil

Gas / Diesel

Oil

Gasoline Jet Kero-sene

LPG Residual Oil

[ton CO2 / TJ]

Netherlands 73.3 73 72.3 73 66.4 77 EU average 71.7 73.3 73.3 71.6 71.1 65.0 76.9 Annex I average 72.2 72.8 72.8 70.8 70.8 63.5 71.1 IPCC default 74.1 69.3 71.5 63.1 77.4

Despite this ‘circumstantial evidence’, it should be concluded that a sufficient basis for estimating Dutch CO2 emission factors for oil products is lacking at the mo-ment, since oil companies do not monitor the carbon content and NCV of oil prod-ucts supplied to the Netherlands [source: J.C.D. Boot of VNPI]. These factors can be improved, in particular for application at European Union scale. Therefore, it is recommended that oil products are measured at a European scale in order to assess an accurate set of CO2 emission factors for oil products, preferably in relation to present specifications. This way it becomes clear when, e.g. after which change in specification regulation, an update of measurements will be needed.

In the case the default set of IPCC CO2 emission factors for several light oil prod-ucts is used, national emissions would decrease with 0.3%. However, the distribu-tion over different fuel types and sectors is quite different when IPCC values are used. Gasoline emissions would decrease substantially, while gas oil emissions would increase.

The compositions of petroleum cokes highly depend on feedstock and type of process used. In general petroleum cokes contain some portions of all the elements,

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which existed in the original feedstock. At the moment, there exists no basis for upholding a specific national emission factor. The impact on national emissions would be negligible.

Theoretically, a large impact could be expected from the shift towards the IPCC default CO2 emission factors for refinery gas, since the national factor is much lower than the IPCC default value (46 versus 66.7 ton CO2 / TJ). The impact on emissions could theoretically 1.5%, but is expected to be none in practice.

The reason for this is that in practice, the emission factors for both refinery gas and petrocokes are not used for the national emission inventory, since the refineries de-liver their emissions based upon a carbon balance calculation [source: P. van Dries-ten of Exxon]. This is much more exact. For control calculations, both the default IPCC values and the national values can be used given the large uncertainties of the annual emission factor if no additional information of measurements is available. It is recommended, however, to publish every year the emission factors based upon measurements and calculations according to the mass balance method applied by the company itself.

4.6 Primary Gaseous fossil fuels

Introduction The use of natural gas is widely spread in the Netherlands, it meets half of the country's energy requirement. The major part of the natural gas originates from the large Groningen gas field and from the smaller fields, some onshore and some off-shore in the Dutch sector of the North Sea. This gas is excavated and purified by the Dutch Petroleum Company (NAM) and sold to the N.V. Nederlandse Gasunie, which was the sole gas trading and transmission company in the Netherlands be-fore the recent gas market liberalisation. Evidently, the Dutch emission factor for natural gas was based upon an analysis of the quality of gas of Gasunie. Although Gasunie also imports gas from other European countries such as Norway, Ger-many, Russia and United Kingdom, the gas quality is kept more or less constant and is in any case controlled by Gasunie.

However, due to the growing liberalization, in 1999 Gasunie has lost industrial sales up to almost 5 billion m3 of gas to other suppliers. Thus, the total Dutch mar-ket share of Gasunie has been reduced to 90% in 1999 and is expected to decrease further to 75% in 2003 [Gasunie Annual Report 1999].

In the North of the country, 2 billion m3 of gas is imported from Statoil (Norway) by the electricity sector each year for combustion in the Eems power station [Ga-sunie Annual Report 1999]. About 0.7 billion m3 of gas from the UK has been bought by the utility company Delta, mainly transported in its own branch of the Zebra-pipeline and sold to customers in the Southwest region of the Netherlands

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[Energie Verslag Nederland 1998]. In these cases, the quality of foreign gas deter-mines the emission factor.

Results Different types of natural gas can be distinguished; the so called Groningen gas (G-gas) from the large Groningen gas field, gas of high calorific value (H-gas) from many of the smaller gas fields and gas of low calorific value (L-gas) also from some of the smaller gas fields. Since the gas appliances of nearly all Dutch con-sumers at the time when the small fields came on stream were designed for G-gas, this became the standard for gas supply to distribution companies and further on to small consumers. Part of the High calorific gas is introduced into the Groningen gas pipelines after conversion to Groningen quality in blending stations. The rest of the High calorific value gas is supplied directly to large consumers with equipment designed to burn H-gas. Import from other European countries also concerns H-gas. However, Statistics Netherlands does not distinguish different types of gas in the monitoring of natural gas consumption. It also uses a standard Net Calorific Value of 31.65 MJ / m3 natural gas equivalent.

Natural gas consists of a mixture of hydrocarbons and non-hydrocarbons. In table 4.6 the different components of Groningen gas and High calorific gas are listed to-gether with their NCV, percentage and finally their EF and the total EF. Also, the data of Marland & Rotty (1984), which founded the default IPCC emission factor value, have been included for comparison under the heading ‘IPCC’. The differ-ence in mix between G- and H-gas is minimal and the only differences between the two of them of significance are the amount of CO2 and the amount of nitrogen. The amount of nitrogen in H-gas is substantially lower (3.5% instead of 14%) which leads to higher shares of organic components (similarly distributed as in Groningen gas) resulting in higher calorific values. So, these changes do not or hardly affect the emission factor. Therefore, using a standard NCV does not cause a problem. The slightly higher CO2 content, however, does cause a small difference in the emission factor of approximately 0.3 kg/GJ.

One difference between G-gas and H-gas is not included in the table. Groningen gas is often odorised by distribution companies with tetra hydro thiophene (C4H8S) since it is supplied to households. This is done in very small amounts (18 mg/m3) and is negligible in terms of CO2 (+/- 0.002%) and SO2 (0.41 g/GJ).

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Table 4.6 The CO2 emission factor of Groningen (G-) gas, High calorific (H-) gas and the gas used for the IPCC default emission factor, calculated as the weighed sum of emission factors of different chemical components, assuming complete oxidation [Source: Physical properties of natural gases, 1980, composition High calorific gas K. Dijkstra (Gasunie), gas IPCC according Marland & Rotty 1984].

Component Net Calorific

Value

Emission Factor of

component

Content of components

[% mol]

Contribution to Emission Factor of gas

[kg CO2/GJ]

[MJ/kmol] [kg CO2/GJ] G- gas H- gas IPCC G- gas H- gas IPCC

CH4 802 54.84 81.3% 91.0% 92.9% 50.5 50.4 50.2 C2H6 1428 61.63 2.9% 3.3% 3.9% 3.6 3.7 4.2 C3H8 2044 64.58 0.4% 0.4% 0.6% 0.7 0.7 1.0 C4H10 2657 66.24 0.2% 0.2% 0.0% 0.4 0.4 0.0 C5H12 3272 67.24 0.0% 0.0% 0.0% 0.1 0.1 0.0 C6H14 3887 67.92 0.1% 0.1% 0.0% 0.2 0.2 0.0 N2 0 0.00 14.3% 3.5% 1.4% 0.0 0.0 0.0 O2 0 0.00 0.0% 0.0% 0.0% 0.0 0.0 0.0 CO2 0 0.00 0.9% 1.5% 1.2% 1 0.6 0.8 0.6 Total gas n.a. n.a. 100.0% 100.0% 100.0% 56.0 56.3 56.1

G-gas: Groningen gas from the Groningen gas field in the North of the Netherlands H-gas: High calorific gas IPCC: the composition of ‘average’ natural gas in 1976 as calculated by Marland & Rotty, 1984. 1 The exact CO2 content is not known; only the amount of non-hydrocarbons has been traced.

The composition of the British H-gas complies in general with the “standard” Dutch high calorific natural gas. The only difference is the amount of CO2 in the gas. In the contract between the British supplier and Delta the supplier commits it-self to a maximum molecular percentage of 3%. In reality the amount of CO2 in the gas is between 0.61% and 1.21% (average 0.91%) [source: N.V. Delta Nutsbedrij-ven, J. op het Hof, 7-1-2002]. A margin of 0.6% gives a spread in emission factor of approximately 0.3 kg/GJ.

Apart from the CO2 in the gas, of course, the relative shares of smaller and larger hydrocarbons determines the overall emission factor, where large shares of larger hydrocarbons tend to increase the emission factor and high shares of methane tend to decrease the emission factor. For example natural gas from Russia contains a high amount of methane and less larger hydro carbons, possibly resulting in a rela-tively low CO2-emissionfactor [source: K. Dijkstra, Gasunie]. Pure methane has an emission factor of 54.84 ton CO2 / TJ, which is the lowest value (neglecting possi-ble CO2 in the gas). The relative changes in shares, however, have to be substantial to have a noticeable impact on the natural gas emission factor, since the values of emission factors of the components hardly differ.

Given the differences in CO2 content and the hydrocarbon mixture as described above, the ranges around the relative shares are small and are estimated to result in ranges in the emission factor of plus or minus 1% [source: K. Dijkstra of Gasunie]. This is consistent with observations based upon large samples [DOE / EIA, 1984].

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However, this range is not monitored regularly since the Gasunie monitors its gas supply on the basis of the Wobbe-index, a combination of heating value and pres-sure.

In a liberalised gas market, the quality of the supplied gas can vary by source. However, when transactions will take place on a larger scale, it is difficult to esti-mate the actual origin and quality of the gas. Chances are high that gas imports will consist of natural gas from relatively nearby sources, although according the con-tract the gas might be from a distant supplier. The liberalisation of the energy mar-ket results in a lot of trade on paper rather than the actual mixing of different types of natural gas. The actual source, however, will become increasingly unclear.

This means that actual measurement of the gas quality by means of a representative sample of end-users is the only really accurate option to estimate the CO2 emission factor of gas in a completely liberalised gas market.

Conclusions The CO2 emission factors calculated for the two networks for small and large con-sumers are 56.0 and 56.3 ton CO2 / TJ, mainly caused by different CO2 contents of the gas. However, gas consumption is not monitored by gas type. The range of un-certainty is estimated to be plus or minus 1%. In fact, both values and the IPCC de-fault value of 56.1 ton CO2 / TJ lie within this range. Therefore, it is recommended to maintain the national value of 56 ton CO2 / TJ for all natural gas within the Netherlands.

It is also recommended to measure natural gas quality on a regular basis. Especially in a liberalised market, the actual source of the gas will become increasingly un-clear. At present, gas supply is measured on the basis of the Wobbe-index and this is not a good proxy for the monitoring of the CO2 emission factor. Especially the CO2 content of the gas can cause deviations that are not noticed in the Wobbe-index. Furthermore, the increasing import of British, Russian and Norwegian gas could also lead to changes in the gas composition that remain unnoticed, but it is expected that the actual import of gas from large distances will remain limited. Es-pecially direct imports from suppliers competing with Gasunie, that deliver their gas directly to their large clients, can have an impact on the average gas composi-tion consumed in the Netherlands.

4.7 Other fuels

Biomass (solid, liquid, gaseous) is only considered by IPCC for information pur-poses and is not accounted in the national CO2 emission estimation. Natural gas liquids are not used in the Netherlands.

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5. Conclusions & recommendations

The objective of this study was to evaluate the documentation and validity of the present national set of CO2 emission factors of the Netherlands and to analyse the currently available information in the literature and at companies in order to make recommendations for adoption, maintenance and further improvement of reliable, well-founded and documented CO2 emission factors for fuels used in the Nether-lands. This report is a discussion paper and provides the information basis for deci-sions on the set of national CO2 emission factors to be taken by the Project group CO2 monitoring. For some fuels, it might be necessary to perform additional re-search or measurements.

It is the view of the authors that all national emission factors have to be docu-mented. According to the IPCC guidelines, only deviations larger than 2% of the default IPCC value of CO2 emission factors have to be explained. In order to avoid arbitrary and unsubstantiated adjustments downward, we believe all national emis-sion factors should be documented.

The IPCC Reference Approach applies national CO2 emission factors on national fuels statistics. These national CO2 emission factors are based on either national values or default IPCC values. The Reference approach only distinguishes ex-tracted, imported and exported fuels. This means that secondary fuels that are being converted within the country and remain within the country are not viewed in this approach. For the Netherlands it concerns fuels such as petrocokes, refinery gas, blast furnace gas, cokes gas and chemical residue gas.

In the Detailed Technology based approach, national emission factors are being used for natural gas and oil products, presently resulting in approximately 75% of national CO2 emissions. CO2 emissions from primary solid fuels and the aforemen-tioned internally produced secondary fuels are presently not calculated on the basis of national emission factors but on the basis of locally measured carbon contents (emission factors) or carbon mass balances. However, the national emission factors for these fuels are used in control calculations and other analyses by research insti-tutes.

It is recommended that the presentation of CO2 emission factors in terms of ton CO2 per TJ (as recommended by IPCC) is supplemented with carbon contents (weight %) and standard national net calorific values as used in the national statis-tics in order to make the background of CO2 calculations transparent and facilitate the proper application of emission factors. It should be avoided that national emis-sion factors are used or assessed with inconsistent local Net Calorific Values.

The following conclusions can be summarised for the different fuel types.

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Coal The mix and quality of coal used in the power generation sector have changed con-siderably from year to year during the last decade. The CO2 emission factors in power generation varied from 93.8 to 95.6 ton CO2 / TJ while the present national emission factor for coal is 93.8 ton CO2 / TJ. The difference with the standard IPCC value of 98.3 is rather large.

The CO2 emission factor for coal in the iron & steel sector was 92.9 ton CO2 / TJ in 2000. This indicates that the national EF of 101 ton CO2 per TJ as presently applied for the steel sector is not a valid factor anymore.

The present use of the coal emission factor of 101 ton CO2 / TJ for cokes is not an accurate proxy of the CO2 emission factor for cokes. Actual measurement of the carbon content in the year 2000 resulted in a national factor for cokes of 113 ton CO2 per TJ. The IPCC emission factor is 108 ton CO2 / TJ.

The changes in supplier countries provide not enough foundation for a quantitative estimation of the change in emission factor. It can only be assessed by regular measurements, such as up to now have been performed annually for the power sec-tor by GKE and the iron & steel sector by the company itself.

Crude oil Using the API gravity method and the Dutch statistical standard Net Calorific Value of 42.71 MJ/kg, the emission factor for Dutch imported crude oil varies in the period 1990 to 2000 within a small band of 0.15 ton CO2 per TJ around an av-erage value of 72.73 ton CO2 per TJ. This is slightly lower than the rounded value of 73 that has been used for Dutch imported crude oil in the Reference emission calculation. The effect on national Reference emissions is in the order of 0.1%.

Oil products The specifications for gasoline and other oil products are being declared at EU level and are becoming more specific over time, herewith narrowing down the variation in oil products in general and their carbon contents in particular. This seems to be confirmed by the fact that the Dutch country specific values are more close to the EU average values than the IPCC default values. Following IPCC de-fault CO2 emission factors would lead to an overall decrease of national emissions of 0.3%. Gasoline emissions would decrease while gas oil emissions would in-crease.

It is concluded, however, that a sufficient data basis for estimating national CO2 emission factors for oil products is presently lacking. Therefore, it is recommended that oil products are being measured at a European scale in order to assess an accu-rate set of CO2 emission factors for oil products, preferably in relation to present product specifications.

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Natural gas The CO2 emission factors calculated for the two networks for small and large con-sumers are 56.0 and 56.3 ton CO2 / TJ, mainly caused by different CO2 contents of the gas. A national value of 56 ton CO2 / TJ is being used. The range of uncertainty is estimated to be plus or minus 1%. Both the national value and the IPCC default value of 56.1 ton CO2 / TJ lie within this range.

It is recommended to measure natural gas quality on a regular basis. At present, the gas supply is measured on the basis of the Wobbe-index which is not a good proxy for the monitoring of the CO2 emission factor. Especially the CO2 content of the gas can cause deviations that are not noticed in the Wobbe-index. The import of British, Russian and Norwegian gas could also lead to changes in gas composition that remain unnoticed in the present situation.

Cokes oven gas, blast furnace gas, refinery gas and petrocokes Refineries and the iron and steel sector base their individually reported emissions of cokes oven gas, blast furnace gas, refinery gas and petrocokes upon a carbon balance calculation. The carbon content as well as the Net Calorific Value of these fuels can vary substantially. Unfortunately, the companies have not provided emis-sion factors for these fuels.

Although the national CO2 emission factors for these gases are used for control purposes only, it is recommended to provide full transparency and publish every year the emission factors based upon measurements and calculations by the com-pany itself.

Responsibility for the assessment of CO2 emission factors The national government is responsible for the establishment and maintenance of a set of national CO2 emission factors. Especially in a liberalised energy market, the actual source and the composition of fuels will become increasingly unclear. It is recommended to measure the quality (i.e. the carbon content and the Net Calorific Value) of fuels on a regular basis. In order to make a reasonable estimate of the CO2 emission factors at national level, representative samples have to be measured at end-users, preferably by an independent organisation. It depends on the fuel how often a useful update has to take place. This information can be used to decide each year whether the national CO2 emission factor has to change.

The national CO2 emission factors can be viewed, in analogy with the IPCC ap-proach, as default factors. As a standard, these factors are used by all parties in-volved in the monitoring process, being it the Reference approach or the Detailed Technology approach. If individual companies have a preference to use different, company specific CO2 emission factors, these companies have the obligation to document and explain the specific emission factor and provide full transparency on the background of the emission calculation, also in analogy with the IPCC ap-proach. In our view, this documentation should be included in the annual environ-

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mental reporting that large energy consuming and producing companies are obliged to provide in the framework of the Pollutant Emission Register.

Adoption criteria It is recommended to adopt explicit criteria for adoption of national CO2 emission factors.

For instance, an explicit decision has to be made on the allowed deviation before adoption of a new emission factor becomes necessary. Important in this respect would be the uncertainty attached to the values of the CO2 emission factor. Given the different properties of fuels, this allowed deviation should be fuel specific.

Also practical reasons can influence the allowed deviation range: e.g. it is practical not to change emission factors to often. For instance, in case of a methodological change or large variation over time of the CO2 emission factor, it is recommended to recalculate the CO2 emissions for historic time series of years for those fuels. Furthermore, changes will have to be communicated to the users. A stable set of national emission factors will result in more consistent and probably more accurate emission estimations.

Although the uncertainty of CO2 emissions is often in the order of 1 ton CO2 / TJ or more, it appears that there is a tendency among institutes or companies to use more accurate numbers, maybe as a result of an increasing importance of CO2 emissions. Therefore it is recommended to specify emission factors in numbers with one decimal that will be used by all parties, although this does not reflect the accuracy of the values.

Guidelines It can be concluded that thorough communication on the right and consistent appli-cation of the set of national emission factors is of high importance. Therefore the recommendation is made to draw up a set of guidelines on the proper application of these factors to accompany the set of national CO2 emission factors. The last up-dated version of the set of emission factors, as well as the guidelines, should be communicated broadly in the framework of obligatory annual environmental re-porting for the PER. An Internet site is a highly suited way to realise this.

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6. References

Literature

[1] Amstel, van, et al. (eds.), 2000: Monitoring of Greenhouse Gases in the Netherlands: Uncertainty and Priorities for Improvement, Proceedings of a National Workshop, Bilthoven, The Netherlands, 1 September 1999, WIMEK/RIVM report 773201 003, July 2000.

[2] Blok, K. et al, CO2 emissiefactoren voor brandstoffen in Nederland, NWS/RU Utrecht, ESC/ECN ESC-WR-88-12, Petten, 1988

[3] CBS 1991, De Nederlandse energiehuishouding, jaarcijfers 1990, Centraal Bureau voor de Statistiek Voorburg/Heerlen, ISBN 90357133 1, ISSN 0923-201X

[4] Coenen and Bakker, 2000: Kwaliteit van emissiedata broeikasgassen in de individuele emissieregistratie ERI, TNO-MEP rapport CR 2000/276 (concept), juli 2000.

[5] DOE / EIA, 1984: Emissions of Greenhouse gases in the United States 1987-1992, DOE/EIA-0573, Washington DC.

[6] Gasunie, 2000: Gasunie Annual Report 1999

[7] Gasunie; Physical properties of natural gas; June 1988.

[8] 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, Paris, France.

[9] IPCC, 1996: Revised 1996 Guidelines for National Greenhouse Gas Inventories, Workbook and Reference Manual.

[10] IPCC, 2000: Good Practice Guidance And Uncertainty Management In National Greenhouse Gas Inventories.

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[11] IPCC/OECD, 1993: IPCC/OECD Workshop on National GHG Inventories: Transparency in Estimation and Reporting, 1 October, 1992, Bracknell, UK. IPCC/OECD Joint Programme on National GHG Inventories, Intergovernmental Panel on Climate Change and Organisation for Economic Co-operation and Development, Paris, France.

[12] Klein, J. et al., 2002: Methoden voor de berekening van de emissies door mobiele bronnen in Nederland, Rapportagereeks MilieuMonitor, nr. 4.

[13] Kooij, van der, KEMA, Arnhem, 16 February 1988

[14] Marland, G. and R.M. Rotty, 1984: Carbon dioxide emissions from fossil fuels: A procedure for estimation and results for 1950-1982, Tellus, Vol. 36B, pp. 232-261.

[15] OECD, 1991: Estimation of Greenhouse Gas Emissions and Sinks; Final Report from OECD Experts Meeting 18-21 February 1991. Prepared for the IPCC, Paris, France.

[16] Okken, P. A. and D.N. Tiemersma, Greenhouse gas emission coefficients from the energy system, two methods to calculate national CO2 emissions, ECN, Petten 1989

[17] Olivier et al., 2000: Greenhouse Gas Emissions in the Netherlands: summary report 1990-1998 (IPCC tables 1-7), RIVM-rapport 773201 002, July 2000.

[18] P.G. Dougle et al., 1999: Energie Verslag Nederland 1998, Energy research Centre of the Netherlands.

[19] PBNA, Poly-energie zakboekje, Arnhem, 1986

[20] RIVM (1999): Review RIVM-instrumentarium Milieubalans 1999, (see a.o. review Turkenburg & van der Sluijs, NW&S, 4. De behandeling van onzekerheden), RIVM rapport 25170137, RIVM, Bilthoven.

[21] Spakman et al., 1997: Methode voor de berekening van broeikasgasemissies, Publicatiereeks Emissieregistratie, nr. 37.

[22] Zonneveld, E.A., 1985, Uitworp van kooldioxide door het stoken van fossiele brandstoffen, 1983. Kwartaalbericht milieustatistieken, CBS, 1985/4.

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Personal communication 1. Corus (former Hoogovens), Mr. R. Boonacker 2. EnergieNed, Mr. Dr. van der Kooij 3. Exxon Mobil, Mr. P. van Driesten 4. Gasunie Research, Mr. R. Aptroot & Mr. K. Dijkstra 5. N.V. Delta Nutsbedrijven, Mr. J. op het Hof 6. Stichting Basismetaalindustrie en Milieu, Mr. J. Weening 7. Vereniging voor Nederlandse Petroleum Industrie, Mr. J.C.D. Boot 8. Vliegasunie / GKE, Mr. J. van den Berg / Mr. J. Breman 9. VNCI, afd. Voorlichting, Mr. E. von der Meer

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7. List of Abbreviations

CEF Carbon Emission Factor

EIS Emission Inventory System

EF Emission Factor

FCCC Framework Convention on Climate Change

GCV Gross Calorific Value

GKE Gemeenschappelijk Kolenbureau Electriciteitsproduktiebedrijven (Common Coal Bureau for Dutch Power companies)

IPCC Intergovernmental Panel on Climate Change

NCV Net Calorific Value

PER Pollutant Emission Register

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8. Authentication

Name and address of the principal:

Novem Ministry of VROM Project group CO2 monitoring

Names and functions of the cooperators:

Drs. A.K. van Harmelen Ing. W.W.R. Koch

Names and establishments to which part of the research was put out to contract:

-

Date upon which, or period in which, the research took place:

May 2001 to March 2002

Signature: Approved by:

Ir. D.C. Heslinga H.S. Buijtenhek, M.Sc. Project Leader Head of Department

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Appendix A

Appendix A The IPCC CO2 methodology

Introduction There are three methods provided in the IPCC Guidelines, Chapter 1, Energy: two Tier 1 approaches (the ‘Reference Approach’ and the ‘Sectoral Approach’) and the Tier 2/Tier 3 approach (a detailed technology-based method, also called ‘bottom-up’ approach). The Reference Approach estimates CO2 emissions from fuel com-bustion in several steps: 1. Estimation of fossil fuel flow into the country (apparent consumption); 2. Conversion to carbon units; 3. Subtraction of the amount of carbon contained in long-lived materials manu-

factured from fuel carbon; 4. Multiplication by an oxidation factor to discount the small amount of carbon

that is not oxidised; 5. Conversion to CO2 and summation across all fuels.

For the Tier 1 Sectoral Approach, total CO2 is summed across all fuels (excluding biomass) and all sectors. For Tiers 2 and 3, the Detailed Technology-Based Ap-proach, total CO2 is summed across all fuels and sectors, plus combustion tech-nologies (e.g. stationary and mobile sources). Both approaches provide more dis-aggregated emission estimates, but also require more data.

The choice of method is country-specific and is determined by the level of detail of the activity data available. The ‘bottom-up’ approach is generally the most accurate for those countries whose energy consumption data are reasonably complete. Con-sequently, inventory agencies should make every effort to use this method if data are available.

The Netherlands provides two estimations to the IPCC, viz. the Reference ap-proach and a Bottom-up estimate using data from sectors and plants (Tier 2 and 3). The latter is partly based upon emission monitoring at individual plants and com-panies in the framework of the national Pollutant Emission Register (PER). The Reference Approach provides only aggregate estimates of emissions by fuel type distinguishing between primary and secondary fuels, whereas the Detailed Tech-nology-based Approach allocates these emissions by source category. The aggre-gate nature of the Reference Approach estimates means that stationary combustion emissions cannot be distinguished from mobile combustion emissions. Estimates of emissions based on the Reference Approach will not be exactly the same as esti-mates based on the Detailed Technology-based Approach. The two approaches measure emissions at differing points and use slightly different definitions. How-ever, the differences between the two approaches should not be significant.

Sources of differences between top-down and bottom-up estimations are the differ-ent data available on products and technological combustion circumstances, which

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Appendix A

are relevant to carbon fixation (storage) and oxidation. Both carbon storage and oxidation can be very process specific. This means that emission factors that cover also carbon storage and oxidation, differ substantially at various aggregation levels.

The default values for carbon oxidation and fixation should be addressed in relation with technological processes and not only fuels. The next paragraphs elaborate on these process specific factors.

Choice of emission factors and calorific values Carbon dioxide emission factors (EF) for fossil fuel combustion depend upon the carbon content of the fuel. The carbon content of a fuel is an inherent chemical property (i.e. fraction or mass of carbon atoms relative to total number of atoms or mass) and does not depend upon the combustion process or conditions. The energy content (i.e. calorific value or heating value) of fuels is also an inherent chemical property. However, calorific values vary more widely between and within fuel types, as they are dependent upon the composition of chemical bonds in the fuel. Net Calorific Values (NCVs) measure the quantity of heat liberated by the com-plete combustion of a unit volume or mass of a fuel, assuming that the water result-ing from combustion remains as a vapour, and the heat of the vapour is not recov-ered. Gross calorific values, in contrast, are estimated assuming that this water va-pour is completely condensed and the heat is recovered. Default data in the IPCC Guidelines are based on NCVs.

Emission factors for CO2 from fossil fuel combustion are expressed on a per unit energy basis because the carbon content of fuels is generally less variable when expressed on a per unit energy basis than when expressed on a per unit mass basis. Therefore, NCVs are used to convert fuel consumption data on a per unit mass or volume basis to data on a per unit energy basis.

Carbon content values can be thought of as potential emissions, or the maximum amount of carbon that could potentially be released to the atmosphere if all carbon in the fuels were converted to CO2. As combustion processes are not 100 percent efficient, though, some of the carbon contained in fuels is not emitted to the atmos-phere. Rather, it remains behind as soot, particulate matter and ash. Therefore, an oxidation factor is used to account for the fraction of the potential carbon emissions remaining after combustion.

For traded fuels in common circulation, it is good practice to obtain the carbon content of the fuel and net calorific values from fuel suppliers, and use local values wherever possible. If these data are not available, default values can be used.

Generally, default oxidation factors for gases and oils are known accurately. For coal, oxidation factors are dependent on the combustion conditions and can vary by several percent. It is good practice to discuss the factors with local users of coal

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Appendix A

and coal products. However, default factors are also provided in the IPCC Guide-lines.

Estimate Carbon Unoxidised During Fuel Use A small part of the fuel carbon entering combustion escapes oxidation but the ma-jority of this carbon is later oxidised in the atmosphere. It is assumed that the car-bon that remains unoxidised is stored indefinitely. Based on work by Marland and Rotty (1984), since 1991 the IPCC has been recommending that 1 per cent of the carbon in fossil fuels would remain unoxidised. This assumption was based on the following findings from Marland and Rotty for the amount unoxidised: − For natural gas, less than 1 per cent of the carbon is unoxidised during combus-

tion and remains as soot in the burner, stack, or in the environment. − For oil 1.5% ±1% passes through the burners and is deposited in the environ-

ment without being oxidised. This estimate is based on 1976 US statistics of emissions of hydrocarbons and total suspended particulates.

− For coal 1% ±1% of carbon supplied to furnaces is discharged unoxidised, primarily in the ash.

However, several countries have commented that the amount of carbon remaining unoxidised is more variable than indicated by the 1 per cent assumption across all fuels. For example, it has been noted that the amount of unburnt carbon varies de-pending on several factors, including type of fuel consumed, type of combustion technology, age of the equipment, and operation and maintenance practices1.

Information submitted by the Coal Industry Advisory Board of the OECD (Sum-mers 1993), provided the following observations for coal combustion technologies: − Unoxidised carbon from electric power stations in Australia averaged about 1

per cent. Test results from stoker-fired industrial boilers, however, were higher, with unoxidised carbon amounting to 1 to 12 per cent of total carbon with coals containing from 8 to 23 per cent ash. As average values, 2 per cent carbon loss was suggested for best practices, 5 per cent carbon loss for average practices, and 10 per cent carbon loss for worst practices. In those cases when coal is used in the commercial or residential sectors, carbon losses would be on the order of 5 to 10 per cent (Summers, 1993).

− In related work British Coal has provided information on the percentage of un-burnt carbon for different coal combustion technologies: − Pulverised Coal 1.6%

1 E.g. 0.6% of total carbon could remain in fly ash, assuming an ash content of

12% and a share of 90% of fly ash with a 5% carbon content; Also, carbon could remain in ground ash. The amount and timing of the emission of carbon depends on the (way of) use of the ashes [Personal communication P. Kroon, ECN]. One of the measures to reduce CO2 emissions in the Netherlands is the use of biomass (wood chips) in coal fired power plants. Although the CO2 emission fac-tor of this wood is assumed to be 0 (since this wood is produced under sustain-able conditions), the influence of biomass on the combustion of coal is not known. In practice it is often assumed to be negligible.

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Appendix A

− Travelling Grate Stoker 2.7-5.4% − Underfeed Stoker 4.0-6.6% − Domestic Open Fire 0.6-1.2% − Shallow Bed Advanced Fluidised Bed Combustion Up to 4.0% − Pressurised Fluidised Bed Combustion / Circulating FBC 3.0%

− Evaluations at natural gas-fired boiler installations indicate that combustion ef-ficiency is often 99.9 per cent at units reasonably well-maintained.

It is clear from the available information that a single global default assumption of 1 per cent unoxidised carbon is not always accurate. While some additional infor-mation is available to refine the assumptions for this portion of the methodology, most of the new information requires some level of detail on the type of technology in which the fuel is combusted or information on which sector is consuming the fuel. The Reference Approach requires data only on the amount of fuels consumed in a country, not data by technology type or sector of the economy. As a result, based on the information available at this point, the default values presented in Ta-ble A.1 are recommended for the percentage of carbon oxidised during combustion by fuel. It should be recognised that the value for coal is highly variable based on fuel quality and technology types. National experts are encouraged to vary this as-sumption if they have data on these factors, suggesting that different average val-ues for their countries are appropriate. It is clear from the information available at this time that additional research should be conducted on this topic.

Table A.1 Recommended default values for the fraction of carbon oxidised in fuel com-bustion [source: IPCC Guidelines 1996].

Fuel Oxidation fraction

Coal (a) 0.98 Oil and oil products 0.99 Gas 0.995 Peat for electricity generation (b) 0.99

(a) This figure is a global average but varies for different types of coal, and can be as low as 0.91.

(b) The fraction for peat used in households may be much lower.

Estimate Carbon Stored in Products The next step is to estimate the amount of fossil fuel carbon that is stored in non-energy products and the portion of this carbon expected to oxidise over a long time period (e.g., greater than 20 years). All fossil fuels are used for non-energy pur-poses to some degree. Natural gas is used for ammonia production. LPGs are used for a number of purposes, including production of solvents and synthetic rubber. A wide variety of products is produced from oil refineries, including asphalt, naph-thas and lubricants. Two by-products of the coking process, oils and tars, are used in the chemical industry. Not all non-energy uses of fossil fuels, however, result in storage of carbon. For example, the carbon from natural gas used in ammonia pro-duction is oxidised quickly. Many products from the chemical and refining indus-tries are burned or decompose within a few years.

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Appendix A

Most of the suggested categories conform to those used by Marland and Rotty (1984) and include naphthas, bitumen (asphalt), lubricants, LPG, and coal oils and tars. The data available from the UN reports (e.g., 1996) correspond to these cate-gories, with the exception of coal oils and tars, which are not reported. The as-sumptions of 75 per cent for naphtha as a feedstock and 50 per cent for gas/diesel oil as a feedstock should be viewed as potential overestimates, since not all of the carbon from the intermediate products will be stored. For example, carbon emis-sions may occur due to losses in the production of final products or incineration of final products. At this time these percentages can be used as the upper bound when determining stored carbon. This suggested approach for estimating carbon stored in products is illustrated in Table A.2. Whenever possible, countries should substitute assumptions that represent more accurately the practices within their own countries and provide documentation for these assumptions.

Table A.2 Estimation of carbon stored in products [source: IPCC Guidelines 1996].

Product / fuel Fraction carbon stored

Lubricants 0.50 Bitumen 1.0 Coal oils and tars from coking coal (use 6% apparent consumption and EF of coking coal)

0.75

Naphta as feedstock 0.75 Gas/diesel oil as feedstock 0.50 Natural gas as feedstock 0.33 LPG as feedstock 0.80 Ethane as feedstock 0.80

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Appendix B

Appendix B Oil data

Table B.1 Crude oil import to the Netherlands by country in ton [source: Statistics Netherlands].

Country 1999 2000

Algeria 3954692 4742924 Angola 0 461238 Denmark 2368563 2928268 Iraq 10145092 5289171 Iran 5470334 6416602 Kuwait 6267291 6883682 Libya 830460 894655 Mexico 531168 0 Nigeria 0 772475 Norway 26215801 24252088 Russia 7545200 8293091 Saudi Arabia 18586808 21487892 Venezuela 1704798 528331 United Kingdom 15885839 18746124 Total 99506046 101696541

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Appendix B

Table B.2 Average API gravity and sulfur content of imported crude oil for 1998 of selected countries listed in Annex I of the UNFCCC [source: IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories].

Country Average API Gravity

Average Sulfur (% weight)

Inferred Carbon Content (% weight)

Australia 39.9 0.34 85.1 Austria 37.4 0.84 84.9 Belgium 32.8 1.25 84.8 Canada 32.4 0.90 85.1 Denmark 40.9 0.22 85.2 Finland 35.8 0.54 85.2 France 35.8 1.01 84.8 Germany 36.5 0.76 85.0 Greece 33.9 1.65 84.5 Ireland 36.9 0.25 85.4 Italy 34.1 1.15 84.8 Japan 34.8 1.51 84.5 Netherlands 33.3 1.45 84.6 New Zealand 34.4 1.01 84.9 Norway 33.3 0.39 85.4 Portugal 33.2 1.39 84.7 Spain 31.5 1.36 84.8 Sweden 34.5 0.76 85.1 Switzerland 39.4 0.46 85.1 Turkey 34.2 1.48 84.6 United Kingdom 35.9 0.64 85.1 United States 30.3 not available not available

Source for API gravity and sulfur content: International Energy Agency.

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Appendix B

Table B.3 Overview of emission factors of oil products as reported in the CRF 2001 by different Annex I countries for 1999.

Party Aviation Gasoline

Diesel Oil

Gas / Diesel

Oil

Gasoline Jet Kero-sene

LPG Residual Oil

Australia 67.3 69.0 69.0 65.3 69.0 58.8 72.9 Austria 74.0 74.2 73.7 73.5 63.1 Bulgaria 92.3 74.4 70.6 Canada 69.5 70.6 70.6 68.1 70.1 74.0 Czech Republic 73.3 73.3 68.6 70.8 62.4 Denmark 73.0 74.0 74.0 73.0 72.0 78.0 Estonia 73.3 73.3 68.6 70.8 75.8 Finland 72.5 73.8 73.4 72.8 70.8 76.6 France 74.7 75.0 72.3 71.6 78.0 Greece 72.8 71.5 68.6 70.8 76.6 Hungary 73.3 68.6 68.6 62.4 Iceland 68.6 73.3 73.3 68.6 70.8 76.6 Ireland 73.3 73.3 70.0 63.7 76.0 Italy 70.9 73.0 75.0 71.2 70.7 65 Japan 72.3 72.3 70.6 70.7 52 0.0 Latvia 74.0 72.8 73.0 70.9 65.9 Luxembourg 73.0 70.0 72.3 Netherlands 73.3 73.0 72.3 73.0 66.4 77 Norway 71.3 73.5 73.5 71.3 73.1 78.8 Portugal 71.7 72.5 73.7 71.1 72.4 76.4 Slovakia 73.9 75.0 73.0 80.2 Sweden 72.3 71.8 74.8 75.5 73.1 76.2 Switzerland 73.6 73.6 73.9 73.2 UK 70.6 72.5 72.5 70.1 71.8 75.9 USA 64.9 67.1 72.3 66.6 66.5 58.4 73.9 Netherlands 73.3 73 72.3 73 66.4 77 EU average 71.7 73.3 73.3 71.6 71.1 65.0 76.9 Annex I average 72.2 72.8 72.8 70.8 70.8 63.5 71.1 IPCC default 74.1 69.3 71.5 63.1 77.4