0DVWHURI6FLHQFH 0 6F - Warmopweg.nlwarmopweg.nl/wp-content/uploads/2017/11/Master-Thesis_DW_Final… · 2014; Mommers, 2016], political ambitions in the Netherlands to close all coal-ﬁred

Determination of the Greenhouse Gas Emissions across the Supply Chain of

Natural Gas in the Netherlands

Master Thesis

zur Erlangung des akademischen Grades eines

Master of Science (M. Sc.)

an der Universität Koblenz-Landau

Fachbereich 3: Mathematik/Naturwissenschaften

Vorgelegt von

Doreen Wunderlich

aus Rijswijk (Niederlande)

Koblenz, 2017

Determination of the Greenhouse Gas Emissions across the Supply Chain of

Natural Gas in the Netherlands

Master Thesis

zur Erlangung des akademischen Grades eines

Master of Science (M. Sc.)

an der Universität Koblenz-Landau

Fachbereich 3: Mathematik/Naturwissenschaften

Vorgelegt:

am 28.09.2017

von Doreen Wunderlich

geb. am 09.09.1979

Referent: Dr. Rainer Elsland, Fraunhofer Institut System- und Innovationsforschung

Koreferent: Prof. Dr.-Ing. Harald Bradke, Fraunhofer Institut System- und Innovationsforschung

Abstract

For a long period, natural gas has been considered a suitable bridge fuel for the transitionto a zero-emission energy system by the year 2050. This view changed since researchersstarted to assess the fuel‘s emissions along its entire supply chain. These life-cycleassessments have revealed significant methane emissions which can offset the benefitsof lower combustion emissions of natural gas compared to coal.

Most of the life-cycle studies of natural gas are, however, based on data from theU.S. gas system. Other regions worldwide are often under-represented. The latest studyon this topic in the Netherlands, an important natural gas producing country, dates backto 1995. Basing the emission determination on such outdated study or on data from adifferent region, e.g. the USA, provides a skewed picture of the Dutch system.

The aim of this study is to overcome this deficiency by providing updated GHGemissions from the Netherlands. During informal expert interviews emission estimatesfor all segments of the supply chain were received both as CO2 and CH4 emissions.Using the Global Warming Potential for the 20-year horizon and the 100-year horizonindicated by the IPCC [IPCC, 2013], the carbon footprint and the methane loss ratewere calculated.

The probably most extensive assessment of available literature on GHG emissionsfrom natural gas was conducted by the Imperial College of London [Balcombe et al.,2015]. They found a wide range of GHG emissions ranging from 2 to 42 gCO2eq/MJ.The Dutch value is even lower. For the year 2016, the carbon footprint across the entirenatural gas supply chain in the Netherlands (excluding end use) was determined as 1.4gCO2eq/MJ (100-year time horizon). The methane loss rate of 0.09% for the Dutchsystem in 2016 is also lower than any known from the literature, which is in the rangeof 0.2-10% according to [Balcombe et al., 2015]. Besides these differences, the maincontributing segments of the supply chain are found in production and processing bothin the literature and for the Dutch system.

Finding the exact reasons for the differences in emissions between the literatureand the Dutch system is difficult. It is not known from the literature which exactemission sources from which operations result in the respective numbers for CO2-equivalent emissions and the methane loss rate. In addition, the data received from theDutch operators lacks transparency and completeness. These reasons hinder the directcomparison of figures from the literature and the Dutch system.

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Contents1 Introduction 1

1.1 Aim and Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . 31.2 Structure of the thesis . . . . . . . . . . . . . . . . . . . . . . . . . . 4

2 Motivation for a comprehensive GHG analysis 62.1 Focus on carbon dioxide . . . . . . . . . . . . . . . . . . . . . . . . 62.2 Climate agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . 62.3 Non-CO2 greenhouse gases . . . . . . . . . . . . . . . . . . . . . . . 72.4 Life-Cycle assessment of fossil fuels . . . . . . . . . . . . . . . . . . 92.5 Need for an update . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

3 Emissions sources across the natural gas supply chain 123.1 The supply chain . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123.2 Emission categories . . . . . . . . . . . . . . . . . . . . . . . . . . . 133.3 Exploration and site-preparation . . . . . . . . . . . . . . . . . . . . 143.4 Exploitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153.5 Processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173.6 Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193.7 Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203.8 Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 213.9 Fuel use (combustion) . . . . . . . . . . . . . . . . . . . . . . . . . . 223.10 Liquefied Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . 24

4 Assessment of GHG emissions 264.1 Measuring and reporting GHG emissions . . . . . . . . . . . . . . . . 26

4.1.1 Measurement approaches . . . . . . . . . . . . . . . . . . . . 264.1.2 IPCC Guidelines . . . . . . . . . . . . . . . . . . . . . . . . 274.1.3 Methodologies for the Natural Gas Industry . . . . . . . . . . 29

4.2 Literature on assessing greenhouse gases for natural gas . . . . . . . . 304.2.1 Assessments from the Netherlands . . . . . . . . . . . . . . . 304.2.2 Comprehensive assessment by the Imperial College London . 334.2.3 Region-based assessment . . . . . . . . . . . . . . . . . . . . 37

4.3 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

5 Emissions from the Dutch natural gas system 415.1 The natural gas industry in the Netherlands . . . . . . . . . . . . . . . 41

5.1.1 Key players . . . . . . . . . . . . . . . . . . . . . . . . . . . 415.1.2 Dutch gas production . . . . . . . . . . . . . . . . . . . . . . 425.1.3 The transmission network and storage facilities . . . . . . . . 445.1.4 The distribution network . . . . . . . . . . . . . . . . . . . . 455.1.5 Final use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

5.2 Empirical method . . . . . . . . . . . . . . . . . . . . . . . . . . . . 475.3 Emission estimates received from the Dutch gas sector . . . . . . . . 48

5.3.1 Emissions from exploration, production and processing . . . . 485.3.2 Emissions from transmission and storage . . . . . . . . . . . 505.3.3 Emissions from distribution . . . . . . . . . . . . . . . . . . 52

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6 Carbon Footprint of Dutch natural gas industry 546.1 Total GHG emissions . . . . . . . . . . . . . . . . . . . . . . . . . . 546.2 Methane only emissions . . . . . . . . . . . . . . . . . . . . . . . . . 576.3 Methane loss rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

7 Conclusion and Outlook 617.1 CO2-equivalent emissions of greenhouse gases . . . . . . . . . . . . . 617.2 Methane only emissions . . . . . . . . . . . . . . . . . . . . . . . . . 627.3 Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

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List of FiguresFig.1 Radiative forcing of greenhouse gases . . . . . . . . . . . . . . . 8Fig.2 Segments of the natural gas supply chain . . . . . . . . . . . . . . 12Fig.3 Emission sources during exploration and site-preparation . . . . . 15Fig.4 Emission sources during exploitation of natural gas . . . . . . . . 17Fig.5 Processing steps for raw natural gas . . . . . . . . . . . . . . . . . 18Fig.6 Emission sources during processing of natural gas . . . . . . . . . 19Fig.7 Emission sources during transmission of natural gas . . . . . . . . 20Fig.8 Emission sources during storage of natural gas . . . . . . . . . . . 21Fig.9 Emission sources during distribution of natural gas . . . . . . . . . 22Fig.10 CO2 emissions and efficiencies of power plants . . . . . . . . . . 23Fig.11 Emission sources during end use of natural gas . . . . . . . . . . . 23Fig.12 Emission factors for LNG . . . . . . . . . . . . . . . . . . . . . . 25Fig.13 IPCC categories for natural gas . . . . . . . . . . . . . . . . . . . 29Fig.14 Emission factors relative to throughput, RIVM-study . . . . . . . 31Fig.15 Methane emissions from the TNO-study . . . . . . . . . . . . . . 32Fig.16 Total GHG emissions by Balcombe et al. . . . . . . . . . . . . . . 34Fig.17 GHG emissions during natural gas processing by Balcombe et al. . 35Fig.18 Variation of the methane loss rate by Balcombe et al. . . . . . . . 37Fig.19 CO2-equivalent GHG emissions for the Netherlands by DBI GUT . 38Fig.20 Carbon footprint from a study of DBI GUT . . . . . . . . . . . . . 38Fig.21 Methane emissions from different countries, IASS-study . . . . . . 39Fig.22 Structure of the natural gas industry in the Netherlands . . . . . . 41Fig.23 Indigenous natural gas production in the Netherlands . . . . . . . 43Fig.24 Mix of primary energy use in the Netherlands in 2015 . . . . . . . 44Fig.25 Gas volume transported by Gasunie . . . . . . . . . . . . . . . . . 45Fig.26 Emissions from exploration, production and processing . . . . . . 49Fig.27 CH4 emissions from transmission and storage . . . . . . . . . . . 50Fig.28 CO2 emissions from transmission and storage . . . . . . . . . . . 51Fig.29 Methane emissions from distribution . . . . . . . . . . . . . . . . 52Fig.30 CO2-equivalent GHG emissions from the entire supply chain . . . 55Fig.31 CO2-equivalent GHG emissions for supply chain segments, 2016 . 56Fig.32 CH4 emissions across the supply chain . . . . . . . . . . . . . . . 57Fig.33 CH4 emission share for segments of the supply chain, 2016 . . . . 58Fig.34 Comparison of methane loss rates . . . . . . . . . . . . . . . . . . 60

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List of TablesTab.1 Global Warming Potential . . . . . . . . . . . . . . . . . . . . . . 8Tab.2 Emission factors for pipelines . . . . . . . . . . . . . . . . . . . . 53Tab.3 Comparison of CH4 emissions for 1990 and 2016 . . . . . . . . . 59

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List of abbreviationsbcm billion cubic meter

BOG Boil-off gases

Btu British Thermal Unit

CHP Combined Heat and Power

CH4 Methane

CO2 Carbon dioxide

DSO Distribution System Operator

EBN Energie Beheer Nederland

e-MJV electronisch Milieu Jaarverslag

EU European Union

g CO2-eq/MJ CO2-equivalent per megajoule

GHG Greenhouse gas

GWP Global Warming Potential

GWP20 Global Warming Potential for a 20-year time horizon

GWP100 Global Warming Potential for a 100-year time horizon

IPCC Intergovernmental Panel on Climate Change

KIWA Keurings Instituut voor Waterleiding Artikelen

LNG Liquefied Natural Gas

NAM Nederlandse Aardolie Matschapij

NIR National Inventory Report

NOGEPA Nederlandse Olie en Gas Exploratie en Productie Associatie

NOx Nitrogen Oxide

N2O Nitrogen dioxide

Mt Megatonne

ppm parts per million

RIVM Rijksinstituut voor Volksgezondheid en Milieu

TAQA Abu Dhabi National Energy Company

Tg CO2-eq Terragram of CO2-equivalent

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TNO Nederlandse Organisatie voor Toegepast NatuurwetenschappelijkOnderzoek

TSO Transmission System Operator

UNFCCC United Nations Framework Convention on Climate Change

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1 Introduction

Since the second half of the 20th Century mankind has been struggling to find solutionsto reduce the worldwide output of greenhouse gases. The negative impact of fossil fuelusage on the climate could no longer be disregarded. For a long time, using naturalgas instead of coal for heat and electricity generation was considered an inevitablecontribution to a zero-emission energy system strategy planned and hoped for by theyear 2050. As natural gas burns "cleaner" than coal, due to a lower emission of Carbondioxide (CO2)1, a switch from coal-fired power generation to gas-fired technologieswas proposed. In 1998 the U.S. Energy Information Adminstration advised: "Naturalgas is expected to play a key role in strategies to lower carbon emissions, because itallows fuel users to consume the same Btu level while less carbon is emitted." [EnergyInformation Agency, 1999].

Two decades later, a growing number of researchers are concerned about the climateimpact of Methane (CH4), the main component of natural gas. CH4 is a greenhousegas having a much higher global warming potential than CO2. Although it has amuch shorter residence time than CO2, the negative implications during its stay in theatmosphere are far more damaging.

Methane attracted the focus of researchers since the beginning of the 21st Centurywhen unconventional natural gas production methods, such as shale gas extraction,became profitable. First studies compared the most important GHG emissions of naturalgas and coal along the supply chain to define the "cleaner" fuel [Hayhoe et al., 2002;Wigley, 2011; Howarth et al., 2011; Cathles, 2011; Howarth, 2014]. Results were notunitary across the plentiful studies. Significant variations in total emission estimateswere visible, depending in part on the applied methodology, the measurement techniquesand on regional differences in gas composition. Still, the common line of these studieswas that the benefit of lower combustion emissions of natural gas compared to coalmight be offset by high methane emissions along the upstream operations (production,processing). Until today, there is no agreed figure of the maximum methane loss ratethat would make natural gas still beneficial over coal. In 2016, the Dutch news portal"de Correspondent" published an article indicating that "depending on what researchyou are looking at, the climate gains of natural gas evaporate over coal at more than 3to 8% leakage"2 [Mommers, 2016]. Two further researchers by Hayhoe and Wigley alimit of 2% appropriate [Hayhoe et al., 2002; Wigley, 2011].

Thanks to publications in Dutch news portals [Redactie duurzaambedrijfsleven,2014; Mommers, 2016], political ambitions in the Netherlands to close all coal-fired

1CO2 from natural gas combustion is about 56% of the emissions from coal combustion2"Afhangelijk van welk onderzoek je erop naslaat, verdampt de klimaatwinst van aardgas boven

steenkool als meer dan 3 tot 8 procent weglekt."

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power plants, including also very efficient newly built plants, in favour of gas-firedpower plants are currently being discussed. What is notable from these discussions isthat they are based mainly on results provided by studies about the U.S. natural gassystem. The gas production and transportation system of the U.S. gas market, however,differs from the Dutch gas market not least of all due to regulatory variations. Thecomposition of natural gas also differs between the two countries. Yet, for discussingemissions in the Netherlands emission factors determined based on the US system areoften used to calculate GHG emissions3. The reason is obvious: There is no up-to-date study about emission factors for the entire Dutch natural gas system, solely forsome parts recent updates can be found. The last comprehensive study on this topicconducted by the Netherlands Organisation for Applied Scientific Research (TNO)dates back to 1995 [Oonk and Vosbeek, 1995], using a data set that is even older. Withall the technological advancement and new insights about methane‘s climate impactthat scientists have gained over the last 20 years this data has to be considered outdated.

Although the Netherlands, as a member state of the United Nations FrameworkConvention on Climate Change (UNFCCC), has to provide an annual inventory onits national GHG emissions, those from the natural gas industry are not reported ona level that would allow to draw conclusions about the actual emission sources. Thecategories foreseen for annual national reporting the CO2 and CH4 emissions of thenatural gas industry according to teh IPCC Guidelines [IPCC, 2013] are: fugitiveemissions separately for all stages of the supply chain (1B2b4), emissions from ventingand flaring (1B2c) and emissions from stationary combustion for electricity and heatproduction (1A1a public sector, 1A4b residential sector). However, the Dutch inventorydoes not report all of these emissions separately. Fugitive emissions are given combinedfor oil and gas related activities. In addition, emissions in segments are providedseparately only for transmission and distribution while emissions from exploration,production and processing are reported in an aggregated manner and in other categories.

It is therefore difficult to investigate the life-cycle emissions of natural gas solelyfrom the publicly available inventories. However, without an in-depth life-cycle assess-ment of the Dutch natural gas system two issues remain: (i) comparison of emissionswith those determined for other gas producing countries is infeasible and (ii) definingconcrete mitigation measures to reduce emissions from the natural gas industry ishindered.

What is needed in view of the under-representativeness of Dutch emission data inthe literature and from the current reporting approach in the Netherlands, is transparentand complete data on GHG emissions from all life-cycle operations of natural gas in

3emission = activity data * emission factor4categories according to the IPCC Guidelines

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the Netherlands.

1.1 Aim and Objectives

The aim of this thesis is to help close the gap held in the scientific research about GHGemissions from the Dutch natural gas system. It will concentrate on the most importantgreenhouse gases in this context, CO2 and CH4. The important GHG, Nitrogen Dioxide(N2O), is not considered, as reporting of this GHG across the supply chain is notelaborated at this time.

The loss rate of methane from operations across the supply chain is of particularimportance as some literature attempts to define the benefit of natural gas over coaldependent on this value. As long as the methane loss rate of natural gas is below a certainpercentage, it is considered by some scientists to be "cleaner" than coal. However, itis to be noted that at this moment there is no single agreed value of the methane lossrate that would indicate natural gas to be "clean" compared to coal. Two publications,[Hayhoe et al., 2002] and [Wigley, 2011] point out that the methane loss rate has to bekept below 2% to achieve a positive effect of a coal-to-gas switch. An article in a Dutchnewsportal even mentions a loss rate of 3-8% [Mommers, 2016].

Besides the methane loss rate, it is also important to determine the entire GHGemissions (carbon footprint) emitted during the fuel‘s lifetime. Due to a lack of detailedmonitoring of greenhouse gases other than CO2 and CH4 at each segment of the supplychain, I will base the carbon footprint on these two gases.

Balcombe et al. from the London Imperial Institute provided an assessment of 240papers about GHG emissions from natural gas [Balcombe et al., 2015]. Due to thiswide scope I will use this assessment as my primary reference when comparing my ownfindings for the Netherlands. In addition, I will determine the methane only emissions.This result will be compared to the TNO-study of 1995 [Oonk and Vosbeek, 1995]).More recent evaluations are not found in the literature, emphasizing once more the needfor an updated analysis of emissions from the Dutch gas system.

The following objectives are pursued in order to achieve the above aim:

1. Identify natural gas infrastructure in the Netherlands and the organizations to beaddressed.

2. Identify the relevant sources of GHG emissions at each stage across the naturalgas supply chain.

3. Assess GHG estimates across the supply chain known from the literature.

(a) Consider CO2 and CH4 emissions individually at each stage across thesupply chain where provided in literature.

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(b) Consider total emissions of the entire supply chain, where provided inliterature.

(c) Identify methodology used in the literature.

4. Collect emissions data of GHG emissions from relevant organizations of theDutch gas sector.

(a) Analyse National Inventory Reports (NIR).

(b) Gather emissions of CO2 and CH4 at each stage in the supply chain fromthe key players in the Dutch natural gas sector.

5. Calculate the GHG footprint and the methane loss rate for the natural gas supplychain.

6. Compare emissions data of the Netherlands with literature.

(a) Compare methane loss rate.

(b) Compare total GHG emissions in CO2-equivalent (carbon footprint).

(c) Evaluate reasons for possible differences and commonalities.

This thesis is restricted to conventional gas as "fracking" is no issue in the Nether-lands at this time. Shale gas exploration was banned by the Dutch government until theyear 2023 [Baker McKenzie, 2016]. Liquefied natural gas (LNG) is likewise excludedas this is still a minor sector in the Netherlands. Currently, LNG is used in one storagefacility to address seasonal variations in gas demand. Additionally, a minor amount of6% of all natural gas imports is LNG [EBN, 2014].

1.2 Structure of the thesis

The thesis is structured as follows:Chapter 2 provides a short overview of the historical development of climate researchstarting with the first climate pioneers and considering the latest international efforts onthe political level. Reasons for the importance of a comprehensive life-cycle emissionsassessment of a fossil fuel will be given. In this context I will explain the GlobalWarming Potential (GWP).

Chapter 3 provides a theoretical background of the main processes and equipmentused in each segment of the supply chain of natural gas. The chapter is intended toprovide the scientific background to understand where emissions are caused.

Chapter 4 comprises a literature review of studies that assessed emissions in thenatural gas industry. Studies in this context are plentiful. The most important ones

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that are considered relevant to provide an overview of what is known so far and toillustrate the problems identified from these studies will be presented. The chapterwill furthermore comprise some background information on the methodologies andreporting methods for assessing GHG emissions in the natural gas industry.

Chapter 5 starts with an overview of the characteristics of the Dutch natural gasindustry to provide a basic understanding of its complex structure and the changes itfaces currently. The empirical method used to gather the emission data is then explained.The chapter finishes with the presentation of the emission data from the Dutch operators.

Chapter 6 illustrates the determination of the carbon footprint and the methane lossrate. The chapter closes with a comparison of the results to the literature.

Chapter 7 will present the key findings of my thesis and discuss relevant issues thatshould be addressed and could be investigated in the future.

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2 Motivation for a comprehensive GHG analysis

2.1 Focus on carbon dioxide

The Industrial Revolution marked a turning point in fossil fuel use by humankind. As aconsequence, the demand of coal for industrial processes boosted. The environmentalimpact of coal, primarily observable by the visual impacts, soon attracted attention.However, it was only 1824 that Joseph Fourier described the greenhouse effect for thefirst time. John Tyndall was the first to measure radiative properties of some greenhousegases in 1859. He discovered that carbon dioxide and water vapour in the atmospheretrap heat rays. In 1896, Svante Arrhenius made the first predictions of global warmingbased on an hypothetical increase of atmospheric gases. He identified CO2 as the keyfactor for global warming. At the same time, Arvid Hoegbom studied the influence ofindustrial activity on the atmospheric CO2 level. At that point, global warming was notconsidered a problem for the near future [Weart, 2017].

It the 1960s, that scientist C. D. Keeling discovered from long-time measurementsthat the level of CO2 in the atmosphere was gradually rising [Weart, 2017]. Thisdiscovery "transformed the scientific understanding of humanity’s relationship with theearth" [?]. Climate impact was suddenly recognized as a severe issue that should soonreach political dimension.

Until the 1960s, a steady worldwide growth of CO2 emissions could be measured.The USA have been by far the biggest emitter. Since then CO2 emissions from Chinaand other Asian countries increased over-proportionally. In 2005, China took over theposition of the top emitter, leaving the USA on the second place. Global CO2 emissionsincreased from 198Mt in 1850 to 32274 Mt in 2011 [Friedrich and Damassa, 2014].

The alarming CO2 level increase stated by Keeling and follow-up measurementsfinally reached the international political world. National and international agreementsabout limitation of the global warming were achieved which increasingly acknowledgedalso the contribution of other greenhouse gases. The most important ones will bediscussed in the next chapter.

2.2 Climate agreements

Today it is accepted among scientists that anthropogenic activities are responsible forthe record maxima of atmospheric CO2 concentration that can be measured. Ice coremeasurements revealed a natural fluctuation between 180 ppm and 300 ppm within thelast 800,000 years, with a pre-Industrial level at 270 ppm. On 10 May 2013, an alarmingrecord of 400 ppm was measured for the first time [Wikipedia, 2017]. However, in

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the 1980s, there was still dispute in the science world about an anthropogenic climatechange.

Alarmed by this brawl, and at request of some member states of the United Nations,a scientific and intergovernmental body was founded: the Intergovernmental Panel onClimate Change (IPCC). The intention was to provide an objective and scientific viewof the anthropogenic climate change.

Upon publication of the first IPCC Assessment Report in 1990, the need for in-ternational climate policy actions became apparent. This prompted the adoption ofthe international environmental treaty in 1992, which is known as the United NationsFramework Convention on Climate Change (UNFCCC). No specific emission reductiontargets were set at that time, believing that the mere intention to stabilize greenhousegases at the level of 1990 would be sufficient for actions of the participating members.Soon it became apparent that this was indeed not satisfactory and that binding targetsfor GHG emission reduction were required. For the first time, reduction targets to beachieved by a decrease of several greenhouse gases, were defined in the Kyoto Protocoladopted in 1997. The Netherlands agreed on a 20% reduction of GHG emissions until2020. More agreements on international level followed in the years after, partly toreplace the Kyoto agreements. The recent Paris Agreement, adopted in 2015, is themost ambitious so far. 196 nations worldwide defined nation-wide targets for GHGemission reduction. The targets were set with the aim of keeping the average globalwarming at below 2°C. The Netherlands‘ contribution of CO2-equivalent reduction is40-50% in 2030 and 85-95% in 2050 compared to the level of 1990.

2.3 Non-CO2 greenhouse gases

Although for many decades, mitigation methods concentrated on CO2, there are furtheranthropogenic greenhouse gases that contribute to global warming. Due to the signifi-cance of these non-CO2 greenhouse gases to global radiative forcing, the Kyoto Protocolhas already requested reduction targets for the five most important non-CO2 green-house gases: Methane (CH4), Nitrogen Dioxide (N2O), Hydrofluorocarbons (HFCs),Perfluorocarbons (PFCs), and Sulfur Hexafluoride (SF6) in addition to targets for CO2.

Owing to individual residence times in the atmosphere, individual greenhouse gasespossess different potentials for global warming (see table 1). To compare the contri-bution of all greenhouse gases to global warming a conversion factor, called globalwarming potential (GWP), has been introduced. The GWP indicates "an index mea-suring the radiative forcing following an emission of a unit mass of a given substance,accumulated over a chosen time horizon, relative to that of the reference substance,carbon dioxide (CO2)" [IPCC, 2013].

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Table 1: Global Warming Potential, [IPCC, 2013, p.714]Gas GWP20 GWP100 Lifetime (yr)

CO2 1 1 200 years and moreCH4 86 34 12.4N2O 268 298 121CF4 4950 7350 50,000

HFC-134a 3790 1550 13.4CFC-11 7020 5350 45

Radiative forcing describes the amount of energy that would be lost to space ifnot absorbed by a gas. The GWP therefore measures how much heat is trapped in theatmosphere by a certain greenhouse gas compared to CO2. Fig.1 provides a scientificapproach for defining the GWP which will be further explained in view of table 1.

Table 1 provides an overview of some selected greenhouse-gases and their GWPfor two different time horizons. GWP20 indicates the 20-year time horizon, GWP100

indicates the 100-year time horizon. The GWP value is calculated based on the integralof the radiative forcing over a chosen time horizon (see fig.1). It is visible from thefigure that radiative forcing of methane (red curve) is initially much higher than radiativeforcing of CO2 (blue curve). The impact of methane on the global warming is thereforemuch stronger within the first years after emission than that of CO2. Hence, avoidingemissions of methane provides a very high potential for preventing an increase in globalwarming at an early stage.

Figure 1: Calculation of the radiative forcing of greenhouse gases [IPCC, 2013, p.711]

At this time there is no single time horizon that scientists agreed on as both havetheir drawbacks. The choice of time horizon, though, can influence political decisionsin terms of the timing of mitigation measures. This applies particularly to mitigationof non-CO2 greenhouse gases. The 20-year time horizon emphasizes the initial high

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climate impact of methane so that the need for prompt mitigation measures is moreeminent. The 100-year time horizon provides an outlook on the long-term climateimpact but does not reflect the high impact of methane in the first years.

As the aim of my thesis is an objective assessment of greenhouse gases with nojudgement on how and when to introduce reduction measures, I will use both GWPs forcalculating the carbon footprint in chapter 6.

It has to be mentioned that the GWP values in table 1 are not fixed. In fact, theyare highly uncertain. The Climate Change 2013 report [IPCC, 2013] indicates theuncertainty for the GWP of methane to be in the range from -30% to +40% (GWP100).Technological advances and scientific developments were responsible for repeatedadaptations of GWPs by the IPCC in the past. Revisions are likely to take place as wellin the future.

After converting the radiative forcing of a non-CO2 GHG using the respective GWPvalue, the emission quantity can be indicated in a single metric, the CO2-equivalent. Itrepresents the amount of CO2 that has the equivalent climate impact to the respectiveGHG.

2.4 Life-Cycle assessment of fossil fuels

The importance of reducing emissions of the six most relevant greenhouse gases wasidentified already in the 1990s when defining reduction targets in the Kyoto Protocol. Formany years, however, emissions from the use of fossil fuels were often considered solelyat the combustion stage. Thus, primarily CO2 emissions were evaluated. Determiningthe emissions during the entire lifetime of a fossil fuel is a relatively new approach.

The life-cycle of natural gas includes the following stages: exploration and site-preparation, exploitation (production), processing, transmission, storage, distributionand end use of the fuel. In a further step it should also include a consideration of theabandoned well after depletion of a gas field. This final stage, however, is not regularlyanalysed. Only very recently, some studies refer to the need of monitoring emissionsfrom abandoned wells [Vaidyanathan, 2014; Hayhurst, 2016; ReFINE research, 2016;Saxena, 2016]. All stages of the supply chain will be presented in chapter 3.

One of the first studies about the impact of multiple greenhouse gases along at leastparts of the supply chain of natural gas and coal was published by Hayhoe et al in2002 [Hayhoe et al., 2002]. Rather than defining which one is the "cleaner" fuel, theymodelled the global temperature depending on the time point of switching from coal tonatural gas. They found that the substitution of coal by natural gas will lead initially toan increase in global warming due to a reduction in SO2 emissions. For their assessment

9

they assumed a methane leak rate of 1.5% over the entire supply chain but indicate thatthis estimate is highly uncertain.

In 2011, T. Wigley performed an update on Hayhoe‘s study about the long-termeffects on global warming by replacing coal with natural gas. His conclusion was thatan additional warming effect could occur depending on the natural gas leakage rate.He indicates that leakage rate has to be kept below 2% over the entire supply chainotherwise "substituting gas for coal is not an effective means for reducing the magnitudeof future climate change" [Wigley, 2011]. He also points out the high uncertainty forestimating the leakage rate.

In 2011, a further study was published by Howarth et al. Providing more detailson the determination of methane emissions at each stage of the supply chain (exceptfinal use), they concluded that life-cycle emissions of conventional gas are about thesame as for coal and diesel oil both for the 20 and 100 year horizon. He showed that thelife-cycle emissions from shale gas are much higher than for conventional gas so thatshale gas cannot be considered an alternative fuel for coal. However, also conventionalgas was found to provide similar life-cycle emissions than other fossil fuels, e.g. coal.

All three publications have in common the critics of very high uncertainties forestimating methane emissions across the supply chain of natural gas. As a consequence,plenty of research was done in the years after 2011 trying to assess the methaneemissions of natural gas. Balcombe et al. from the London Imperial College presentedan assessment of 240 papers on this topic that were published until 2015 [Balcombeet al., 2015]. One of their key findings was the under-representativeness of researchfrom regions outside the USA, in particular from Europe. Not a single one of the 240papers considered the Dutch natural gas system. Additionally, Balcombe et al. claimeda lack of transparency of data provided by some studies and significant methodologicaldifferences. Due to these deficiencies they had difficulties in providing an explanationfor the vast range of GHG emissions determined in the studies they assessed. Theyrequested further research to overcome these deficiencies.

2.5 Need for an update

From the literature mentioned before it is understood that the benefit of natural gas overcoal depends highly on the methane leakage rate across the supply chain. Methaneestimates known from the literature are, however, uncertain. The reasons are many-fold:Most studies use data from the U.S. gas market. Other regions are under-represented interms of region-specific activity and emission data. Methodologies of how emissiondata is gathered are not always indicated in the papers. Where they are known, theydiffer significantly in some parts. In the case papers only indicate an estimate for the

10

entire supply chain and not for each stage, it is impossible to derive the actual methanesources. As a consequence, defining accurate mitigation measures is hindered.

To help overcome above deficiencies at least in part, this thesis aims to provide GHGemissions across the natural gas supply chain for the Netherlands as the CO2-equivalentbased on the CO2 and CH4 emissions. This shall be done on a level that identifies thekey emission sources to allow for the definition of specific mitigation measures. It isnot the purpose of this thesis to actually define these measures.

In a complete assessment the following emissions would need to be considered:emissions from upstream operations (exploration, production and processing) within theNetherlands and within the country of origin for the imported natural gas, midstreamemissions (transmission and storage) within the Netherlands and, for imported gas, tothe border of the Netherlands, and downstream emissions from regional distribution andfinal fuel use within the Netherlands. Such a comprehensive assessment is, however,not possible within the framework of this thesis. It therefore truncates the life-cycle andconsiders the segments from exploration to regional distribution. The final stage of fueluse is omitted as this segment is very complex encompassing many different gas-driventechnologies which, for a comprehensive analysis, have to be addressed separately. Formany of them, such as gas-driven boilers and cooking pits in households, determiningactivity data and specific emissions factors is not feasible within the framework of thisstudy. Nonetheless, I will provide background information about the final fuel use. Thisalso for the reason to show the complexity of this life-cycle part. Likewise is it toocomplex for this thesis to determine the emission estimates from production, processingand transmission to the Netherlands for all the countries from which natural gas isimported.

In the remaining text the expression "entire supply chain" encompasses operationsof exploration, production, processing, transmission, storage and regional distributionwithin the Netherlands.

The emissions from each segment of the supply chain will be aggregated to deter-mine the carbon footprint of natural gas. It is determined as the total GHG emissions ofthe entire supply chain in the metric CO2-equivalent per megajoule (g CO2-eq/MJ).

At present, only conventional gas production is done in the Netherlands. Hence, nodata for shale gas is provided. Theoretical backgrounds of shale gas will be discussed tounderstand why it is much more harmful than conventional gas. Liquefied natural gas(LNG) is used as a peak-shaver in the Netherlands by the Dutch transmission systemoperator. A minor part of imports is also LNG. I will therefore provide the basic theoryon LNG. The empirical analysis of emissions in the Dutch gas system covers emissionsfrom LNG only in so far as it is part of the transported natural gas after re-gasification.

11

3 Emissions sources across the natural gas supply chain

To evaluate the life-cycle GHG emissions of natural gas, it is important to understandwhere along the supply chain emissions are caused. In this chapter the operationstaking place at all stages of the supply chain with the possible emission sources will bedescribed. Where estimates are known from literature, they will briefly be presented.Where data is missing from literature or is under-represented this will be mentioned. Adetailed presentation of emissions estimates known from other studies will be providedin chapter 4. A lack of harmonization of methodologies used for obtaining the data andincompleteness of data make it difficult to provide a comprehensive brief overview ofthe relevant literature within this chapter. The literature will be discussed in more detailseparately in chapter 4.

3.1 The supply chain

The supply chain of natural gas is divided into three streams: upstream, midstream anddownstream. They comprise the stages of exploration and site-preparation, exploitation,processing, transmission and storage, distribution and end use as illustrated in fig.2.

EXPLORATION PRODUCTION PROCESSING TRANSMISSION STORAGE DISTRIBUTION FINAL USE

UPSTREAM MIDSTREAM DOWNSTREAM

Figure 2: Segments of the natural gas supply chain

Emissions occur during operations at all of these stages. Key sources that were iden-tified in the literature concentrate on leaks during transmission, storage and distributionthat directly emit the harmful methane into the atmosphere. After processing of thenatural gas, it contains about 98% methane. Large pipeline leakages that are not detectedand repaired promptly can emit a high amount of methane. Fortunately, such incidentsdo not happen often and, with modern technology, can be detected quickly. On the otherhand, pumps, valves, compressors and other equipment needed for transportation of nat-ural gas frequently each emit small amounts of natural gas that count up to a significantamount due to the multiplicity of devices. Other key sources identified in the literatureare well-completion, particularly from unconventional gas production sites, and liquidsunloading during exploitation. Treatment of gas, comprising several steps to removepollutants in the raw gas, further contributes to GHG emissions. These emissions areeither caused by the equipment or are waste gases of the processes, such as CO2 fromthe CO2 removal phase. In addition, all stages require energy, which is either generatedby gas-driven engines or turbines at the site of use. When burned in gas-driven enginesor gas turbines, combustion emissions are released. They comprise primarily of CO2

but, in case of incomplete combustion, also CH4. Alternatively, electricity is purchased

12

from the general grid system. Generation of this electricity emits greenhouse gases atthe location of production, for example in central power plants. Emissions for electricitygeneration is generally not accounted for by the operators in the natural gas system,thus somewhat skewing the life-cycle emissions. All emission sources will be discussedin more detail in the following chapters.

3.2 Emission categories

Life-cycle emissions of natural gas can be distinguished into three categories:

• Emissions from venting and flaring: Flaring is the controlled burning of gas toprotect against dangers of over-pressure. The CO2 released during this processis technically a combustion emission. However, common practice is to reportflaring emissions separately. Where gas is not flared for safety operations, itis directly emitted to the atmosphere, i.e. vented. Intentional vents take placeduring well drilling, well testing and pipeline pigging activities, in gas-drivenpneumatic devices, during purging and blow-down in maintenance activities, frompressure relief during process upsets, during release of off-gases from processingfacilities and as discharge from the raw gas processing. Emission sources ofintentional leaks can be relatively well characterised but have high uncertaintiesas measurements feasibility is limited.

• Fugitive emissions: They result from unintentional gas leaks and occur through-out the supply chain. Fugitive emissions are transitory and elusive and subject tohigh uncertainties. Reasons are wearing of mechanical parts, bad constructionand corrosion as well as equipment that is not operating properly. Main compo-nents responsible for fugitive emissions are: pump seals, valves (through-valveleak in sampling valves, pressure relieve valves, shut-off valves in open-endedlines and dump valves), fitting of compressors (centrifugal and reciprocating)that are not tight due to continuous vibrations and continuous temperature andpressure variations, connectors (flanges) and improperly operated storage tanks.Malfunctioning pneumatic devices with high bleed gas are a main source offugitive emissions.

• Combustion emissions from energy use: Heat and electricity needs throughoutthe supply chain are primarily met by on-site combustion of natural gas or bypurchase from the grid. Burning of natural gas emits CO2. The amount ofemissions depends almost entirely on the carbon content of the natural gas.Caused by incomplete combustion, some hydrocarbons including methane arereleased as well. While emissions from on-site energy generation are generallyreported explicitly for stages across the natural gas supply chain, this does not

13

apply to those from electricity generation. In this case, emissions are counted forthe categories of public heat and electricity generation. This is somewhat skewingthe life-cycle emission estimates of natural gas.

Throughout the literature, other categories are also used. Sometimes emissions fromflaring are considered as combustion emissions, some researchers distinguish betweenintentional and unintentional emissions. The description of all the supply chain stages inthe next chapters will use the above categories to classify emission sources and, wheredata is available from the literature, quantify the emissions briefly.

3.3 Exploration and site-preparation

The search for viable natural gas starts with a seismic survey to model the geologicalmap of a region. For on-shore exploration, a seismic signal is generated by a heavyvibrating plate. The signal‘s reflection from the boundary of two Earth layers isreceived and evaluated. During marine exploration operations compressed air is sentout and returning sound waves are captured by hydrophones. In both cases, seismicmeasurements provide information about the underground rock structure from whicha possible gas reservoir can be identified. Gas fields can be found either alone or inconnection with oil fields. In the latter case, natural gas is called "associated gas".

Following the identification of a possible gas reservoir, site preparation starts byclearing the surface vegetation and constructing necessary infrastructure. During thesubsequent exploration drilling, "drilling mud", a mixture of clay, water, polymers andsuspended materials for density control, is circulated down the drilling string. The staticpressure of the drilling mud exceeds the pressure in the reservoir to avoid the risk foruncontrolled gaseous emissions.

A well is completed by installing a casing, cementing, perforating the well-casingon the lower part and placing a well head. In case of unconventional gas, hydraulicfracturing is required at this stage. Rock is fractured by inserting a high-pressureliquid, thereby allowing natural gas to flow out of the rock. Methane emissions duringhydraulic fracturing occur due to the energy demand for intensive drilling activities anddue to venting in the flowback period. Reservoirs are used for storing this flowbackliquid. Where they are open, such as in the USA, the gas can escape freely into theatmosphere. Caused by these fracturing operations, very high emissions of methanecan be released. Balcombe et al. [Balcombe et al., 2015] indicate emissions of up to6,800,000 m3 CH4 per well. This can be reduced to 25,000 m3 CH4 when employingReduced Emission Completion (REC) measures5. Some flaring is required even with

5additional equipment to reduce flaring or to separation of the flowback liquid into re-usable ormarketable components

14

RECs, which might lead to significant CO2 emissions. For comparison, Balcombe et al.indicate emissions for well-completion of conventional gas to be up to 7,400 m3 CH4

per well.

After installation of the well, feasibility of exploitation is investigated in a testwherein gas is extracted at varying production rates for a duration of 20-70 hours.This gas is generally vented. Finally, the well is cleaned by removing impurities andincreasing permeability of the rock to enable gas exploitation. Cleaning has to berepeated several times during a well‘s life time, each time requiring natural gas vents.

Emissions during the exploration and site-preparation phase occur primarily asCO2 from energy use during transportation of equipment to the production site and fordrilling activities. During well cleaning some gas is flared, leading to CO2 emissions,or simply vented, releasing the methane directly into the atmosphere. Fugitive methaneleakage is reduced to a negligible amount as the drilling mud pressure exceeds thepressure in the reservoir. The key emission source from exploration and site-preparationis well-completion, which is of particular importance in unconventional gas fields.Nonetheless, I will include these emissions as they contribute to the life-cycle emissionsand should actually not be omitted.

Exploration as such is often ignored in the life-cycle analysis as it cannot be directlylinked to production. Some drilling will lead to production and others not. "Therefore, itis common practice to exclude exploration from the life cycle inventory and assessment"[Sevenster, 2006].

COMBUSTION EMISSIONS: VENTING EMISSIONS: FUGITIVE EMISSIONS:


energy demand for trans-porta�on and site-prepara�on

well comple�on

well tes�ng

negligible

Figure 3: Emission sources during exploration and site-preparation

3.4 Exploitation

During production gas is collected from the well. Non-associated natural gas simplyflows from the reservoir with a pressure of several bars to several hundreds of bars.Flow-rate and pressure are constantly controlled using compressors and flow regulatingvalves. Both contribute to combustion emissions and fugitive emissions. In the case ofassociated gas it is brought up together with oil and then has to be separated in a firststage.

For maintenance activities of the equipment, gas flow has to be stopped. A fluid isbrought into the well with specific density high enough to counterbalance the reservoir

15

pressure. Work-overs are necessary when the quantity of extracted gas decreases, thusrequiring re-stimulation of gas flow. Work-overs normally comprise the removal andreplacement of the production tubing string, repairing leaks, perforating new partsof the well and, in the case of shale gas, hydraulic fracturing. During shut-down,work-over and start-up flare gases are released from the well. Flaring of gas duringmaintenance can last for months and therefore produce a significant amount of emissions.Fortunately, work-overs are rare. The actual frequency of work-over depends on theinitial pressure with which gas is extracted, the porosity of the well, liquids concentrationand hydrates formation. In average, 0.03-0.17 work-overs can be expected per well andyear [Balcombe et al., 2015].

A further process that might have to be done regularly during the well’s lifetime isliquids unloading. In mature wells, as gas flow and velocity reduce, it might happen thataccumulated liquids are not brought up any more by the normal pressure of the gas in thereservoir. Processes employed during liquids unloading are well-blow down, plungerartificial lift, velocity tubing, well swabbing and injection of foaming agents. CO2 andCH4 is thereby released. The underlying idea is to increase the pressure of the gasflow by these processes so that the liquids are brought up. The actual need for liquidsunloading, its frequency per year and emissions per event depend on the technology,the well age and physical characteristics in the well (presence of liquids, pressure, sizeand permeability). Methane emissions estimates are therefore wide-ranging and canbe anywhere from zero to 500,000 m3 per year (primary studies), the later indicating aso-called super emitter, and zero to 38,000 m3 per year (secondary studies6) [Balcombeet al., 2015]. Using a smaller well diameter leads to a higher pressure with which thegas is brought up, therefore reducing the need for regular liquids unloading.

Balcombe et al. indicate emissions from liquids unloading with less than 1% of thetotal GHG emissions. At the same time, they entertain doubts about validity of thisfigure due to a lack of transparency of the data provided by the studies they assessedand they criticize that it is unclear if emissions are rather from flaring or venting.

Only a relatively small amount of emissions during exploitation originates fromenergy generation. The largest amount, however, is emitted by leaking and venting,primarily from pneumatic controllers. Finally, some gas is released in vents from liquidsstorage tanks in gas gathering facilities. Leaking valves and leaks in pipelines fortransportation to the facilities contribute to further CH4 emissions.

Actual estimates are scarce from literature. One study indicates a methane emissionrate from 0.7 to 700 kg/h [Mitchell et al., 2015]. According to their calculations this isless than 1% of production throughput. They also point out that this data is "skewed"

6Primary studies are measurement-based, while secondary studies model emissions rates.

16

as "30% of gathering facilities contribute 80% of the total emissions"[Mitchell et al.,2015].



energy demand for gasextrac�on

energy demand for

gas release during

liquids unloading equipment leaksliquids unloading

energy demand forworkovers

vents at gas gatheringfacili�es (storage tanks)

gathering facili�espipeline transport to

and work-overs

Figure 4: Emission sources during exploitation of natural gas

For off-shore natural gas production, a platform is built at the production site, eitherfloating or attached to the sea-ground. In contrast to on-shore production sites, off-shoreplatforms comprise of only simple gas treatment plants. Required processes that have totake place before transportation is possible are primary separation, glycol dehydrationand separation of ethane, butane and propane. Transportation is carried out in pipelinesor by shipping.

Emission data for offshore activities is often missing from literature. It is, at thisstage, not possible to quantify these emissions.

3.5 Processing

The natural gas extracted from the well is not directly suitable for transportation.It commonly contains the following contaminants: water vapour, acid gases (CO2,sulphurous compounds), Nitrogen, condensable hydrocarbons, Ethane, Butane andPropane. Processing is required to separate all or some of the components at the wellexit to produce pipeline quality dry natural gas. Fig.5 provides an overview of theprocesses that the raw gas has to undergo. Depending on the actual gas composition andreservoir pressure in the gas field, all or only some of these processes have to be done.

17

oil

condensates

water

Nitrogen

Natural Gas

oil & gas separa�on

separa�on of condensates

glycol dehydra�on

H S & SO separa�on2 2

SO2

H O2

Nitrogen extrac�on

frac�ona�ng

fro

m t

he

we

ll

Liquids

Dry gas

Figure 5: Processing steps for raw natural gas

When associated gas is exploited, this has to be separated from oil at first. Additionalprocessing is required where gas is dissolved in oil. These processes might also beaccounted for in the production stage as they occur right at the exit of the well.

Primary separation of non-associated gas from the well includes flashing processesto isolate raw gas from fluid and solid components. A further process is the removalof water vapour by glycol dehydration. Glycol is the principle agent in this processand extracts water from the stream of natural gas. A small amount of methane mightbe carried away by the glycol solution which often is vented. Nowadays, flash tanksare used that allow vaporization of methane and other hydrocarbons before the glycolsolution reaches the boiler, thereby reducing venting emissions.

Amine gas treatment covers processes that aim to separate sulphur in the formof hydrogen sulphide (H2S) and CO2 from the raw gas. CO2 emerging during theseprocesses is often vented. The CO2 removal process contributes up to 50% of the entireGHG emissions from processing in the case of a very high CO2 content of the extractedgas [Balcombe et al., 2015, page 28]. Mitigation measures are limited and will stillresult in small amounts of CO2 from flaring.

Further processing includes nitrogen removal and rejection to some degree7. In thelast step, natural gas liquids (Propane, Ethane, Butane) are separated.

During emergency situations, when equipment becomes over-pressured, some gashas to be vented or flared. In the case of flaring, pressure regulating valves release some

7In the Netherlands 2% of Nitrogen remain in the gas

18

natural gas to flare stacks, where it is burned. Vented gas is released directly into theatmosphere. For maintenance works the natural gas that is present in the equipmenthas to be flared or vented. Methane is released during shut-down of reciprocatingengines when flushing them with air and flushing again with natural gas before start up.Compressor seals cannot be made entirely gas-tight and therefore always leak to somedegree. Chronic leakages also occur at joint flanges and valves.

The energy demand from compressors and heaters used during these processes ismet primarily by natural gas. During combustion, CO2 is emitted. Due to incompletecombustion minor amounts of methane are emitted as well. Estimates indicate that upto 9% of the produced gas is used as fuel gas at the processing stage [Balcombe et al.,2015, page 27]. The actual amount of fuel gas needed depends on the gas compositionand well pressure which dictates how much treatment of the raw gas is needed.



energy demand forheaters

energy demand for

�aring of unmarketable

pressure reducing leaks from othercompressors valves

shut-down and start-up

(seals, valves, �anges)

leaks in compressors

gases from processes

for maintenance

equipment

Figure 6: Emission sources during processing of natural gas

3.6 Transmission

The transmission network comprises thousands of kilometres of high pressure pipelinesand a high number of compressor stations, import/export stations and pressure regulationand metering stations. The natural gas is transported in long-distance pipelines with apressure of about 70 bar. Re-compression is required every 80-160 km to compensatefor losses by friction on the pipeline wall. The high number of compressor stationslead to a significant energy demand and therefore significant emissions of CO2 fromcombustion of gas. About 0.5-5% of the total gas production is used as energy fuelfor compressors. No possibility of re-compression is given in sub-sea pipelines so thatnatural gas is pressurized up to 200 bar at the entrance of these pipelines.

Natural gas is vented during blow-down, start-up and as purge gas in compressors.Additional emissions are caused from measurement instruments and filter cleaning.These emissions contribute with a fixed amount from operational processes in the com-pressors. Additionally, there are variable emissions from pneumatic devices: frequentlyused pressure level controllers and infrequently used pressure relieve valves which areopened and closed by natural gas. The latter being operated occasionally but discharge

19

a relatively high amount of natural gas per actuation.

A very significant source of methane emissions are pipeline leaks. They mightrange from small to large leaks. Fortunately, the latter does not occur often these days.Nonetheless, pipeline leaks are of importance as they release almost pure methane intothe atmosphere. After the treatments of the raw gas extracted from the well, natural gascontains about 98% methane.

Eurogas-Marcogaz conducted a study [Papadopoulo et al., 2011] for which theygathered emission rates from six European gas transporting companies. Their combus-tion emissions from compressors ranged from 0.074% to 0.715% of the transported gasvolume. This is significantly lower than estimates from other studies which indicate anemission rate of up to 5% [Balcombe et al., 2015]. Balcombe et al. indicate a fuel use of0.5% to 8.6% of the total production [Balcombe et al., 2015, p.31]. Fugitive emissionsindicated in the Marcogaz study are likewise low. They range from 0.002% to 0.041%of the transported natural gas volume. Whereas Balcombe et al. indicate emissionsfrom leaks and vents across the entire transmission stage in the range of 0.05% to 4%of the total produced methane.

Emission mitigation is possible with corrosion repair, replacement of high-bleedingpneumatic devices, targeted inspection and forward line pumping. Gasunie, the trans-mission system operator in the Netherlands, uses mobile compressor stations to avoidthe release of natural gas into the atmosphere. Additionally, a leak detection programmeis useful to prevent persistent leakages.



energy demand ofcompressor sta�ons

measuring instruments

pressure-control valves

leaks of pipelines

shut-down and start-up leaks of equipment

pneuma�c devices

for maintenance

Figure 7: Emission sources during transmission of natural gas

3.7 Storage

To balance seasonal variations in natural gas demand, storage facilities are required.Geological underground structures suitable for natural gas storage are aquifers, depletedoil and gas reservoirs, empty coal mines and salt cavities. 80% of the worldwideunderground storage capacity is supplied by depleted oil and gas reservoirs. Relativelynew and uncharted are empty mines and lined rock caverns. Above ground storages are

20

rarely used. For smaller volumes, natural gas might be liquefied and stored as LNG instorage tanks.

In order to inject the natural gas into the underground storage, it has to be compressedto about 200 bar. Above-ground storages, usually tanks of much lower volume thanunderground storages, require a pressure of 10-20 bar of the gas. The high pressures forunderground facilities cause high operational emissions from the compressor stations,mainly combustion emissions from energy generation. During underground storage gasis likely to pick up water from the surroundings. It therefore has to be treated again in adehydrator facility before distribution. Sometimes sulphurous compounds have to beremoved as well. Both processes require energy and therefore contribute to combustionemissions.

Further emissions occur from storage tank venting. Some methane is releasedduring venting at blow-down and start-up operations as well as from purge gas inthe compressor. A study conducted by Marcogaz reports a fugitive emission rate of0.023%-0.109% of the gas throughput [Papadopoulo et al., 2011].



energy demand ofcompressor sta�ons

storage tanks

leaks of pipelines

metering sta�ons leaks of equipment

maintenanceenergy demand forprocessing

Figure 8: Emission sources during storage of natural gas

3.8 Distribution

Downstream operations start at the city gate where the natural gas arrives from the highpressure transmission pipelines and is reduced to less than 1 and up to 8 bar. Someenergy is required to heat the gas before it cools down during the pressure reduction(Joule Thompson Effect). As gas is distributed at much lower pressure, over shorterdistances and in pipelines with smaller diameters, compressors stations are typicallysmaller than for transmission. As a consequence, energy demand is also much lower,which comes together with reduced combustion emissions.

Further equipment used in the distribution network comprises measurement instru-ments and pressure control devices. Although every single device vents only smallamounts, it is the high number of such devices that amount to significant emissions ofCH4. Venting is also required for maintenance works as the equipment has to be freedof gas before work can start. Additionally, small leaks in the equipment lead to fugitiveemissions.

21

The main contribution to fugitive emissions during the distribution stage is frompipeline damages. Material failure, corrosion and third party damage are the mainreasons for pipeline leakages. Leakage amounts differ strongly depending on thematerial used for the pipelines. In the past, grey cast iron and rigid steel was regularlyused. These days, flexible plastic, primarily polyethylene, is available. Balcombe etal. show that emission factors for plastic pipelines are about one third of the emissionfactors for the other materials [Balcombe et al., 2015, fig.13].

Historically, distribution emissions were determined as the difference between gasproduced at the well and gas delivered to customers ("unaccounted for gas"). Thisway 1-10% of the gas production was estimated to leak. This neglects the natural gasrequired for on-site energy generation and losses from theft, faulty metering devicesand unknown temperature gradients. The loss rate from gas unaccounted for leadsto over-estimation. Hence, since the mid 1990s estimates have to be determined bythe "bottom-up method" based on emission factors that are provided for differentcomponents in the distribution system and for different pipeline materials.



energy demand forhea�ng gas before

metering instruments

leaks of pipelines

safety and opera�on leaks of equipment

valvespressure reduc�on

maintenance opera�ons

Figure 9: Emission sources during distribution of natural gas

3.9 Fuel use (combustion)

The energy kept in natural gas is converted into thermal and electric energy by burn-ing the fuel in a combustion process. Various technologies exist that generate eitherelectricity or heat or both in a combined process. Heat generation is normally decen-tralized close to the customer to minimize the high transportation losses. Electricityis traditionally generated centralized in conventional gas-fired power plants and thentransported over long distances. A much higher efficiency can be achieved in combinedheat and power plants (CHP). In this technology the waste heat of a gas-turbine is usedin a steam turbine. There is a visible trend towards decentralized CHP generation on asmall scale. Such Micro-CHP technologies can be gas-turbines, gas-engines or they canbe based on other fuels.

Emissions from gas-driven technologies for heat and electricity generation arecaused by the combustion of natural gas. In this chemical reaction, the hydrocarbonsburn in oxygen, thereby releasing primarily CO2 into the atmosphere. The amount

22

of CO2 emitted depends on the carbon content in the natural gas, the specific energycontent and the efficiency of the used technology. Fig.10 illustrates an overview of CO2

emissions generated in some selected types of power plants. For comparison, coal andnatural gas fired power plants are indicated together in addition to the average efficiencyof the respective technology [Lattanzio, 2015].

Coal:

Gas: Combined Cycle (50.2%) - case study

Steam Generator (33.0%) - exis�ng

Combined Cycle (44.5%) - exis�ng

Internal Combus�on (35.6%) - exis�ng

Gas Turbine (30.0%) - exis�ng

Combined Cycle (42.1%) - case study¹

Steam Generator (39.3%) - case study�

Combined Cycle (39.7%) - case study²

Combined Cycle (39.0%) - case study³

Steam Generator (36.8%) - case study�

Steam Generator (33.8%) - exis�ng

1 - General Electric; 2 - ConocoPhilips; 3 - Shell; 4 - subcri�cal; 5 - supercri�cal

365 kg/MWh

407 kg/MWh

508 kg/MWh

549 kg/MWh

603 kg/MWh

723 kg/MWh

776 kg/MWh

782 kg/MWh

802 kg/MWh

856 kag/MWh

964 kg/MWh

Figure 10: CO2 emissions and efficiencies of power plants, based on [Lattanzio, 2015]

Incomplete combustion of natural gas, resulting from a lack of oxygen, will resultin a small amount of methane and other hydrocarbons being emitted. These emissionsare often neglected in view of the overwhelming emissions of CO2.

Additional methane emissions in natural gas fired power plants occur due to leakagefrom the equipment, for example compressors, before combustion takes place.

Besides industrial electricity and heat generation, natural gas is also used for domes-tic heating and cooking. Gathering emissions estimates for residential natural gas use isdifficult. A high number of different types of boilers for warm water and space heatingare available. Determining emissions for all of them, thereby taking into account theactual efficiency due to age, maintenance and setup conditions for each household, isnot feasible. At most an average emission factor for some boiler types operated atstandard conditions might be determined. The same applies to gas-driven cooking pits.However, it is currently not possible to determine fugitive emissions from leaks of allof these devices.



heat and electricitygenera�on before combus�on

equipment leaks

Figure 11: Emission sources during end use of natural gas

23

3.10 Liquefied Natural Gas

An increasing amount of natural gas is transported worldwide as liquefied natural gas(LNG) in storage tanks on container ships. This provides an opportunity of export forremote gas markets without international pipeline connection: Australia, Algeria, Qatar,Iran, Malaysia, Brazil, Trinidad and Tobago and Indonesia are the main LNG producers.

Natural gas liquefies when being cooled to -162°C. The cooling process is energyintensive and uses 8-12% of the natural gas throughput [Sevenster, 2006]. Smalleramounts of the energy demand are met by electricity and Diesel oil. During liquefaction,CO2 from fuel combustion and methane from venting and leaks are emitted. Impuritiesin the natural gas that might freeze such as CO2, H2S, N2 and heavy hydrocarbons areremoved before cooling, leaving a gas that is 95-100% pure methane, making leakseven more hazardous.

The liquefied gas is then stored in containment tanks consisting of a concrete outertank and an inner tank of 9% nickel steel. A significant amount of boil-off gases (BOG)are produced in the tanks (0.1-0.25% per day) which are compressed [Sevenster, 2006].They can meet, in part, the fuel need for shipping or be recovered and converted back toLNG. At the destination location, re-gasification takes place, normally by heat exchangewith sea-water at ambient temperature. In some cases, additional heating is involved.Energy use for re-gasification is estimated as 1.5% of the throughput wherein energysaving measures can be implemented to lower this rate and thereby CO2 combustionemissions [Sevenster, 2006].

Emission estimates for LNG is scarce in the literature. One of the more detailedstudies on emissions from LNG was published in 2015 by the American PetroleumInstitute (API) [American Petroleum Institute, 2015]. They classify emission factorsfor operations across the LNG supply chain into combustion (flaring), venting, fugitive,transportation-related and non-routing emissions (from start-up, shut-down, plant upsetsituations). The results are presented in fig.12.

24

Category Emission source Emission Factor

Flaring Processing and Liquefac�on 1.8 - 4-9 g/m³ (raw gas)

CH�

Fugi�ve Components of LNG storage

and import/export terminals

0.0012 - 0-0033 g/m3 (raw gas)

Ocean Tanker, natural gas and BOG

0.0096 - 0.118 m³/hr per component

Leaks from components and processing 0.057 - 1.123 m3/hr per component

CH�

57.6 kg/Btu

CH�

Transporta�on

CH� 0.0916 kg/Btu

Non-rou�ng

Barge, natural gas

CO�

CO�

CO�

CH�

57.6 kg/Btu

0.0381 kg/Btu

Heaters

Marine �ares

CO�

CH�

CO�

CH�

282 - 3250 kg/hr

0.0242 - 0.0248 kg/hr

5.7 - 12.17 ton/hr

0.0069 - 0.015 ton/hr

Marine maintenance CO�

CH�

0.927 kg/hr

1.13 kg/hr

Ven�ng

Plant upsets

BOG storage tanks

CO�

CH�

CH�

44.51 - 53.10 ton/hr

0.05 - 0.059 ton/hr

0.15% of ship storage per day

0.12 - 1.2% per 1000km

BOG vessels during shipping CH�

0.05% of tanker volume per day

Transfer pipelines CH�

Figure 12: Emission factors for LNG by [American Petroleum Institute, 2015]

25

4 Assessment of GHG emissions

The parties of the United Nations Framework Convention on Climate Change (UN-FCCC) agreed on country-specific emission reduction targets for the first time at theconference in Kyoto in 1997. To review the progress in reaching these targets emis-sions have to be quantified and reported annually. Quantification of country-specificemissions includes the measurement or estimation of nationwide GHG emissions fromvarious sectors. Basic measurement approaches will be discussed in the this chapter.The quantified emissions are then reported following the IPCC Guidelines which willbe presented in chapter 4.1.2. Details on the Guidelines that are of particular interest forreporting emissions across the natural gas supply chain will be provided in chapter 4.1.3.In chapter 4.2 I present some studies that provide emissions estimation regarding naturalgas. I selected them from the literature with the intention to illustrate the problemsinvolved in assessing life-cycle emissions of natural gas and to show the wide-rangingestimates that are known from literature.

4.1 Measuring and reporting GHG emissions

This chapter will look into basic approaches of measuring emissions of greenhousegases and instruction on reporting them on a national level.

4.1.1 Measurement approaches

Two basic approaches for determining GHG emissions exist: bottom-up and top-down.Bottom-up approaches involve in the first step the identification of specific emissionsources which are, in the second step, quantified. Direct measurement of all emissionssources is generally not feasible. Hence, some sources are selected and measuredto determine an average amount of release of a GHG. This average value is used asan emission factor that specifies a particular emission source. By multiplying theemission factor with the activity data (a record of activity leading to GHG emissions),the emission is calculated. The relatively accurate characterisation of an emissionsource comes at the cost of high time investment. As a consequence, only few sourceswill be measured. Accuracy of the resulting emissions depends strongly on the qualityof the determination of the emission factor. A good knowledge of possible emissionsources is required in order not to miss out on a source, either due to over-simplificationor due to ignorance. Finally, also the completeness of the activity data, usually extractedfrom nationwide statistics, contributes to the accuracy of the emission estimate.

In top-down approaches concentrations of greenhouse gases in the atmosphere aremeasured, viz. from an airplane flying over a region of interest or from a satellite8.

8AThe first satellite dedicated to CO2 and CH4 measurements, GOSAT, has a resolution of about 100

26

Applying the concentrations into specialized models, it is possible to derive an estimateof the emission source. The advantage of this method is that due to real measurementsof the atmospheric concentration of greenhouse gases no emission source can beoverlooked. On the other hand, it is more difficult to identify the specific emissionsources as atmospheric concentrations mirror the emissions of all sources in a region.For example, in a region with gas production and agriculture, methane emission fromboth sources add up to the atmospheric concentration. Ideally, top-down measurementsshould be aligned with bottom-up measurements. In reality, measurements are at mostaligned with knowledge about specific activity at the time of measurement. For example,well-drilling might be done at the time of measuring concentrations at an explorationsite. The drawback of this top-down approach is the low scale of allocation of possibleemission sources compared to the bottom-up method. The latter can identify emissionson the level of equipment parts, the first on the level of processes.

Plenty of literature is available for both approaches. Generally, top-down studiesestimate higher emissions than bottom-up approaches. Brandt et al. attempted toreconcile emissions known from the literature from both approaches [Brandt, A. R. etal, 2014]. He attributes the gap between top-down and bottom-up emission estimatesto leakages from the natural gas system, thereby ending up with an unreasonably highleakage rate. The authors themselves note that they require "an implausible set ofassumptions" [Berkeley Earth, 2015]. Brandt et al. conclude that a direct combinationof both approaches would be needed to determine emissions estimates across the naturalgas supply chain. I am not aware of any comparable study using this approach.

4.1.2 IPCC Guidelines

On behalf of the United Nations Framework convention on Climate Change (UNFCCC),the IPCC published their first Guidelines for National Greenhouse Gas Inventories in1995. The Guidelines comprise internationally agreed methodologies for the calculationand reporting of greenhouse gas emissions for both sources and sinks. The latest revisionwas agreed on in 2006. Currently, a revision of the 2006 Guidelines, accounting for newscientific and empirical knowledge and providing updated emission factors, is currentlyin progress. The final report is expected for 2019.

The IPCC Guidelines cover all greenhouse gases for which the Kyoto Protocol setsout binding targets, further greenhouse gases not in the Kyoto Protocol and precursors(CO, NOx etc.). These GHG are to be reported in the following main categories:

• Energy

km x 100 km. Identifying specific emission sources is therefore difficult. A further satellite, Tropomi,due to be launched in August 2017, will provide measurements with a resolution of 10 km by 10 km,thus allowing a better identification of emissions sources.

27

• Industrial processes and product use

• Agriculture, forestry, other land use

• Waste

• Others

Each main category is divided into sub-categories. These are too numerous to list.However, fig.13 in the next chapter shows the categories used for reporting the naturalgas life-cycle emissions. Categories that have a significant influence on a nation‘stotal GHG emissions, hence providing the highest potential of reduction, are called keycategories. According to the IPCC Guidelines the emissions of key categories add up to95% of the national GHG emissions. They are determined for both the absolute leveland the trend of emissions. Due to emissions mitigation measures the definition of keycategories has to be re-evaluated each year.

Emissions in each category are calculated by the formula: Emissions = activity data* emission factor. To determine activity data and emission factors, the IPCC Guidelinesforesee three levels of methodological complexity:

• Tier 1 is the basic method and provides the lowest level of complexity. Nationalor international emission factors provided by the IPCC. They are advised to beused where country-specific emission factors are not available. The requiredinput for calculating the emissions with the Tier 1 approach covers the activitydata, which is normally provided from readily available national statics, and theappropriate default emission factor.

• Tier 2 provides an intermediate level of complexity. This approach requirescountry-specific emission factors which are determined on the basis of country-specific data. Activity data is determined on a higher disaggregation level withhigher resolution but still often from national statistics.

• Tier 3 provides the highest level of complexity and data requirements. Activitydata and emission factors are determined from detailed inventories on the levelof processes, for typical designs and for all operating practices. This normallyinvolves detailed measurements. For natural gas transportation, for example,the Tier 3 data distinguishes different materials of pipelines, different pressurelevels, the maintenance and repair program. A typical emission factor is thereforeCH4 emission per km of pipeline per year and per type of material used. Thecorresponding activity data is then indicated as the length of the pipeline network.

An important part of reporting inventories is the estimation of uncertainties. This shouldbe done on category level and comprises the uncertainty of emission factors, activity

28

data and other parameters. Due to the implicated complexity of the data acquisition,higher Tier approaches imply lower uncertainties.

Generally, uncertainty can be caused by a lack of available data, lack of representa-tiveness of data, limitation and simplification of models, statistical random samplingerrors, measurement errors or limitations of measurements as well as false classification(incomplete or unclear reporting). Just as for the activity data and emission factors, un-certainty can be reported based on default values from the Guidelines or be determinedbased on country-specific data where they are available.

4.1.3 Methodologies for the Natural Gas Industry

This chapter will provide more details about the methodologies for determining emis-sions of the natural gas industry. All activities relating to the exploration, exploitationand conversion of primary energy sources, the transmission and distribution of fuelsand the final use of fuels fall into the main category "Energy Sector". Fig.13 providesan overview of the sub-categories foreseen for reporting the emissions.

1 ENERGY SECTOR

1A FUEL COMBUSTION 1B FUGITIVE EMISSIONS

1A1 Energy Industries

1A1c Manufacture of solid fuels

1A1cii Other than solid fuels

and other energy

industries

1B2b Natural gas

1B2bi Ven�ng

1B2bii Flaring

1B2biii Others

1B2biii 1 Explora�on

1B2biii 2 Produc�on

1B2biii 3 Processing

1B2biii 4 Transmission,

Storage

1B2biii 5 Distribu�on

1B2biii 6 Others

Figure 13: IPCC categories for reporting emissions of the natural gas life-cycle

The following specifics are to be mentioned for the Tier approaches: GHG emis-sions from combustion of natural gas depend on the gas composition, the combustiontechnology, operating and maintenance conditions and the age of the equipment. Allthese conditions can be accounted for in the Tier 3 approach. However, for Tier 1 andTier 2 average emission factors are determined. It is obvious that they involve highuncertainties. In contrast, as CO2 emissions from fuel combustion depend entirely onthe carbon content in the fuel, a Tier 3 approach is not necessary. Country-specific CO2

emission factors that account for the carbon content in the natural gas are sufficient. In

29

contrast, CH4 emissions are highly dependent on above conditions. However, the IPCCGuidelines can only provide emission factors for the main technologies. Uncertaintiesare consequently high and according to the IPCC Guidelines in the range of 50-150%.

For fugitive emissions from gas activity, the IPCC Guidelines provide defaultemission factors for the following industry segments: well drilling, well testing, wellservicing, production, processing, transmission, storage and distribution. They arerelated to the production volume. As they are based on data from North America, theymight differ from other regions due to other gas composition, different efficiencies ofthe involved equipment and different hours of operating services, thus leading to highuncertainties when using the default emission factors. Reporting emissions with theTier 1 approach has the disadvantage that changes in emissions over time reflect solelythe changes in activity data and not the real changes of emission intensity. Only theTier 2 or 3 approach can show the real changes. A Tier 3 approach can best describethe fugitive emissions as it takes into account all sources of vents, flares, equipmentleaks and accidental leaks. This is, however, cumbersome as all the equipment has to bemonitored.

The papers that will be discussed in the following chapters, rely at least in part onthe national inventories and therefore use either of the Tier 1, Tier 2 or Tier 3 methods.Where it is mentioned in the papers, the methodology will be shortly explained. Themethodology used in the Dutch natural gas industry will be explained in chapter 5.

4.2 Literature on assessing greenhouse gases for natural gas

In this chapter I present studies that assessed greenhouse gas emissions in the past. Atfirst, I refer to two studies that evaluated methane emissions in the Netherlands. Inparticular, the research by TNO is considered important, despite being published in1995, as it presents the last study providing a detailed evaluation of methane emissionscaused by the Dutch natural gas Industry. In chapter 4.2.2 I will present the results ofan assessment conducted by the Imperial College in London [Balcombe et al., 2015].They analysed life-cycle emissions of natural gas from 240 papers. Chapter 4.2.3explores three publications that analyse GHG emissions of natural gas region-based bydetermining production emissions in the producing country and transmission emissionsto and in the target region.

4.2.1 Assessments from the Netherlands

RIVM: In 1993, van Amstel et al. published a study on behalf of the RIVM (the NationalInstitute of Public Health and Environment Protection of the Netherlands) consideringpossible sources of CH4 emissions during gas production, processing, transportation

30

and distribution (as well as in other sectors such as agriculture, animal waste and more)[van Amstel et al., 1993]. Possible sources during exploration, site-preparation andstorage were not reported. It is not clear if they did not investigate possible sources ofemissions in these stages at all or if they considered them negligible. An estimate forend use was indicated. However, the authors did not provide the actual sources of theemissions. From table 3.2 in [van Amstel et al., 1993] it might be understood that theemissions are solely due to combustion. Total global losses due to flared and ventedgas were indicated as 3.9% of the production. Additional losses, not specified, werequantified to be 4.2%. The data is based on a study by R. J. Nielen published in 1991who used data from 1988.

For their assessment, they used emission factors from the U.S. EnvironmentalProtection Agency (EPA) from the year 1990. These were derived from the U.S. naturalgas system. Van Amstel et al. therefore did not use emission factors specific to the Dutchnatural gas system which distorts the actual emission estimates for the Netherlands.Fig.14 illustrates the EPA emission factors.

Figure 14: Emission factors in % of throughput [van Amstel et al., 1993]

The authors identified the production processes and distribution as the most im-portant methane sources. They also stated that the required data to assess methaneemissions, in particular the number of wells and gas composition, were not available.No differentiation between onshore and offshore was made. Neither did they providesufficient evidence of the methodology used or the involved uncertainties. The studytherefore has to be considered carefully. It is mentioned here as it presents one of thefirst Dutch research on methane emissions in the natural gas system.

TNO: In 1995, the TNO (Netherlands Organisation for Applied Scientific Research)published a report on methane emissions in Dutch oil and gas operations [Oonk andVosbeek, 1995]. In a first study (engineering study) they identify possible sourceemissions during exploration, production, processing, transport and distribution ofnatural gas in the Netherlands. They determine emission factors and activity data, thus

31

being able to calculate the methane emissions. An overview of the emission estimatescan be found in fig.15.


0.2 kt

well tes�ng< 0.1 kt

vents55.5-94.5 kt

�ared1.6 kt

compressors2.3 kt

fugi�ve0-7 kt

energy use3.1 kt

compressors

5.3 mil m³

metering2.9 mil m³

LNG storage2.1 mil m³

pipelines0.7 mil m³

well tes�ng0.2 kt

well cleaning*maybe incorrect, see chapter 6.2

total: 128.3 - 167 kt

Figure 15: Methane emissions across the supply chain based on [Oonk and Vosbeek,1995]

In a second study, atmospheric methane concentrations were measured both sta-tionary and mobile. A stationary measurement station was set up in Kollumerwaardnear Groningen, the region containing the biggest Dutch gas field and multiple produc-tion sites. Mobile measurements were taken near several drilling and production siteswhere the time of drilling and production activities was known. The dispersion modelSTACKS was used to simulate the strength of an emission source from the measuredatmospheric concentration.

The total annual CH4 emissions obtained by both studies were then compared (seeTable 7.12 in [Oonk and Vosbeek, 1995]. Data for 1993 obtained during an engineeringstudy represents an extrapolation of the 1990 data with consideration of mitigationmeasures that were implemented in the meantime.

For determining the bottom-up emissions, the authors of this study used emissionfactors and activity data from various studies. They comprise, at least in part, emissionfactors obtained primarily from data characterizing the U.S. natural gas system. Theauthors themselves mention drawbacks in applying these emission factors to the Dutchsystem to assess fugitive emissions during the production as both systems differ fromeach other. They indicate that this leads to higher uncertainties of the estimates, in therange of -100% to +300%.

The data on which methane emission are estimated in both studies, RIVM and TNO,date back to the late 1980s or beginning 1990s. Since then not only the measurementtechnique but also the understanding of the importance of emission monitoring changed,thereby providing an improved database for evaluating the life-cycle emissions ofnatural gas. Despite these changes, no further comprehensive study on life-cycleemissions was conducted in the Netherlands since the 1990s. At the time of writing thisthesis, TNO and the Environmental Defense Fund (EDF) are engaged in a project tomeasure atmospheric GHG concentrations in the region of Groningen with the purpose

32

of comparing them to bottom-up emissions indicated by companies involved in theDutch natural gas industry. The results of this study are, however, not yet available.

4.2.2 Comprehensive assessment by the Imperial College London

Balcombe et al. from the Imperial College London conducted a wide-ranging assessmentof 240 papers relating to life-cycle emissions of natural gas [Balcombe et al., 2015].Data mentioned in this chapter refer to the year 2012 where not indicated otherwise.Their key findings are:

• The overall GHG estimations at each step across the supply chain (without fueluse) vary significantly. According to literature, 2 to 42 g CO2eq/MJ HHV (HigherHeating Value) for a 100 year time horizon (GWP of 34) are emitted across theentire supply chain. Methane contributes to the total GHG emissions with 0.5%to 3% in average. According to some studies, they can be as low as 0.2% and ashigh as 10%. Fig.5 illustrates the ranges of CO2 equivalents for the main sourcesacross the supply chain.

• In concert with the figure, key emission sources were identified as well com-pletion (for unconventional gas), venting from liquids unloading and workovers.Further important sources come from vents in pneumatic devices and compressorsthat are used during transmission, storage and distribution. The actual amountof emissions depends strongly on the employed technology. It is possible toavoid venting during liquids unloading. Reduced Emission Completions cansignificantly reduce emissions at unconventional wells. Pneumatic devices couldbe changed to air instruments. Additionally, a good maintenance and operationalsystem can reduce reductions. Where this is not done, so called "super emitters"are possible that have extremely high emissions.

• The authors critically mentioned that methodological differences, non-transparencyof available data and under-representativeness of data for some processes (forexample for offshore extraction, well completion with RECs) distorted the assess-ment. Additionally, Balcombe et al. found fault with the fact that most of thestudies they assessed used data from the US gas system. Very few included datafrom Russia and Europe. However, not a single study provided emission datafor Dutch gas system, despite the Netherlands being a very important natural gasproducer.

33

Figure 16: GHG emissions across the supply chain, [Balcombe et al., 2015]

Balcombe et al. provided a detailed evaluation of all emission sources at each stageacross the supply chain. Fig.16 shows their results of GHG emissions. The main sourceswill be presented now:

Pre-production phase: The process of well completion is of particular interest,particularly for unconventional gas due to its high methane emission potential. Thisis caused by "fracking", a well stimulation technique wherein a pressurized liquid isinjected into the underground to fracture the rock formation. As a result, natural gas canflow freely to the well. High amounts of methane can escape from the wells during thisoperation. Maximum methane emissions for well completion reported by Balcombeet al. are 6,800,00 m3 per completion. Using RECs they can be reduced to 25,000 m3

per completion. In contrast, conventional wells account for a maximum of 7,400 m3

per completion. In addition to methane, CO2 is emitted during combustion of energyuse for bore drilling. As this drilling is more intense than for conventional wells, thecombustion emissions present a significant emission source.

Production phase: A further important source of emissions identified by Balcombeet al. is liquids unloading during the production phase. The frequency of unloadingemissions ranges from several times a day to some events per year per well, dependingon the technology. Where a plunger lift system is installed, a plunger that is usually heldon top of the well is released and falls to the bottom of the borehole, thereby closing it.The pressure increases and, when re-opening the well, the pressurized gas will push upthe plunger and the liquid. Where this does not happen automatically as the pressure isstill not sufficient, further measures have to be done. Emissions are caused primarily by

34

malfunctioning plunger systems.

In wells without plunger lifts, manually operated diversion of the gas flow to a lowerpressure destination results in a higher pressure gradient, thereby increasing velocity inthe tubing and lifting of the liquids. During this process, it is required to vent gas fromthe well.

Average emissions from liquids unloading range from zero to 80,000 m3 per yearand well [Balcombe et al., 2015]. Super-emitters might even release up to 500,000 m3

methane per year.

Processing: GHG emissions during processing were classified by Balcombe et al.in CH4 from leaking and venting, CO2 from flaring, due to fuel use and from CO2

separation. Except for emissions from combustion, there is less variability in theseestimates than at other life-cycle stages. Compressors, heaters and other equipment areprimarily gas-driven and amount to a fuel use of 0.5% to 9% of the produced naturalgas. This range is caused by the actual processing that the extracted gas requires. Thisin turn depends strongly on the gas composition and the pressure of the gas at the wellexit. A further source is CO2 from venting resulting from the CO2 removal process. Fornatural gas containing up to 50% of CO2 this makes it an emission source that shouldnot be underestimated. Fig.17 illustrates the range of emissions during processing.

Figure 17: GHG emissions during natural gas processing [Balcombe et al., 2015]

Transmission: A main source of emissions in transmission is caused from combus-tion by gas-driven compressors. Fuel use is estimated to be between 0.5% and 8.6%caused by the high number of compressor stations required in a transmission network.Due to pressure losses in the pipelines, a compressor station is required every 80-160km.

35

Other emission sources are venting from compressors and pneumatic devices andunintentional leaks (fugitive emissions) of the pipelines. Methane emission factorsindicated by Balcombe et al. for the US natural gas sector are 248-1,422 m3 per dayand device for compressors, depending on the technology, and 4,591 m3 per year anddevice for pneumatic devices. These might be considered small amounts. However, dueto the great number of devices needed in the transmission network, the total emissionsare significant.

A further important emission source are fugitive emissions due to leakage in thepipelines. Leakage rates depend strongly on the material. Emission factors for cast ironand unprotected steel are about three times higher than that for plastic according to onestudy assessed by Balcombe et al.9. Cast iron and unprotected steel are therefore notused any longer and, where possible, replaced by plastic pipelines.

Total methane emissions from transmission activities amount for 0.05% to 4% ofthe total produced methane [Balcombe et al., 2015]. However, the authors point out thatestimates higher than 1.6% are considered outdated.

Storage: To compensate seasonal variations, natural gas is stored primarily inunderground structures. Compressors are required to inject the gas into the storagereservoir and back into the transmission network. Balcombe et al. mentioned that themethane emissions due to venting from compressors are 43% of all emissions from gasstorage.

Distribution: Emissions from the distribution network originate primarily frompipeline leakages and venting of pneumatic devices. Aforementioned emission factorsapply. No compressor stations are required in the distribution network.

Besides CH4 emissions at each stage, Balcombe et al. assessed the total GHGemissions of the supply chain. Fig.18 illustrates the variation in methane loss rates thatwere assessed from the literature they reviewed.

9see fig.13, Lamb et al., the emission factor provided by the EPA are considered too high

36

Figure 18: Variation of the methane loss rate in the literature [Balcombe et al., 2015]

It can be seen that most estimates are in the range of 0.5-2.5%. Two studies havevery high estimates of 9% and 10% GHG of the estimated ultimate recovery rate. Aminimum of 0.2% was found.

Balcombe‘s assessment illustrates the dependence of emission estimates on regionalregulations, the selection of equipment, processing practices and, not least, the gascomposition. It is, however, not possible to illustrate these factors in the framework ofthis thesis. Rather, this short overview should indicate the most important results of theassessment.

4.2.3 Region-based assessment

After publication of the assessment by Balcombe et al. several other studies appearedthat tried to evaluate the life-time emissions of natural gas. Three of them are by Exergia,DBI Gut and IASS.

Exergia: The Exergia-study European Comission [2015] was conducted on behalfof the European Commission. This study evaluated life-cycle emissions from gas that isdistributed in four regions in the EU: South East EU, South West EU, North EU andCentral EU. It took into account the emissions emitted during production and processingin all producing countries that delivered to the respective EU-region: producers insidethe EU and outside, transportation by pipeline and as LNG. Life-cycle emission datawere modelled for different operations across the supply chain of natural gas using theGHGenius model.

DBI GUT: Critics about the Exergia study came from DBI GUT DBI GUT [2016],among others. They consider the Exergia-study to rely partly on obsolete data orestimations and to lack transparency of the calculations. To provide better data, DBI

37

GUT conducted a similar study. Their data came from various European organisations,among them also operators in the Dutch natural gas industry (Gasunie, Gazprom, Shell,Uniper) and from national inventories in the years 2012-2014. GHG emissions werethen estimated for production in Germany, the Netherlands, Norway and Russia. TheGHG emissions from production in the Netherlands can be found in fig.19.

CH� emissions

66.8

6

11

produc�on

processing

CO�, S�O removal

transmission, storage, distribu�on

transport to anotherEU country

CO� emissions

924

127.3

24.2

0.8

1.1

Figure 19: CO2-equivalent GHG emissions for the Netherlands in g/GJ [DBI GUT,2016]

Finally, the Carbon Footprint was determined for all natural gas distributed inCentral EU and the contribution of each producing country to said Carbon Footprint.The GHGenius model was used for the calculations. For comparison the study usedtwo global warming potentials from AR4 (GWP100=25) and AR5 (GWP100=34). TheCarbon Footprint of natural gas produced in the Netherlands and distributed in CentralEU is illustrated in fig.20 together with the total emissions in gCO2/GJ for GWP100=25and GWP100=34.

produc�on

processing

CO�, S�O removal

transmission, storage, distribu�on

transport to anotherEU country

GWP�� gCO�eq/GJ

25

34

3185

3631

Figure 20: Carbon footprint of natural gas produced in the Netherlands and distributedto central EU in 2014 [DBI GUT, 2016]

IASS: The Institute for advanced sustainability studies (IASS) in Potsdam publishedan assessment of methane leakage rates for Germany, the Netherlands, Russia and theUSA in December 2016 [Cremonese and Gusevs, 2016]. Their rationale behind it was

38

the lack of harmonized methodology in estimating emissions, the poor reporting andmeasurements as well as partly outdated data that were used in the past to estimatemethane emissions for natural gas. Hence, accuracy of the estimates in studies in thisfield is sometimes doubtful. The authors Cremonese and Gusev highlight that a methaneleakage rate equal to or higher than 2.7% across the supply chain makes natural gasworse than coal in terms of climate impact. It is therefore important to identify theemission sources to enable the definition of well-directed mitigation measures. Theauthors refer to the World Energy Outlook Special Report 2015 which underlines that"upstream oil and gas methane reductions could yield 15% of the reductions neededto deliver such an early peak in emissions", a peak in 2020 [Cremonese and Gusevs,2016].

The basis for methane estimates in the IASS-study were the national inventoriesof Germany, the Netherlands, Russia and the USA. For the Netherlands, they resultedin a total methane emission of 27.21 kton in the year 2014. This number comprisesemissions during production, processing, transmission and distribution of natural gas asillustrated in fig.21. The distribution in Germany, Russia and the USA are illustratedfor comparison.

(21%) (49%)

(30%)

Figure 21: Methane emissions in the Netherlands and other countries in 2014 [Cre-monese and Gusevs, 2016]

Large variations in the share of each stage across the supply chain can be seen forthe four countries. The high emissions during production in the USA can be partlyexplained by the higher emissions due to unconventional gas production. Russia has

39

a very extensive pipeline network, which might contribute to the high emissions intransmission. On the other hand, regulations are stricter in Europe than in the USAand Russia which might contribute to the lower share of production and processingemissions compared to the US system. "It is challenging to explain this large variancethrough practices or legislative regimes" as the authors emphasize [Cremonese andGusevs, 2016]. Differences might be due to a lack of understanding the diverse sourcesof methane emissions and inappropriate measurements across the natural gas supplychain. Or they might be from incomplete activity data in the national inventories.

4.3 Summary

The selected literature presented in chapter 4 illustrates the diversity of estimatingemissions in the life-cycle of natural gas. Some studies do not consider all possiblesources of emissions, thereby skewing emission estimates for the entire supply chain.Other studies apply emissions factors, primarily determined based on data from the USgas system, to other regions that might differ significantly. Region-specific emissionfactors are therefore required. The assessment by Balcombe et al. illustrates how wide-ranging emission estimates are, therefore leaving doubt on the accuracy and reliability ofthese estimates. Differences are partly due to different technologies being compared, forexample unconventional and conventional gas production. However, these differencescannot explain the entire range of variations in emissions.

40

5 Emissions from the Dutch natural gas system

To understand the complexity of the Dutch natural gas industry and the involveddifficulties in a harmonized reporting of emissions, this chapter will provide an overviewof the key players. The production figures from the Dutch gas fields and a description ofthe characteristics of each segment across the supply chain will be provided subsequently.The chapter finishes with explanations on the empirical method that was employed inthis study and a presentation of the emission data that was gathered.

5.1 The natural gas industry in the Netherlands

5.1.1 Key players

The Netherlands is an important natural gas producing country. They rank second inEurope (after Norway) and tenth worldwide. After the discovery of the biggest gas fieldin the province of Groningen (Groningen Gas Field) in 1959 they quickly developed awide-ranging natural gas infrastructure.


State

stateowned

100%

shareholder

Trading

Figure 22: Structure of the natural gas industry in the Netherlands

The key players participating in the Dutch natural gas system are illustrated in fig.22.NAM (Nederlandse Aardolie Maatschapij), owned equally by Shell and Exxon, is byfar the biggest producer of natural gas. The state-owned organisation EBN (EnergieBeheer Nederland B.V.) is involved with 40% in exploration and production projects.Besides NAM many more organizations have a license for exploring Dutch gas fields.They are usually active in the many small fields both on-shore and off-shore. Some ofthe producing companies, mainly NAM, TAQA and EBN, utilize depleted gas fields inthe Netherlands and a salt cavern in Germany as working gas storages.

41

The only transmission system operator active in the Netherlands is the N.V. GasunieNederland (short: Gasunie) of which the state is the 100% shareholder. To cope withseasonal variations in gas demand Gasunie maintains an underground storage with avolume of 0.2 bcm. An additional LNG storage tank in Maasvlakte near Rotterdamserves as a peak shaver. Energy providers and large industry companies are directlyserved by Gasunie.

City gates form the transition points between the high pressure transmission networkand the low pressure distribution network. Gas arriving with a pressure of 40 baris converted to lower pressures for regional distribution. In the Netherlands, sevendistribution system operators are active within defined regions to transport the gas tothe households and to small industry companies. About 98% of the Dutch householdsare connected to the natural gas grid.

5.1.2 Dutch gas production

Until 2016 a total of 477 gas fields were discovered in the Netherlands. Of this, 253were producing both on-shore and off-shore [EBN, 2017]. The Groningen gas field isthe biggest in the Netherlands and the tenth biggest worldwide. Based on an estimationof EBN, the total remaining reserves on Dutch territory in 2016 are 891 bcm of naturalgas of which 665 bcm is the Groningen gas field [EBN, 2017].

Composition of Dutch gas differs between the Groningen gas field and most of thesmaller fields. Methane content ranges from 70% to 95%. Due to its higher amount ofNitrogen, Groningen gas has a low-calorific value (L-gas) while most small fields havea high-calorific value (H-gas). At the beginning of the Dutch natural gas production,appliances were adapted to the L-Gas from Groningen, back than the only producingfield. Currently there are only few customers, mainly industry companies, that receive H-gas nowadways. The H-gas from the smaller fields is therefore enriched with Nitrogento make it conform to L-Gas. The same applies for imported gas which is generallyhigh-calorific. In this thesis I will not distinguish between high and low calorific values.Where calorific values are applied they comply with the Dutch L-gas norm (44.3 MJ/m3

[RVO, 2015]).

Total natural gas production in 2015 was 49.7 bcm, with a volume of 28.1 bcmfrom Groningen and the remaining 21.6 bcm from the small fields [International EnergyAgency, 2012]. This is a significant decrease compared to the years before. Forcomparison, in 2012 the total production was 80.2 bcm [International Energy Agency,2012]. After heavier than usual earthquakes hit Groningen due to the natural gasextraction from the underground, the Dutch government decided to put a productioncap on this field. It was set to an annual output of 24 bcm from 2016 on. However, an

42

updated regulation further reduced the maximum production by another 10%. Fig.23shows the decrease in production volume for the years 2013-2016.

80.07 bcm

65.98 bcm

49.84 bcm47.91 bcm

2013 20162014 2015

Figure 23: Indigenous natural gas production in the Netherlands10

The production cap will lead to a higher importance of imported gas in the future.Eventually, the Netherlands will switch from a net exporter to a net importer. Currently,gas is imported from Norway, Russia and to a small amount from Denmark and as LNGfrom further countries.

The importance of natural gas for the Netherlands is apparent from statistics aboutgas consumption. In 2015, 38% of the primary energy consumption was from naturalgas. Fig.24 illustrates the energy mix in the Netherlands in 2015. The main consumingsectors of natural gas are energy production (32% of the total Dutch gas consumption),agriculture (34%) and households (28%). In 2015, natural gas was the primary fuelfor electricity generation (42%), followed by coal (35%). Significant CO2 emissionsare released during combustion of the natural gas. According to the NIR 2017 RIVM[2017] public heat and electricity generation and residential stationary combustion fromnatural gas contributed to the total greenhouse gases in 2015 with 10.4% and 9.2%,respectively.

10received via email from NOGEPA on 28.08.2017

43

20%

6%

2%

Figure 24: Mix of primary energy use in the Netherlands in 2015, based on [InternationalEnergy Agency, 2012] and [EBN, 2014]

In the next chapter I will provide details about each stage across the supply chainof natural gas in the Netherlands. I will provide the emissions data received from theorganizations and explain how I gained them.

5.1.3 The transmission network and storage facilities

Gasunie, of which the Dutch state is a 100% shareholder, is the only Dutch transmissionsystem operator (TSO). It operates about 12,000 km of transmission network in theNetherlands and another 3,500km in Germany. Gas is transported in high pressuretransmission lines with 66 bar and in regional transmission lines with 40 bar. The firsttype is used to deliver gas to power plants and the large industry as well as to exportingstations. The regional transmission lines bring the gas to the receiving stations (citygates) which form the transition point to the distribution network.

Part of Gasunie‘s transmission network are 22 compressor stations, 19 blendingstations, 93, regulation stations, 1,300 gas delivery stations, 14 export stations and 2LNG peak shaver storage tanks. For import and export, the network has connectionpoints with the transmission networks from Norway, Russia, Belgium, the UK andGermany. Additionally, they have 2 facilities where H-gas is blended with Nitrogento make it L-gas compliant. Nitrogen is stored in Gasunie‘s own underground storagefacility. To cope with seasonal variations in gas demand, Gasunie uses an undergroundgas storage and a LNG storage tank as peak shaver.

The information about annual transport volume of natural gas shown in fig.25 isextracted from the annual reports by Gasunie [Gasunie, 2015, 2016, 2017].

44

116 bcm

99.7 bcm94.8 bcm

99 bcm

2013 20162014 2015

Figure 25: Transported gas volume in the Netherlands, based on [Gasunie, 2015, 2016,2017]

5.1.4 The distribution network

The regional distribution operators in the Netherlands receive gas from Gasunie at theircity gates. The pressure is reduced from 40 bar to 8 bar and gas is injected into the highpressure distribution grid. Some of this gas is directly distributed to industry companies.What remains is fed to supply stations where the pressure is further reduced to 100-300mbar. The gas is then transported to households and other industry companies using afine-meshed low pressure distribution grid.

KIWA is an independent institution active in manufacturing, trading, inspectionand certification of new technologies. Additionally, they are involved in draftingsafety standards. On behalf of Netbeheer Nederland, the inter-trade organizationfor all electricity and gas network operators in the Netherlands, KIWA published areport on the emissions from gas distribution. More accurately, they considered onlymethane emissions from pipeline leakages. During an email interview, NetbeheerNederland indicated that venting and flaring emissions were estimated for gas facilitiesand maintenance work during a project in the past. Due to their small amount comparedto emissions from pipeline leaks, venting and flaring emissions are not reported. Nofollow-up investigation on these emissions has been to-date.

To improve this situation, KIWA is engaged in the MEEM project that will nowbe briefly presented. The European Gas Research Group (GERG11), a partnership ofseven European nations among them the Netherlands, launched a project to develop aconsistent and accurate method for methane emission estimation from the distributiongas grid (MEEM). Motivation for this project is based on a study by DBI GUT on

11Groupe Européen de Recherches Gazières

45

behalf of GERG that analysed the various methods used at present in different Europeannations [GERG, 2016b]. The aim of this first study was to identify best practices andpotentials for optimizing the reporting of distribution emissions.

DBI GUT assessed multiple studies and expert interviews from the years 1989 to2015 to determine the strengths and weaknesses of the various methods used at present.They found that not all studies consider all possible emission sources either intentionallydue to minor impact on the total methane emissions or due to different system boundariesbetween the transmission and distribution systems12. The authors suggest using adifferent level of complexity for determining emissions from sources13 with minorcontribution and sources with main contribution to the total methane emissions.

Phase II of the project to develop the Methane Emission Estimation Method (MEEM)for the gas distribution has started in 2016. The final result is expected for Spring 2018[GERG, 2016a]. A parallel project for developing a corresponding method for the gastransmission grid is foreseen to start in autumn of 2017 with the final result expectedfor the winter 2018 [GERG, 2017].

5.1.5 Final use

Natural gas is the main fuel for energy generation in the Netherlands, both for residentialand public heat and electricity generation. 74% of the energy of household originatesfrom gas use, only 19% from electricity. Public centralized and decentralized electricityproduction uses 42% of natural gas, 35% of coal and the remaining for renewableenergies and nuclear energy. 34% of all industrial processes use natural gas as fuel[EBN, 2014].

The annual reports (NIR) aggregate CO2 and CH4 data of final use in differentcategories, for example public heat and electricity generation, residential stationarycombustion and gas use for the manufacturing industries. However, this data does notallow to distinguish emissions for different technologies. Moreover, the NIR reportsaggregate emissions from all "gaseous fuels", thus going beyond solely natural gas.Due to the extent of available gas-driven technologies for which specific emission datawould have to be considered, it was not possible within the framework of this thesis tocollect emissions data for all of the heat and electricity generating technologies.

Emissions from the segment "final use" is therefore omitted from the calculation ofthe carbon footprint of natural gas.

12Some studies count the city gates to the transmission network, others to the distribution network.13The authors distinguish emissions from gas facilities and from pipelines, the latter being categorized

as follows: intrinsic emissions (permeation, pinholes, cracks, leaking joints), operational emissions(venting and purging), incidental emissions (large leakages).

46

5.2 Empirical method

The annual national inventory reports of GHG emissions (NIR reports) do not providethe emissions with the level of detail required for my analysis. It was therefore necessaryto contact the organizations involved in the Dutch natural gas industry to receive moredetails.

The natural gas industry in the Netherlands is diverse in terms of its organizationsinvolved in operations across the supply chain as can be seen from fig.22. A greatnumber of companies is provided with a license to exploit the gas fields, both on-shoreand off-shore. These companies also undertake all required raw gas treatments toprovide dry gas that can be transported. Gasunie transmits the natural gas along highpressure pipelines to power plants, to large industry, to export stations and to city gates.At the latter, the pressure of the gas is reduced for transportation in the distributionnetwork. Seven regionally operating distribution system operators share the Dutchdistribution network.

All companies along this chain set up their own reporting programme. This involvescompany-specific categories of emissions and the free choice of metrics. In viewof this in-harmonized emissions reporting of the companies I chose for qualitativeinterviews with the key players in the gas industry rather than for a questionnaire. Theinterviews took place as informal expert interviews or as email interviews. Duringthe interview, the aim of this thesis and the importance of gathering the emissionson a higher level of detail than provided by the national inventory were discussed.The organizations provided not only the emission data but also insightful informationregarding their monitoring programmes (as far as this was possible without revealingsecrecy information). I addressed the following organizations:

• NOGEPA: They represent all Dutch companies having a license for natural gasexploitation. They provided me with emission estimates from operations in thesegments of gas field exploration, production and processing. Emissions fromon-shore and off-shore activities were reported individually. So were emissions ofCO2 and CH4. The data was gathered from the electronic environmental reportingtool (e-MJV) which is used by the Dutch gas industry to report their emissions.

• Gasunie: The Dutch transmission system operator provided me with emissionestimates that originate from their own monitoring system.

• Netbeheer Nederland: They represent the seven regionally operating Dutchdistribution system operators and provided me with methane emissions from thedistribution network. This data was aggregated in a report about pipeline leakagesthat was recently published by KIWA, an independent institution for inspectionand certification of new technologies in the Netherlands.

47

Every organization has its own internal emission monitoring scheme. This includes acategorization of emission sources that do not have to coincide with those of the IPCCGuidelines or those of other studies. The presentation of the emission estimates aretherefore dependent on the monitoring programme of each organization and might notbe directly comparable to those of the literature discussed in chapter 4.2. A requirementwas, however, to receive emission estimates for CO2 and CH4 separately.

5.3 Emission estimates received from the Dutch gas sector

5.3.1 Emissions from exploration, production and processing

The Netherlands Oil and Gas Exploration and Production Association (NOGEPA)represents the interest of the all companies with natural gas exploration license in theNetherlands. NOGEPA provided emission data from well preparation operations andoperations during production and processing of the raw gas. The emission data wasextracted from the database of the electronic environmental reporting tool (e-MJV). Useof this tool for reporting emissions from the oil and gas companies in the Netherlandsis compulsory since 2006. However, there is no regulation for a harmonized reportingamongst the companies. They define their own company-specific emission categories.As a consequence, fugitive emissions are not explicitly reported but are aggregatedwith emissions from other sources in the category "others". It is not clear which otheremission sources are included in this category.

The e-MJV database is administered by the Netherlands National Institute for PublicHealth and the Environment (RIVM). However, no formal check of the emissions datareported by the operators is done. In particular, they do not control how the reportedemissions were determined, if they are reliable and complete or if possible emissionsources were excluded. As a consequence, wrongly emission reports are not identifiedby the RIVM. Spotting them might be possible at a later stage such as happened inmy thesis. The original data set I received contained one value that was obviouslyinconsistent. The emission for one year was a magnitude higher than for other years.This mistake could be corrected as the respective operator who originally reportedthe wrong emissions could be addressed by NOGEPA and a corrected value was sent.However, this indicates the lack of control of the reported values.

Fig.26 provides an overview of the aggregated emissions from all natural gasproducing companies in the Netherlands. The data includes emissions from on-shoreand off-shore facilities. Due to the reporting system of NOGEPA, it was not possible toreceive emissions data separately from production and processing operations.

48

CO� emissions in tonne:

CH� emissions in tonne:

2013 2014 2015 2016

Explora�on: 242 363 975 615

Well drilling 2 8 11 1

Well tes�ng 241 355 964 614

produc�on and processing: 19,558 14,054 13,260 11,967

Energy genera�on 1,779 855 908 732

Flaring 213 168 126 168

Ven�ng 15,942 10,660 10,405 9,218

Other (including fugi�ve) 1,623 2,372 1,821 1,849

Total 19,800 14,417 14,235 12,583

2013 2014 2015 2016

Explora�on: 69,274 117,376 101,680 50,292

Well drilling 43,970 77,526 71,964 38,441

Well tes�ng 25,304 39,850 29,716 11,852

produc�on and processing: 1,917,846 1,908,348 1,745,991 1,600,332

Energy genera�on 1,762,233 1,846,346 1,674,175 1,547,271

Flaring 61,310 58,333 54,481 49,354

Ven�ng 2,180 2,327 2,275 2,258

Other (including fugi�ve) 92,123 1,341 15,060 1,449

Total 1,987,120 2,043,601 1,847,671 1,650,624

Figure 26: CO2 and CH4 emissions from exploration, production and processing14

As can be seen from fig.26 the data for exploring new gas fields is dominated byCO2 emissions. It is noted that methane emissions are not converted to CO2-equivalentsyet. They should therefore not be directly compared with the CO2 values. However,due to the difference in magnitude of CO2 and CH4 for the exploration phase, it canbe seen that methane emissions are much smaller. Both CO2 and CH4 emissions arefluctuating strongly on an annual basis. The reason is their direct correlation with theactual exploration activity and therefore the drilling events per year.

Emissions from production and processing are more consistent, although a slightdecrease is visible over the last four years which is caused primarily by CO2 emissionsfrom on-site energy generation. If this is achieved by more efficient equipment or anincrease in electricity purchase from the grid, hence a mere shift of emissions sourcesto the electricity generation companies, is not derivable from the data.

What is visible from fig.26 are the highly unstable CO2 estimates in the category"others". This includes the fugitive emissions. However, it is not known which otheremission sources are reported here, hence which share is actually from the fugitiveemissions. This lack of disclosure of the emission sources prevents from taking any

14received from NOGEPA via email on 27.07.2017

49

conclusion about the reasons for the fluctuations. CH4 estimates are relatively constantfor this category.

CO2 emissions from venting and CH4 emissions from flaring are relatively stablewhereas CO2 emissions from flaring and CH4 emissions from venting are continuouslydecreasing. This trend is likely caused by the drop in production volume in the lastyears but also by implemented mitigation measures.

5.3.2 Emissions from transmission and storage

Gasunie pursues the goal of a 20% reduction in GHG emissions by 2020. To achievethis goal they increase the energy efficiency to reduce their energy demand and theyimplement measures to reduce methane emissions. Efficiency is improved by enhancedinsulation of the compressor stations and by routing gas along the most efficient transportroutes to thereby reduce the need for re-compression. Mobile compressor stations areused to reduce methane emissions. In the past, for maintenance of a pipeline sector,the gas enclosed in this pipeline sector was vented or flared until the sector is freedof natural gas. With a mobile compressor the gas from the closed pipeline sector ispumped to a parallel pipeline, thus avoiding releasing it into the atmosphere. Furtheremission reduction is achieved by the ongoing replacement of gas-driven engines bycompressed-air engines, thereby avoiding the emission of CO2 from on-site combustion.

2013 2014 2015 2016

Pneuma�c emissions: 1.457 1.348 1.314 1.269

Pressure control valves 1.041 932 898 852

Turbine related 84 84 84 84

Others 332 332 332 333

Vents: 2.910 2.382 2.553 3.134

Compressor starts 210 103 119 112

Compressor stops 624 477 702 458

Incidents 0 0 0 0

Maintenance 1.018 614 550 408

Measurements 336 336 336 336

Others 603 795 765 1.715

Unburned 119 57 81 105

Fugi�ve emissions: 5.109 4.383 3.336 2.465

Total: 9.476 8.113 7.203 6.868,, , , ,

,

,

,

, , , ,

, , , ,

, , , ,

2013 2014 2015 2016

CH₄ emissions in tonne:

Figure 27: CH4 emissions from transmission and storage of natural gas15

Recently, Gasunie implemented a rigid emission measurement programme. Withina period of four years, all of their equipment is measured at least once. This allows adetailed record of CH4 emissions. Key emission sources can therefore be identified and

15received from Gasunie during an interview on 30.06.2017

50

focused mitigation measures can be developed. The CH4 emissions received during myinterview with Gasunie are shown in fig.27.

Methane emissions from transmission are continuously decreasing within the years2013-2016, which might be due to the rigid emissions monitoring, particularly forpipeline leaks. As is visible from fig.27 fugitive emissions more than halved within fouryears, thereby contributing most to the overall decrease of CH4 reduction. This evenoffsets other emissions sources that increased in the same time such as "others". It isnot derivable which emissions sources exactly are reported in this category.

Besides CH4 emissions, Gasunie reports their CO2 emissions from on-site energygeneration, primarily from gas-driven engines, and from electricity they purchase fromthe grid. The latter is usually not reported explicitly by gas transporting companies asthe emissions are generated at location of the electricity generation company. However,Gasunie reports according to the Greenhouse Gas Protocol, an initiative of businesses,governments and NGOs to develop international standards to account and inventorisegreenhouse gases [Greenhouse Gas Protocol, 2016]. They suggest reporting in threescopes:

1. Scope 1 comprising emissions from sources a company owns or controls;

2. Scope 2 comprising emissions from generation of electricity that is consumed byown equipment and

3. Scope 3 comprising emissions for production of purchased material.

CO2 from electricity generation in devices operated by Gasunie are therefore reportedunder Scope 2.

In addition to methane emissions, Gasunie indicates in their annual reports theamount of CO2 emitted [Gasunie, 2015, 2016, 2017]. Fig.28 illustrates these emissionswhich are from energy generation by equipment used on-site (scope 1) and fromgeneration of the electricity that is purchased via the grid (scope 2).

2013 2014 2015 2016

111.90 67.10 51.30 50.40

Emissions from gas use [kt] 200 122 91 89

Electricity consump�on [mil kWh] 441.20 431.3 548.90 685.90

Emissions from electricity use [kt] 164 157 232 308.60

Gas consump�on [mil m³]

Figure 28: CO2 from gas and electricity consumption [Gasunie, 2015, 2016, 2017]

As can be seen, consumption of natural gas steadily decreased within the lastfour years caused by the replacement of gas-driven compressors by electricity-drivencompressors. As a consequence, electricity consumption increased at the same time.

51

For 2016, an over-proportional increase in electricity use can be seen. This is justifiedby an increased need for Nitrogen blending due to a higher import of natural gas whichis caused by the production cap set for the Groningen gas field.

5.3.3 Emissions from distribution

In a recent study conducted by KIWA in 2017 [Ophoff, 2017] methane emissions weredetermined for the years 1990 to 2016. The result is illustrated in fig.29, with a detailedindication of the annual CH4 emissions for the years 2013-2016, that will be used laterto calculate the carbon footprint.

8.8

8.5

8.2

7.9

7.6

7.3

19

90

19

95

20

00

20

05

20

10

20

15

20

13

20

14

20

16

7.9

38

.008.0

98.2

1

Me

tha

ne

em

issi

on

in

[m

il m

³]

Figure 29: CH4 emissions from pipeline leaks during distribution16

After a first rise in CH4 emissions, they could be continuously reduced since 2004despite an ever growing distribution network. Since 2013, the emissions are on a levellower than in 1990. This is likely caused by a steady replacement of old cast ironpipelines with plastic pipelines having lower emissions factors.

The country-specific emissions factors which formed the basis for the emissionscalculation, were determined in a study by KIWA that was published in 2015 [Ophoff,2015]. The emission factors were determined from a total of 50 measurements ofleaks that were found during the regular leakage monitoring by the Dutch gas networkoperators in the years 2005, 2006 and 2014. However, the entirety of measurementsdo not present all possible combinations of pipeline materials and pressure levels.Nevertheless, KIWA considers them a representative mix of the Dutch gas grid. Basedon the measurements, the average emission factors shown in table 2 were calculated.

16values received from Netbeheer Nederland via email on 24.08.2017

52

Table 2: Emission factors for pipelines [Ophoff, 2017, p.3]

Type of pipeline Emission factor

Gray cast iron 323 m3 CH4 / kmOther materials ≤ 200 mbar 51 m3 CH4 / kmOther materials > 200 mbar 75 m3 CH4 / km

CO2 emissions from the distribution of natural gas are caused primarily by com-bustion of gas-driven compressors. The emission estimate is extracted from the annualinventory reports (NIR). For the years 2013-2015 the annual emissions were 0.18 ktCO2. At the time of writing this thesis no information was available for the year 2016.Considering the consistency of the reported emission value over the past years, theamount of 0.18 kt will be assumed for the year 2016.

53

6 Carbon Footprint of Dutch natural gas industry

In this chapter I will combine all emission data received from the Dutch gas operatorsto determine the GHG emission (carbon footprint) across the entire supply chain. Thecarbon footprint is given as a single metric: the carbon dioxide equivalent (short CO2eq).It indicates the amount of CO2 that, when released into the atmosphere, would havethe same global warming effect over a defined time period as the emission of a givenmixture of greenhouse gases.

To complement, the methane loss rate across the supply chain is of interest. This willbe determined as the percentage of methane emissions of the total volume of extractedmethane, thus depending on the annual production volume.

Both results, the GHG emissions and the methane loss rate, will finally be comparedto the literature.

6.1 Total GHG emissions

The carbon footprint of natural gas is a measure for the total amount of greenhousegases emitted from operations across the fuel‘s lifetime. The natural gas industryprovides in-depth emissions for the two most important greenhouse gases: CO2 andCH4. National inventories provide also emission estimates for N2O. However, this datais not available for individual supply chain segments.

To indicate the carbon footprint in a single metric (CO2-equivalent), CH4 emissionvalues are multiplied by the Global Warming Potential (GWP). The GWP indicates ameasure of radiative forcing over a certain time horizon. The time horizons chosenby the IPCC are 20 and 100 years. As was mentioned in chapter 2.3, the choice ofthe time horizon can influence the timing of mitigation measures. As an independentstudy my thesis is not intended to bias any decision. I will therefore indicate the carbonfootprint for both time horizons using the conversion values GWP20=86 and GWP100=34provided by the IPCC Guidelines 2006 [IPCC, 2006]. However, comparison to theliterature will be based on the 100-year time horizon as this is used by [Balcombe et al.,2015].

Fig.30 shows the carbon footprint for the years 2013-2016 in CO2-equivalent, i.e.the CH4 estimates were converted to CO2-equivalent and then combined with the CO2

estimates to provide a single metric. It is given in dependency of the annual naturalgas production volume for the respective years extracted from fig.23. For the unitconversion of the production volume from billion m3 to MJ, a calorific value of 44.3MJ/m3 is used, which is according to the Dutch L-gas norm.

54

GWP

GWP

2.5

2.0

1.5

1.0

0.5

0.0

2013 2014 2015 2016

gC

Oe

q /

MJ

Figure 30: CO2-equivalent GHG emissions from the entire supply chain

Fig.30 illustrates the stronger impact of methane due to its higher GWP value, thusresulting in a 1.5 times higher carbon footprint for the 20-year time horizon. Irrespectiveof this, both timelines reveal a slight increase of the carbon footprint in the years 2013-2016. This is despite a decrease of the production volume (see fig.23). This allows theconclusion that the emission estimate does not not directly correlate to the amount ofproduced gas, as would be expected. One possible explanation for this might be thatthe many Dutch gas fields are depleting, which increases the effort to extract the rawgas, hence resulting in a higher energy demand during exploitation and more intensetreatment. This presumption would hae to be verified by taking an insight look on theoperational changes of the production companies. It is not possible to find reasonsmerely based on the available emission data.

The carbon footprint determined for the year 2016 is 1.4 gCO2eq/MJ. Comparedto the indication in [Balcombe et al., 2015, summary], who indicate a range of 2-42 gCO2eq/MJ for the 100-year time horizon (GWP=34), this value is in the samemagnitude and can therefore be considered reliable. Finding an explanation for thisexceptionally low value for the Dutch system is difficult. It would be necessary tounderstand the exact emission sources that contributed to the value of 2 gCO2eq/MJfrom the literature. They are not indicated by [Balcombe et al., 2015]. Possible reasonsfor the higher value could be a different methane content in the raw gas, the need of amore intense treatment of the raw gas or high leaks during transportation. Moreover,the value could be from unconventional gas production.

More details on emissions across the supply chain can be found in fig.31 whichillustrates a breakdown of the total GHG emissions for all segments. The higher climateimpact of the CH4 emissions for the 20-year time horizon compared to the 100-year

55

time horizon is visible from fig.31. Nonetheless, contributions from CO2 are oftenhigher than from CH4 (in CO2-equivalent).

Figure 31: CO2-equivalent GHG emissions for supply chain segments, 2016

The aggregated segment "exploration + production + processing" (EPP) is identifiedas the main contributor to the entire GHG emissions. As can be seen on the right side ofthe figure, combustion emissions (CO2) from on-site energy generation has by far thehighest share, followed by CH4 emissions from venting and "others". It is not derivablewhich share of this is due to fugitive emissions.

56

In the segment "transmission + storage" (TS) emissions from different sourcesare more uniform. For the 20-year time horizon, CO2 emissions from on-site energygeneration and CH4 emissions from venting and fugitive emissions provide the mainshare.

Not surprisingly, the key emission sources found in [Balcombe et al., 2015] arenot found back in the Dutch gas industry. Well-completion is a problem particularlyfor unconventional gas fields. They are not allowed in the Netherlands. Also liquidsunloading is not an issue in the Netherlands. During my interview with NOGEPA itwas indicated that this process is not required due to higher pressures with which thenatural gas is extracted.

That said, it has to be noted that no details are known about some of the emissionsources during in the EPP segment. For example, it is unclear which sources contributeto the venting, flaring and fugitive emissions in detail. This lack of transparency doesnot allow to judge if the data is complete. If possible emission sources are neglected thetotal emissions might be under-estimated.

6.2 Methane only emissions

Methane‘s high global warming potential emphasizes the interest in the CH4 emissionsacross the life-cycle of natural gas. This chapter will provide results on the methaneonly emissions. An overview of the methane emissions at each segment of the supplychain and for the entire supply chain can be found in fig.32.

2013 2014 2015 2016

40

30

20

10

0

CH

em

issi

on

s in

kt

Expl./Prod./Proc. Trans./Storage Distribu�on Total

2527

28

35

Figure 32: CH4 emissions across the supply chain

With about half of the entire CH4 emissions, the segment "EPP" provides the maincontribution. A continuous decrease is visible from the diagram for the years 2013-2016.

57

This is caused primarily by reduced emissions from production and processing and tosome degree from reduced emissions from transmission and storage. In contrast, CH4

emissions from distribution are very stable.

More details on the actual emission sources within the segments are illustrated infig.33. With about 70% of all methane emissions in the segment "EPP", emissions fromventing are by far the highest share. Another 15% are from the category "others" whichincludes the fugitive emissions. As mentioned earlier it is, however, not possible toretrieve the actual amount of fugitive emissions from the data. The remaining 25% areshared by energy production and well testing. Flaring and well drilling emissions areinsignificant.

Figure 33: CH4 emission share for segments of the supply chain, 2016

Almost half of the CH4 emissions in the segment "transmission and storage" arecaused by vents from the equipment and from maintenance work. Another 36% arefrom fugitive emissions and the remaining from pneumatic devices.

The CH4 emissions will now be compared to the literature. The latest comprehensiveassessment of emissions caused by the Dutch natural gas industry was done in 1995by the Netherlands Institute for Applied Scientific Research (TNO). Indications forindividual segments of the supply chain add up to an average value of 148 kt CH4 [Oonk

58

and Vosbeek, 1995, sum of data from tab.6.8, tab.6.11, tab.6.13 and p.61]. The totalCH4 emissions for 2016 are at 25 kt. This results in a net reduction of more than 80%.

However, emissions from the distribution network in [Oonk and Vosbeek, 1995] areindicated with 56 kt for the year 1990 which appears unreasonably high. In addition,the report published by KIWA [Ophoff, 2015] indicates for the same year a value of8.28 mil m3, which converts to 5.95 kt CH4. It is therefore suggested that the value of56 kt in [Oonk and Vosbeek, 1995] should be replaced by 5.95 kt. It is at this pointreferred to table 3 which provides a per-segment overview of the methane emissionestimates from 1990 [Oonk and Vosbeek, 1995] and from 2016 (fig.32). As can be seenfrom this table, the total emissions across the entire supply chain in 1990 are rather 98kt than 148 kt. Compared to the value in 2016, a net reduction of more than 70% wasachieved, which is still a considerable success.

Table 3: Comparison of CH4 emissions for 1990 and 2016Segment 1990 - TNO 1990 - TNO and KIWA 2016

exploration: 0.5 kt 0.5 kt 0.615 ktproduction/processing: 85.5 kt (average) 85.5 kt average 11.97 kt

Transmission: 5.8 kt 5.8 kt 6.89 ktDistribution: 56 kt 5.95 kt 5.69 kt

Sum: 147.8 kt 97.75 kt 25.165 kt

6.3 Methane loss rate

It is evident that the production and processing operations yielded the highest reductionwhile in other segments a slight increase can be seen. These values are absolute, thus nottaking into account differences in the production volume or the transportation volumeof gas. It is therefore advised to rather evaluate the methane loss rate which indicatesthe amount of methane emissions in percentage of the extracted methane, which isproportional to the production volume. The amount of extracted methane is calculatedas:

extracted volume of CH4 = production volume * methane content * CH4 density

The methane content from different Dutch gas fields ranges from 70% to 95%. Forsimplification, the average of 82.5% will be used. The density of methane is 0.718kg/m3. The production volumes for 2013-2016 are taken from fig.23. The methaneloss rates resulting for the respective years are illustrated in fig.34. For comparisonthe value for 1990 is provided as well. This value is calculated using the total CH4

amounts according to table 3 and a production volume of 72,441 mil m3 according tothe TNO-study [Oonk and Vosbeek, 1995, table 1].

59

201620152014201319900.0

0.5

1.5

1.0

0.07

Me

tha

ne

le

aka

ge

ra

te in

%

0.07 0.09 0.09

0.34¹0.23²

Hayhoe et al.

Balcombe et al. (min)

1 - with distribu�on emissions from TNO-study

2 - with distribu�on emissions from KIWA-study

2.0

Figure 34: Comparison of methane loss rates

The methane loss rate is visibly stable throughout the last four years, althoughslightly increasing. Yet, compared to the value of 1990 the methane loss rate is aboutthree times lower. Reasons for this drop can be found in the mitigation measuresthat were implemented in the Netherlands since the 1990s and in an enhanced way ofestimating the emissions. In particular the augmented determination of country-specificemission factors and direct emission measurements of at least some operations acrossthe supply chain compared to the wide-spread use of default emission factors back inthe 1990s, possibly over-estimated, leads to a more accurate estimation of the CH4

emissions.

The methane loss rate for the Dutch gas system is much lower than values knownfrom literature. Balcombe et al. found in the literature the range of 0.2-10% with acentral cluster of 0.5-3% [Balcombe et al., 2015]. It is reminded here that Hayhoe et al.[Hayhoe et al., 2002] and Wigley [Wigley, 2011] considered that a switch from coal tonatural gas was considered not beneficial for a methane loss rate of 2.0% and higher.The indication for the natural gas industry in the Netherlands is far below this value.

One reason for the higher values in the literature might be due to the inclusion ofunconventional gas fields in the assessments. Furthermore, regulations in the Nether-lands are very strict, at least in part based on a high sense of responsibility that ishistorically manifested and additionally required in view of the dense population neargas fields. In addition, estimates from the literature might be over-estimated, those fromthe Netherlands under-estimates. Further research would be required on this topic toverify if any of these presumptions holds true.

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7 Conclusion and Outlook

To achieve the aim of this thesis, viz. determining the GHG emissions from operationsacross the natural gas supply chain, the two most important greenhouse gases CO2

and CH4 were gathered from the Dutch natural gas industry. The carbon footprint ofnatural gas along its lifetime (with exclusion of the end use) was calculated. In addition,the methane loss rate, indicating the amount of emitted methane to the total extractedmethane, across the supply chain was determined. This chapter will provide a summaryof my findings and an outlook on possible further research.

7.1 CO2-equivalent emissions of greenhouse gases

The carbon footprint of the Dutch natural gas system for the year 2016 was lower thanany indication found in the literature that was assessed by Balcombe et al. [Balcombeet al., 2015]. This extensive study analysed more than 240 papers published before 2015of which very few studies used data obtained from European natural gas producers. Themajority was based on data from the USA. The U.S. gas system is, however, known tohave relatively high GHG emissions across the supply chain. Some studies includeddata from Russia, indicating very high emissions from pipeline leaks. This is likelycaused by the extensive and mainly remote pipeline network where leak detection mighttake a period. This is in contrast to the compact pipeline system in the Netherlandswhere leaks are quickly discovered. The lack of European data might explain whyindications in the literature are generally higher.

It is, however, difficult to find the exact reason(s) that explain the different carbonfootprint values. It is not known from [Balcombe et al., 2015] which operations acrossthe supply chain lead to which respective values. Generally, the following issues mightplay a role: The Netherlands applies strict regulations to the natural gas productionindustry which is currently not the case in the USA. Lower-emitting technologies forproduction and processing as well as a low-leaking pipeline networks result from theseregulations. Not least the dense population requires high quality standards near Dutchgas fields. The abandonment of unconventional production sites, known to have higheremissions compared to conventional sites, positively contributes to low emissions.

Taking a closer look at each segment across the supply chain, it is noticeable thatthe segment "extraction, production, and processing" (EPP) accounts for more than 2/3of the entire CO2-equivalent emissions. This coincides with the findings in [Balcombeet al., 2015] despite having identified different key emission sources. Well completionand liquids unloading, identified as key sources by Balcombe et al. are no issue of theDutch industry due to the abandonment of unconventional gas production and the useof different well technology. In fact, key emission sources of the Dutch system are

61

on-site energy generation (CO2) and venting (CH4). During transmission operations,also fugitive emissions are of importance. The actual share of fugitive emissions fromproduction and processing operations is not derivable as these emissions are not reportedindividually but together with further emissions in the category "others".

In the segment "distribution", the Dutch distribution system operators report solelyon pipeline leaks as this was identified as the key source of methane by KIWA. Emissionsfrom other typical emissions at distribution (metering stations, regulators) are unknownand can therefore not be compared to the literature. Emissions from pipeline leaks arerelatively low in the Netherlands which is likely due to the very low share of gray ironpipelines. The latter accounting for only 3% of the entire distribution network [Ophoff,2017]. Moreover, large leaking incidents are very rare in the Netherlands, with noincidents in most years. Besides, leaks can be discovered quickly as pipelines are notremote but in densely populated areas. This contributes to the relatively low fugitiveemissions from the distribution network.

7.2 Methane only emissions

The absolute amount of methane emissions from the Dutch natural gas industry in 2016is more than 70% lower than in 1990. This trend is reflected by the methane loss rate,which dropped from 0.23% in 1990 to 0.09% in 2016. Considering the years 2013-2016,it is relatively stable, although slightly rising. This trend cannot be explained solelyfrom the data at hand.

In their assessment Balcombe et al. mentioned a methane loss rate of 0.2-10%. Thislarge range is explained in [Balcombe et al., 2015] by differences in the processes alongthe entire supply chain and, in addition, by different regulations. However, the exactoperations and emission sources contributing to the value of 0.2% are not derivable fromthis study. It is therefore impossible to name the exact differences with the operationsin the Dutch gas system that lead to an even lower methane loss rate of less than 0.1%.The use of enhanced technology, smaller leaks from pipeline transportation systems, animproved emissions reporting system and many other reasons could all contribute.

On the other hand it has to be mentioned that the methane estimates provided bythe Dutch gas operators might be under-estimated. I did not receive details on howemissions are estimated for the segment "EPP". It is therefore difficult to evaluatethe accuracy and completeness of these estimates. It might be that some emissionsources were not accounted for. At least from the distribution system operators it isknown that they neglect some methane emissions sources. It would be necessary toidentify these sources and the respective emissions. They are, however, not expectedto significantly levy the total methane emissions to result in a noticeable difference ofthe methane loss rate. The transmission system operator is conducting an excessive

62

emission monitoring on its own volition. This data is, however, also not verified by athird party. Other gas producing industries, particularly those for which much higheremissions are discussed in the literature, might react sceptically on the low resultsfrom the Netherlands. To create more confidence in the Dutch data, the followingwould be required: (i) a transparent accounting of the emissions and (ii) a control ofthe measurements and emission factors forming the basis for the calculation of theemissions by an independent institute.

7.3 Outlook

An aspect that emerged from the thesis is the need for future research in view of thechanges that the Dutch natural gas industry is facing currently. The production capfor the Groningen gas field will result in a significant rise of imports in the future,transforming the Netherlands from a net exporter to a net importer of natural gas.Emissions from the producing countries (production, processing, transport to the Dutchborder) should therefore not be neglected. In particular, LNG should be brought intothe focus as this share on the total imported gas will likely rise. Currently, a lack ofclear-cut research provides uncertainties about emissions from LNG production andtransportation. In the long term, changes of emission data due to depletion of gas fieldswould be of interest. Higher expenditure, associated with a higher energy demand forgas extraction and processing, will further contribute to rising emissions. Effectivemitigation measures across the entire supply chain should be defined precociously tocountervail the expected increase of GHG emissions.

A second aspect transpired from this thesis: The emission data reported from theDutch gas industry appears substantive at first glance. At the same time it lacks trans-parency and completeness. Of uttermost importance is, however, that the reportedemissions are not verified. An improved accounting process including at least a con-sistency check will improve the correctness of the data that is reported. In addition,to guarantee credibility of the emission estimates some control mechanism would berequired to verify the determination of the emission factors or the direct emissionmeasurements which are used by the operators. An independent third party shouldbe involved. When implementing such an auditing system also in other natural gasindustries, it will augment the confidence in the emission estimates from differentcountries and, not least, allow for a better comparison of differences, thereby identifyingthe reasons in operations that lead to the wide-ranging emissions estimates that can beseen in the literature.

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Erklärung

Hiermit erkläre ich, dass ich die vorliegende Arbeit selbständig verfasst und keineanderen als die angegebenen Hilfsmittel und Quellen verwendet habe.

Rijswijk, den 28.09.2017

Mit der Weitergabe meiner Master Thesis durch die Universität Koblenz-Landau anDritte (z.B. Bibliotheken, Behörden, Unternehmen, interessierte Privatpersonen)erkläre ich mich einverstanden.

Rijswijk, den 28.09.2017

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Documents

0DVWHURI6FLHQFH 0 6F - Warmopweg.nlwarmopweg.nl/wp-content/uploads/2017/11/Master-Thesis_DW_Final… · 2014; Mommers, 2016], political ambitions in the Netherlands to close all coal-ﬁred