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TECHNICAL REPORT – FINAL REPORT

GHG EMISSIONS RELATED TO THE LIFE CYCLE OF NATURAL GAS AND COAL IN DIFFERENT GEOGRAPHICAL CONTEXTS

JUNE 2016

June 2016GHG EMISSIONS RELATED TO THE LIFE CYCL

GEOGRAPHIC

This report was prepared by the International Reference Centre for the Life Cycle ofProducts, Processes and Services (CIRAIG).

Established in 2001, the CIRAIG was created to meet the demands of industry andgovernments to develop leading edge academic expertise in sustainable developmenttools. The CIRAIG is an internationally acclaimed centre of expertise in life cycle issues.The centre collaborates with many research centres worldwide and actively participatesin the United Nations Environment Programme (UNEP) and the Society of EnvironmentalToxicology and Chemistry (SETAC)’s Life Cycle Initiative.

The CIRAIG has developed a recognised expertise in life cycle tools including Life CycleAssessment (LCA) and Social Life Cycle Assessment (SLCA). Completing this expertise, itsresearch projects also cover Life Cycle Costing (LCC) and other tools such as carbon andwater footprinting. CIRAIG’s activities include applied research projects that span severalactivity sectors including energy, aerospace, agri-food, waste management, forestry andpulp and paper, mining and metals, chemical products, telecommunications, financialservices, urban infrastructure management, transport as well as green product design.

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CIRAIGInternational Reference Centre for the Life Cycleof Products, Processes and ServicesPolytechnique MontréalChemical Engineering Department2900, Édouard-MontpetitMontréal (Québec) CanadaP.O. 6079, Station Centre-villeH3C 3A7

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E OF NATURAL GAS AND COAL IN DIFFERENT

AL CONTEXTSPage 1

Montréal (Québec) H3C 3A7

http://www.ciraig.org/

GHG EMISSIONS RELATED TO THE LIFE CYCLE OF NATURAL GAS AND COAL IN DIFFERENT

GEOGRAPHICAL CONTEXTSJune 2016

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June 2016GHG EMISSIONS RELATED TO THE LIFE CYCLE OF NATURAL GAS AND COAL IN DIFFERENT

GEOGRAPHICAL CONTEXTSPage 3

Working group

Environmental component (CIRAIG-Poly)

Pierre-Olivier Roy, Ph.D.

Author and LCA modeling

Pablo Tirado, M. Sc. A,

LCA modeling

Project management

Valérie Patreau, CIRAIG

Director of operations

Réjean Samson, Director General, CIRAIG-Poly

Chairholder, ILC ChairProject manager for the environmental component



Summary

Numerous studies have shown that natural gas, even from unconventional sources, should bepreferable to coal with regards to the amount of greenhouse gases (GHG) it emits when used to produceelectricity. However, it has also been shown that, in certain particular situations, the coal may emit lessGHGs than natural gas. Considering that results from past studies are dependent on their underlyingassumptions and are only representative of the specific geographical context to which they apply, TOTALwishes to ascertain the life cycle GHG emissions from some of their activities (or those of their partners)from the extraction to electricity production. Therefore, TOTAL has mandated the CIRAIG to:

“Establish and compare the life cycle GHG emissions of natural gas and coal from different sources(conventional and unconventional) and geographical contexts in order to produce electricity in Europe

and Asia.”

It should be noted that this comparison will be based on some of TOTAL’s (or their partners’) natural gasproductions and generic coal data.

In order to answer this question, the CIRAIG has proposed a three-tier approach to evaluating the GHGemissions of the different investigated natural gas and coal systems:

• Application of literature values to the investigated systems;

• TOTAL reporting and other in-house data;

• Life cycle modeling based, mostly, on the ecoinvent1 database.

Each of these approaches provides a level of information which can be used to answer the overarchingquestion, provide an identification of where the GHG emissions occur (i.e. hot spots) and provide TOTALwith recommendations regarding future data collection.

The GHG emissions assessment showed that:

From the literature values:

• The combustion of natural gas and coal, related to electricity production, is the life cycle stepwhich emits most of the GHG emissions;

• Reported GHG emissions in the literature showed that natural gas, on average, has fewer GHGemissions than coal systems

o It also shows that some natural gas systems (i.e. Yemen onshore) may emit more GHGthan coal for worst cases/best cases scenarios for natural gas and coal systems,respectively.

From TOTAL’s internal GHG reporting:

• The reporting generated the most representative GHG assessment of TOTAL’s activities andreporting but only included the Scope 1-2 emissions; not the scope 3 emissions;

• Reporting data did not include the coal systems GHG emissions;

1Ecoinvent is a life cycle inventory database (which provides a set of inputs, outputs and emissions for different

processes) and is considered as one of the most complete database available. Ecoinvent is amongst the bestavailable LCA databases from a quantitative (number of included processes) and qualitative (quality of thevalidation processes, data completeness, etc.) perspective and is internationally recognized by experts in the field.



• Amongst the reported processes, liquefaction emitted the highest amount of GHG followed byeither transoceanic transport or natural gas extraction.

From the life cycle modeling:

• The GHG emissions from our life cycle model were globally in line with literature values andTOTAL’s internal GHG reporting;

• All investigated natural gas systems had fewer GHG emissions comparatively to coal systems;

• The combustion of natural gas and coal related to electricity production, emits more GHG thanany other life cycle step;

• The liquefaction process is the second most important contributor to GHG emissions for thenatural gas systems which considered an exportation to another continent;

• Natural gas extraction and processing are also important contributors to the GHG assessment;

• Apart from the combustion, coal systems have no other important contributors apart from themethane emissions (sent directly to the atmosphere) related to coal extraction.

Sensitivity analysis:

Sensitivity analyses are used to test the consequences of modifying some influential parameters,processes or system boundaries as a way to test the robustness of our analysis. In total, we tested sevendifferent scenarios/parameters: different shale gas fugitive emissions, the fugitive emission equivalency,the influence of the (low) heating value, the combustion efficiency, the methane capture during coalmining operations, a change in allocation rules and a change in GHG’s global warming potentialsstemming from different IPCC reports and time horizons (i.e. 20 and 100 years).

• Even though the variations may decrease the advantage of natural gas systems, they still emitless GHG emissions, on average, than hard coal systems.

Uncertainty analysis:

Uncertainty analyses are used to assess the importance of the systems variability on the conclusions.Uncertainty analysis was carried out with a Monte Carlo simulation which accounts for the systems datavariability using a probabilistic approach:

• With a 90% confidence interval, all natural gas systems emitted less GHG than coal systems;

• With a 95% confidence interval, US shale gas may emit more GHGs than Colombian hard coalsystems;

Considering the level of uncertainty in our life cycle modeling and the relatively close proximity of theGHG emissions between some natural gas and hard coal systems, we cannot completely rule out apossible overlap in terms of generated GHG emissions. However, it should be noted that such overlapwould only occur with a worst case scenario (i.e. shale gas fugitive emissions in the order of 7% of itsEUR) of a natural gas system and a best case scenario of a coal system (i.e. highest coal-fired plantefficiency). On average, however, natural gas systems (even the unconventional ones) emit less GHGemissions than coal systems.

The results of this study can be used to Identify strengths and weaknesses of the investigated naturalgas or coal system and identify conditions for which alternative seems preferable to the other. Theresults can also be used to identify potential improvement to enhance future studies.

The main limitations of this study include the fact that the GHG emissions were the sole focus of thisstudy; no other impacts were investigated. Furthermore, the study is limited to the investigated naturalgas and coal systems and therefore our findings should not be extrapolated to systems in othergeographical contexts. Finally, there are some issues regarding the completeness and validity of some of



the inventory data pertaining the coalbed methane extraction and the lack of primary data for the coalsystems.



Table of contents

WORKING GROUP ................................................................................................................................................. 3

SUMMARY ............................................................................................................................................................ 4

TABLE OF CONTENTS ............................................................................................................................................. 7

LIST OF TABLES...................................................................................................................................................... 9

LIST OF FIGURES ...................................................................................................................................................11

ABBREVIATIONS AND ACRONYMS .......................................................................................................................13

1 INTRODUCTION............................................................................................................................................14

2 LITERATURE REVIEW ....................................................................................................................................15

2.1 NATURAL GAS ................................................................................................................................................ 15

2.1.1 Natural gas extraction........................................................................................................................... 15

2.1.2 Conventional and unconventional natural gas processing.................................................................... 16

2.1.3 Natural gas transmission ...................................................................................................................... 16

2.1.4 Natural gas exportation: liquefaction, LNG tankers, and regasification............................................... 16

2.2 COAL............................................................................................................................................................ 17

2.3 GLOBAL WARMING AND GLOBAL WARMING POTENTIAL (GWP)............................................................................... 18

2.4 LIFE CYCLE ASSESSMENT (LCA) .......................................................................................................................... 19

2.5 LIFE CYCLE GHG EMISSIONS ESTIMATES .............................................................................................................. 20

2.5.1 Upstream natural gas GHG emissions................................................................................................... 20

UPSTREAM GHG EMISSIONS ................................................................................................................................25

2.5.2 Natural gas exportation: liquefaction, LNG transport, and regasification............................................ 27

2.5.3 Natural gas combustion ........................................................................................................................ 27

2.6 COAL LIFE CYCLE GHG EMISSIONS ESTIMATES....................................................................................................... 29

3 GOAL AND SCOPE OF THE STUDY .................................................................................................................32

3.1 OBJECTIVE AND INTENDED APPLICATION .............................................................................................................. 32

3.2 SYSTEM FUNCTION AND FUNCTIONAL UNIT........................................................................................................... 33

3.2.1 Coal systems.......................................................................................................................................... 35

3.3 NATURAL GAS AND COAL SYSTEMS LIFE CYCLE BOUNDARIES ..................................................................................... 41

3.4 NATURAL GAS SYSTEMS COMPOSITION ................................................................................................................ 43

3.5 GHG EMISSIONS ASSESSMENT – GENERAL FRAMEWORK ........................................................................................ 43

3.6 LIFE CYCLE MODELING...................................................................................................................................... 45

3.6.1 Multifunctional processes and allocation rules..................................................................................... 45

3.6.2 Life cycle boundaries, inventory data, sources, and assumptions......................................................... 45

3.6.3 System 1: US Shale gas to European power plant ................................................................................. 46



3.6.4 System 2: Offshore North Sea natural gas to European power plant ................................................... 50

3.6.5 System 3: Australian coalbed methane to Asian power plant............................................................... 51

3.6.6 System 4: Indonesian offshore natural gas to Asian power plant ......................................................... 54

3.6.7 System 5: Yemen onshore natural gas to Asian power plant ................................................................ 56

3.6.8 Systems 6 to 14: Coal from Eastern Europe, Russia, China, Australia, Indonesia, Colombia, UnitedStates or South Africa used in either a European or Asian power plant............................................................. 60

3.6.9 Temporal and geographical boundaries ............................................................................................... 63

3.6.10 GHG emission accounting ................................................................................................................. 63

3.6.11 Interpretation.................................................................................................................................... 64

3.7 CRITICAL REVIEW............................................................................................................................................ 67

4 RESULTS AND DISCUSSION...........................................................................................................................68

4.1 COMPARISON BASED ON VALUES FROM THE LITERATURE......................................................................................... 68

4.2 COMPARISON BASED ON TOTAL REPORTED DATA................................................................................................. 70

4.3 LIFE CYCLE GHG EMISSIONS MODELING .............................................................................................................. 73

4.3.1 Evaluation based on IPCC 2007’s GWP100.............................................................................................. 73

4.3.2 Inventory contribution to the natural gas and coal systems................................................................. 74

4.3.3 Sensitivity analysis................................................................................................................................. 77

4.3.4 Complementary assessments ................................................................................................................ 89

4.3.5 Life cycle inventory uncertainty: Monte Carlo simulation results.......................................................... 91

4.4 LIFE CYCLE DATA QUALITY ................................................................................................................................. 92

4.5 LIMITATIONS.................................................................................................................................................. 96

4.6 SUMMARY..................................................................................................................................................... 97

4.7 RECOMMENDATIONS..................................................................................................................................... 102

5 CONCLUSION .............................................................................................................................................104

6 REFERENCES...............................................................................................................................................105



List of tables

Table 2-1 : Global warming potential (GWP) provided by the IPCC through the years for different time horizons... 19

Table 2-2 : Onsite and offsite fugitive emissions ........................................................................................................ 24

Table 2-3 : Upstream fugitive emissions from several studies (2010-2013) ............................................................... 25

Table 2-4 : Jamarillo et al. (2007) GHG estimates for the liquefaction, LNG transport, and regasification in the US 27

Table 2-5 : Natural gas-fired power plant efficiencies ................................................................................................ 27

Table 2-6 : GHG emissions from hard coal and lignite ................................................................................................ 30

Table 2-7 : Coal-fired power plant efficiencies ........................................................................................................... 31

Table 3-1 : Targeted market and travel distances for investigated natural gas systems............................................ 35

Table 3-2 : Targeted markets and travel distances for investigated coal systems...................................................... 38

Table 3-3 : Coal production and imports in major European and Asian countries ..................................................... 38

Table 3-4 : Natural gas composition (% mol) at the well and the transmission network. .......................................... 43

Table 3-5 : Included/excluded processes and assumptions related to the US shale gas exploitation system ........... 46

Table 3-6 : Included/excluded processes and assumptions related to the offshore North Sea exploitation system. 50

Table 3-7 : Included/excluded processes and assumptions related to the Australian coalbed methane system ...... 52

Table 3-8 : Included/excluded processes and assumptions related to the Indonesian offshore natural gas system. 55

Table 3-9 : Included/excluded processes and assumptions related to Yemen onshore natural gas system.............. 57

Table 3-10 : Included processes and assumptions related to coal systems................................................................ 60

Table 3-11 : Coal mining methane emissions.............................................................................................................. 62

Table 3-12 : Temporal data quality criteria................................................................................................................. 63

Table 3-13 : Reliability and representativeness data quality criteria.......................................................................... 65

Table 3-14: Members of the Critical Review Committee ............................................................................................ 67

Table 4-1 : Natural gas systems GHG emissions (based on IPCC’s 2007 GWP100) summary. All values are provided ing CO2 eq./kWh electricity..................................................................................................................... 71

Table 4-2 : Shale gas fugitive emissions scenarios ...................................................................................................... 78

Table 4-3 : Increased natural gas losses to the atmosphere to find equivalency with the lowest coal system GHGemissions .............................................................................................................................................. 82



Table 4-4 : Natural gas liquids properties. .................................................................................................................. 83

Table 4-5 : Natural gas liquids according to allocation rules. ..................................................................................... 83

Table 4-6 : Detailed data quality assessment.............................................................................................................. 94

Table 4-7 : Natural gas systems GHG emissions (based on IPCC’s 2007 GWP100) summary. ...................................... 98

Table 4-8 : Coal systems GHG emissions (based on IPCC’s 2007 GWP100) summary. ............................................... 100



List of figures

Figure 2-1: Types of coal (World Coal Association, 2009)........................................................................................... 17

Figure 2-2: NETL’s (2014) natural gas GHG emissions estimates in the US. ............................................................... 21

Figure 2-3: Weber et Clavin (2012) harmonized upstream GHG emissions estimates for onshore natural gas in theUS.......................................................................................................................................................... 22

Figure 2-4: Weber et Clavin (2012) harmonised upstream GHG emissions estimates for shale gas .......................... 23

Figure 2-5 : Natural gas fugitive emissions from numerous studies as reported by Brandt et al. (2014)................... 26

Figure 2-6: Whitaker et al. (2012) harmonized GHG emissions estimates for coal-generated electricity around theworld..................................................................................................................................................... 30

Figure 3-1: Natural gas system overview .................................................................................................................... 34

Figure 3-2: Coal system overview ............................................................................................................................... 36

Figure 3-3: Steam coal imports market share in Europe (IHS MCR, 2014).................................................................. 39

Figure 3-4: Coal imports market share in China (up), Japan (middle) and South Korea (down) (IHS MCR, 2014)...... 40

Figure 3-5: Natural gas system boundaries................................................................................................................. 41

Figure 3-6: Hard coal system boundaries.................................................................................................................... 42

Figure 4-1: Literature review values applied to the investigated systems.................................................................. 69

Figure 4-2: Relative contribution of reported GHG emissions .................................................................................... 72

Figure 4-3: Life cycle GHG emissions of the investigated systems based on data from ecoinvent and some data (i.e.power plant efficiency, gas composition, EUR and transmission fugitive emissions) from TOTAL (IPCC2007, GWP100)....................................................................................................................................... 74

Figure 4-4: Contribution of the specific GHG to the overall natural gas and coal GHG assessment (IPCC 2007,GWP100)................................................................................................................................................. 75

Figure 4-5: Contribution of the specific GHG to the upstream (all processes except at the power plant) natural gasand coal GHG assessment (IPCC 2007, GWP100) ................................................................................... 76

Figure 4-6: Shale gas fugitive emissions variations (IPCC 2007’s GWP100) .................................................................. 79

Figure 4-7: Importance of the shale gas fugitive emissions (IPCC 2007’s GWP100) ..................................................... 80

Figure 4-8: Influence of shale gas fugitive emission rate (IPCC 2007’s GWP100) ......................................................... 81

Figure 4-9: Natural gas processing allocation rules consequences on the overall GHG emission estimations .......... 84

Figure 4-10: Importance of low heating values for natural gas (IPCC 2007’s GWP100) ............................................... 85



Figure 4-11: Consequences of varying the electricity production efficiency at the power plant on the GHGemissions estimates (IPCC 2007’s GWP100)........................................................................................... 86

Figure 4-12: Consequences of methane capture during coal extraction (IPCC 2007’s GWP100) ................................. 87

Figure 4-13: Consequences of varying the GWP’s time horizon and reported values on the GHG emissionsestimates. ............................................................................................................................................. 88

Figure 4-14: Comparison of natural gas systems with conventional natural gas from Russia (IPCC 2007’s GWP100). 89

Figure 4-15: GHG emissions from lignite production in Europe comparatively to the other coal systems (IPCC 2007’sGWP100)................................................................................................................................................. 90

Figure 4-16: Monte Carlo analysis results using the IPCC’s 2007 GWP100: 95 % confidence interval ......................... 91



Abbreviations and acronyms

CH4 Methane

CO2 Carbon Dioxide

GHG Greenhouse gas(es)

GWP20 Global Warming Potential at a 20 years time horizon

GWP100 Global Warming Potential at a 100 years time horizon

IPCC Intergovernmental Panel on Climate Change

ISO International Standard Organization

LCA Life Cycle Assessment

LCI Life Cycle Inventory

LCIA Life Cycle Impact Assessment

LHV Low heating value

LNG Liquefied natural gas

MARCOGAZ Technical Association of the European Natural Gas Industry

NGL Natural gas liquids

N2O Nitrous oxide



1 Introduction

Numerous studies (Burnham et al. 2012, Jiang et al. 2011, Skone et al., 2011, Cathles, 2012) havecompared the greenhouse gas (GHG) emissions from natural gas and coal systems. For the time beingmost of these studies show that natural gas, even from unconventional sources, is preferable to hardcoal when producing electricity. However, it was also shown that in certain situations, natural gas GHGemissions could be on par with coal (e.g. depending on fugitive methane emissions). Considering thatGHG estimates from past studies rely on a range of assumptions and geographical context, TOTALwishes to ascertain the life cycle GHG emissions from some of their activities (or those of their partners)from the extraction to electricity production.

Therefore, TOTAL has mandated the CIRAIG to:

“Establish and compare the life cycle GHG emissions of natural gas and coal from different sources(conventional and unconventional) and geographical contexts in order to produce electricity in Europe

and Asia.”


In order to answer this question, the CIRAIG has proposed a three-tier approach to evaluating the GHGemissions of the investigated natural gas and coal systems:


• Comparison of TOTAL reporting and other in-house data;

• Life cycle modeling based, mostly, on the ecoinvent2 database.

Each of these approaches provide a level of information which can be used to answer the overarchingquestion, evaluate situations in which natural gas systems could potentially emit more GHG emissionsthan coal systems, provide an identification of where the emissions occur and perhaps, moreimportantly, provide TOTAL with recommendations regarding future data collection to improve uponthis study’s findings.

2Ecoinvent is a life cycle inventory database (which provides a set of inputs, outputs and emissions for different

processes) and is considered as one of the most complete database available. Ecoinvent is amongst the bestavailable LCA databases from a quantitative (number of included processes) and qualitative (quality of thevalidation processes, data completeness, etc.) perspective and is internationally recognized by experts in the field.



2 Literature review

This section highlights the concepts and assumptions that are necessary for a better understanding ofthis study.

2.1 Natural gas

2.1.1 Natural gas extraction

Onshore conventional natural gas

To extract natural gas from a conventional well, machinery must be used to drill into the natural gasreservoir. The natural gas reservoir is a naturally occurring pocket within a rock formation in whichbiological processes have occurred over the ages to create natural gas and/or oil. During the drillingprocess pipes are laid down the shaft and are then enclosed in cement to prevent soil and watercontamination in the event of a pipe rupture. Once the pocket has been breached, natural gas can travelto the surface. At the beginning, the natural gas travels back to the surface by a simple pressuredifference. In time, additional techniques could be required to further extract the natural gas.

Offshore conventional natural gas

Offshore natural gas exploitations increase the exploitation technical difficulties by dealing with a morechallenging environment. Indeed, just as with the onshore conventional natural gas, natural gas hasbeen trapped inside a pocket within a rock formation. The difference in this instance is that the pocketlies underneath a sea or ocean bed.

The most current offshore exploitation method is to build a fixed platform which is equipped with thetools to drill through the soil underneath the sea/ocean and extract the natural gas. Otherwise, theextraction method is quite similar than with onshore natural gas: a shaft is drilled in decreasingdiameters and pipes are laid down into the shaft. At the beginning, the natural gas travels back to thesurface by a simple difference in pressure. In time, additional techniques could be required to extractthe natural gas.

Some practices have integrated the natural gas processing facilities directly on the platform before it issent back to the mainland by pipeline.

Unconventional natural gas: shale gas

Shale gas is natural gas that has been trapped, not within a pocket, but rather within the pores of ashale rock formation. In recent years, techniques have been developed to access this natural gas.Fracking consists of drilling a vertical well, and then, starting from the kick-off point, a horizontal well.Pipes are laid down into the shaft and are then enclosed in cement to prevent soil and watercontamination in the event of a pipe rupture. Explosives are then inserted at the end of the pipe.Detonation of these explosives destroys part of the pipe and part of the surrounding shale rockformation. Highly pressurised fracking liquids, consisting of water, sand and some chemical agents, arethen sent down the well further widening the gaps into the shale rock formation which then allows forthe circulation of the shale gas back to the surface. The sand and chemical agents are used to keep thegaps intact for a longer period. At the beginning, the shale gas travels back to the surface by a simpledifference in pressure. In time, additional techniques could be required to extract the shale gas.



Unconventional natural gas: coalbed methane

Coalbed methane (CBM) is formed within a water-saturated coal seam and held there by adsorption tothe coal surface within the seam and pressure from the water (Kember, 2012). This gas can berecovered through the use of shallow horizontal drilling. The development of a well for coal bedmethane requires horizontal drilling followed by a depressurization period during which naturallyoccurring water is discharged from the coal seam.

2.1.2 Conventional and unconventional natural gas processing

Extracted natural gas consists of methane, propane, ethane, butane, pentane, hexane, carbon dioxide,nitrogen, hydrogen sulfide and water; some of which must be removed in order to produce standardisednatural gas (EIA, 2006).

To do so, natural gas processing plants are usually built in gas producing regions. A plant may processseveral wells within a specific region (EIA, 2006). The natural gas is transported from the extraction sitesto these plants through a system of low-diameter, low-pressure pipelines.

At the plant, water vapor is first removed from the gas by using absorption or adsorption methods.Glycol dehydration is an example of absorption, in which glycol, which has a chemical affinity for water,is used to absorb the vapor.

Natural gas is then processed to remove sulfur and carbon dioxide. Often, natural gas from the wellscontains high amounts of these two compounds. Removing sulfur and carbon dioxide from the gas issimilar to the absorption processes previously described.

Natural gas is then processed to remove other hydrocarbons (i.e. ethane, propane, butane, pentane,hexane). The removal of these hydrocarbons, called Natural Gas Liquids (NGL), is typically done with theabsorption method or the cryogenic expander process. The absorption method is similar to the waterabsorption method, but instead of glycol, absorbing oil is used. The cryogenic expansion methodconsists of dropping the temperatures of the gas causing the hydrocarbons to condense so that they canbe separated from the natural gas. The absorption method is typically used to remove heavierhydrocarbons while lighter hydrocarbons are removed using the cryogenic expansion process.

2.1.3 Natural gas transmission

The natural gas transmission consists of high-pressure pipelines that transport the gas from producingareas to high demand areas. The pipeline system uses compressor stations along the way, to compressthe natural gas and maintain the pipeline high-pressure requirements. The compressors are generallyrun with a small amount of the pipeline gas.

2.1.4 Natural gas exportation: liquefaction, LNG tankers, and regasification

In order to economically move gas across oceans, reducing volume through liquefaction is the leadingoption. Liquefaction allows reducing the natural gas volume by a factor of 610 by cooling andpressurizing the natural gas converting it to liquid form.

The liquefied natural gas (LNG) tankers can then transport the LNG everywhere worldwide (or at leastwhere there are regasification facilities).

Regasification facilities are LNG marine terminals where LNG tankers unload the natural gas. Theyconsist of storage tanks and vaporization equipment that warm the LNG to its former (gaseous) state.



2.2 Coal

Coal formation began during the Carboniferous Period which spanned 360 million to 290 million yearsago. The build-up of silt and other sediments, together with movements in the earth's crust buriedswamps and peat bogs. With the burial, the plant material was subjected to high temperatures andpressures which caused physical and chemical changes to the peat and bogs transforming them intocoal.

There are four types of coal: peat, lignite, bituminous (typically referred to as hard coal) and anthracite.Initially, the peat is converted into lignite or 'brown coal' which are characterised by low organicmaturity and, therefore, low carbon/energy content (World Coal Association, 2009). Over many moremillions of years, the continuing effects of temperature and pressure produce further changes,progressively increasing the lignite’s organic maturity and transforming it into the range of 'sub-bituminous' coals (World Coal Association, 2009). Further chemical and physical changes occur untilthese coals became harder and blacker, forming the 'bituminous' or 'hard coals' (World Coal Association,2009).

Figure 2-1: Types of coal (World Coal Association, 2009)

There are two different types of mine for coal extraction: surface mining and underground mining.Surface mining methods were found to be more productive, but also more environmentally damagingdue to surface disturbances (Union of concerned scientists, 2016). In recent years, surface mining hasovertaken underground mining as the predominant way of extracting coal (Union of concernedscientists, 2016).

Underground mining typically uses either a « room and pillar » or a « longwall mining » method (Unionof concerned scientists, 2016). In « room and pillar » mining, coal seams are mined partially, leavinglarge pillars of coal intact to support the overlying layers of rock thus creating a network of alternatingopen spaces and large pillars of coal (Union of concerned scientists, 2016). « Longwall mining » involves



cutting long tunnels into a coal seam and removing the extracted coal by conveyor belt (Union ofconcerned scientists, 2016).

Surface mining is employed when the coal seam is located much closer to the surface (Union ofconcerned scientists, 2016). Extracting the coal first requires clearing the vegetation and soil from theimmediate surface (Union of concerned scientists, 2016). Then the large intermediate layer of sedimentand rock must be blasted and removed (Union of concerned scientists, 2016). With the underlying coalseam finally exposed, it is removed in strips and moved by conveyor belt or truck to its final destination(Union of concerned scientists, 2016).

2.3 Global warming and global warming potential (GWP)

Global warming is the name given to the phenomenon in which an increase in the global average surfacetemperature has been observed. This phenomenon may be explained by the GHG emissions. Thesegases prevent the sun’s infrared radiations reflected by the earth from reaching outer space thus“trapping” heat in the troposphere and increasing the average surface temperature which, in turn,increases the melting of glaciers, the oceans’ level, the oceans’ temperature and changes in climaticconditions in certain areas (e.g. desertification, an increase in precipitation) (Levasseur, 2011). Theseperturbations create a number of potential impacts on human populations and ecosystems such asfloods, storms, hurricanes, ice caps melting, an increase in heat waves, infectious diseases (coming frominsects’ multiplication), population displacement, death and/or biodiversity losses etc. (Levasseur,2011).

The global warming potential (GWP) is a metric which allows a comparative assessment between aspecific GHG’s cumulative radiative forcing3, integrated over a certain time horizon (typically 100 years)and the cumulative radiative forcing of CO2 for the same time horizon (Levasseur, 2011).

GHG emissions are generally reported through the Greenhouse Gas Protocol (GHGP), which provides “acomprehensive, global, standardised framework for measuring and managing emissions from privateand public sector operations, value chains, products, cities, and policies” (http://www.wri.org/our-work/project/greenhouse-gas-protocol). The GHGP differentiates between direct and indirect emissionsaccording to three different scopes (GHG Protocol, 2016):

• Scope 1: All direct GHG emissions.• Scope 2: Indirect GHG emissions from consumption of purchased electricity, heat or steam.• Scope 3: Other indirect emissions, such as the extraction and production of purchased materials

and fuels, transport-related activities in vehicles not owned or controlled by the reportingentity, electricity-related activities (e.g. T&D losses) not covered in Scope 2, outsourcedactivities, waste disposal, etc.

Where:

• Direct GHG emissions are emissions from sources that are owned or controlled by the reportingentity.

3Defined by the IPCC (AR-4 report) as: ‘the change in net (down minus up) irradiance (solar plus longwave; in W m

-2)

at the tropopause after allowing for stratospheric temperatures to readjust to radiative equilibrium, but with surfaceand tropospheric temperatures and state held fixed at the unperturbed values”

Ju

• Indirect GHG emissions are emissions that are a consequence of the activities of the reportingentity but occur at sources owned or controlled by another entity.

Thup

* In

Wsoqu

Indlifeimmeto

Thpe

2.

Lifa pideits

An

1.2.

3.

4In

e IPCC (e.g. Myhre et al. 2013)) provides GWPs for more than 60 gases and have been periodicallydated through the years. Table 2-1 presents the GWP100 evolution for some GHG.

ne 2016GHG EMISSIONS RELATED TO THE LIFE CYCLE OF NATURAL GAS AND COAL IN DIFFERENT


Table 2-1 : Global warming potential (GWP) provided by the IPCC through the years fordifferent time horizons

Substances

100 years time horizon(kg CO2 éq. /kg )

20 years time horizon(kg CO2 éq. /kg )

AR3

IPCC 2001

AR 4

IPCC 2007

AR 5

IPCC 2013

AR3

IPCC 2001

AR 4

IPCC 2007

AR 5

IPCC 2013

CO2 1 1 1 1 1 1

CH4 2125

4

(27.5)*34 62 72 86

corporates the oxidation of methane into carbon dioxide.

hile the GHGP states that only the GWPs related to a horizon of 100 years (GWP100) should be used,me authors (Howarth et coll, 2011, Howarth et coll, 2012, O’Sullivan et coll, 2012) have come toestion this time horizon in GHG accounting.

eed, methane has a shorter lifespan in the atmosphere (decades) than the persistent CO2, with aspan of more than 500 years. Hence, by selecting a longer time horizon (e.g. 100 or 500 years), the

portance of methane radiative forcing decreases comparatively to CO2, thus artificially decreasingthane’s GWP. Therefore, these authors support a reduction of the time horizon to 20 years as a wayavoid an underestimation of methane importance regarding global warming.

e European Union (2013) recommends using the factors from the IPCC AR4 for assessing life cyclerformance on a 100 years time horizon.

4 Life cycle assessment (LCA)

e cycle assessment (LCA) is a tool which allows an evaluation of the environmental impacts related toroduct or system during its entire life cycle; from raw material extraction to end of life. LCA aims tontify and quantify the inputs and outputs such as material and energy related to the product duringlife cycle and to evaluate their related potential impacts.

LCA is constituted of four steps:

The goal and scope, which set the objectives and the boundaries of the study;The life cycle inventory, which aims to quantify (e.g. in kg) the product life cycle inputs andoutputs;The evaluation of the potential impacts related to the inputs and outputs (in this study: GHGemissions);

this study, the GWP100 of 25 for CH4 from the AR4 (IPCC 2007) will be used, unless otherwise specified



4. The interpretation of the life cycle inventory data and potential impacts in relation to the goal andscope.

Several studies have been published in recent years regarding the life cycle GHG emissions of natural gasand coal processes. The following sub-section summarises the results from some of these studies.

2.5 Life cycle GHG emissions estimates

2.5.1 Upstream natural gas GHG emissions

The National Energy Technology Laboratory (NETL, 2014) provided a GHG assessment of natural gassources (i.e. production and imports) in the United States (US). According to these estimates, all naturalgas sources (both conventional and unconventional) show similar GHG emissions. It should be notedthat these estimates only include the upstream natural gas processes, which comprise:

• Exploration/exploitation5;

• Processing;

• Transmission/distribution.

The imported liquefied natural gas (LNG) also includes (all accounted for in the raw material processing):

• Liquefaction;

• LNG transoceanic transport;

• Regasification.

5Extraction of either coal or natural gas includes both the exploration and exploitation phases.

Note : A life cycle assessment approach applied to a carbon footprinting procedure will provide, bydefault, an assessment classified as Scope 1-2-3 under the Greenhouse Gas Protocol.



Figure 2-2: NETL’s (2014) natural gas GHG emissions estimates in the US.

Further assessments are provided in the next subsection for onshore conventional gas and shale gas.

Onshore conventional natural gas GHG estimates

Figure 2-3 presents different GHG estimates, stemming from different sources/studies related to USonshore conventional natural gas exploitation. This figure was taken from Weber and Clavin (2012), towhich we added the estimate from the ecoinvent life cycle database. Weber and Clavin (2012) observedseveral discrepancies in the GHG estimates between existing studies. They could not conclude if thesewere stemming from intrinsic variations or simply from different study assumptions. Therefore, theytried to harmonise the assumptions between the existing studies and reported their best estimate (i.e.the Weber et Clavin column in Figure 2-3).

According to the overall results, the United States onshore natural gas upstream processes account for 7to 22 g CO2 eq/MJ of natural gas. While this evaluation provides a larger GHG emission interval than theprevious NETL (2014) study, they provide similar GHG emissions estimations.

GHG EMISSIONS RELATED TO

Figure 2-3: Weber et Clavin (2012)

Shale gas GHG estimates

Weber et Calvin (2012) have also harmonised thegas exploitation. According to these results upstream shale gas processes in the US account for 8 to27 g CO2 eq/MJ of natural gas. While this evaluation provides a larger GHG emission interval than thprevious NETL (2014) study, they provide similar GHG emissions estimations.

6Howarth et al. (2011) study has been presented for histor

worst case scenario. Indeed, while the study is transparent in wishing to portray a worst case scenario, severalrebuttals were also published regarding the study underlying assumptions and data use.

EMISSIONS RELATED TO THE LIFE CYCLE OF NATURAL GAS AND COAL IN DIFFERENT

GEOGRAPHICAL CONTEXTS

Weber et Clavin (2012) harmonized upstream GHG emissions estimates foronshore natural gas in the US6

harmonised the GHG results from different studies related to US shaleAccording to these results upstream shale gas processes in the US account for 8 to

eq/MJ of natural gas. While this evaluation provides a larger GHG emission interval than ththey provide similar GHG emissions estimations.

Howarth et al. (2011) study has been presented for historical reasons and should be considered, at best, as aworst case scenario. Indeed, while the study is transparent in wishing to portray a worst case scenario, severalrebuttals were also published regarding the study underlying assumptions and data use.

June 2016

upstream GHG emissions estimates for

different studies related to US shaleAccording to these results upstream shale gas processes in the US account for 8 to

eq/MJ of natural gas. While this evaluation provides a larger GHG emission interval than the

ical reasons and should be considered, at best, as aworst case scenario. Indeed, while the study is transparent in wishing to portray a worst case scenario, several

June 2016GHG EMISSIONS RELATED TO

Figure 2-4: Weber et Clavin (2012) harmonis

Fugitive emissions are considered paramount in the debate regarding theevaluation. Fugitive emissions were defined by the US

“intentional and unintentional emissions of methane/natural gas of the extraction, processing antransmission and distribution systems

The intentional emissions include the “normal” emissions related to the operation of an equipment orsystem (e.g. venting). Unintentional emissionpiece of equipment. The intentional emissions are typically larger than the unintentional ones(US EPA, 2010a).

Controversy surrounds the estimation of shale gas fugitive emissions.from a lack of consistency between theor estimations (as intentional or accidental emissions are not measured)made apparent when comparing studies based on

The bottom-up approach is based on direct measurements of emissions at given sites.measurements are essential to identifying specifvalues from identified sources of emissions.emissions, over several sites and wells. One such study is Allen et al. (2013) whose values are reported inTable 2-2. These values were completed with the US EPA offsite fugitive emissions estimates for thenatural gas processing and the transmission and distribution steps.

7Howarth et al. (2011) study has been presented for historical reasons and should be considered, at best, as a

worst case scenario. Indeed, while the study is transparent in wishing to portray a worst case scenario, severalrebuttals were also published regarding the study underlying assumptions and data use



Weber et Clavin (2012) harmonised upstream GHG emissions estimates forshale gas7

d paramount in the debate regarding the shaleFugitive emissions were defined by the US Environmental Protection Agency (

“intentional and unintentional emissions of methane/natural gas of the extraction, processing antransmission and distribution systems” (US EPA, 2010a).

the “normal” emissions related to the operation of an equipment orUnintentional emissions are the result of wear, rupture or damage incurred

piece of equipment. The intentional emissions are typically larger than the unintentional ones

the estimation of shale gas fugitive emissions. The controversyfrom a lack of consistency between the conclusions of past studies as they used different data sources

(as intentional or accidental emissions are not measured) (see Table 2made apparent when comparing studies based on a bottom-up or a top-down approach

approach is based on direct measurements of emissions at given sites.measurements are essential to identifying specific sources of methane pollution but only providesvalues from identified sources of emissions. As such, some studies measured/estimated the onsiteemissions, over several sites and wells. One such study is Allen et al. (2013) whose values are reported in

. These values were completed with the US EPA offsite fugitive emissions estimates for thenatural gas processing and the transmission and distribution steps.

Howarth et al. (2011) study has been presented for historical reasons and should be considered, at best, as aworst case scenario. Indeed, while the study is transparent in wishing to portray a worst case scenario, several

arding the study underlying assumptions and data use

Page 23

ed upstream GHG emissions estimates for

shale GHG emissionsProtection Agency (EPA) as the

“intentional and unintentional emissions of methane/natural gas of the extraction, processing and

the “normal” emissions related to the operation of an equipment orthe result of wear, rupture or damage incurred by a

piece of equipment. The intentional emissions are typically larger than the unintentional ones

he controversy mainly stemsof past studies as they used different data sources

2-3). The former isdown approach (see Table 2-3).

approach is based on direct measurements of emissions at given sites. Bottom-upane pollution but only provides

As such, some studies measured/estimated the onsiteemissions, over several sites and wells. One such study is Allen et al. (2013) whose values are reported in

. These values were completed with the US EPA offsite fugitive emissions estimates for the

Howarth et al. (2011) study has been presented for historical reasons and should be considered, at best, as aworst case scenario. Indeed, while the study is transparent in wishing to portray a worst case scenario, several



Table 2-2 : Onsite and offsite fugitive emissions

Emission source

Fugitive emissions (m3 CH4/well lifetime)(values in parentheses indicated % of well

EUR) Comment

Average Minimum Maximum

On site fugitive emissions (Allen et al. 2013)8

Chemical injection pump5.43×103

(0.01%)

2.93×103

(0.006%)

7.95×103

(0.02%)

Equipment was assumed operationalduring the well lifetime (15 years)

Pneumatic controllers2.44×104

(0.05%)

1.94×104

(0.04%)

2.94×104

(0.06%)


Equipment leaks8.12×103

(0.02%)

5.20×103

(0.01%)

1.10×104

(0.02%)


Well unloading1.27×105

(0.28%)

8.07×102

(0.002%)

5.68×105

(1.26%)

Per year evaluation was multiplied bythe well lifetime (15 years)

Onsite emissions

Flaring

Unburnt natural gas is expected to be 2% ofthe natural gas sent to flare. 100% of the

natural gas in the exploration phase is sent tothe flare while 0.002% is sent to the flare

during exploitation

Based on data from the Quebecgovernment and validated by TOTAL;

Offsite fugitive emissions

Processing6.75×104

(0.15%)

2.70×104

(0.06%)

1.04×105

(0.23%)

Based on the EPA’s number as reportedby Burnham et al. (2012) and

considering an estimated ultimaterecovery (EUR) of 45 Mm3

Transmission and distribution3.02×105

(0.67%)

1.31×105

(0.29%)

4.73×105

(1.05%)

Based on the EPA’s number as reportedby Burnham et al. (2012) and

considering an EUR of 45 Mm3

Total (excluding flaring) 5.34×105 1.86×105 1.19×106

% of well EUR (excluding flaring) 1.2% 0.4% 2.6% Considering an EUR of 45 Mm3

Top-down approaches are based on measurements of atmospheric concentration around the siteswhich are then used to calculate the level of fugitive emissions. They thus provide a snapshot ofemissions over a whole region, identifying potential sources which have been neglected by the bottom-up approach. However, top-down approach (than bottom-up) are more uncertain as they may measureatmospheric emissions/concentrations which have not originated from the investigated site.

8Representative of the types and number of equipment found at approximately 489 wells in the United States



Table 2-3 present some of the discrepancies between bottom-up and top-down studies.

Table 2-3 : Upstream fugitive emissions from several studies (2010-2013)

Authors AffiliationEUR

(Mm3)

Upstream GHG emissions

[% of EUR]

Bottom upU.S. Environmental

Protection Agency (2010,2012)

US EPA N/A 2.4 %

Skone (2011) NETL 85 2.3 %

Hughes (2011);

correcting Skone

(2011)

Post Carbon Institute 24 to 85 3.31 to 8.8 %

Jing et al. (2011) Carnegie Mellon University 78 2 %

Stephenson et al. (2011) Shell 57 -

Howarth et al. (2011)9

Cornell University35 3.6 to 7.9 %

Howarth et al. (2012) 3.3 to 7.6 %

Burnham et al. (2012) Argonne National Laboratory 452.01 %

(0.71 - 5.23 %)

Cathles et al. (2012) Cornell University N/A ≈ 2.2 %

O’Connor (2013) (S&T)2

Consultants Inc. N/A. 0.56 %

Top downPetron et al. (2012) NOAA N/A 4%

Toleffson (2013) NOAA N/A 9%

Karion et al. (2013) NOAA N/A 9%

Figure 2-5 expands on the last topic by comparing the results from numerous bottom-up and top-downstudies against the results from the US EPA for the entire natural gas extraction process or for specificprocess or equipment. As seen, GHG emissions evaluation varies over several orders of magnitude.

9Howarth et al. (2011) study has been presented for historical reasons and should be considered, at best, as a

worst case scenario. Indeed, while the study is transparent in wishing to portray a worst case scenario, severalrebuttals were also published regarding the study underlying assumption and data use



Figure 2-5 : Natural gas fugitive emissions from numerous studies as reported by Brandtet al. (2014).

In the last figure, values on the right-hand side of the line show estimations that are higher than theones reported by the US EPA (2013) while the values on the left side of the line show estimations thatare lower than reported by the US EPA (2013).

Consequently, efforts were made, in recent years, to increase the reliability of the underlying data. Buteven today, some uncertainties regarding fugitive emissions are to be expected due to the naturalvariations, different practices, and methodological choices.



2.5.2 Natural gas exportation: liquefaction, LNG transport, and regasification

Jamarillo et al. (2007) provided a GHG assessment of the liquefaction, LNG tankers and regasificationsteps for the US. The assessments are presented in Table 2-4.

Table 2-4 : Jamarillo et al. (2007) GHG estimates for the liquefaction, LNG transport, andregasification in the US

Processes GHG estimates(g CO2 eq. /MJ natural gas)

Liquefaction 4.8-13.3

LNG transport 0.94-3.14

Regasification 0.36-1.6

2.5.3 Natural gas combustion

The previous assessment does not include the natural gas combustion to produce electricity. If onewould wish to do so:

• the GHG emissions would range between 489 (Jamarillo, 2007) to 529 (ICF consulting Canada,2012) g CO2 eq./kWh electricity. The previous estimation included the combustion GHGemissions and normalised (to the given efficiency) upstream GHG emissions.

For the latter, we considered a 45 % efficiency at the electricity power plant. Efficiency is an importantfactor for the combustion of both coal and natural gas. Table 2-5 provides the power plant efficienciesfor numerous European and Asian countries for natural gas systems. Data was provided by TOTAL fromEnerdata “Power plant tracker” database detailing, for each country, operational power generationcapacities and average efficiency per type of fuel. The most recent figures were considered, i.e. thosefor the year 2014.

Table 2-5 : Natural gas-fired power plant efficiencies

Country Installed capacity (GW) Heat rate (BTU) Efficiency (%)

AverageEurope*

159.7 6865.2 49.7

Germany 22.7 7754.5 44

UnitedKingdom

35.4 6437.7 53

France 12.7 6824.0 50

Italy 55.5 7417.4 46

Spain 33.4 6092.9 56

Average Asia* 186 7482.5 45.6

China 41 7582.2 45

India 26.5 7417.4 46

Japan 59.1 7417.4 46

South Korea 28.7 7754.5 44

Malaysia 14.8 8322.0 41

Taiwan 15.9 6561.5 52

* Continental average efficiencies were calculated from the weighted average (following installed capacity) of thecountries in the continents.



In brief:

● Conventional onshore natural gas upstream (excluding any transcontinental exportation processes) GHG emissions range from 6 to 21 g CO2 eq./MJ natural gas;

● Shale gas upstream (excluding any transcontinental exportation processes) GHG emissions range from 8 to 17 g CO2 eq./MJ natural gas (excluding Howarth et al. 2011 study);

● Several uncertainties regarding shale gas fugitive emissions exist between studies especially if one uses a bottom-up or a top-down approach;

● Natural gas liquefaction GHG emissions range from 4.8 to 13.3 g CO2 eq./MJ natural gas;

● LNG transport GHG emissions range from 0.94 to 3.14 g CO2 eq./MJ natural gas;

● Natural gas regasification GHG emissions range from 0.36 to 1.6 g CO2 eq./MJ natural gas;

● Gas-fired power plant efficiencies range between 46 and 56% in Europe and between 41 and 52% in Asia ;

● the GHG emissions related to electricity production range between 489 to 529 g CO2 eq./kWhelectricity. The previous estimation included the combustion GHG emissions and normalisedupstream GHG emissions considering a 45 % efficiency at the electricity power plant.



2.6 Coal life cycle GHG emissions estimates

Whitaker et al. (2012) collected and harmonised the results from more than a hundred studies aroundthe world pertaining to the coal electricity production GHG emissions. Indeed, they had observedseveral discrepancies in the GHG estimates and could not conclude if they were stemming from intrinsicvariations or simply from different hypotheses.

Therefore they:

1) Harmonised the GHG emission calculation method according to IPCC 4th Assessment Report(2007);

2) Removed, if necessary, the electricity losses during transmission and distribution from thesystem boundaries;

3) Added, if necessary, the methane emissions related to coal mining;4) Harmonised the results according to a single power plant efficiency;5) Harmonised the GHG emission factor according to the coal quality:

CEF = 0.99 × (44/12 × C) / (LHV x eff)10

6) Distinguished the GHG emissions associated with different technologies.

The obtained statistical results, stemming from the collection of numerous studies, are provided in thefollowing Figure. Unfortunately, the study’s results do not allow a differentiation between the life cyclesteps. However, it could be surmised that most of the GHG emissions stem from the coal combustion.

Results have shown that GHG emissions vary between 200 and 400 g CO2 eq./MJ electricity.

10Where CEF represents the GHG emissions related to coal combustion (kg CO2/MJ), 0.99 represents the percentage of carbon

converted into CO2 during combustion, C the coal carbon content, 44/12 the molar ratio between CO2 and carbon, LHV coal’slow heating value and eff the combustion efficiency.


Figure 2-6: Whitaker et al. (2012) harmonized GHG emissions estimates for

Some of the GHG emissions estimates may depend on the coal mining GHG emining are believed to emit more methane emissions than surface mining.from the US EPA (Kirchgessner, 2000surface mining.

As for lignite, it typically shows a lower (low) heating value thanConsequently, the quantity of required lignite to achieve the same energy output is greater. However,also has a lower carbon content thpower plant is situated close to the mine) limiting the transport distancesemissions associated with lignite arelignite mines are opencast. This prompted a conclusion to say “(instead of direct emission only) lignite fares well in comparison with hard coal where transport and coalmine methane emissions may add cons(Weisser,2016).

The following table lists some LCAseen, the GHG estimations between lignite and coal are practically identical in term of r

Table 2-6

Source

International Atomic EnergyAgency (Weisser)

The World NuclearAssociation

11Boxplot middle line indicate technology average, boxplot limit the 25

indicate minimum-maximum.



Whitaker et al. (2012) harmonized GHG emissions estimates forelectricity around the world11

Some of the GHG emissions estimates may depend on the coal mining GHG emissions as undergroundmining are believed to emit more methane emissions than surface mining. Indeed,

Kirchgessner, 2000), underground mining operations emit 70 % more methane than

pically shows a lower (low) heating value than hard coal (seeConsequently, the quantity of required lignite to achieve the same energy output is greater. However,also has a lower carbon content than coal. Besides, most lignite power plants are minepower plant is situated close to the mine) limiting the transport distances (Weisser

ssions associated with lignite are also considered less than with coal mining (Weis. This prompted a conclusion to say “if full LCA emissions are considered

(instead of direct emission only) lignite fares well in comparison with hard coal where transport and coalmine methane emissions may add considerable [emissions] to cumulative

The following table lists some LCA studies who reported GHG emissions for both lignite and coal. Asseen, the GHG estimations between lignite and coal are practically identical in term of r

6 : GHG emissions from hard coal and lignite

Lignite GHG emissions(g CO2 eq./kWh)

Hard coal GHG emissions(g CO2 eq./kWh

800-1700 950-1250

1054(790-1372)

888(756-1310)

Boxplot middle line indicate technology average, boxplot limit the 25th

and 75th

percentile while whiskers

June 2016

Whitaker et al. (2012) harmonized GHG emissions estimates for coal-generated

missions as undergroundaccording to data

% more methane than

(see Table 3-10).Consequently, the quantity of required lignite to achieve the same energy output is greater. However, it

most lignite power plants are mine-mouth (i.e. the(Weisser, 2016). Methane

(Weisser, 2016) asif full LCA emissions are considered

(instead of direct emission only) lignite fares well in comparison with hard coal where transport and coalGHG emissions”

reported GHG emissions for both lignite and coal. Asseen, the GHG estimations between lignite and coal are practically identical in term of range.

oal GHG emissionsg CO2 eq./kWh)

1250

8881310)

percentile while whiskers



Table 2-7 provides the power plant efficiencies for numerous European and Asian countries for coalsystems. Data was provided by TOTAL from Enerdata “Power plant tracker” database detailing, for eachcountry, operational power generation capacities and average efficiency per type of fuel. The mostrecent available figures were considered, i.e. those for the year 2014.

Table 2-7 : Coal-fired power plant efficiencies

Country Installed capacity (GW) Heat rate (BTU) Efficiency (%)

AverageEurope*

107.6 9050.4 37.7

Germany 56.9 8978.9 38

UnitedKingdom

21.5 9477.8 36

France 10.3 8748.7 39

Italy 7.1 8530.0 40

Spain 11.8 9221.6 37

Average Asia* 1206.2 10035.3 34

China 895 10035.3 34

India 197 12637.0 27

Japan 68 7934.9 43

South Korea 29.4 8978.9 38

Taiwan 16.8 8748.7 39

Lignite

Germany 8748.7 39

* Continental average efficiencies were calculated from the weighted average (following installed capacity) of thecontinents’ countries.

In brief:

● Hard coal GHG emissions mainly stem from its combustion;

● GHG emissions variations mainly stem from used technologies;

● Coal-fired power plant efficiencies range between 36 and 40% in Europe and between 27 and 43% in Asia;

● Reported GHG emissions related to coal-fired power plant range between 720 and 1440 g CO2 eq./kWh electricity (200 and 400 g CO2 eq./MJ electricity).



3 Goal and scope of the study

This chapter describes the goal and scope of the study, stating the methodological framework for thestudy following stages.

3.1 Objective and intended application

This investigation aims to establish and compare the GHG emissions related to the life cycle of naturalgas and coal from different sources (conventional and unconventional) and in different geographicalcontexts in order to produce electricity in Europe and Asia.


This study wishes to provide a total carbon footprint of the investigated natural gas and coal systems.The results of this study are intended to improve understanding of the natural gas and coal systems inorder to identify hot spots, potential problems and improvements opportunities in the natural gassupply chain.

According to ISO standards, LCA critical reviews are optional when the results are intended for internaluse. However, such a review is mandatory prior to public communication (e.g. environmental productdeclarations according to the ISO 14020 standards or comparative assertions disclosed to the publicaccording to the ISO 14040 standards). Moreover, it is an important step to enhance validity andcredibility and improve public acceptance of the results.

A critical review has been conducted by an external LCA expert panel. See section 3.7 for more details

on the critical review process.



3.2 System function and functional unit

The studied systems are evaluated here on the basis of the function: “producing electricity”.

The functional unit, i.e. the reference to which all input and output data are normalised, is defined hereas:

“1 kWh of electricity produced from either natural gas or coal sources at a European or Asian powerplant in 2015”.

The following provides an overview of the studied scenarios:

The natural gas scenarios are not necessarily representative of the European or Asian natural gasmarkets but rather of some of TOTAL’s (or their partners’) productions.

Investigated natural gas systems (as developed by TOTAL):

1) Utica shale gas is transmitted by pipeline to a liquefaction terminal. The LNG is then loaded on atanker destined for a regasification terminal in France (Dunkirk). The gas is then transmitted(after 20% of the received quantity went through a temporary storage) to a representativeEuropean gas-fired power plant to produce electricity;

2) North Sea (Alwyn and Dunbar sector) offshore conventional natural gas is transmitted bypipeline to continental Europe. The gas is then transmitted (after 20% of the received quantitywent through a temporary storage) to a representative European gas-fired power plant toproduce electricity;

3) Coalbed methane is produced from fields in Australia some 450-500 km from Gladstone. Thecoalbed methane is then transported by pipeline to the Gladstone liquefaction plant. The LNG isthen loaded on a tanker destined to regasification terminals in Asia. The gas is then transmitted(after 20% of the received quantity went through a temporary storage) to a representativeaverage gas-fired power plant in Asia to produce electricity;

4) Shallow offshore conventional gas is produced in Indonesia (Mahakam sector) and transmittedby pipeline to the Bontang liquefaction plant The LNG is then loaded on a tanker destined toregasification terminals in Asia. The gas is then transmitted (after 20% of the received quantitywent through a temporary storage) to a representative average gas-fired power plant in Asia toproduce electricity;

5) Onshore conventional natural gas is produced in Yemen and transmitted by pipeline to theYemen LNG liquefaction terminal in Balhaf. The LNG is then loaded on a tanker destined for theregasification terminals in Asia. The gas is then transmitted (after 20% of the received quantitywent through a temporary storage) to an average representative gas-fired power plant toproduce electricity.


Figure

Table 3-1 presents the targeted markets and trasystems. The natural gas systems were selected by TOTAL, based on TOTAL’s internal data, to representdifferent worldwide productions.

12While Russian natural gas is not part of the base scenarios, it has been evaluated in a sensitivity analysis. It has

therefore been added to the figure.



Figure 3-1: Natural gas system overview12

presents the targeted markets and travel distances associated with each of the natural gassystems. The natural gas systems were selected by TOTAL, based on TOTAL’s internal data, to represent

Russian natural gas is not part of the base scenarios, it has been evaluated in a sensitivity analysis. It has

June 2016

vel distances associated with each of the natural gassystems. The natural gas systems were selected by TOTAL, based on TOTAL’s internal data, to represent

Russian natural gas is not part of the base scenarios, it has been evaluated in a sensitivity analysis. It has



Table 3-1 : Targeted market and travel distances for investigated natural gas systems

Natural gas sourceTransportation

typeStarting point Destination Considered distance (km)

US shale gas

Pipeline Utica shale Sabine Pass500

(50-2000)

LNG tankerSabine Pass

(near Houston)Dunkirk(France)

9097

Pipeline DunkirkEuropean gas-fired power

plant100

(50-2000)

Offshore North Sea pipeline Alwyn/Dunbar Europe500

(50 - 2000)

Australian coalbedmethane

Pipeline CBM well Gladstone 450-500

LNG tanker GladstoneAsian regasification

terminal7300

PipelineAsian regasification

terminalAsian gas-fired power plant

100(50-2000)

Indonesian shallowoffshore

Pipeline Mahakam Delta Bontang500

(50-2000)

LNG tanker BontangAsian regasification

terminal4200



100(50-2000)

Yemen onshore

Pipeline Marib Balhaf500

(50-2000)

LNG tanker BalhafAsian regasification

terminal10800



100(50-2000)

3.2.1 Coal systems

The coal scenarios, as developed by CIRAIG, were developed to reflect coal origins in the Asian andEuropean markets whose productions and importations values were provided by TOTAL based on IHSdata:

6) Australian coal is mined and transported by train to Newcastle where it is loaded onto a shipbound for Asia (i.e. China, India, South Korea, Japan and Taiwan). Once in Asia, the coal is thenloaded onto a train headed for a representative (average) Asian coal-fired power plant toproduce electricity.

7) Chinese coal is mined and transported by train to a representative (average) Asian coal-firedpower plant to produce electricity;

8) Indonesian coal is mined and transported by train to Taboneao where it is loaded onto a shipbound for Asia (i.e. China, India, South Korea, Japan and Taiwan). Once in Asia, the coal is thenloaded onto a train headed for a representative (average) Asian coal-fired power plant toproduce electricity.

9) European coal is mined and transported by train to a representative (average) European coal-fired power plant to produce electricity;

10) Russian coal is mined and transported by train to a representative (average) European coal-firedpower plant to produce electricity;

11) US coal is mined and transported by train to the port of Norfolk where it is loaded onto a shipbound for Europe. Once in Europe, the coal is then transported by train to a representative(average) European coal-fired power plant to produce electricity;


12) Colombian coal is mined and transported byship bound for Europe. Once in Europe, the coal is then loaded onto a train headed forrepresentative (average) European

13) South African coal is mined and transported by trailoaded onto a ship bound forheaded for a representative (average) Asian

Figure

13While European lignite is not part of the base scenarios, it has been evaluated in a sensitivity analysis. It has

therefore been added to the figure.



bian coal is mined and transported by train to Puerto Bolivar where itship bound for Europe. Once in Europe, the coal is then loaded onto a train headed forrepresentative (average) European coal-fired power plant to produce electricitySouth African coal is mined and transported by train to Richards Bay coal terminal

for Asia. Once at its destination, the coal is then loaded onto a traina representative (average) Asian coal-fired power plant to produce electricity

Figure 3-2: Coal system overview13

European lignite is not part of the base scenarios, it has been evaluated in a sensitivity analysis. It has

June 2016

where it is loaded onto aship bound for Europe. Once in Europe, the coal is then loaded onto a train headed for a

to produce electricity;Richards Bay coal terminal where it is

Asia. Once at its destination, the coal is then loaded onto a trainto produce electricity.

European lignite is not part of the base scenarios, it has been evaluated in a sensitivity analysis. It has



Table 3-2 presents the targeted markets and travel distances associated with each of the coal systems.Coal markets were established according to European/Asian production and coal import data from IHS(based on data from 2014) and TOTAL in-house experts (see Figure 3-3 and Figure 3-4).



Table 3-2 : Targeted markets and travel distances for investigated coal systems

Coal sourcesTransport

modeStarting point Destination Considered distance (km)

Australia

Train Australia Newcastle500

(50-2000)

Freight ship Newcastle Asian port 8800

Train Asian port Asia100

(50-2000)

China Train China Asia500

(50-2000)

Indonesia

Train Indonesia Taboneao500

(50-2000)

Freight ship Taboneao Asian port 3600


(50-2000)

Europe Train Europe Europe500

(50-2000)

Russia Train Russia Europe1000

(50-2000)

United States

Train United States United States port500

(50-2000)

Freight ship United States port European port 6615

Train European port Europe100

(50-2000)

Columbia

Train Columbia Columbia port500

(50-2000)

Freight ship Columbia port European port 8102

Train European port Europe100

(50-2000)

South Africa

Train South Africa South Africa port500

(50-2000)

Freight ship South Africa port Asian port 8100


(50-2000)

The coal systems were crafted according to the European and Asian coal production and majorimports statistics in major European and Asian countries based on a sample of European and Asiancountries described in Table 3-3. Data were provided by IHS (based on data from 2014) and TOTAL in-house experts (for the representative countries).

Table 3-3 : Coal production and imports in major European and Asian countries

Market CountryDomestic production

[Mt]Imports

[Mt]

Europe 80-97 98-130

France 0 2-4

United Kingdom 35-40 30-40

Germany 40-50 40-50

Italy 0 14-18

Spain 5-7 12-18

Asia 3500-3600 570-650

China > 3000 170-200

India 500-600 150-180

South Korea 0 80-85

Japan 0 110-120

Taiwan 0 60-65



Origin of imported coal in Europe and Asia were calculated according to the import share in Europe anddifferent Asian countries as shown in Figure 3-3 and Figure 3-4.

Figure 3-3: Steam coal imports market share in Europe (IHS MCR, 2014)



China

Japan

South Korea

Figure 3-4: Coal imports market share in China (up), Japan (middle) and South Korea(down) (IHS MCR, 2014)


3.3 Natural gas and coal systems life cycle boundaries

The life cycle boundaries of natural gas and coal systems must allow the two compared systemequivalent. To achieve this goal, we considered the following boundaries.

The life cycle processes included within the

• Exploration for and exploitation of conventional and unconventional natural gas;

• Processing of the natural gas;

• Transmission: transport by pipeline

• Liquefaction (for natural gas systems considering overseas exportation);

• Liquefied natural gas (LNG) transportation overseas (in LNG carriers; for natural gas systemsconsidering overseas exportation);

• Regasification (for natural gas systems considering overseas exportation);

• Underground gas storage;

• Transmission: transport by pipeline to

• Electricity production in the appropriate geographical context

These processes are illustrated in Figure

Figure

The life cycle processes included within the

• Exploration for and exploitation of coal;

• Transmission to exportation port

• Transportation overseas (for coal systems considering overseas exportation);

• Transmission to power plant: transport by train

• Electricity production in the appropriate geographical context



Natural gas and coal systems life cycle boundaries

The life cycle boundaries of natural gas and coal systems must allow the two compared systemwe considered the following boundaries.

processes included within the boundaries of the natural gas systems are as follow:

and exploitation of conventional and unconventional natural gas;

al gas;

Transmission: transport by pipeline to liquefaction plant (if applicable);

Liquefaction (for natural gas systems considering overseas exportation);

fied natural gas (LNG) transportation overseas (in LNG carriers; for natural gas systemsering overseas exportation);

Regasification (for natural gas systems considering overseas exportation);

mission: transport by pipeline to gas-fired power plant;

in the appropriate geographical context.

Figure 3-5:

Figure 3-5: Natural gas system boundaries

processes included within the boundaries of the coal systems are as follow:

and exploitation of coal;

to exportation port: transport by train (for coal systems considering exportation)

Transportation overseas (for coal systems considering overseas exportation);

r plant: transport by train;

in the appropriate geographical context.

Page 41

The life cycle boundaries of natural gas and coal systems must allow the two compared systems to be

are as follow:

and exploitation of conventional and unconventional natural gas;

fied natural gas (LNG) transportation overseas (in LNG carriers; for natural gas systems

are as follow:

systems considering exportation);


Figure



Figure 3-6: Hard coal system boundaries

June 2016



3.4 Natural gas systems composition

Table 3-4 provides the natural gas composition at the extraction point and at the transmission network.These compositions are mainly useful for the natural gas processing step and the calculation of theemissions related to the compressors. All data, unless mentioned otherwise, came from TOTAL’sinternal reporting (data is representative of the annual campaign made in 2014).

Table 3-4 : Natural gas composition (% mol) at the well and the transmission network.

Location/SourceComposition (% mol)

Methane Ethane Propane CO2 N2 H2S Others

At the well (values provided by TOTAL)

Shale gas (Utica) 80.3 12.5 4.1 0.1 0.3 ≈0 2.7

North Sea (Alwyn)offshore gas

86.0 5.8 2.5 3.4 0.55 0 1.7

Australian coalbedmethane

95.1 0.05 1.2 3.65 0 0

Indonesian offshore gas

(Borneo sector)87.0 3.7 2.7 4.3 0.3 0 2.0

Yemen onshore gas 90.1 5.7 2.5 0.3 0.1 0 1.4

At the transmission/distribution network

US transmitted gas,average

14 95.0 3.2 0.2 0.5 1.0 N/D

3.5 GHG emissions assessment – General Framework

We propose a three-tier approach to evaluating the GHG emissions of the different investigated naturalgas and hard coal systems.


• Comparison of TOTAL reporting and other in-house data;

• Life cycle modeling based on the ecoinvent database.

Each of these approaches provides a level of information which can be used to answer the overarchingquestion, which was to establish a comparison between natural gas and coal systems and evaluatesituations (if any) in which natural gas systems could emit more GHG emissions than coal systems.

1) The first approach is to apply directly the values from the literature to the investigated systemsprocesses. Such an assessment provides an overview of the possible GHG emissions level for thedifferent processes of the investigated systems as obtained from past life cycle studies.However, such an approach is not specific to TOTAL’s practices and may not be based oncoherent underlying assumptions or data;

14Union Gas, 2014



2) The second approach is simply to collect data from TOTAL GHG emissions reporting (data mostlyfrom 2014 with historical data ranging from 2008, 2009 or 2012 to 2014 for the liquefactiondata for different terminals). This approach is specific to TOTAL’s practices but is somewhatincomplete as the reporting data pertains to direct emissions and GHG emissions fromelectricity consumption (scope 1-2 according to the GHG Protocol). Therefore, the emissions donot account for the entire life cycle. However, such an assessment could be seen as theminimum threshold of the different natural gas processes. Furthermore, TOTAL is no longerdirectly associated with coal extraction and, therefore, could not provide proper data for thehard coal systems. This assessment thus only pertains the natural gas systems;

3) The third approach is a hybrid between the first and second approach. It relies on CIRAIG’s lifecycle modeling. The underlying data from these models mostly stems from the literature and lifecycle inventory databases (i.e. secondary data). The life cycle model was improved, whenpossible, with data provided by TOTAL (i.e. primary data). Therefore, this approach is morecomplete (i.e. GHG protocol’s scope 1-2-3 rather than scope 1-2) than TOTAL’s reporting databut not as representative of its actual practices. It is also an improvement upon the applicationof literature GHG emissions to the different processes since some of TOTAL’s practices and datawere incorporated in the life cycle modeling.

The next subsection provides an overview of the developed life cycle models for each of the investigatedsystems.



3.6 Life cycle modeling

3.6.1 Multifunctional processes and allocation rules

Life cycle assessment does not study products on their own but considers them through the functionsthese products fulfill. Therefore, multifunctional processes must be considered with care. Secondaryfunctions include the production of co-products and the generation of by-products.

In this study, the natural gas processing is a multifunctional process, as it produces both standardisednatural gas and natural gas liquids (NGL); both of which have an economic/energy interest. Therefore,the GHG emissions associated with the processing step were allocated on an energy basis according tothe extracted natural gas input and output composition. A sensitivity analysis regarding the allocationrules (i.e. energy, economic, mass) was also performed.

For the other processes, allocations rules were already chosen by the processes used in the life cycledatabase ecoinvent.

3.6.2 Life cycle boundaries, inventory data, sources, and assumptions

Life cycle inventory data collection mainly concerns the materials used, the energy consumed, thewastes and emissions generated for each process included in the system boundaries.

The data collection process is typically an important step as the quality of the life cycle modeling resultsdepends on the quality of data used in the inventory analysis. Therefore, every effort has been made tointegrate the most robust and representative information.

Data collection has been conducted by the CIRAIG with TOTAL’s help. However, limited primary datawere collected and were only limited to the natural gas systems. Missing, incomplete or non-accessibledata were completed by secondary data, e.g. the life cycle inventory database ecoinvent 2.215, CIRAIG’sinternal database (which includes data from 15 years of LCA activity), datasets from publicly availabledatabases, literature reviews, and expert judgment.

The following sub-sections detail the included processes, data sources, and assumptions for each of theinvestigated natural gas and hard coal systems.

To the best of our knowledge no activities/processes were excluded from our assessment apart fromprocesses/activities that are not typically considered in LCA such as:

• Employee transportation to and from work;

• Desk work (material and energy) supplies;

• Impacts arising from geological surveys;

• Waste management indirectly related to the included processes.

These activities are generally unaccounted for due to data gaps and presumed low impacts.

15Ecoinvent most recent release v 3.2 was not integrated in the LCA software Simapro during the project

timeframe. The previous version (v3.1) cannot adequately perform uncertainty analysis due to erroneousstatistical distributions (e.g., normal distributions were given to process creating artificial negative masses ofinputs or outputs). We qualitatively checked if data between versions 2.2 and 3.1 were significantly modified andobserved no major discrepancies. Thus we opted for ecoinvent 2.2 as it was our wish to perform an uncertaintyanalysis

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3.6.3 System 1: US Shale gas to European power plant

Table 3-5 lists the included processes and assumptions associated with the exploitation of US shale gasand used for electricity production in Europe. Data was implemented in the SimaPro 8.0.5 software,developed by PRé Consultants (www.pre.nl), to assist in the LCA system modeling, link the referenceflows with the life cycle inventory database and compute the complete life cycle inventory of thesystem.

No cut-off criteria were used. Therefore, all inventory data available were included in the systemmodeling.

Table 3-5 : Included/excluded processes and assumptions related to the US shale gasexploitation system

Processes Value/Data source Data type Comment

General

Natural gas density (kg/m3) 0.9 LiteratureNatural gas property (Engineering toolbox,

2016)

Low heating value (MJ/m3)37.4

(36-38)Literature

Natural gas property (van Durme et al. 2012).Should be coherent with the natural gas

composition at the transmission/distributionnetwork in the U.S. See Table 3-4

EUR/well (Mm3) (25-250)* Primary/literature

Site-specific data provided by TOTAL (surveyedin 2015)

Interval is based on the production of morethan 3000 shale gas wells in the US (O’Sullivan

et al, 2012)

Site width (m)90

(50-140)Primary

Based on Quebec surveys (van Durme et al.2012

Site length (m)110

(25-165)Primary

Based on Quebec surveys (van Durme et al.2012

Exploitation lifetime (years) 15 (3-50) PrimaryBased on Quebec surveys (van Durme et al.

2012)

Machinery travel distance (km) 3500 AssumptionAn average continental traveling distance (van

Durme et al. 2012)

Exploration

Numbers of well per site (-) 1 (1-8) Primary


Interval based on Quebec surveys (van Durmeet al. 2012)

Numbers of fracturing per well (-)

1 (1-8) Primary



Abandoned wells (%)0

(0-5)Primary


Interval based on Quebec surveys ((van Durmeet al. 2012)

Fracking fluids (m3)1670

(877-3377)Primary

Based on Quebec surveys (van Durme et al.2012)

Fracking fluids recipe Varied PrimaryBased on Quebec surveys (van Durme et al.

2012)

Drilling mud (kg)4.1×10

5

(SD^2=1.09)Primary


Drilling mud recipe Varied PrimaryBased on Quebec surveys (van Durme et al.

2012)



Liquid flow back (%/well)44

(27-73)Primary


Gas sent to flare (%) 100 Assumption

Based on Quebec laws (van Durme et al. 2012)TOTAL provided some qualitative data

indicating that its strategy included both flaringand capture. However, it is unclear if capture isan option for exploration. In doubt, we optedfor the worst case scenario which would be

flaring.

Flaring efficiency (%) 98 PrimaryData provided by TOTAL (2015)

Corroborated by Quebec surveys (van Durmeet al. 2012)

Explosives (kg/well) 4.4 (0.85-9.3) Primary Based on Quebec surveys

Fugitive emissions (m3/site)1.36×10

3

(2.33×102

-8.68×104)

Literature/Calculated

Based on the values published by Allen et al.(2013) from several sites in the US. Fugitiveemissions were broken down proportionally

between the exploration and exploitation stepsaccording to the volume of extracted natural

gas of each step.

Exploitation (only the processes which are different from the exploration phase are reported)

Numbers of fracturations perwell (-)

1(1-18)

Primary



Number of additional wells persite

2.74(1-6)

Primary



Gas sent to flare (%) 0.02 Assumption

Based on Quebec surveys. (van Durme et al.2012)

Assumption seems to be validated byqualitative information from TOTAL in-house

experts

Gas sent to processing (%) 99.98 Calculated

Fugitive emissions (m3/site)6.17 ×10

5

(1.06×105

– 3.93×107)

Literature/Calculated

Based on the values published by Allen et al.(2013) from several sited in the US. Fugitiveemissions were broken down proportionally

between the exploration and exploitation stepsaccording to the volume of extracted natural

gas of each step.

Processing

Distance to processing (km)24

(5-50)Primary

Site-specific data from TOTAL (surveyed in2015)

Brine removal (barrels/MMcf) 12.5 (5-20) LiteratureBarrels of brine removed by MMcf of extracted

gas (NY State department of environmentalconservation, 2011)

CompressorsBased on US EPA Non-

Road modelLiterature

Energy and atmospheric emissions related to apressurization from 100-200 psi at the well to900 psi for the transmission (van Durme et al.

2012).Compressor efficiency was set at 95 %; valuefound during the Quebec surveys (van Durme

et al. 2012)

DehydrationBased on published ProSim

plus simulationLiterature

Process includes the production of triethyleneglycol, some of its emissions to the atmosphere

and required energy

Followed ProSim (2015) plus simulationassumption: Water mass fraction in gas



assumed to be 0.06 % (input) and 0.002% inoutput

Amine processBased on Aspentech

simulation Literature

The process includes electricity, amineproduction, heat, and emissions are included.

Follows the Aspentech simulation (Aspentech,2014)

Based on gas CO2 input and outputcomposition

Removed CO2 is considered as emitted to theatmosphere.

Turbo-expander processBased on GHGenius

natural gas processingplant data

LiteratureElectricity, heat, and emissions included for the

extraction of nitrogen

Quantity of recovered naturalgas liquids (% mass)(not considered in the mainscenario)

26.3 CalculatedBased on the natural gas composition provided

by TOTAL (2014)

Quantity of recovered naturalgas liquids (% energy)


by TOTAL (2014) and energy content

Transmission

Distances (km)500

(50-2000)Assumption

Based on traveling distances from Barnet (FortWorth) to Sabine Pass;

Interval represents continental distanceassumption

CompressorsBased on US EPA Non-Road

modelLiterature

Energy and atmospheric emissions related tomaintaining pressure in the pipeline. 3590 hp

compressors (4 per stations) are efficient at95%.

A compressor station is required every 120 km(on average) and can move 700 MMcf/day

16

Fugitive emissions(kg/MJ km)

2.3×10-7

(1.6×10-7

– 3.8×10-7

)Literature

Values provided by TOTAL from a Marcogaz(2016) study

Liquefaction

Liquefaction Ecoinvent database

The dataset includes the infrastructure, theenergy use (from 1999 published data) and

atmospheric emissions (from 1990 publisheddata)

LNG transportation

Distance (km) See Table 3-1

LNG transportation Ecoinvent Database

Includes the infrastructure and emissions;based on 1998-1999 data from Italian LNG fleet.

All vessels were equipped with gas turbine toburn evaporated gas

Regasification

Regasification Ecoinvent DatabaseIncludes energy use, emissions, and

infrastructure

Underground storage

Fraction of gas going intostorage after being regasified(%)

20(15-25)

PrimaryBased on French Ministry of Environment and

Transport (2015).Interval is based solely on assumption


modelLiterature/Primary

Benchmark data (volume of gas in storage peryear and natural gas consumption) from 2

storage operators was used, in conjunction with

16https://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngcompressor/ngcompressor.pdf



the US EPA Non-Road model, to calculate theemissions from the compressors.

Fugitive emissions (kg/ year) 0 Primary/assumption

Data/assumption provided by TOTAL in-houseexperts (2015) who believe that fugitive

emissions are marginal (considering the limitedaboveground infrastructure) and, therefore,

were neglected in the main scenario but wereconsidered in a sensitivity analysis

Transmission

Distances 100 (50-2000) Assumption Continental short distance values



Energy and atmospheric emissions related tomaintaining pressure in the pipeline.

Calculations were based on GRT Gaz publicdata, confirmed by internal data from TOTAL

and benchmark with other Transmission SystemOperators

Fugitive emissions (kg/MJ km)2.3×10

-7

(1.6×10-7

– 3.8×10-7

)Literature


Electricity production

Efficiency (%) in European plant49.7%

(44%-56%)Literature

Data provided by TOTAL from Enerdata PowerPlant Tracker database

Heat rate (BTU)6865.2

(6092.9 – 7754.5)Calculated Calculated from the efficiency

Combustion Ecoinvent Database

Includes the infrastructure, atmosphericemissions, and substances needed for

operations. Data represent an average ofEuropean power plants (timeframe of data is

not listed)

Well end of life

Fugitive emissions (m3/site) 0 Assumption

Fugitive emissions were reported after thewell life. The reported cause was either

defective cement or wear; both of whichare typically unaccounted for in LCA.

* EUR and %EUR figures were used to assess the fugitive emissions and were not disclosed forconfidentiality reasons

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3.6.4 System 2: Offshore North Sea natural gas to European power plant

Table 3-6 lists the included and excluded processes and assumptions associated with the exploitation ofoffshore natural gas in the North Sea and used for the production of electricity in Europe. Data wasimplemented in the SimaPro 8.0.5 software, developed by PRé Consultants (www.pre.nl), to assist in theLCA system modeling, link the reference flows with the life cycle inventory database and compute thecomplete life cycle inventory of the system.


Table 3-6 : Included/excluded processes and assumptions related to the offshore NorthSea exploitation system

Processes Value Data source Comment

General


2016)


(36-38)Literature Natural gas property (van Durme et al. 2012).

Number of wells 92 Primary Site-specific data provided by TOTAL (2014)

Exploration/Exploitation/part of transmission

Offshore natural gas extraction Ecoinvent database

Data is representative of exploitation of naturalgas in the North Sea in 1998-2000

The process includes the infrastructure, energyand atmospheric emissions related to the

exploration, exploitation and transmission ofgas to the coast

Processing (uncertain if considered in the ecoinvent process for the natural gas extraction)17


modelLiterature

Energy and atmospheric emissions related to apressurization from 100-200 psi at the well to

900 psi for the transmission.Compressor efficiency was set at 95 %; valuefound during the Quebec surveys (van Durme

et al. 2012)

DehydrationBased on published ProSim

plus simulation resultsLiterature

Process includes the production of triethyleneglycol, some of its emissions to the atmosphere

and required energy

Followed ProSim plus (2015) simulationassumption: Water mass fraction in gas






17It is unsure whether the processing step has been accounted for in the ecoinvent North Sea natural gas

extraction process. As mentioned in the literature review, some platforms directly process the natural gas and theecoinvent process only states that it accounts for “all processes on the platform”. In doubt, we have accounted forthe processing step. We may have overestimated the emissions if they were already considered in the ecoinventprocess.





Turbo-expander processBased on GHGenius naturalgas processing plant data

LiteratureElectricity, heat, and emissions included for the

extraction of nitrogen



by TOTAL (2014)



by TOTAL and energy content

Transmission (once back on the coast)

Distances 500 (50-2000) Assumption Continental long distance assumption


modelLiterature

Energy and atmospheric emissions related tomaintaining pressure in the pipeline. Based on

GRT Gaz public data, confirmed by internal datafrom TOTAL and benchmark with other

Transmission System Operators


-7

(1.6×10-7

– 3.8×10-7

)Literature


Underground gas storage

Fraction of gas going into storageafter being regasified (%)

20(15-25)





Benchmark data (volume of gas in storage peryear and natural gas consumption) from 2

storage operators was used, in conjunction withthe US EPA Non-Road model, to calculate the

emissions from the compressors.


Data/assumption provided by TOTAL in-houseexperts (2015) who believe that fugitive

emissions are marginal (considering the limitedaboveground infrastructure) and, therefore,

were neglected in the main scenario but wereconsidered in a sensitivity analysis


Efficiency (%) in European plant49.7 %

(44%-56%)Literature




Combustion Ecoinvent database


operations. Data represent an average ofEuropean power plants (timeframe of data is

not listed)

Well end of life



defective cement or wear; both of whichare typically unaccounted for in LCA

3.6.5 System 3: Australian coalbed methane to Asian power plant

Table 3-7 lists the included and excluded processes and assumptions associated with the exploitation ofcoalbed methane in Australia and used for the production of electricity in Asia. Data was implemented

http://www.pre.nl/



in the SimaPro 8.0.5 software, developed by PRé Consultants (www.pre.nl), to assist in the LCA systemmodeling, link the reference flows with the life cycle inventory database and compute the complete lifecycle inventory of the system.


Table 3-7 : Included/excluded processes and assumptions related to the Australiancoalbed methane system


General

Natural gas density (kg/m3) 0.9 Literature Natural gas property


(36-38)Literature

Natural gas property. Should be coherent withthe natural gas composition at the

transmission/distribution network in the U.S.See Table 3-4

Exploration/exploitation

Number of wells 3185 PrimarySite-specific data provided by TOTAL

(surveyed 2015)

Wells and field constructionTaken from from

literatureLiterature

Includes the materials and energy needed forconstruction. Data represent Australian

conditions. (WorleyParsons, 2011)

Operation of compressor andpower generation turbines atgas compressor stations

Taken from fromliterature

LiteratureData represent Australian conditions.

(WorleyParsons, 2011)

Water management operationsTaken from from

literatureLiterature

Includes the energy needed for water transferand treatment (reverse osmosis). Data

represent Australian conditions.(WorleyParsons, 2011)

Gas field combustion emissions(kT CO2eq/PJ)

2.5 Literature

Data represent Australian conditions.(Kember, 2012). Combustion of gas and

petroleum fuels used in exploration, drillingand pumping gas to a processing plant

Fugitive emissions(kT CO2eq/PJ)

9.7(3.4-16)

Literature

Data represent Australian conditions.(Kember, 2012). Process includes themethane from well completion, liquidunloading, blowdowns, leakage from

gathering pipeline and CO2 from flares (notconsidered as fugitive emissions in other

systems)

Processing



Energy and atmospheric emissions related toa pressurization from 100-200 psi at the well

to 900 psi for the transmission.Compressor efficiency was set at 95 %; valuefound during the Quebec surveys (van Durme

et al. 2012)

DehydrationBased on ProSim plus

simulationLiterature

Process includes the production of triethyleneglycol, some of its emissions to theatmosphere and required energy

Followed ProSim plus simulation assumption:Water mass fraction in gas assumed to be

0.06 % (input) and 0.002% in output

Amine process Based on Aspentech Literature The process includes electricity, amine



simulation production, heat, and emissions are included.






LiteratureElectricity, heat, and emissions included for

the extraction of nitrogen


0.22 CalculatedBased on the natural gas composition

provided by TOTAL (2014)



provided by TOTAL and energy content

Transmission

Distances475

(50-2000)Assumption

Site-specific data provided by TOTAL. Valuesin bracket represent the regional to

continental distances




GRT Gaz public data, confirmed by internaldata from TOTAL and benchmark with other



2.3×10-7

(1.6×10-7

– 3.8×10-7

)Literature

Values provided by TOTAL from a Marcogazstudy (2016)

Liquefaction




LNG transportation


LNG transportation Ecoinvent database

Includes the infrastructure and emissions;based on 1998-1999 data from Italian LNGfleet. All vessels were equipped with gas

turbine to burn evaporated gas

Regasification

Regasification Ecoinvent databaseIncludes energy use, emissions, and

infrastructure

http://www.pre.nl/



Underground storage


20(15-25)




Road modelLiterature/Primary

Benchmark data (volume of gas in storage peryear and natural gas consumption) from 2storage operators was used, in conjunction

with the US EPA Non-Road model, to calculatethe emissions from the compressors


Data/assumption provided by TOTAL in-houseexperts (2015) who believe that fugitiveemissions are marginal (considering the

limited aboveground infrastructure) and,therefore, were neglected in the main

scenario but were considered in a sensitivityanalysis

Transmission

Distances 500 (50-2000) Assumption Regional to continental values







2.3×10-7

(1.6×10-7

– 3.8×10-7

)Literature



Efficiency (%) in Asian plant45.6%

(41%-52%)Literature






operations. Data represent an average ofAsian power plants (timeframe of data is

not listed)

Well end of life



defective cement or wear; both of whichare typically unaccounted for in LCA

3.6.6 System 4: Indonesian offshore natural gas to Asian power plant

Table 3-8 lists the included and excluded processes and assumptions associated with the exploitation ofoffshore natural gas in Indonesia and used for the production of electricity in Asia. Data wasimplemented in the SimaPro 8.0.5 software, developed by PRé Consultants (www.pre.nl), to assist in theLCA system modeling, link the reference flows with the life cycle inventory database and compute thecomplete life cycle inventory of the system.




Table 3-8 : Included/excluded processes and assumptions related to the Indonesianoffshore natural gas system


General


2016)



Exploration/exploitation/transmission to land

Offshore natural gas extraction Ecoinvent proxy databaseData is not representative of Indonesia. It relieson the same process as the one from the North

Sea. See Table 3-6 for further details

Processing (unclear if included in natural gas extraction process; if not include the following)





et al. 2012)

DehydrationBased on a published

ProSim plus simulationLiterature


Followed ProSim plus simulation assumption:Water mass fraction in gas assumed to be

0.06 % (input) and 0.002% in output













provided by TOTAL (2014)



provided by TOTAL and energy content

Transmission (once back on the coast)

Distances500

(50-2000)Assumption Continental long distance values







-7

(1.6×10-7

– 3.8×10-7

)Literature

Values provided by TOTAL from Marcogaz(2016)

Liquefaction

Liquefaction Ecoinvent databaseThe dataset includes the infrastructure, theenergy use (from 1999 published data) and

http://www.pre.nl/




LNG transportation





Regasification


infrastructure

Underground storage


20(15-25)






with the US EPA Non-Road model, to calculatethe emissions from the compressors



limited aboveground infrastructure) and,therefore, were neglected in the main scenario

but were considered in a sensitivity analysis

Transmission

Distances 100 (50-2000) Assumption Continental short distance values







-7

(1.6×10-7

– 3.8×10-7

)Literature




(41%-52%)Literature






operations. Data represent an average ofAsian power plants (timeframe of data is not

listed)

Well end of life


Fugitive emissions were reported afterthe well life. The reported cause was

either defective cement or wear; both ofwhich are typically unaccounted for in

LCA

3.6.7 System 5: Yemen onshore natural gas to Asian power plant

Table 3-9 lists the included and excluded processes and assumptions associated with the exploitation ofconventional onshore natural gas in Yemen and used for the production of electricity in Asia. Data wasimplemented in the SimaPro 8.0.5 software, developed by PRé Consultants (www.pre.nl), to assist in the



LCA system modeling, link the reference flows with the life cycle inventory database and compute thecomplete life cycle inventory of the system(s).


Table 3-9 : Included/excluded processes and assumptions related to Yemen onshorenatural gas system


General


2016)




Natural gas extraction Ecoinvent database

Ecoinvent is supposedly representative ofmiddle east operations. However, it is mostlybased on European data. Process includes the

infrastructure, energy and atmosphericemissions related to the exploration,

exploitation, and processingLeakage was assumed to be 0.6% for theexploitation and 0.13% for the processing

Energy demand data is from 2000 Norwegiandata

Quantity of flared gas was based on 1991German data

Leakage was from 1990 German data

Processing (unclear if included in natural gas extraction process; if not, include the following)





et al. 2012)

DehydrationBased on published

ProSim plus simulationLiterature


Followed ProSim (2015) plus simulationassumption: Water mass fraction in gas














Quantity of recovered naturalgas liquids (% mass)


by TOTAL (not considered in the mainscenario)



by TOTAL and energy content

Transmission

Distances 500 (50-2000) Assumption Continental long distance values







-7

(1.6×10-7

– 3.8×10-7

)Literature

Values provided by TOTAL from a Marcogazstudy (2016)

Liquefaction




LNG transportation





Regasification


infrastructure

Underground storage


20(15-25)






with the US EPA Non-Road model, to calculatethe emissions from the compressors.



limited aboveground infrastructure) and,therefore, were neglected in the main scenario

but were considered in a sensitivity analysis

Transmission

Distances 500 (50-2000) Assumption Regional to continental values







-7

(1.6×10-7

– 3.8×10-7

)Literature

Values provided by TOTAL from Marcogaz(2016)



(41%-52%)Literature




Combustion Ecoinvent database Includes the infrastructure, atmospheric



emissions, and substances needed foroperations. Data represent an average of

European/Asian power plants (timeframe ofdata is not listed)

Well end of life


Fugitive emissions were reported afterthe well life. The reported cause was

either defective cement or wear; both ofwhich are typically unaccounted for in

LCA.

http://www.pre.nl/



3.6.8 Systems 6 to 14: Coal from Eastern Europe, Russia, China, Australia, Indonesia, Colombia,United States or South Africa used in either a European or Asian power plant

Table 3-10 lists the included and excluded processes and assumptions associated with coal systems fromEurope, Russia, China, Australia, Indonesia, Colombia, USA and South Africa for the production ofelectricity in either Europe or Asia. Data was implemented in the SimaPro 8.0.5 software, developed byPRé Consultants (www.pre.nl), to assist the LCA system modeling, link the reference flows with the lifecycle inventory database and compute the complete life cycle inventory of the system(s).


Table 3-10 : Included processes and assumptions related to coal systems


General

Coal low heating value (LHV)(MJ/kg) in Europe and North

America

24(23-26)

LiteratureData provided by TOTAL from IHS (2014) and corroborated

by ecoinvent

Coal low heating value (LHV)(MJ/kg) in Asia

22(19-26)

LiteratureData provided by TOTAL from IHS (2014) and corroborated

by ecoinvent


Europe hard coal extraction Ecoinvent database

Average operational conditions in Europe for undergroundand open cast mine: land use, electricity, heat, diesel,pumped groundwater, explosives, emissions to air and

water and solid waste.All coalbed methane from seam is accounted as natural gas

and is not recovered (thus emitted):0.0082 kg CH4/kg coal

Russian hard coal extraction Ecoinvent database

Average operational conditions in Russia for undergroundand open cast mine: land use, electricity, heat, diesel,pumped groundwater, explosives, emissions to air and



Australian hard coal extraction Ecoinvent database

Average operational conditions in Australia forunderground and open cast mine: land use, electricity,

heat, diesel, pumped groundwater, explosives, emissionsto air and water and solid waste.

All coalbed methane from seam is accounted as natural gasand is not recovered (thus emitted):

0.0027 kg CH4/kg coal

Indonesian hard coal extraction Ecoinvent proxy databaseUnavailability of geographically relevant data in the

ecoinvent database. Modeled as Australian coal.

Chinese coal extraction Ecoinvent database

Average operational conditions in China for undergroundand open cast mine: land use, electricity, heat, diesel,pumped groundwater, explosives, emissions to air and



Colombian coal extraction Ecoinvent database

Average operational conditions in South America forunderground and open cast mine: land use, electricity,




All coalbed methane from seam is accounted as natural gasand is not recovered (thus emitted):


US coal extraction Ecoinvent database

Average operational conditions in North America forunderground and open cast mine: land use, electricity,


All coalbed methane from seam is accounted as naturalgas and is not recovered (thus emitted):


South Africa coal extraction Ecoinvent database

Average operational conditions in South Africa forunderground and open cast mine: land use, electricity,


All coalbed methane from seam is accounted as naturalgas and is not recovered (thus emitted):


Continental train transportation

Distance from extraction pointto port

500(50-2000)

Assumption Interval based on continental distance assumption

Train transportation Ecoinvent databaseIncludes the energy supply (electrical, diesel or coal)

depending on the geographical context, direct airborneemissions, and infrastructures.

Transoceanic transport

Distance (km)See

Table 3-2

Transoceanic transport Ecoinvent databaseIncludes the fuel supply, direct airborne emissions,

disposal of bilge oil and emissions of tributyltincompounds are included

Train transport to power plant

Distance from European port toplant (km)

100(50-2000)


Distance from Asian port toplant (km)

100(50-2000)


Distance Eastern Europe toGermany (km)

500(50-2000)


Distance extraction Russia toEurope (km)

1000(50-2000)


Distance extraction to China(km)

500(50-2000)


Train transportation Ecoinvent databaseIncludes the energy supply (electrical, diesel or coal)

depending on the geographical context, direct airborneemissions, and infrastructures.




Efficiency (%) in European plant37.7%

(36%-40%)Literature

Data provided by TOTAL from Enerdata Power PlantTracker database

Heat rate in European plant(BTU)

9050.4(8530.0 – 9477.8)

Calculated Calculated from the efficiency

Efficiency (%) in Asian plant34%

(27%-43%)Literature

Data provided by TOTAL from Enerdata Power PlantTracker database

Heat rate in Asian plant (BTU)10 035.3


Lignite efficiency (%) inEuropean plant

39%(33%)

Literature

Data provided by TOTAL.The value in parenthesis is from Ecoinvent who estimatesthat the efficiency should be 33% based on data collected

in 2000.

Lignite heat rate (BTU)8748.7

(10 339.4)Calculated Calculated from the efficiency


Includes the infrastructure, atmospheric emissions, andsubstances needed for operations. Data represent an

average of European power plants (timeframe of data isnot listed)

The ecoinvent coal extraction processes considered a range of methane emissions (see Table 3-11). Theecoinvent methane emissions were compared to the average coal mining methane emissions providedin the coal studies compiled by Withaker et al. (2012).

This comparison typically highlights ecoinvent’s higher coal mining methane emissions (by a factorranging from 0.06 to 6.71), especially in China (factor of 6.71), Russia (factor of 3.58) and Europe (factor3.25). According to ecoinvent, these three countries have the largest proportion of underground mineswhich are known to emit more methane from mining operations than opencast. References supportingthe ecoinvent database coal mining methane emissions seem sound though outdated (early 1990).

Table 3-11 : Coal mining methane emissions

Coal sourcesSurfacemining

Undergroundmining

Methaneemissions

(kg CH4/kg coal)

Whitaker et al.average coal

mining methaneemissions

(kg CH4/kg coal)

Difference factorbetween ecoinventand Whitaker et al.

(ecoinvent/Whitaker)

Australian/Indonesian coal 68 % 32 % 0.0027

0.0025218

1.07

Chinese coal 0 % 100 % 0.0169 6.71

European coal 0 % 100 % 0.0082 3.25

Russian coal 33 % 67 % 0.0092 3.58

Colombian coal 100 % 0 % 0.00016 0.06

US coal 58 % 42 % 0.0030 1.19

South African coal 50 % 50 % 0.0035 1.39

18This value was calculated from Whithaker et al. (2012) 63 g CO2 eq./kg coal and methane IPCC 2007 GWP100

factor



3.6.9 Temporal and geographical boundaries

According to the functional unit, this LCA is representative of the world context in 2015. We, however,relied heavily on the ecoinvent processes whose underlying data were from the early and late 1990 aswell as early 2000 and therefore may not be representative of available technologies in 2015. We havenot discarded these data and increased the uncertainty related to temporal representativeness(considered in the Monte Carlo analysis). Lower quality data may be very appropriate in the case of aprocess whose contribution is minimal. On the contrary, representative data should be collected forprocesses having a great influence on the conclusions of the study.

It should be noted, however, that some processes within the system boundaries might take placeanywhere or anytime, as long as they are needed to achieve the functional unit. For example, theprocesses associated with the supply, and the waste management can take place anywhere in theworld. In addition, certain processes may generate emissions over a longer period of time than thereference year. This applies to landfilling, which causes emissions (biogas and leachate) over a period oftime whose length (several decades to over a century/millennium) depends on the design and operationparameters of the burial cells and how the emissions are modeled in the environment.

Table 3-12 : Temporal data quality criteria

Score Temporal coverage criteria

1 Process underlying data is recent (last 5 years) – data has the best temporal coverage

2 Process underlying data is somewhat recent (last 5 -10 years) – data has acceptable temporalcoverage

3 Process underlying data is somewhat old (last 10-20 years) – data is usable

4 Process underlying data is too old (> 20 years) – data is probably unreliable

3.6.10 GHG emission accounting

This study wishes to provide a total carbon footprint of the investigated natural gas and coal systems.

GHG emissions were assessed using, alternatively, the GWP100 and GWP20 provided by the IPCC reportsfrom 2001 (AR-3), 2007 (AR-4) and 2013 (AR-5). GWP offers a comprehensive synthesis of climatechange science to date and involved experts from more than 130 countries.

Main results were reported using the GWP100 of the 2007 (AR-4) IPCC report as most reporting data fromTOTAL and GHG emission estimates from the literature used these GWP factors.

In a sensitivity analysis, we also tested other time horizon and GWP from older and more recent IPCCreports. Therefore, we are sure that our conclusions will be robust since all possible GHG emissionsreporting options would have been covered.

Time horizon: Based on the Kyoto agreement and GHG protocol, a time horizon of 100 yearsshould be used. However, some (e.g. Howarth et al, 2011, Howarth et al, 2012, O’Sullivan et al,2012) advocate that a shorter time horizon should be used for high methane emitters. Indeed,methane has a shorter lifespan in the atmosphere than carbon dioxide and increasing the timehorizon artificially decreases the importance of methane emissions. For this reason, we alsoreported the results for a time horizon of 20 years.



Reporting year: we selected the IPCC 2007 (AR-4) for our main results because they were usedfor the literature GHG estimations; comparison between literature and life cycle modelingvalues should be coherent. However, we also considered the IPCC 2001 and IPCC 2013 GWPbecause some institutions still use either the oldest (e.g. the Canadian government) or thenewest reported GWP values.

3.6.11 Interpretation

This last phase of the LCA allows to discuss the results obtained from the life cycle GHG accounting andput them into perspective. Given the objective of the study and its target audience, the discussion of theresults is presented in simplified terms. The conclusions are nevertheless based on a complete and in-depth analysis of the inventory data and the LCIA. This includes, specifically:

• A data quality assessment and contribution analysis;

• A consistency and completeness analysis;

• Sensitivity and scenario analyses;

• Uncertainty analyses.

The methodology used for data analysis and interpretation is summarized in the following paragraphs.First, however, a clarification is provided concerning the inventory analysis.

Inventory analysis

Inventory results in terms of quantities of material and energy associated to each system under studyare not presented in the body of the report. Generally, a comprehensive analysis of inputs and outputsdoes not serve the understanding of issues involved. Indeed, inventory results usually convey muchinformation, which does not directly allow any conclusion to be drawn out. However, an inventoryanalysis is typically more effective when performed in parallel with impact assessment. Hence, thesubsequent GHG emission estimation is actually an interpretation of LCI results and of their significanceon the environmental damages, which is in agreement with ISO 14 044 standards. Also, the contributionanalysis allows identifying those inventory flows that cause most of the impact within each impactcategory.

Data quality analysis

The reliability of the results and conclusions of the life cycle modeling depend on the quality of thestudy’s inventory data. It is important to ensure that the information meets certain requirements thatare in line with the objectives of the study.

Though ISO does not propose a particular method, two criteria that impact inventory quality wereselected to assess the data:

• Reliability: Pertains to the data sources, acquisition methods, and verification methods. Reliabledata has been verified and measured in the field. The criterion chiefly refers to flowquantification.

• Representativeness: assesses the geographic and technological correlations. Does all of the datareflect reality? Data is representative when the technology is directly related to the field. Thiscriterion chiefly refers to the choice of processes used when modeling the system.

In parallel to the data quality assessment, an estimation of the processes contribution (i.e. to whatextent the process modeled with these data contributes to the overall impact of the system under



study) was performed. Lower quality data may be very appropriate in the case of a process whosecontribution is minimal. On the contrary, quality data should be collected for processes having a greatinfluence on the conclusions of the study.

An ideal situation would require the highest level of reliability (i.e. all primary data) andrepresentativeness (i.e. use of exact technology in the correct geographical context) for all contributingprocesses. Such a situation rarely arises in life cycle assessment. In this study, best available data wasused but as one of the study’s objective was to identify the gaps in knowledge for future studies,unreliable or unrepresentative data were accepted. Such data were flagged in the limitation orrecommendation section.

Table 3-13 : Reliability and representativeness data quality criteria

Score Reliability criteria

1 Data was measured or calculated on the field – this data meets the highest criteria of reliability

2 Data stems from assumptions based on some field measurements or calculations OR data stemsfrom the literature or from unverified documents provided by TOTAL. This data is deemed to be ofsufficient reliability.

3 Unverified data based on assumptions OR expert judgment. This data is deemed usable butshould/could be improved in terms of reliability.

4 Data grossly estimated. This data doesn’t meet the reliability criteria.

Score Representativeness criteria

1 On field data.- this data meets the highest criteria of representability

2 Good geographical/technological representativeness. – This data representativeness is deemedsufficient

3 Data represents the same process or materials but from a different technology – This data isdeemed usable but data should/could be improved.

4 Inadequate geographical and/or technological representability. The data is not easily accessible, useof a proxy – this data does not meet the representativeness criteria.

Consistency and completeness

Throughout the study, attention was paid to ensure that the systems were represented in a mannerconsistent with the definition of the objectives and the field of the study. In addition, during datacollection and modeling, the definition of the boundaries, the hypotheses, the methods and the datawere applied in a similar way to all the systems. There is consistency among the studied systems withregard to data sources, their precision and technological, temporal and geographic representativeness.

Completeness was ensured thanks to a careful definition of the analysed system boundaries. When datawere missing, a sensitivity analysis was carried out to verify the effect of the hypotheses andapproximations used.

Sensitivity and scenario analyses

Several parameters were used to model the systems; each of which presents a certain degree ofuncertainty, especially with regards to the generic data assumptions and modules and methodological



choices. The obtained results relate to these parameters and their uncertainty is transferred to theconclusions.

Sensitivity analyses were performed on the following parameters:

• Shale gas fugitive emissions variations;

• Additional natural gas fugitive emissions to equal the lowest coal GHG emissions

• Variations of natural gas and coal low heating values;

• The efficiency of the electricity production (for both gas-fired and coal-fired power plants);

• Capture of methane emissions during coal extraction;

• The GWP’s reference year (2013, 2007 and 2001) and time horizon (20 and 100 years);

• Allocation rules (energy, mass and economic)

All other parameter variability was also evaluated during the uncertainty.

To complement the assessment (for interpretation purposes) we also compared the investigated naturalgas and coal systems with the ecoinvent processes for:

• Russian natural gas sent to Europe;

• European lignite.

Uncertainty analysis: inventory data

An analysis of the uncertainty due to the variability of inventory data has been performed. TheSimaPro 8.0 software includes a module for Monte Carlo simulation, which allows assessing how thevariability embedded in inventory data spreads over final results. Hence, results become probabilistic.The analysis has been performed for 1 000 iteration steps.

Out of the thousands of individual elementary flows inventoried in the elementary processes of thescenarios studied, the very large majority were provided by the ecoinvent database. Most of these flowsexhibit a variability which takes the form of a lognormal distribution around the central value specified(and used in the deterministic calculations), characterised by its standard deviation. However, thesevariabilities were not determined statistically (by using real measurements) but were rather estimatedusing a pedigree matrix describing the quality of the data based on its source, method of collection andgeographic, temporal and technological representativeness (Weidema and Suhr Wesnæs, 1996).

In the same way, the variability of most of the data collected was represented by either a lognormaldistribution (for which the standard deviation was estimated using this same pedigree matrix) or by atriangular statistical distribution (bounded by minimum and maximum values as listed in the systems“included/excluded processes and assumptions” tables). In total, between 70 and 75% of the data had anassociated statistical distribution.

It should also be noted that each process probability distributions were considered independentlybetween systems. Consequently, systems common processes’ uncertainties are thus added instead ofbeing subtracted. Therefore, the uncertainty is conservative.



3.7 Critical Review

Because the results of this study are intended to be used to support a comparative assertion disclosedto the public and/or for communication of a carbon footprint project, a critical review had to beconducted by a panel of interested parties, i.e. a committee composed of an LCA expert and otherstakeholders.

The selected critical review committee was composed of the following members (Table 3-14: ).

Table 3-14: Members of the Critical Review Committee

Name Affiliation Implication/Expertise

Philippe Osset Solinnen President, LCA expert

Stéphane Amant Carbone 4 Carbon strategy expert

Bob Ineson IHS Energy expert

In accordance with 14040 and 14044 ISO standards (2006a, b), the goal of the critical review processwas to check if:

• the methods used by CIRAIG to carry out the LCA are:o consistent with the 14044 International Standards;o scientifically and technically valid;

• the data used are appropriate and reasonable in relation to the goal of the study;

• the interpretations of CIRAIG reflect the limitations identified and the goal of the study;

• the study report is transparent and consistent.



4 Results and discussion

This section presents the GHG emissions estimates from the literature (applied to the investigatedsystems), internal reporting data from TOTAL and our life cycle GHG assessment.

A detailed summary of the GHG emissions results is available in Table 4-7 and Table 4-8.

4.1 Comparison based on values from the literature

Figure 4-1 (numerical values are presented in Table 4-7) shows the results of applying the literature GHGemissions estimates to the different processes of the investigated systems. Literature GHG emissionestimates were previously shown in Table 2-3, Table 2-4, Table 2-6 and Table 2-5.

Results show that19:

• The combustion of natural gas (to produce electricity) is the major contributor to the GHGemissions of the natural gas systems;

• The differentiation of the natural gas systems may be explained by the upstream processes:o The North Sea offshore exploitation shows the lowest GHG emissions (410 g CO2

eq./kWh comparatively to the other natural systems (505 to 783 g CO2 eq./kWh) simplybecause it has less life cycle processes;

o The natural gas coming from Australian coalbed methane, Indonesian shallow offshoreand Yemen onshore show similar GHG emissions;

o Shale gas is the natural gas system showing the widest spread (473 to 710 g CO2eq./kWh) of GHG emissions. This is due to the lack of consensus, in past studies, toascertain the fugitive emissions from the shale gas upstream processes.

• For coal, the literature does not provide details regarding the exact occurrence of the GHGemissions. However, one could assume that the coal combustion is the major contributor toGHG emissions.

• Natural gas systems typically show lower (i.e. 410 to 756 g CO2 eq./kWh) GHG emissions thancoal (i.e. 731 to 1372 g CO2 eq./kWh). However, the upper limit of the GHG emission interval ofsome natural gas systems (e.g. Yemen onshore) may be equivalent or higher than the coalsystem lower limit.

However, this assessment should not be seen as a definitive conclusion on whether natural gassystems can be better or worse than coal. Indeed, such an approach has important limitations.

19The assessment excluded the Howarth et al. (2011) studies due to its controversies


Figure 4-1: Literature review values applied to the investigated sy

The previous comparison is interestingand indicates the variability of the practices and assumptions related to these systems. It can also beused to validate our life cycle modeling

However, as previously mentioned,on whether natural gas systems can beimportant limitations since they:

• Present the best and worse (minprobability of occurrence;

• Are not representative of TOTAL ‘s activitieso The GHG estimates for transmission also include the fugitive emissions from

distribution network whic

• Are based on different studies whichcoherent between themselves

o They may not all be based on the same IPCCto be coming from IPCC AR

Comparison with literature values and life cycle modeling results are presented in4-8.

20The assessment excluded the Howarth et al. (2011) studies due to its controversies.



Literature review values applied to the investigated sy

nteresting since it provides an indication of the most important processesthe variability of the practices and assumptions related to these systems. It can also be

modeling GHG assessment.

as previously mentioned, such an assessment should not be seen as a definitive conclusionon whether natural gas systems can be better or worse than coal. Indeed, such an approach has

best and worse (min-max) scenarios without any appreciation of the

representative of TOTAL ‘s activities;The GHG estimates for transmission also include the fugitive emissions fromdistribution network which is out of this study’s system boundaries;

Are based on different studies which rely on different assumptions and, in the end, may not bethemselves;

ay not all be based on the same IPCC100 methodology (even if most of thembe coming from IPCC AR-4 report).

Comparison with literature values and life cycle modeling results are presented in Table

The assessment excluded the Howarth et al. (2011) studies due to its controversies.

Page 69

Literature review values applied to the investigated systems20

since it provides an indication of the most important processesthe variability of the practices and assumptions related to these systems. It can also be

should not be seen as a definitive conclusion. Indeed, such an approach has

max) scenarios without any appreciation of the scenarios

The GHG estimates for transmission also include the fugitive emissions from the

on different assumptions and, in the end, may not be

methodology (even if most of them seem

Table 4-7 and Table



4.2 Comparison based on TOTAL reported data

Table 4-1 provides the GHG emissions as reported by TOTAL for the evaluated natural gas systems.

It should be noted that reporting data only accounts for direct emissions and GHG emissions from theuse of electricity consumption; they do not account for the entire life cycle of the natural gas systemsand are therefore not as complete, in terms of emission sources, as life cycle modeling.

However, reporting values best represent TOTAL’s practices and, therefore, could be seen as aminimal threshold of emissions.

It can be observed that:

• GHG emissions only cover the natural gas systems; no coal reporting data were provided;

• Some processes reporting data were not provided by TOTAL (i.e. N/D in Table 4-1);

• Scope 3 emissions were not part of the reporting data;

• Reported values, even if they do not cover the life cycle of the natural gas, are relatively close tothe reported values from the literature. Direct emissions and electricity consumption (Scope 1-2emissions) can thus be considered as major contributors to the investigated systems.

• Liquefaction showed the highest GHG emissions followed by either transoceanic transport ornatural gas extraction.

Comparison with literature values and life cycle modeling results are presented in Table 4-7 and Table4-8.



Table 4-1 : Natural gas systems GHG emissions (based on IPCC’s 2007 GWP100) summary.All values are provided in g CO2 eq./kWh electricity

Processes US shaleNorth Sea

offshore gasAustralian CBM

Indonesian shallowoffshore

(South sectorMahakam)

Yemen onshore Comment

Exploration/extraction25.3

(8.2-48.5)12.0

(3.1-17.9)N/D

2.7(0.2-4.7)

N/D

TOTAL provided thedata from internal

reports. However, itis difficult to

appreciate howmuch of the

processes havebeen

included/excludedin these reports.

Processing N/D N/D N/D N/D N/D

No processing datawas provided byTOTAL; only the

natural gascomposition whichwas used in the life

cycle modeling

Transmission0.007

(0.005-0.011)

N/A

0.007(0.005-0.012)

0.001(0.001-0.002)

0.001(0.001-0.002)

Data from aMarcogaz (2016)

study. Fugitiveemissions only.

(for either 500 kmor 100 km)

Liquefaction 23.735.2

(2.3-72.7)65.1

(48.8-80.7)40.9

(40.7-218.5)

Data provided byTOTAL for 2014,

brackets includeshistorical data from

2008, 2009 and2012 to 2014

LNG transport 18.7 16.4 9.6 24.2

Based on the valueof 0.0118 kg CO2

eq./t.km based onTOTAL reporting(verified). Used

distances were thesame as for the life

cycle modelingscenarios

Regasification:

Technology: withSubmergedCombustion

Vaporizers (SCV), withgas self-consumption

6.7 7.4 7.3 7.35

Direct emissions.Data, from 2014

was provided per kgCO2 eq/MJ HHV

(38.8 MJ/m3). Weconverted theresults to LHV

Electricityconsumption was

provided by TOTAL(2014)


Regasification:

Technology: withOpen Rack Vaporizers

(ORV), no gas self-consumption

1.2(0.3-1.7)

Storage N/D

Transmission (fugitiveemissions only)

0.0014(0.001-0.002) (0.005

Figure 4-2 illustrates the relative contribution of the reported values from the previous table. The figureshould not be used to compare the different natural gas systems together as several life cycle processeare missing. Indeed, combustion and processing are not considered for all investigated systems whileextraction is lacking for the Australianat best, as a visualisation tool.

Figure 4-2: Relative contribution of



1.3(0.4-1.8)

1.3(0.4-1.8)

N/D N/D

0.007(0.005-0.01)

0.0015(0.001-0.003)

0.001(0.001-0.002)

illustrates the relative contribution of the reported values from the previous table. The figureshould not be used to compare the different natural gas systems together as several life cycle processeare missing. Indeed, combustion and processing are not considered for all investigated systems while

the Australian CBM and Yemen onshore natural gas. The figure should be seen,

: Relative contribution of reported GHG emissions

June 2016

1.3(0.4-1.8)

Direct emissions.Data from 2014 was

provided per kgCO2 eq/MJ HHV

(38.8 MJ/m3). Weconverted theresults to LHV

Electricityconsumption was

provided by TOTAL(2014)

N/D

Calculations in thelife cycle modelswere based on

TOTAL’s data from2014. However, no

GHG reportingvalues were

provided.

0.001(0.001-0.002)

Data from theMarcogaz (2016)

study. Fugitiveemissions only.

illustrates the relative contribution of the reported values from the previous table. The figureshould not be used to compare the different natural gas systems together as several life cycle processesare missing. Indeed, combustion and processing are not considered for all investigated systems while

onshore natural gas. The figure should be seen,

reported GHG emissions



4.3 Life cycle GHG emissions modeling

4.3.1 Evaluation based on IPCC 2007’s GWP100

Figure 4-3 shows the GHG emissions (average values; the range related to variability is presented inanother section) of the natural gas and coal systems. It also shows the contribution of each life cyclestep to the overall GHG emissions according to the GWP100 as reported by the IPCC in 2007 (AR-4).

These results show that:

• Natural gas systems present systematically lower GHG emissions (452-711 g CO2 eq./kWh)than coal systems (968 to 1476 g CO2 eq./kWh);

• Natural gas systems:o Most of the GHG emissions from natural gas systems stem from natural gas

combustion. An important parameter of the combustion is the efficiency and lowheating value. Both will be evaluated with a sensitivity analysis;

o The upstream processes do not significantly contribute to the GHG emissionscomparatively to combustion; Amongst the upstream processes for the natural gas systems, the liquefaction

process seems to be the most important contributor followed by both theprocessing and the exploration/extraction of the natural gas;

Fugitive emissions during the upstream processes do not seem tocounterbalance or exceed the GHG emissions from coal systems combustion.

o The North Sea offshore natural gas system shows the least GHG emissions (452 g CO2eq./kWh) while the Australian CBM showed the highest GHG emissions (710.8 g CO2eq./kWh): The absence of liquefaction, transoceanic transport, and regasification

processes mainly explains the lower GHG emissions for the North Sea naturalgas system.

The CBM extraction is responsible for the discrepancies between natural gassystems. More than 75 % of the GHG emissions of this process stems from thecombustion (2.5 kTCO2 eq./PJ of natural gas) and fugitive emissions of coal seamgas. The latter is reported as extremely variable ranging from 3.4 to 16 kTCO2eq./PJ of natural gas (12 to 57 g CO2eq./kWh of natural gas). In our assessment,we considered the average value of this interval: 9.7 kTCO2 eq./PJ of natural gas(35 g CO2eq./kWh of natural gas). Therefore, the fugitive emissions (includingflaring CO2 emissions) of Australian CBM, only, were equal to the entireupstream process emissions reported for other natural gas systems (seeFigure 2-2).

• Hard coal systems:o Most of the GHG emissions from coal systems stem from coal combustion. An

important parameter of the combustion is the efficiency and low heating value. Bothwill be evaluated with a sensitivity analysis;

o The upstream processes do not contribute significantly to the GHG emissions whencompared to combustion; The observed difference in the coal extraction process stems from the

registered regional difference associated with the coal mining methane. Aspreviously reported (see Table 3-11), reported coal mining emissions are, in theworst case (i.e. China) nearly 7 times the average usually reported in theliterature. Therefore, methane capture or flaring could decrease significantly


the GHG emissions from the coal extraction. The latter is the subject of asensitivity analysis

Figure 4-3: Life cycle GHG emissions of the investigated systemsecoinvent and some data

transmission fugitive emissions)

Comparison with literature values and life cycle modeling results are presented in4-8.

4.3.2 Inventory contribution to the natural gas and coal systems

Figure 4-4 shows the emitted GHG’sinvestigated systems.

As shown:

• Carbon dioxide (CO2) emissions account for more than 90investigated systems; an unsurprising conclusion considering that cgas is the main contributors to GHG emissions

• The remainder of the GHG emissions can be traced to methane (CHother GHGs.

o Methane (CH4) typically accnatural gas systems and(detailed values are provided in Appendix) Methane emissions

the extraction process. Natural gas systems may also emit fugitive emissionsduring the natural gas processing and the transmission



the GHG emissions from the coal extraction. The latter is the subject of asensitivity analysis.

GHG emissions of the investigated systems based on data fromand some data (i.e. power plant efficiency, gas composition, EUR and

transmission fugitive emissions) from TOTAL (IPCC 2007, GWP

literature values and life cycle modeling results are presented in Table

Inventory contribution to the natural gas and coal systems

emitted GHG’s contribution to the overall GHG assessment

) emissions account for more than 90 % of the GHG emissions of thems; an unsurprising conclusion considering that combustion of coal or natural

main contributors to GHG emissions;

The remainder of the GHG emissions can be traced to methane (CH4), nitrous oxide (N

typically accounts for 1 to 3% of the life cycle GHG emissions for thenatural gas systems and 5 to 10 % of the life cycle GHG emissions of the coal system(detailed values are provided in Appendix).

Methane emissions from both coal and natural gas systems mostlythe extraction process. Natural gas systems may also emit fugitive emissionsduring the natural gas processing and the transmission. Even so, methane

June 2016

the GHG emissions from the coal extraction. The latter is the subject of a

based on data fromefficiency, gas composition, EUR and

(IPCC 2007, GWP100)

Table 4-7 and Table

to the overall GHG assessment for each of the

% of the GHG emissions of thestion of coal or natural

nitrous oxide (N2O) and

1 to 3% of the life cycle GHG emissions for theof the coal system

both coal and natural gas systems mostly stem fromthe extraction process. Natural gas systems may also emit fugitive emissions

Even so, methane


emissions, from coaloverall GHG emissio

o Nitrous oxide (N2O) and other GHGs contribute only marginally to the overall GHGemissions.

Figure 4-4: Contribution of the specific GHG to the overall natural



emissions, from coal mining, may have a higher contribution (0.5 to 15overall GHG emissions than for natural gas system (1 to 3.5 %).

O) and other GHGs contribute only marginally to the overall GHG

Contribution of the specific GHG to the overall natural gas and coal GHGassessment (IPCC 2007, GWP100)

Page 75

may have a higher contribution (0.5 to 15 %) to the.

O) and other GHGs contribute only marginally to the overall GHG

gas and coal GHG


Figure 4-5 provides the upstream process GHGgate). Results show:

• CO2 emissions are still the most importancoal systems:

o Natural gas systems COexample, prior to liquefaction, methane emissions from shale gas were the GHGemissions’ main contributorthe inclusion of the liquefaction process modified significantly the GHG contribution.TOTAL annual reporting data corroborated that more COthan methane during the liquefdifference of more than a factor 1000 between CO

o Coal mining methane is an important contributor for theespecially in China,proportion of underground mines

Figure 4-5: Contribution of the specific GHG to the upstream (all processes except at thepower plant) natural gas and coal GHG assessment (IPCC 2007, GWP



upstream process GHG contribution (i.e. from extraction to the power plant

emissions are still the most important contributor to the natural gas system

Natural gas systems CO2 emissions mostly stem from the liquefaction process. Forexample, prior to liquefaction, methane emissions from shale gas were the GHGemissions’ main contributor accounting for nearly 55 % of the GHG emissions. However,

of the liquefaction process modified significantly the GHG contribution.TOTAL annual reporting data corroborated that more CO2 emissions were generated

during the liquefaction process. Annual reporting data showed adifference of more than a factor 1000 between CO2 and CH4 emissions;

methane is an important contributor for the upstream coal systemsespecially in China, Europe, and Russia who, according to ecoinventproportion of underground mines (see Table 3-11).

Contribution of the specific GHG to the upstream (all processes except at theural gas and coal GHG assessment (IPCC 2007, GWP

June 2016

(i.e. from extraction to the power plant

the natural gas system and most of the

from the liquefaction process. Forexample, prior to liquefaction, methane emissions from shale gas were the GHG

% of the GHG emissions. However,of the liquefaction process modified significantly the GHG contribution.

emissions were generatednnual reporting data showed a

emissions;upstream coal systems

invent, have a higher

Contribution of the specific GHG to the upstream (all processes except at theural gas and coal GHG assessment (IPCC 2007, GWP100)



4.3.3 Sensitivity analysis

Shale gas fugitive emissions

Estimation of the fugitive emissions related to US shale gas has sparked a lot of controversy regardingthe environmental benefits of shale gas (see Figure 2-5). Even though past studies typically agree on thefugitive emissions in absolute values, they generally disagree when reporting fugitive losses according toEUR. Indeed, on a relative baseline, with well/site production being extremely variable, several studieshave published methane losses21 ranging from 0.5 % to 10 % of a well/site gas production.

Therefore, we investigated different production rates and fugitive emissions coming from averagepractices in the US. The following table details the different scenarios. Average and low emissionsfugitive emission scenarios were taken from the values presented in Table 2-2 (average and minimumcolumns). The maximum scenario was crafted to represent those studies stating that fugitive emissionscan reach as high as 10-12 % of the EUR. These scenarios were scaled, from the average scenario, tomeet the relative fugitive emissions. All other parameters were left just as described in Table 3-5.

21Includes all intentional and unintentional emissions of methane



Table 4-2 : Shale gas fugitive emissions scenarios

Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Scenario 6 Scenario 7 Scenario 8 Scenario 9

EUR (Mm3) Base case Base case Base case 25 25 25 250 250 250

Number of wells per site 3.74

Fugitive emissions per site

Average Low High Average Low High Average Low High

Exploration 1.36 × 103 2.33 × 102 8.68 × 104 6.13 × 103 1.05 × 103 8.20 × 104 5.98 × 103 1.02 × 102 8.75 × 104

Exploitation 6.17 × 105 1.06 × 105 3.93 × 107 6.12 × 105 1.05 × 105 8.20 × 106 6.18 × 105 1.06 × 105 9.04 × 107

Fugitive emission related to flaringduring exploration and

exploitation2.49× 106 2.49× 106 2.49× 106 9.02× 105 9.02× 105 9.02× 105 5.11× 106 5.11× 106 5.11× 106

Production 6.12 × 105 2.45 × 105 9.38× 105 1.35 × 105 5.41 × 104 2.07× 105 1.40 × 106 5.59 × 105 2.14× 105

Transmission 5.26 × 105 5.26 × 105 5.26 × 105 5.26 × 105 5.26 × 105 5.26 × 105 5.26 × 105 5.26 × 105 5.26 × 105

Sum 4.25 × 106 3.37 × 106 4.33 × 107 2.18 × 106 1.59 × 106 4.33 × 107 7.65 × 106 6.30 × 106 9.83 × 107


As shown, there is a maximum difference of 450 g CO8 (i.e. minimum).

Considering that the combustion of the shale gas accounts for 408 g CO2 eq/kWh, and remains constantbetween the scenarios, it could be concluded that this particular phase is stillcontributor to the GHG emissions in most average (i.e. scenarios 1, 4 and 7) and miniscenarios 2, 5 and 8). Fugitive emissions are mscenarios 3, 6 and 9).

Figure 4-6: Shale gas fugitive emissions variations



ere is a maximum difference of 450 g CO2 eq./kWh between scenarios 6 (i.e. maximum) and

of the shale gas accounts for 408 g CO2 eq/kWh, and remains constantbetween the scenarios, it could be concluded that this particular phase is still a (if

in most average (i.e. scenarios 1, 4 and 7) and minimum scenarios (i.e.Fugitive emissions are major contributors for the maximum scenarios (i.e.

Shale gas fugitive emissions variations (IPCC 2007’s GWP

June 2016

eq./kWh between scenarios 6 (i.e. maximum) and

of the shale gas accounts for 408 g CO2 eq/kWh, and remains constanta (if not the) major

mum scenarios (i.e.aximum scenarios (i.e.

GWP100)


Figure 4-7 illustrates the importancefigure shows that the shale gas can be equivalent to coal when

• Shale gas fugitive emissions equallowest GHG emission reported

• Shale gas fugitive emissions equal 11.1average GHG emission value found in the literature (i.e.

• Shale gas fugitive emissions equal 19.highest GHG emission value found in the literature (i.e.

Figure 4-7: Importance of the shale gas fugitive emissions (IPCC 2007’s GWP



illustrates the importance of an increase in GHG emissions due to the fugitive emissions.igure shows that the shale gas can be equivalent to coal when:

fugitive emissions equal 4.3 % of a site production if coal GHG emissionsGHG emission reported value found in the literature (i.e. 731 g CO2 eq.)

Shale gas fugitive emissions equal 11.1 % of a site production if coal GHG emissionsvalue found in the literature (i.e. 1026 g CO2 eq.);

Shale gas fugitive emissions equal 19.0 % of a site production if coal GHG emissionsvalue found in the literature (i.e. 1372 g CO2 eq.).

Importance of the shale gas fugitive emissions (IPCC 2007’s GWP

June 2016

to the fugitive emissions. The

if coal GHG emissions equal the;

% of a site production if coal GHG emissions equal the

% of a site production if coal GHG emissions equal the

Importance of the shale gas fugitive emissions (IPCC 2007’s GWP100)


Figure 4-8: Influence of shale gas fugitive emission rate (IPCC 2007’s GWP



Influence of shale gas fugitive emission rate (IPCC 2007’s GWP

June 2016

Influence of shale gas fugitive emission rate (IPCC 2007’s GWP100)



Fugitive emissions equivalency

Table 4-3 evaluates the increased losses of natural gas to the atmosphere during the entire natural gaslife cycle to reach the same level of GHG emission as the European hard coal. The assessment is limitedto the main scenarios. The results should be interpreted as such: for example, for each m3 of Utica shalegas used to produce 1 kWh of electricity under the main scenario, an additional 0.2001 m3 of methaneneeds to be emitted to the atmosphere during its life cycle to equal the European hard coal GHGemissions.

As seen, significant additional fugitive emissions would be required to achieve an equivalency with thecoal system.

Table 4-3 : Increased natural gas losses to the atmosphere to find equivalency with thelowest coal system GHG emissions

Natural gassystems GHG

emissions(GWP100,

IPCC2007, AR-4)[g CO2 eq/kWh]

European hardcoal GHGemissions(GWP100,

IPCC2007, AR-4)[g CO2 eq/kWh]

Additional methaneemission to reach

equivalency(GWP100, IPCC2007, AR-4)

[g CH4/kWh]

Increased natural gas losses tothe atmosphere to reach

equivalency

Utica shale gas 585.0

1018.4

17.3 20.01%

Offshore NorthSea

451.622.7 26.17%

Australian CBM 710.8 12.3 14.20%

Indonesia shallowoffshore

597.116.9 19.45%

Yemen onshore 627.0 15.7 18.07%

Fugitive emissions during underground storage were set at 0 kg/yr following TOTAL’s experts’assumptions. However, the IPCC22 reported methane emissions in the order of 0.84 g CH4/m3 natural gasstored. Such fugitive emissions would increase the Utica shale gas and offshore North Sea GHGemissions by 0.78 g CO2 eq/kWh while Australian CBM, Indonesian shallow offshore and Yemenonshore would increase by 1.18 g CO2 eq./kWh; all in all these values are inconsequential on the overallconclusions of this study.

22http://www.ipcc-nggip.iges.or.jp/public/gp/bgp/2_6_Fugitive_Emissions_from_Oil_and_Natural_Gas.pdf



Natural gas processing allocation rules

The main scenario considered an energy allocation rule for the processing step which provides bothnatural gas and natural gas liquids (NGL). This section wishes to ascertain the consequences ofmodifying the allocation rules on the overall conclusions. Table 4-4 and Table 4-5 provides theconsidered information necessary for a change of allocation rule.

Table 4-4 : Natural gas liquids properties.

Energy content[MJ/kg]

Economic value[$/gal]

References

Methane 55.45 2.09 (Engineering toolbox, 2016)

Ethane 51.70 0.13 (Engineering toolbox, 2016)

Propane 50.22 0.43 (Engineering toolbox, 2016)

Butane 50.40 0.52 (Engineering toolbox, 2016)

Pentane 48.7 0.72 (Engineering toolbox, 2016)

Hexane 47.8 0.92 (Engineering toolbox, 2016)

Heptane 49.0 0.92 (Engineering toolbox, 2016)

Table 4-5 : Natural gas liquids according to allocation rules.

% of natural gas liquids(energy allocation)

% of natural gas liquids(mass allocation)

% of natural gas liquids(economic allocation)

Utica shale gas 24.76 26.30 17.07

Offshore North Sea 13.83 14.83 8.64

Australian CBM 0.20 0.22 0.12

Indonesia shallow offshore 12.79 12.64 7.19

Yemen onshore 14.33 14.15 8.55

Figure 4-9 provides the variation of the overall GHG emissions when considering a different type ofallocation rule for the natural gas processing step. As seen, the allocation rule change does notsignificantly (< 1%) affect the overall GHG emissions estimates. This situation arises from the fact thatthe percentage of natural gas liquids doesn’t significantly change according to the different allocationrules. Considering the latter and the fact that processing was not shown as a major GHG contributor,variations of the overall GHG emissions were expected to be relatively small.


Figure 4-9: Natural gas processing allocation rules consequences on the overall GHG



gas processing allocation rules consequences on the overall GHGemission estimations

June 2016

gas processing allocation rules consequences on the overall GHG


Importance of low heating value

We have assumed a low heating value of 37 MJ/mtransmission/distribution network natural gas composition.vary, so can the low heating value. Fromvalue may vary between 36 and 38market analysis) regarding the steam coal LHV which ranged from 19 to 26 MJ/kg.

Figure 4-10 shows the variations of the different natural gas and coal systems

• The natural gas systems still show lower GHG emissions than coal systemsAustralian CBM highest GHG estimate (low LHV) and Columbian hard coal lowest GHG emission(high LHV) show a near overlap.

o For natural gas systems,either a low heating value of 36is less than 40 g CO

o For coal systems,between the considered LHV.

Figure 4-10: Importance of low heating values for natural gas

23Boxplot limits represent the min-max values while the horizontal bar represents the value of the main (i.e.

average) scenario.



e assumed a low heating value of 37 MJ/m3 for the natural gas systems based on thetransmission/distribution network natural gas composition. However, as natural gasvary, so can the low heating value. From TOTAL’s provided data, we have observed that the low heating

alue may vary between 36 and 38 MJ/m3. TOTAL provided the data (from IEA, EURACOALmarket analysis) regarding the steam coal LHV which ranged from 19 to 26 MJ/kg.

e variations of the different natural gas and coal systems for different

The natural gas systems still show lower GHG emissions than coal systemsAustralian CBM highest GHG estimate (low LHV) and Columbian hard coal lowest GHG emission

h LHV) show a near overlap.For natural gas systems, the variations are relatively unimportant when consideringeither a low heating value of 36 or 38 MJ/m3. Indeed, the observed maximum variation

CO2 eq./kWh.For coal systems, variations are important ranging from 300 to 460 gbetween the considered LHV.

Importance of low heating values for natural gas (IPCC 2007’s GWP

max values while the horizontal bar represents the value of the main (i.e.

June 2016

for the natural gas systems based on the USnatural gas composition may

observed that the low heatingEURACOAL, and internal

for different LHV.

The natural gas systems still show lower GHG emissions than coal systems. However,Australian CBM highest GHG estimate (low LHV) and Columbian hard coal lowest GHG emission

the variations are relatively unimportant when consideringthe observed maximum variation

ns are important ranging from 300 to 460 g CO2 eq./kWh

(IPCC 2007’s GWP100)23

max values while the horizontal bar represents the value of the main (i.e.


Importance of the combustion efficie

Figure 4-3 showed that the combustion of natural gas and coal is, by far,to emissions of GHG. This particular process is heavily dependent on theand, therefore, its efficiency. Consequentlyemissions. It should be noted that variation of efficiency for coaland 43 % while efficiency is most lithese variations to incorporate most recentfired (60%) power plants.

As shown:

• The electricity production efficiencyespecially for coal systems.

o The natural gas systems varied between 395 to 791 g CO2 eq./kWh; a difference of396 g CO2 eq./kWh;

o The coal systems varied between 849 and 1859 g CO2 eq./kWh; a difference of1010 g CO2 eq./kWh;

• If natural gas-fired plant efficiency is higher thansystems can be found;

• For the most likely efficiencies (41that efficiency alone, could notand natural gas systems,

• Equivalency between natural gas and coal systems could occur if coalaround 46% and natural gas

Figure 4-11: Consequences oplant on the GHG emissions estimates (IPCC 2007’s GWP



combustion efficiency

he combustion of natural gas and coal is, by far, the most important contributorto emissions of GHG. This particular process is heavily dependent on the electricity production process

ts efficiency. Consequently, we highlighted, in Figure 4-11, its importance onIt should be noted that variation of efficiency for coal-fired plants is most likely between 27

% while efficiency is most likely between 41 and 56 % for natural gas-fired plantsthese variations to incorporate most recent available technologies for coal-fired (46%) and natural gas

efficiency may have severe consequences in terms of GHGespecially for coal systems.

The natural gas systems varied between 395 to 791 g CO2 eq./kWh; a difference ofg CO2 eq./kWh;

The coal systems varied between 849 and 1859 g CO2 eq./kWh; a difference ofCO2 eq./kWh;

efficiency is higher than for coal-fired plant, no equivalency between

For the most likely efficiencies (41-56 % for natural gas and 27 to 43 % for coal)d not generate an overlap between the GHG emissions from coal

Equivalency between natural gas and coal systems could occur if coal-fired plant% and natural gas-fired plant efficiency around 40 %.

Consequences of varying the electricity production efficiency at the poweron the GHG emissions estimates (IPCC 2007’s GWP100

June 2016

the most important contributorelectricity production process

importance on the GHGis most likely between 27fired plants. We extended

%) and natural gas-

severe consequences in terms of GHG emissions,

The natural gas systems varied between 395 to 791 g CO2 eq./kWh; a difference of

The coal systems varied between 849 and 1859 g CO2 eq./kWh; a difference of

, no equivalency between

% for coal) it would seemthe GHG emissions from coal

fired plant efficiency is

varying the electricity production efficiency at the power

100)


Capture of methane emissions during coal extraction

The coal mining methane emissions were assumed, byatmosphere. However, what if partinstead of being emitted?

This sensitivity analysis wishes to ascertainpertaining the methane emissions during coal extraction.possible to completely capture the methane emissions during the coal extraction.

In such circumstances, we can observe a decrease of the coal systems GHG emissions:

• Eastern European coal: from 1018 to

• Columbian coal: from 968 to

• US coal: from 991 to 961 g CO2 eq./kWh electricity

• South African coal: from 1135

• Russian coal: from 1047 to 958

• Indonesian coal: from 1116 to 1083

• Australian coal: from 1139 to

• Chinese coal: from 1476 to 1

However, even under this best-casesystems (937 to 1273 g CO2 eq./kWh)eq./kWh) (see Figure 4-12).

Figure 4-12: Consequences of



apture of methane emissions during coal extraction

methane emissions were assumed, by ecoinvent, to be totally emitted to theosphere. However, what if part or the entirety of methane emissions were either captured or flared

This sensitivity analysis wishes to ascertain the consequences of possibly changing onsite practicespertaining the methane emissions during coal extraction. This best case scenario postulates that it ispossible to completely capture the methane emissions during the coal extraction.

we can observe a decrease of the coal systems GHG emissions:

Eastern European coal: from 1018 to 937 g CO2 eq./kWh electricity

to 966 g CO2 eq./kWh electricity

g CO2 eq./kWh electricity

1135 to 1096 g CO2 eq./kWh electricity

958 g CO2 eq./kWh electricity

donesian coal: from 1116 to 1083 g CO2 eq./kWh electricity



case scenario, the results still show higher GHG emissionsg CO2 eq./kWh) comparatively to average natural gas systems (4

Consequences of methane capture during coal extractionGWP100)

June 2016

, to be totally emitted to theemissions were either captured or flared

the consequences of possibly changing onsite practicesscenario postulates that it is

GHG emissions for the coal(452 to 711 g CO2

(IPCC 2007’s


IPCC report year and time horizon

Figure 4-13 shows the variability of the different systems in terms of used GWP for different reportedyears (2001, 2007 and 2013 corresponding to IPCC Assessment Report publications(20 and 100 years).

The results suggest that:

• GWPs (year or time horizon)comparisons: natural gas systems, on average, emits less G

o High GHG emissions estimates stem from(i.e IPCC 2013);

o Lowest GHG emissions estimates stem from(i.e IPCC 2001);

• Differences between the time horizon GHG estimatesemissions being constant whichever the used time horizon;

o As seen in Figure 4during their coal mining operationsusing different time horizons;

Figure 4-13: Consequences of varying the GWP’s time horizon and reported values

24Grey boxplot illustrates the variation for a 20 years time horizon; white boxplot, the 100 years ti

Boxplot limits represent the minimumgiven time horizon. Horizontal bar inside the boxplot illustrates



variability of the different systems in terms of used GWP for different reportedcorresponding to IPCC Assessment Report publications) and time horizons

(year or time horizon) variations do not affect the main conclusion of the previouscomparisons: natural gas systems, on average, emits less GHG emissions than coal systems;

High GHG emissions estimates stem from a 20 years time horizon and newest factors

GHG emissions estimates stem from a 100 years time horizon and oldest factors

Differences between the time horizon GHG estimates only stem from methane emissions; COemissions being constant whichever the used time horizon;

4-4, coal systems emitted more methane than natural gas systemduring their coal mining operations and, therefore, showed greater variability whenusing different time horizons;

Consequences of varying the GWP’s time horizon and reported valuesGHG emissions estimates.24

Grey boxplot illustrates the variation for a 20 years time horizon; white boxplot, the 100 years ti(i.e. 2001) and maximum (i.e. 2013) values for the different reports at the

Horizontal bar inside the boxplot illustrates the main scenario with IPCC 2007 values.

June 2016

variability of the different systems in terms of used GWP for different reported) and time horizons

do not affect the main conclusion of the previousHG emissions than coal systems;

and newest factors

100 years time horizon and oldest factors

stem from methane emissions; CO2

, coal systems emitted more methane than natural gas systemsshowed greater variability when

Consequences of varying the GWP’s time horizon and reported values on the

Grey boxplot illustrates the variation for a 20 years time horizon; white boxplot, the 100 years time horizon.values for the different reports at the

IPCC 2007 values.


4.3.4 Complementary assessments

Russian natural gas

Figure 4-14 compares the GHG emissions of the inprocess (no changes to the process were made)and its subsequent pipeline transport and combustion in a European power plant (eff

As shown:

• the GHG emissions from the Russian natural gasmodeled natural gas systems

• The Russian natural gas chainliquefaction, LNG shippingneeds for compression are high. TheRussian natural gas system GHG emissions stem from the Russian tranvery high figure may be accounted for by reportedly outdated,downgraded networks with fugitive methane emissions.

Figure 4-14: Comparison of natural



Complementary assessments

compares the GHG emissions of the investigated natural gas systems with the(no changes to the process were made). The latter includes the Russian natural gas extraction,

its subsequent pipeline transport and combustion in a European power plant (eff. 49.7%).

the GHG emissions from the Russian natural gas is not significantly differensystems (with the exception of the North Sea);

chain, even if it does not contain any process specific to LNGand regasification) has a longer transmission network, meaning the

needs for compression are high. The ecoinvent process estimates that nearly 20% of the overallRussian natural gas system GHG emissions stem from the Russian transmission network; thisvery high figure may be accounted for by reportedly outdated, low-efficiencydowngraded networks with fugitive methane emissions.

Comparison of natural gas systems with conventional natural gas from Russia(IPCC 2007’s GWP100)

June 2016

vestigated natural gas systems with the ecoinventRussian natural gas extraction,

49.7%).

different from the other

specific to LNG (i.e.has a longer transmission network, meaning theprocess estimates that nearly 20% of the overall

smission network; thiscompressors, and

gas systems with conventional natural gas from Russia



Sensitivity analysis: lignite instead of hard coal

Figure 4-15 compares the GHG emissions of European lignite with the other investigated natural gas andcoal systems.

As shown:

• the GHG emissions from the ecoinvent European lignite burnt in German power plants are notsignificantly different from other coal systems apart from the Chinese coal system whichshowed higher coal mining methane than other coal systems (see Table 3-11).

o This could seem surprising considering the lignite’s lower (low) heating valuecomparatively to hard coal: 8.7 MJ/kg comparatively to 24 MJ/kg for lignite and hardcoal, respectively. However, even if more lignite is required to produce the sameamount of energy, GHG emissions, related to combustion, are relatively similar in termsof GHG, according to the ecoinvent process. Therefore, lignite emits less GHG per kg.Indeed, lignite has not matured enough and its carbon content is lesser than hard coal(approximately 30-35 % for lignite comparatively to 80-85 % for hard coal).

o Therefore, coal and lignite are almost exclusively differentiated by their extractionprocess. One of the most significant difference in the ecoinvent process is related to themethane emission which has been evaluated, by ecoinvent, as 0.00023 kg CH4/kg lignite;an order of magnitude lower than evaluated for the European hard coal. Suchdifferences may be explained by the fact that European lignite mostly stems fromsurface mining instead of underground mining.

Figure 4-15: GHG emissions from lignite production in Europe comparatively to the othercoal systems (IPCC 2007’s GWP100)

0

200

400

600

800

1000

1200

1400

1600

Lignite

Germany

Hard coal

Europe

Hard coal

Colombia

Hard coal US Hard coal

Russia

Hard coal

Indonesia

Hard coal

South Africa

Hard coal

Australia

Hard coal

China

g CO2 eq/kWh electricity

Electricity production Shipping Land transportation Extraction


4.3.5 Life cycle inventory uncertainty:

Figure 4-16 shows the results of the Monte Carlo analysis

As seen:

• At a 95 % confidence level:o the North Sea offshore natural gas, Indonesian shallow offshore and Yemen onshore gas

emit fewer GHG emissions thano the Utica shale gas

coal; Overlap may typically occur over Overlap occur

favorable scenarios for the Lowering the confidence level, to 90%,

the investigated natura

Figure 4-16: Monte Carlo analysis

While a possible overlap was shown, it seems relatively unlikely that it occurs.can say that 90 % of the time shale gas will not overlap Colsensitivity analysis, fugitive emissions

25Reminder: A Monte Carlo simulation evaluates the variability embedded in life cycle inventory data over final results. Hence,

results become probabilistic. The analysis has been performed for 1

26Boxplot limits represent the 2.5 % and 97.5

(i.e. average) scenario.



Life cycle inventory uncertainty: Monte Carlo simulation results

shows the results of the Monte Carlo analysis25 of each of the systems.

level:offshore natural gas, Indonesian shallow offshore and Yemen onshore gas

GHG emissions than other natural gas systems;the Utica shale gas may generate GHG emissions which may overlap the Col

Overlap may typically occur over a range of 17 g CO2 eq./kWh;occurs for the shale gas most unfavorable scenarios and with

scenarios for the Colombian hard coal;Lowering the confidence level, to 90%, removes any possible overlap betweenthe investigated natural gas and coal systems.

Monte Carlo analysis results using the IPCC’s 2007 GWP100: 95interval26

While a possible overlap was shown, it seems relatively unlikely that it occurs. From our% of the time shale gas will not overlap Colombian coal. As seen from our

fugitive emissions estimate is the main parameter driving an increase in GHG

evaluates the variability embedded in life cycle inventory data over final results. Hence,

results become probabilistic. The analysis has been performed for 1 000 iteration steps.

% and 97.5 % confidence interval while the horizontal bar represents the value of the main

June 2016

offshore natural gas, Indonesian shallow offshore and Yemen onshore gas

overlap the Colombian hard

and with the most

removes any possible overlap between

: 95 % confidence

From our assessment, wembian coal. As seen from our shale gas

estimate is the main parameter driving an increase in GHG

evaluates the variability embedded in life cycle inventory data over final results. Hence,

erval while the horizontal bar represents the value of the main



emissions. Considering the obtained regression (see Figure 4-7), equivalency with the lowest MonteCarlo simulated value for Colombian coal (i.e. 867.0 g CO2 eq./kWh) would only be reached if fugitiveemissions were equivalent to approximately 7 % (of the EUR); a figure which has only been reachedwhen evaluating fugitive emissions with a top-down approach. Considering this fact, reconciliationbetween top-down and bottom-up approaches seem paramount to establish if it would be possible toobtain an overlap between shale gas and Colombian coal systems.

4.4 Life cycle data quality

The following presents a summary of the important data quality issues while Table 4-6 details the dataquality assessment for each life cycle steps.

Extraction: exploration and exploitation

• The data quality (and therefore the modeling) of the exploration/exploitation step for thenatural gas systems is extremely variable (see details below). Considering the relatively lowimportance of this particular step (3 to 123 g CO2 eq./kWh), comparatively to combustion (408to 444 g CO2 eq./kWh), one could question the necessity to improve the quality of theassessment/data.

o Exploration/exploitation of shale gas has been modeled mostly according to datacoming from the practices of the industry (numerous companies) in Quebec in recentyears (i.e. 2010-2012). The shale gas life cycle model is also extremely detailed and canbe adapted to represent different on-site practices. We adapted the model to some ofTOTAL practices such as well EUR;

o Data for the North Sea offshore, Indonesian offshore and Yemen onshore gas weremodeled following the available data from ecoinvent which are either outdated (fromthe 90’s) and/or applied to the wrong geographical context. For example, data from theNorth Sea was applied to Indonesia or data from Germany was applied to the naturalgas exploitation of onshore Yemen natural gas. These processes are not thoroughlydetailed and, therefore, cannot be easily adapted to represent on-site practices. WhileTOTAL provided some insight into the operations of these exploitations, the data couldnot be satisfactorily used as they did not meet the required completeness level of a lifecycle assessment modeling. They also could not be used to improve the ecoinventprocesses because the latter were simply not detailed enough to satisfactorily improvepart of the data. Data quality is believed to be mediocre and should be improved infuture efforts;

o Coalbed methane was modeled from existing studies who, at first glance, seemthemselves incomplete from an LCA perspective. Data quality is believed to be poor andshould be improved in future efforts.

• The modeling of the exploration/exploitation step for the coal systems appears to be better.Even if the data are outdated, they, at least, come from the correct geographical context (exceptIndonesia which was modeled after the data from Australia). Furthermore, considering that thisparticular step is a relatively minor contributor to the GHG emissions, comparatively to thecombustion, the data seems of sufficient relevance for the assessment;

Processing

• Processing of hydrocarbons (both oil and natural gas) are known to be outdated in ecoinvent;

• For numerous ecoinvent processes, it is unclear whether the natural gas processing step isincluded. Therefore, we simplified our LCA assessment of the processing step based on the



composition of the natural gas. Even if data quality is poor, our study conclusions are believed tobe sound as the overall contribution of the processing step is relatively low (14 to 34 g CO2eq./kWh).

Transmission to liquefaction and/or power plant

• The life cycle modeling took into account the fugitive emissions provided by TOTAL from aMarcogaz study. We also considered the natural gas compressors along the transmissionpipeline which are used to keep the natural gas at the required pressure. These compressorstypically use the natural gas inside the pipeline; combustion of natural gas increases theatmospheric CO2 emissions. Data is thus judged of sufficient quality;

Liquefaction

• The liquefaction process used in the life cycle modeling represents a technological average. Evenif the considered data are outdated, we believe the data is sufficiently sound. It does carry acertain level of uncertainty as we do not consider the exact spatial variability attributed to thedifferent terminal whose latitude may increase the required energy levels to liquefy the naturalgas. Indeed, colder temperatures increase gas density which improves compression yields,leading to an increase in production for the same energy consumption; also, from atechnological point of view, recent facilities show improved liquefaction efficiency as comparedto older LNG plants.

LNG transport

• The LNG transport process used in the life cycle modeling represents a technological average. Itis based on the late 1990 – early 2000 Italian LNG fleet. LNG carrier technologies (i.e. cryogenicmembranes, engine design and efficiency) have evolved since then. Data could be improved butis deemed of sufficient quality for the purposes of this study.

Regasification

• Data are outdated and not representative of the European context. Therefore, the data qualityis believed to be poor-mediocre. Considering that it is not an important GHG contributor to theoverall system this particular step should not affect the conclusions of our study;

Storage

• Data was mostly provided by TOTAL. Even if It remains a marginal contributor comparatively tothe other life cycle steps, data is believed to be excellent both in terms of geographical andtemporal representativeness;


• The most important GHG contributor is modeled satisfactorily in terms of geographicalvariability. Furthermore, considering the importance of this step, recent data were collected forthe efficiency of the power plants. However, secondary data, such as infrastructure or waterconsumption, are from the early 2000’s. Even though these processes have no significantcontribution to the overall GHG emissions, they could still be improved upon.



Table 4-6 : Detailed data quality assessment.

Contribution Reliability Representativeness Temporal coverage

Extraction

Utica shale gas 3.29% 1 2 1

Offshore North Sea 0.73% 2 3 3

Australian CBM 17.37% 3 2 1

Indonesia shallow offshore 0.60% 3 4 3

Yemen onshore 3.17% 2 3 3

Hard coal Europe 9.77% 2 3 3

Hard coal Colombia 1.23% 2 3 3

Hard coal US 4.20% 2 3 3

Hard coal South Africa 4.46% 2 3 3

Hard coal Russia 11.35% 2 3 3

Hard coal Indonesia 4.13% 2 4 3

Hard coal Australia 4.04% 2 3 3

Hard coal China 29.27% 2 3 3

Processing






Transmission to liquefaction plant (natural gas) or to other continents (coal)


Offshore North Sea N/A N/A N/A N/A




Hard coal Europe N/A N/A N/A N/A




Hard coal Russia N/A N/A N/A N/A



Hard coal China N/A N/A N/A N/A



Liquefaction






Transoceanic transport (natural gas)






Regasification






Storage


Offshore North Sea 0.81% N/A N/A N/A




Transmission/transport to plant






























Considering this data quality assessment, the CIRAIG feels that the assessment is sound. Some additionaldata collection efforts could be considered. However, lower quality data have typically low contributionto the GHG emissions and therefore, improvement of these processes should not alter the overallconclusions of this study.

4.5 Limitations

This study aimed to:

“Establish and compare the GHG emissions related to the life cycle of natural gas and coal fromdifferent sources (conventional and unconventional) and geographical contexts in order to produce

electricity.”

It should be noted that this comparison was based on some of TOTAL’s (or their partners’) natural gasproductions and generic coal data.

All conclusions taken out of the original context or this study must be avoided.

Its results can be used to:

• Identify strengths and weaknesses of each natural gas or coal system and identify conditions forwhich alternative seems preferable to the other;

• Identify improvement efforts for future studies.

The main limitations of this study include:

• the GHG emissions were the sole focus of this study; other impacts were out of the scope of thestudy. GHG emissions are most likely to drive the environmental impacts related to Humanhealth and Ecosystem quality endpoint category of newest impact assessment methods ReCiPeand IMPACT World +;

• the study is limited to the investigated natural gas and coal systems; it should not be used toextrapolate our findings to other geographical contexts;

• The completeness and validity of the inventory data. In particular,o the CBM extraction;



o the limited primary data for natural gas systemso the lack of primary data for coal systems;o the database limitations in terms of temporal or geographical context.

• ecoinvent processes typically rely on underlying data which were representative of the earlyand late 1990’s as well as early 2000’s. They may not be typically representative of technologiesavailable for the required scope of the study (i.e. 2015);

• The interpretation of the GHG results can only be based on the results obtained, that is to say,substances for which a characterization factor exists in the method database;

• Unlike the environmental risk assessment conducted in a regulatory context, which uses aconservative approach, this study seeks to provide the best possible estimate (Udo de Haes etal., 2002). It tries to represent the most probable case, i.e. that the models do not attempt tomaximize exposure and environmental damage;

• Finally, the results are relative expressions and do not predict real impacts, the exceeding ofthresholds, safety margins or risks.

4.6 Summary

Table 4-7 and Table 4-8 summarise the numerical GHG estimates obtained, per life cycle step, from theliterature, the reporting values from TOTAL and the LCA modeling for the investigated natural gas andcoal systems.

In general terms, we can conclude that…

● GHG emissions from the life cycle modeling, even with some source of uncertainties, were shown to be consistent with values from the literature or reporting data from TOTAL.

● The approach based on literature review may provide some scenarios in which some natural gas exploitation used for the production of electricity may be on par or worse than coalsystems. However, this situation only arises for the natural gas worst case scenario and bestcase scenario for coal. On average, natural gas systems showed less GHG emissions than coalsystems.

● Life cycle modeling consistently provided, on average, a lower GHG emission estimate for natural gas systems comparatively to coal systems.

● Monte Carlo analysis, based on the variability of life cycle inventory input parameters, showed GHG emissions overlap, with a confidence level of 95 %, of 17 g CO2/kWh between the USshale gas and Colombian coal. However, the probability of such overlap is low as it impliesconsidering simultaneously the best case scenario for coal, and a high fugitive emissions figurefor shale gas (7% of EUR);

• At a confidence level of 90 %, all natural gas systems showed lower GHG emissions than hardcoal.



Table 4-7 : Natural gas systems GHG emissions (based on IPCC’s 2007 GWP100) summary.

All values are provided in g CO2 eq./kWh electricity

US shale gas North Sea offshore Australian coalbed methane

Sources Lit.Reporting

TOTAL

Life cycle(95%

confidencein brackets)

Lit.Reporting

TOTAL

Life cycle(95%

confidencein brackets)

Lit.Reporting

TOTAL

Life cycle(95%

confidence inbrackets)

Exploration/Extraction 10.1-34.025.3

(8.2-48.5)19.3

40.6-49.227

12.0(3.1-17.9)

6.7

56.8-66.3

N/D 123.5

Processing 30.4-81.9 N/D 32.6 N/D 33.1 N/D 14.3

Transmission toliquefaction plant

9.4-53.60.007

(0.005-0.011)0.01 N/A

0.007(0.005-0.012)

0.01

Liquefaction 34.8-96.3 23.7 69.0

N/A

37.9-105.035.2

(2.3-72.7)75.2

LNG tankers 6.8-22.7 18.7 37.8 7.4-24.8 16.4 33.2

Regasification 2.6-11.64.0

(3.5-4.2)14.4 2.8-12.6

4.3(3.9-4.6)

15.7

Storage N/D N/D 3.6 N/D N/D 3.6 N/D N/D 4.0

Transmission to powerplant

9.4-53.60.001

(0.001-0.002)0.007 N/A

0.007(0.005-0.01)

0.01 10.3-31.60.001

(0.001-0.002)0.007

Electricity production 369.4-405.6 N/D 408.2 369.4-405.6 N/D 408.2 403-442 N/D 444.8

Sum 473-710585

(468-884)410-455

452(411-496)

517.9-682.4711

(641-789)

27The included transmission step is to the power plant; not the liquefaction plant



Table 4-7 (continued) : Natural gas systems GHG emissions (based on IPCC’s 2007 GWP100) summary.


Indonesian shallow offshore Yemen onshore

Sources Lit. Reporting TOTALLife cycle

(95% confidence inbrackets)

Lit. Reporting TOTALLife cycle

(95% confidence inbrackets)

Exploration/Extraction

44.2-53.7

2.7(0.2-4.7)

3.138.7-108.9

N/D 19.8

Processing N/D 34.7 N/D 18.1

Transmission0.001

(0.001-0.002)0.007 10.3-31.6

0.001(0.001-0.002)

0.007

Liquefaction 37.8-105.065.1

(48.8-80.7)75.2 37.9-105.0

40.9(40.7-218.5)

75.2

LNG tankers 7.4-24.8 9.6 19.6 7.4-24.8 24.2 49.2

Regasification 2.8-12.61.3

(0.4-1.8)15.7 2.8-12.6

4.3(3.9-4.6)

15.7

Storage N/D N/D 4.0 N/D N/D 4.0

Transmission 10.3-31.60.001

(0.001-0.002)0.007 10.3-31.6

0.001(0.001-0.002)

0.007

Electricity production 403-442 N/D 444.8 402.6-442.1 N/D 444.8

Sum 505-669597

(555-645)510.0-756.6

627(576-682)



Table 4-8 : Coal systems GHG emissions (based on IPCC’s 2007 GWP100) summary.


Coal European coal Columbian coal US coal South African coal Russian coal

Sources Lit.Life cycle modeling

(95% confidence in brackets)

Exploration/Extraction 99.5 11.9 41.7 50.6 118.8

Transmission 18.2 55.2 48.1 73.3 27.9

Electricity production 900.7 900.7 900.7 1010.8 900.7

Sum1026

(731-1372)1018

(908-1159)967

(867-1077)990

(874-1152)1135

(977-1470)1047

(927-1183)

Coal Indonesian coal Australian coal Chinese coal

Sources Lit.Life cycle modeling

(95% confidence in brackets)

Exploration/Extraction 46.1 46.1 432.1

Transmission 58.7 82.4 33.3

Electricity production 1010.8 1010.8 1010.8

Sum1026

(731-1372)1116

(878-1510)1139

(897-1542)1476

(971-2888)



Table 4-7 and Table 4-8 also allow a comparison of the individual life cycle processes’ GHG estimateswith values from the literature and reporting data from TOTAL.

Even though reporting data should typically show lower GHG emissions as they consider a fraction (i.e.direct emissions and/or emissions associated with electricity production) of the process’ GHG emissions,they should nevertheless constitute a relatively high proportion of the life cycle emissions (Scope 1-2-3)and therefore should provide a life cycle modeling lower limit.

Overall, there is generally a good agreement between both literature estimates, TOTAL reporting valuesand life cycle modeling. The following discrepancies have been observed:

• North Sea offshore extraction: our life cycle modeling of this particular process is acceptablebut should be revised considering that TOTAL’s reporting values are higher by a factor 2 andconsidering the relative lack of details in the ecoinvent database for this particular process;

• Australian CBM extraction: CBM assessment produced higher GHG emissions than thosereported in the literature. Even though our estimation for this process could be considered as aworst case, it never overlapped the coal systems;

• Chinese coal: the coal mining methane emissions of this particular process are nearly seventimes higher than the average coal mining emissions reported by Whitaker et al. (2012). Eventhough the References supporting the ecoinvent database coal mining methane emissions arerepresentative of Chinese mining operations they are outdated (early 1990). Considering thediscrepancies with other coal operations, further investigations regarding coal mining emissionsin China should be carried out.

• Natural gas transmission: this process presents the greatest discrepancies between literatureand life cycle modeling. Literature considers the United States distribution in their assessmentwhich cannot be separated from transmission; distribution networks in parts of the UnitedStates are old and made of cast iron. Even though these cast iron pipes only represent 3 % ofthe entire distribution main, they are believed to be accountable for the vast majority oftransmission and distribution leaks28. Considering that European transmission pipeline is notmade of cast iron, this fact alone could explain the discrepancies between literature and lifecycle modeling which was based on European data.

• Liquefaction: life cycle modeling of this process is in line with literature values. However, forthis particular process, TOTAL’s reporting data are probably more representative of the GHGemissions for this process due to the high dependence on energy use which is captured by thereporting.

• Electricity production: coal or gas-fired power plant GHG emissions are in line with literaturevalues although in the high end of reported literature values. This situation is flagged becauseof the importance of the combustion phase.

28http://www.sourcewatch.org/index.php/Natural_gas_transmission_leakage_rates



4.7 Recommendations

The CIRAIG is fairly confident in the validity of the assessment for several processes either because theyare not major contributors to GHG emissions or that data is judged to be of satisfactory quality. Amongthese processes are:

• Natural gas transmission to liquefaction plant;

• Liquefaction;

• Storage;

• LNG carriers;

• Natural gas transmission to power plant;

• Electricity production.

Electricity production is the most important contributor to the natural gas and coal systems. The CIRAIGfeels that the assessment of this particular process is sound. Some variability is expected with thisprocess however with the variability in efficiency or (low) heating value. Such variability has beenconsidered in either a sensitivity analysis or uncertainty analysis; neither of which significantly modifiedour study findings.

Furthermore, even though we believe our life cycle modeling has slightly overestimated the GHGemissions related to the regasification process, we do not believe that an extensive data collectionshould be necessary to refine this analysis, as the contribution of this particular process is small (14-16 g CO2 eq./kWh). All in all, this particular process should not affect the conclusion of our study.

As for the natural gas processing, we have simplified it based on the composition of the natural gas. Thisprovided us, at best, with an estimation of an order of magnitude for this particular process. Somefurther data collection could be necessary to improve this particular process as the worst case scenariowould see an increase of natural gas systems GHG emissions by approximately 50 g CO2 eq./kWh, whencompared to the literature estimations.

As previously mentioned, the quality of the modeling of the exploration/exploitation step for the naturalgas systems is extremely variable. While the shale gas modeling is believed to be reliable, the samecannot be said of the other natural gas systems. The CIRAIG would recommend collecting life cycleinventory data at the North Sea, Indonesian, and Yemen sites to have a more detailed assessment of thepractices in these geographical contexts. However, this particular data collection is not paramount tothe credibility of the study, as the results (6,7, 3.1 and 19.9 g CO2 eq./kWh for the North Sea, Indonesia,and Yemen, respectively) are not that far off from credible literature values. It would nonethelessimprove the reliability of its results.

The same could not be said for the Australian coalbed methane. Indeed, the exploration/exploitationstep of this particular natural gas system was modeled according to existing studies which seemincomplete. Reliability of the literature assessment in Australia is slim due to the lack of studies and dataon the subject. For example, Australian CBM fugitive emissions have been reported to range from 3.4 to16 kTCO2 eq./PJ of natural gas (12 to 57 g CO2eq./kWh of natural gas) and we considered the averagevalue of this interval: 9.7 kTCO2 eq./PJ of natural gas (35 g CO2eq./kWh of natural gas) (Kember et al.2012). However, the NETL (2014) study in the US considers a value of 7.8 g CO2eq/MJ of natural gas (i.e.2.2 CO2eq/kWh of natural gas) for the entire upstream process. Considering the fact that our limitedassessment showed that coalbed methane had possibly the highest level of GHG emissions for theexploration/exploitation step, we recommend ascertaining the life cycle inventory of such anexploitation with a thorough data collection.



As for the coal systems, all were within range of previously published studies. The only exception beingChinese coal which showed coal mining methane emissions that were nearly twice as high than all othercoal systems (see Table 3-11). While the ecoinvent data rest upon Chinese reported values, they aresomewhat outdated. Therefore, some inquiries should be made to have a betterunderstanding/assessment of Chinese coal mining methane emissions.

http://www.aspentech.com/White-Paper-Acid-Gas-Validation-DEPG-Nov-2014.pdf

https://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngprocess.pdf

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http://www.engineeringtoolbox.com/gas-density-d_158.html

http://eur-lex.europa.eu/legal-content/EN/TXT/HTML/?uri=CELEX:32013R0525&qid=1464017451704&from=FR

http://eur-lex.europa.eu/legal-content/EN/TXT/HTML/?uri=CELEX:32013R0525&qid=1464017451704&from=FR

http://www.ghgenius.ca/reports.php

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http://www.ghgprotocol.org/calculation-tools/faq

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http://www.capp.ca/~/media/capp/customer-portal/documents/215278.pdf

http://www.ipcc.ch/pdf/assessment-report/ar4/wg1/ar4-wg1-chapter2.pdf



5 Conclusion

This report fulfilled TOTAL’s objective which was to:

“Establish and compare the GHG emissions related to the life cycle of natural gas and coal fromdifferent sources (conventional and unconventional) and geographical contexts in order to produce

electricity.”

It should be noted that this comparison was based on some of TOTAL’s (or their partners’) natural gasproductions and generic coal data.

In order to fulfill this objective, the CIRAIG has proposed a three-tier approach to evaluating the GHGemissions of the different investigated natural gas and coal systems:


• TOTAL reporting and other in-house data;

• Life cycle modeling mostly based on ecoinvent data.

Our life cycle assessment was typically in line with literature values and internal TOTAL GHG reporting.

While the assessment of the literature showed a possible overlap between the GHG emissionsgenerated by Colombian coal and US shale gas, our life cycle probabilistic approach showed no overlapbetween systems at a 90 % confidence level; overlap occurring only at a 95% confidence level over arange of 17 g CO2 eq./kWh. The probability of such overlap is low as it implies consideringsimultaneously the best case scenario for coal, and a high fugitive emissions figure for shale gas (7% ofEUR).

Thus, considering the amount of uncertainty related to our life cycle modeling and the relatively closeproximity of the GHG emissions of some natural gas and coal systems, we cannot completely rule outa possible GHG emissions overlap.

However, it should be noted that such overlap would only occur with a worst case scenario of anatural gas system and a best case scenario of the coal system.

On average, our results show that the natural gas systems (even the unconventional ones) (452-711 gCO2 eq./kWh) emit fewer GHG emissions than coal systems (968-1476 g CO2 eq./kWh).

It should be noted that the results of this study can be used to identify strengths and weaknesses of theinvestigated natural gas or coal systems and identify conditions for which one alternative seemspreferable to the other. The results can also be used to identify potential improvement to enhancefuture studies.

The main limitations of this study include the fact that the GHG emissions were the sole focus of thisstudy; no other impacts were investigated. Furthermore, the study is limited to the investigated naturalgas and coal systems and therefore our findings should not be extrapolated to systems in othergeographical contexts. Finally, there are some issues regarding the completeness and validity of some ofthe inventory data pertaining the coal bed methane extraction and the lack of primary data for the coalsystems.

http://www.netl.doe.gov/File Library/Research/Energy Analysis/Life Cycle Analysis/NETL-NG-Power-LCA-29May2014.pdf

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th2015

Critical Review of

“GHG EMISSIONS RELATED TO THE LIFE CYCLE OF NATURAL GAS AND COAL IN

DIFFERENT GEOGRAPHICAL CONTEXTS June 2016”

according to ISO 14040, ISO 14044 and ISO/TS 14071

SOL 16-007.2

23rd of June 2016

for

TOTAL

Critical Review Panel for TOTAL

Critical Review Report “GHG EMISSIONS RELATED TO THE LIFE CYCLE OF NATURAL GAS AND COAL IN DIFFERENT GEOGRAPHICAL CONTEXTS” dated June 2016

SOL 16-007.2 23rd of June 2016 page 2 of 4

1 Introduction CIRAIG has done a LCA study for TOTAL. The title of this study was to evaluate the “GhG emissions related to the Life Cycle of Natural Gas and Coal in Different Geographical Contexts”. The study report is dated June 2016.

The goal of the study was “Establish and compare the life cycle GhG emissions of natural gas and coal from different sources (conventional and unconventional) and geographical contexts in order to produce electricity in Europe and Asia”.

This comparative study has been done applying ISO 14040:2006 and ISO 14044:2006 recommendations and may be published. Therefore, TOTAL & CIRAIG have requested a CR panel to make a critical review of this study.

The present report is the “Final CR report”, prepared by the CR panel under the direction of Philippe Osset (Solinnen). This CR report, including appendices, is dedicated to be integrated as a whole within the final report of CIRAIG.

2 Composition of the panel The CR panel consisted of the three following independent members:

Dipl. Eng. Philippe Osset, CEO, Solinnen. Mr. Osset has over 20 years of experience of the LCA practice, including CR practice. Mr. Osset has applied the LCA practice to different energy production systems, including based on natural gas and coal. Mr. Osset has acted as the chair of the Critical Review panel.

Robert Ineson, Managing Director, IHS. Mr. Ineson holds a M.B.A. from the University of Pennsylvania's Wharton School. Mr. Ineson has over 30 years of energy industry experience, including many years in the pipeline industry. Mr. Ineson leads the Global LNG research team at IHS.

Dr. Stéphane Amant, Senior Manager, Carbone 4. Dr. Amant has 10 years of experience in the Industry sector (aeronautics) and 8 years of experience in consultancy on energy and low-carbon transition

The intention of the panel set up was to make available competencies which cover the studied topics, i.e. sector specific expertise, GhG related inventories, and the LCA expertise.

3 Nature of the CR work, CR process and limitations The CR panel has worked according to the requirements of ISO 14040:2006 and 14044:2006 concerning CR, and according to the requirements of ISO/TS 14071. According to ISO 14044, the critical review process has worked in order to check if:

the methods used to carry out the LCA are consistent with ISO 14044 requirements,

the methods used to carry out the LCA are scientifically and technically valid,

the data used are appropriate and reasonable in relation to the goal of the study,

the interpretations reflect the limitations identified and the goal of the study, and

the study report is transparent and consistent.

The first goal of the CR was to provide CIRAIG with detailed comments in order to allow CIRAIG to improve its work. These comments have covered methodology choices and reporting. The panel has checked the plausibility of the data used in the report, through sample tests, including a review of the database within the software used by CIRAIG. Additionally, the present final critical review report provides the future reader of the CIRAIG report with information that will help understanding the report.

The CR work has started after the generation of a first full LCA report by CIRAIG. The work has started in April 2016 and ended up in June 2016. During this period, different oral and written exchanges have been held between the CR panel and CIRAIG, including clarification exchanges regarding the CR comments, and the production of one new final version of the report by CIRAIG. CIRAIG has taken into account most of the comments and significantly modified and improved its report.

The present final CR report is the synthesis of the final comments by the reviewers. Some detailed comments are provided within this final CR report, together with the full detailed exchanges as appendix (this appendix is made according to Annex A of ISO/TS 14071).

The present CR report is delivered to TOTAL and CIRAIG. The CR panel cannot be held responsible of the use of its work by any third party. The conclusions of the CR panel cover the full report from CIRAIG “GhG emissions related to the Life Cycle of Natural Gas and Coal in Different Geographical Contexts – June 2016” and no other




report, extract or publication which may eventually be done. The CR panel conclusions have been set given the current state of the art and the information which has been received. These CR panel conclusions could have been different in a different context.

4 Conclusions of the review

The CR first set of comments covered the following points:

General comments (27 key comments),

Technical comments (41 key comments),

Editorial comments and other miscellaneous comments (76 comments).

Out of these comments, 16 have been set as discrepancy by the panel, and the rest were comments for improvement.

An exhaustive work has been done by CIRAIG to provide a final report integrating answers to all the CR points, and the final result has improved as compared to the first one.

As a whole, the CR panel considers that the final report answers to the goals which have been set up, within the scope of the limitations that are mentioned in the report.

One of the limitations which is mentioned is the fact that “GhG only” have been addressed – as being a goal of the study. As said in the draft version of the appendix of ISO 14044 related to footprints: “One “footprint” addresses only one area of concern. […] This is in conflict with the comprehensiveness principle of LCA. Therefore, the quantification of footpr ints shall document the limitations with regard to selected environmental impacts in a transparent manner. [This documentation has been provided in the current report of CIRAIG] While the selected footprint can be an important environmental aspect of the life cycle of a product or organization, the life cycle typically has a broader set of other environmental impacts of concern. An objective of LCA is to allow an informed decision regarding a comprehensive set of environmental impacts. Footprints are limited to only one or a limited set of environmental impacts. As a consequence, footprints shall not be used for comparative assertions intended to be disclosed to the public.” This limitation reminds that fact that the comparison which is done in the current study of CIRAIG does not allow to conclude about “the superiority of one technology over another one” as such. It only allows concluding regarding about the lower or higher level of GhG emitted over its life cycle by one technology as compared to another one.

5 Detailed comments The following lines bring some highlights that a reader of the final LCA report may use to assist his reading and understanding of the report. They mainly recap some critical comments which were not addressed, or which were addressed in a way which is different from what the CR panel expected. The reading of the detailed comments and answers (see appendices) is recommended, since they cover key issues when dealing with the comparison which has been made.

5.1 Consistency of methods used with ISO 14040 and ISO 14044 requirements

The final structure of the report reflects the ISO 14040 and ISO 14044 standard requirements. The methods that have been selected for reference calculations are clearly presented. Additionally, the panel has produced comments according to ISO 14067, even if this standard is now under revision. These comments have also been mostly integrated by CIRAIG.

Incorporation of the comments of the CR panel has improved the clarity of the report as to methodology and as to the nature and sources of assumptions used in the calculations.

5.2 Scientific and technical validity

The modelling of the different routes which have been taken into account is clear and documented, and reflects the variety of origins of Natural Gas used by TOTAL and the variety of origins of Coal that is used worldwide.

For its study, CIRAIG referred to numerous scientific publications and even took into consideration additional ones in its second report. On top of that, their methodology of calculation and the way the sensitivity analysis was performed are well described and in line with what can be expected from a reliable analysis of GHG emissions from complex systems.




The routes considered, both for Natural Gas and for Coal, are specifically and clearly defined and represent supply chains that appropriately represent the way the fuels are produced and consumed in the marketplace.

5.3 Appropriateness of data used in relation to the goal of the study

The overall data used and the calculations done are adapted to provide the final results in the scope of the goal of the study. The test which has been done of alternative characterization factors has been highly welcomed.

The variety of sources, as well the performance of the sensitivity analysis, make the data used in the study appropriate. Furthermore, when TOTAL (or partners’) data were used, CIRAIG was very transparent and showed they didn’t influence the overall conclusion. Eventually, the controversial study from Howarth et al was considered in the study, even though its conclusions were not always taken into account in the calculations (this exclusion being explicitly stated when used).

5.4 Validity of interpretations in the scope of the limitations of the study

The choice of values which have been used for the interpretations is plausible. The limits of the study (chapter 4.5) are adapted and clearly stated: the reader shall take it into account when reading the conclusions.

Despite a certain number of limitations, exhaustively mentioned, the inherent uncertainties don’t invalidate the interpretations done by the authors. On the scientific ground, CIRAIG conclusions reflect in a very honest way what can be deduced from the data and the computations. Assessments such as considering how high the fugitive emissions rate for natural gas would need to be for gas emissions to be high enough to overlap with the bottom of the range of Coal emissions strengthen this conclusion.

5.5 Transparency and consistency

The overall level transparency and consistency of the report is good, and in line with the ISO 14044:2006 expectations. The limitations which are mentioned concerning data sources looks in line with the data source used in the report.

Already good in the first report, CIRAIG transparency was even improved in its second issue. The consistency level required by this type of scientific study was perfectly reached.

6 Appendices The detailed critical review tables exchanged during the work are the appendices of the present CR report. They recap the detailed exchanges between the CR panel and CIRAIG.

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