KEB, Alm.del - 2012-13 - Endeligt svar på spørgsmål 139: Spm., om ministeren vil fremsende og kommentere EU-Kommissionens rapport over "et studie, der skal vurdere størrelsen af drivhusgasemissionen fra skifergasprojekter set over et projekts levetid", til klima-, energi- og bygningsministeren

Executive SummaryAs readily accessible oil and gas reserves are becoming progressively limited the energy supplyindustry is increasingly turning to unconventional reserves which were previously too complex or tooexpensive to extract. In particular there has been a growing interest in Europe in the exploitation ofgas reserves trapped within shale rock. This is commonly referred to as ‘shale gas’.As with any drilling and extraction process shale gas extraction may bring environmental and healthrisks which need to be understood and addressed. In particular the potential contribution of shale gasproduction to greenhouse gas (GHG) emissions is a key area of interest. These impacts are thesubject of this report. The report has been commissioned by DG Climate Action of the EuropeanCommission and delivered by AEA, in collaboration with CE Delft and Milieu.Drawing upon existing research this report provides an examination of the potential climate impacts ofshale gas production in the EU. It begins with a review of existing estimates of GHG emissions fromshale gas production and of the potential options for abating emissions from shale gas processes.This evidence is then used to estimate the potential emissions that might be associated with shale gasexploitation in the EU. A brief review is also provided of the current legislative framework in the EU forcontrolling GHG emissions from shale gas operations. Finally the report provides an examination ofthe current GHG emissions reporting framework and explores the extent to which emissions fromshale gas operations would be captured within the existing reporting requirements. Where there areidentified gaps the report addresses the need for further reporting guidelines.The report does not explore the potential role of shale gas in the future energy supply mix, or anypotential implications of the exploitation of indigenous shale gas resources on the development ofrenewable or other energy sources in Europe. These issues are important considerations for energyand climate policy makers but are beyond the scope of this study. However, the results provided herecan be used as inputs to discussions around these issues.Shale gas exploitationIn the U.S. there has been a rapid growth in the exploitation of shale gas reserves, with productionincreasing by 48% between 2006 and 2010. Despite there being significant shale gas reserves inEurope, with technically recoverable shale gas resources estimated at approximately 18 trillion cubic3metres (m ), exploitation of shale gas to date has been limited and there is no commercial productionat present.The recent combination of higher natural gas prices, and the development of shale gas production inthe U.S., has increased interest in shale gas exploitation within Europe. As a result permission is nowbeing sought in several EU Member States for exploratory works with the explicit aim of bringingforward sites / projects for the extraction of shale gas.A number of the key processes involved in the extraction of shale gas reserves are similar toconventional natural gas. However, certain process steps are more specific to unconventional gasextraction and the scale and complexity of operations differ from conventional practices. In particular,the extraction of shale gas typically involves a process known as hydraulic fracturing (fracking) wherewater, chemicals and proppants are pumped at high pressure into the well in order to open fractures inthe rock and release the shale gas.Other aspects of shale gas extraction differ from conventional natural gas. For example, additionaldrilling is required for horizontal wells, along with much greater volumes of water required in thehydraulic fracturing process.Once production begins at the well the subsequent process steps in the exploitation of shale gas(processing, transportation, distribution) are largely comparable with conventional natural gas.GHG emissions from shale gas productionThe GHG emissions from shale gas production have been the subject of a number of studies since2010. These studies have yielded a large variation in the estimated impacts of shale gas. Somestudies, which have received a lot of media attention, have concluded that the lifecycle GHGemissions from shale gas may be larger than conventional natural gas, oil, or coal when used togenerate heat and viewed over the time scale of 20 years (Howarth et al, 2011). However the majority

of studies suggest that emissions from shale gas are lower than coal, but higher than conventionalgas, based on other assumptions. These estimates are discussed further in this report.In practice most of the existing studies have drawn upon a narrow set of primary data from shale gasoperations in the U.S. Differences in the estimated emissions frequently arise from the interpretationby the authors of the primary data, in addition to the different underlying assumptions used in theirGHG assessments. As new information sources have come to light this has led to new and improvedestimates of the GHG impacts. However a number of uncertainties remain including: the level ofemissions associated with the well completion stage; about levels of water re-use and treatment ofwaste water. Overall, the emissions from shale gas are dominated by the combustion stage.Significant emissions also arise from the well completion, gas processing and transmission stages, butthe overall significance of these pre-combustion stages is less. Emissions from exploration have notbeen taken into account in any previous studies.Drawing upon these studies, and their underlying data sources, a hypothetical analysis has beencarried out of the potential lifecycle GHG emissions that may arise from shale gas exploitation withinEurope. In our base case, which does not represent a preferred scenario, we have estimated the GHGemissions per unit of electricity generated from shale gas to be around 4% to 8% higher than forelectricity generated by conventional pipeline gas from within Europe. These additional emissionsarise in the pre-combustion stage, predominantly in the well completion phase when the fracturingfluid is brought back to the surface together with released methane. If emissions from well completionare mitigated, through flaring or capture, and utilised then this difference is reduced to 1% to 5%. Thisfinding is broadly in line with those of other U.S. studies which found that generation from shale gashad emissions about 2% to 3% higher than conventional pipeline gas generation.This study also considered sources of gas outside of Europe which make a significant contribution toEuropean gas supply. Based on our hypothetical analysis, and drawing upon existing LCA studies forconventional gas sources, the analysis suggests that the emissions from shale gas generation (basecase) are 2% to 10% lower than emissions from electricity generated from sources of conventionalpipeline gas located outside of Europe (in Russia and Algeria), and 7% to 10% lower than that ofelectricity generated from LNG imported into Europe.However, this conclusion is far from clear-cut. Under our ‘worst’ case shale gas scenario, where allflow back gases at well completion are vented, emissions from electricity generated from shale gaswould be similar to the upper emissions level for electricity generated from imported LNG and for gasimported from Russia. This suggests, where emissions from shale gas are uncontrolled, there may beno GHG emission benefits from utilising domestic shale gas resources over imports of conventional1gas from outside the EU . In fact, for some pipeline sources emissions from shale gas may exceedemissions from importing conventional gas.The relative comparison with coal is clearer cut. In our analysis, emissions from shale gas generationare significantly lower (41% to 49%) than emissions from electricity generated from coal. This is on thebasis of methane having a 100 year GWP of 25. This finding is consistent most other studies into theGHG emissions arising from shale gas.These conclusions are based on experiences drawn largely from the U.S. Whilst attempts have beenmade to take into account the different circumstances in Europe, and how this may influence overallemissions, this comparison is still largely hypothetical. Where the shale gas industry develops inEurope this information should be used to update the results of the analysis.Best available technologies for reducing GHG emissionsOne of the key assumptions which can influence the scale of emissions estimated in the life cycleanalysis is the assumed management practices and technologies employed at the shale gasextraction site. The use of best practice techniques has the potential to significantly reduce emissionsrelative to other practices.A large proportion of the best practice techniques that have been identified include measures whichhave been demonstrated, and are a regulatory requirement, in specific regions in North America (andwill be a regulatory requirement in the U.S. from 2015). It is reasonable to assume that thesetechniques will be applicable in Europe with the following caveats:1

Geology: the effectiveness of certain techniques requires sufficient gas pressure, which maynot be the case at all locations in Europe.Infrastructure: at least initially any captured gas which doesn’t meet the required natural gasspecification would need to be processed further. This may be a constraint if the pipeline orprocessing infrastructure is not in place and suitable connections available for transferringcaptured gas do not exist.Availability and experience in equipment / technology: to capture the gas released on wellcompletion and re-fracturing activity. This may be an issue in initial stages of developmentuntil vendors develop suitable solutions.With respect to emissions resulting from flow back from well completions, the application of ReducedEmissions Completions has the potential to reduce emissions by around 90%. These technologieshave been used extensively in the U.S. both in response to regulations and existing drivers (e.g.economic value of captured methane). While there are some restrictions on the sites where thesemeasures can be used, in principle, they have the potential to deliver significant reductions inemissions from this stage in the process.Further emissions reductions can be achieved at other stages in the gas cycle. These measures arenot specific to shale gas and are also applicable to conventional gas sources. These includemeasures such as: more efficient compressors; improved leak detection or utilisation of gas stemmingfrom production testing.Legislation controlling GHG emissions from shale gas productionThe overview analysis of the EU legal acts identified as relevant to shale gas has shown that there arevery few requirements applicable specifically to GHG emissions from shale gas projects.The EIA Directive (85/337/EEC; 2011/92/EU (codified)) is the most relevant as it sets requirements asto the consideration of climate change effects and air emissions as part of a full EIA. It requiresMember States to ensure that developers supply certain information, such as a description ofestimated air emissions and significant environmental impacts resulting from the project, including airand climatic factors. Furthermore, the Directive provides for competent authorities to give an opinionon the information supplied which, as a minimum, should include a description of the measuresenvisaged in order to avoid, reduce and if possible, remedy significant adverse side effects.However, despite these requirements, many uncertainties remain as to whether Member States wouldrequire an EIA for shale gas operations and if so how Member States should implement the EIA. Forexample the way in which they would implement the methodology to be used to quantify GHGemission baseline scenarios.Directive 92/91/EEC concerning minimum requirements for improving the health and safety of workersin the mineral-extracting industries through drilling does not contain any provisions specifically relatingto GHG emissions. It does, however, set requirements to protect workers from harmful and / orexplosive substances. This would primarily apply to methane present in such concentration that itcould represent a risk in terms of flammability for workers.With regard to the Directive on Industrial Emissions (2010/75/EU) it is not clear in whichcircumstances it would apply to shale gas exploration and exploitation activities and whether itsmeasures on air emissions would cover methane contained within flow back.It is beyond the scope of this report to make specific recommendations on how to overcome thepotential shortfalls identified above.Finally, the EU ETS Directive (Directive 2003/87/EC) could provide precedents for the regulation ofshale gas emissions, through its treatment of venting and flaring, and emissions related to carboncapture and storage processes.In order to encourage the application of best available techniques the following could be furtherinvestigated:Consideration of the issues identified related to the scope of the EIA Directive with regard toshale gas exploration and exploitation activities (Annex I or II);Consideration of information requirements on measures taken by developers to limit GHGemissions under the EIA Directive, or other pieces of relevant legislation;Consideration of the need for measures to limit GHG emissions for shale gas exploration andexploitation;Ref: AEA/ED57412/Issue 2

Consideration of the issues identified related to the scope of the Industrial Emissions Directivewith regard to shale gas exploration and exploitation activities;Consideration of the application of the emission limit values requirements under the IndustrialEmissions Directive to methane emissions from exploration and exploitation activities.Consideration could also be given to the application of emission limit values for methane emissionsfrom exploration and exploitation activities.However, in principle the legislation described above could provide a good approach with which toenforce best shale gas technologies, although this would likely need to be supplemented by BATreference documents, guidance specific to shale gas technologies and clarification on the applicabilityof key directives. Alternatives, such as voluntary agreements could also be considered, but additionalmeasures would be required to ensure they are rigorously applied.Assessment of the current GHG emissions reporting frameworkIn order to ensure the effective control of GHG emissions from potential shale gas development inEurope it is important to ensure that emissions, where they arise, are reported. This information isimportant for understanding the net impact of any shale gas installations, and for assessing theimpacts of control measures, and the potential for further controls.A review has been carried out of the adequacy of current GHG emissions reporting frameworks, underthe auspices of the UNFCC and IPPC, with the view to identifying areas where improvements may beneeded in relation to shale gas production.The review has identified no emission factors, GHG estimation methods, industry activity or emissionsdata specific to shale gas Exploration and Production (E&P) sources within the EU. However,information and reporting protocols from regulators in Canada and the U.S. provide estimationmethods and indicative emission factors for these sources that are specific to shale gas E&P whichcould be developed for application in the EU.IPCC Guidelines do not provide emission estimation methodology details or emission factors that areapplicable to calculate emissions from sources specific to shale gas E&P such as well completions,well work-overs and the related management of flow back fluid.The UNFCCC reporting format (CRF) does not require that countries specify GHG emissions fromshale gas E&P, or from any other specific technology or sub-sector. Emissions and activity data aretypically reported by countries at an aggregated level across all gas E&P sectors, with additionalmethodological detail provided within National Inventory Reports (NIRs). The level of detail providedregarding emission estimations within the NIRs is subject to the discretion of the inventory agency.Several process stages in shale gas E&P, including processing and compressing the gas fordistribution, require the same steps as with conventional gas. Therefore the current IPCC Guidelinesand national GHG inventory methodologies should be adaptable to allow inventory agencies to derivecomplete and accurate estimates for these sources. Development of appropriate emission factors(ideally at the gas-basin level) through gas sampling and compositional analysis will be required toensure that emission factors reflect the local shale gas composition.

Table of contents1Introduction ................................................................................................................................. 11.1Background to the study .................................................................................................... 11.2Objectives of the study ...................................................................................................... 21.3Report Structure................................................................................................................. 2Shale gas exploitation ................................................................................................................ 42.1Introduction ........................................................................................................................ 42.2Overview of shale gas production...................................................................................... 42.3Process stages for the extraction of shale gas .................................................................. 52.4Comparison of high volume hydraulic fracturing and conventional hydrocarbon extractionpractices ...................................................................................................................................... 10Greenhouse Gas (GHG) emissions from shale gas production ........................................... 143.1Introduction ...................................................................................................................... 143.2Compilation of the evidence base.................................................................................... 143.3Pre-production stage ....................................................................................................... 153.4Production and Processing Stage ................................................................................... 273.5Transportation and distribution ........................................................................................ 283.6Well plugging and abandonment ..................................................................................... 283.7Summary.......................................................................................................................... 28Best available techniques for reducing GHG emissions ...................................................... 334.1Introduction ...................................................................................................................... 334.2Pre-production ................................................................................................................. 334.3Production Stage ............................................................................................................. 374.4Well Plugging and Abandonment .................................................................................... 394.5Applicability to Europe ..................................................................................................... 414.6Management techniques ................................................................................................. 42

5Hypothetical estimation of the lifecycle greenhouse gas (GHG) emissions from possiblefuture shale gas exploitation in Europe ............................................................................................ 445.1Introduction ...................................................................................................................... 445.2Modelling the shale gas life cycle .................................................................................... 445.3Gas Life Cycle.................................................................................................................. 465.4Coal Cycle........................................................................................................................ 655.5Summary.......................................................................................................................... 666Legislation controlling GHG emissions from shale gas production ................................... 696.1Introduction ...................................................................................................................... 696.2Initial review of existing legislation ................................................................................... 696.3Case Studies.................................................................................................................... 78Assessment of current GHG emissions reporting framework ............................................. 997.1Introduction ...................................................................................................................... 997.2Study Approach ............................................................................................................... 997.3Evaluation of UNFCCC GHG Emission Reporting Frameworks and IPCC Guidelines 1007.4Summary........................................................................................................................ 1137.5Recommendations ......................................................................................................... 116References ............................................................................................................................... 118Glossary ................................................................................................................................... 123

List of Figures:Figure 1: Schematic cross-section of the subsurface illustrating types of natural gas deposits (From:U.S. DOE, Energy Information Administration, 2011b) ........................................................................... 4Figure 2: Well development process ....................................................................................................... 5Figure 3: Stages in well development ..................................................................................................... 5Figure 4: Life cycle emissions from pre-production stages (gCO2eq/MJ gas combusted, using 100year GWPs for CH4 and N2O of the IPCC Fourth Assessment Report) .............................................. 30Figure 5: Total life cycle emissions for shale gas (CO2eq/MJ gas combusted using 100 year GWPs forCH4 and N2O of the IPCC Fourth Assessment Report) ....................................................................... 31Figure 6: Reduced Emissions Completion Equipment (U.S. EPA 2011d) ............................................ 35Figure 7: Lifecycle GHG emission from electricity production using shale gas (gCO2/kWh) ................ 60Figure 8: Lifecycle GHG emissions from electricity using shale gas – pre combustion stages only(gCO2/kWh) ........................................................................................................................................... 61Figure 9: Comparison of lifecycle GHG emissions from pre-production stages for shale gas from thisstudy and others .................................................................................................................................... 63Figure 10: Comparison of lifecycle GHG emissions for shale gas from this study and others ............. 64Figure 11: Total emissions from conventional gas (g/kWhe) ................................................................ 64Figure 12: Lifecycle emissions from coal and gas fired electricity generation ...................................... 68Figure 13: Lifecycle emissions from coal and gas fired electricity generation, with future improvementsin electrical efficiency............................................................................................................................. 68Figure 14: Shale Gas E&P Processes, Emission Sources and GHG Inventory Impacts ................... 108

List of Tables:Table 1: Estimated shale gas recoverable resource for select basins in Europe ................................... 1Table 2: High Volume Hydraulic Fracturing: Stages, Steps, and Differences from ConventionalHydrocarbon Practices .......................................................................................................................... 10Table 3: Existing estimates of emissions associated with site preparation ........................................... 16Table 4: Existing estimates of emissions associated with drilling ......................................................... 17Table 5: Existing estimates of emissions associated with transport of materials .................................. 20Table 6: Existing estimates of emissions associated with resource use ............................................... 21Table 7: Existing estimates of emissions associated with treatment of waste water ............................ 22Table 8: Existing estimates of emissions associated with flow back .................................................... 24Table 9: Typical emission from the production stage ............................................................................ 27Table 10: Typical emissions from activities used during the production stage ..................................... 27Table 11: Summary of life cycle emissions estimates for shale gas (g CO2/MJ) .................................. 32Table 12: Gas use for treatment and fugitive emissions (% of gas throughput) ................................... 51Table 13: Emissions from gas treatment (kg/GJ gas delivered) ........................................................... 52Table 14: Gas use for treatment and fugitive emissions – LNG (% of gas throughput) ........................ 54Table 15: Emissions from LNG gas processing (kg/GJ) ....................................................................... 54Table 16: Examples of LNG installation specific energy consumptions and fugitive emissions .......... 54Table 17: Emissions from Pipeline transmission (% of gas throughput) ............................................... 55Table 18: Emissions from Pipeline transmission (kg/GJ) ...................................................................... 55Table 19: Comparison of emissions estimates from LNG transport from alternative sources. ............. 56Table 20: Emissions from LNG transport (% of gas throughput) .......................................................... 57Table 21: Emissions from LNG transport (kg/GJ) ................................................................................. 58Table 22: Parameters varied in each scenario ...................................................................................... 59Table 23: Lifecycle emissions for electricity generation from shale gas (g CO2/kWh electricity) .......... 61Table 24: Influence of GWP for methane on lifecycle emissions for electricity generation from shalegas (g CO2/kWh electricity) ................................................................................................................... 62Table 25: Lifecycle emissions from coal fired electricity generation (g CO2eq/kWh) ............................ 66Table 26: EIA relevant for shale gas exploration and exploitation ....................................................... 97Table 27: Shale Gas Sources – Gap Analysis for UNFCCC Reporting and IPCC Guidance ............. 104Table 28: Typical emission factors for unconventional gas E&P ........................................................ 112

1 Introduction1.1 Background to the studyAs readily accessible oil and gas reserves are becoming progressively limited the energy supplyindustry is exploring the potential of unconventional reserves which were previously too complex ortoo expensive to extract.The United States of America (U.S.) is ahead of the rest of the world in this energy field. Extraction ofcoal bed methane and gas extraction from sandstone and shale represents a growing proportion ofthe energy mix in the U.S. In 2010, Shale gas represented ~23% of total U.S. dry gas production.From 2006 – 2010 shale gas production increased by 48% and is projected to account for 47% ofU.S. production in 2035 (U.S. DOE, Energy Information Administration, 2011a). The U.S. has3accessible reserves of over sixty trillion m of natural gas, amounting to over one hundred years’ ofU.S. consumption at current levels. The total technically recoverable shale gas resource is estimated3to be 13 trillion m (U.S. DOE, Energy Information Administration, 2012).Table 1 (U.S. DOE, Energy Information Administration, 2011b) shows the estimated technicallyrecoverable resources for selected basins in Europe, compared to existing reported reservesproduction and consumption, during 2009. This indicates that technically recoverable shale gasresources in Europe are of a similar scale to those technically recoverable in the U.S.Table 1: Estimated shale gas recoverable resource for select basins in Europe(1)

recent estimates suggest that recoverable shale gas reserves represent a much lower volume than2previously thought, and potentially as much as 85% less than U.S. Energy Department estimates ,3with some companies ending exploration activities . In France, shale gas developments have madelittle progress. The process of hydraulic fracturing is banned. However a committee has been set upwhich will assess the environmental risks of hydraulic fracturing and provide an opinion on theconditions for the implementation of research projects under public supervision.(Decreen� 2012-385of 21 March 2012 and Law n� 2011-835 of 13 July 2011).As with any drilling and extraction process shale gas extraction may bring environmental and healthrisks which need to be understood and addressed. In particular the contribution that potential shalegas production may make to climate change is a key issue. The European Commission (EC) hascommissioned a number of studies to investigate the possible consequences of exploiting shale gas.This study is aimed at exploring the evidence base for GHG emissions from shale gas and possibleways to mitigate these emissions through legislation and reporting mechanisms.

1.2 Objectives of the studyThe objective of this study is to provide state-of-the-art information to the European Commission onthe potential climate implications of possible future shale gas production in Europe.Four specific objectives were set out in the Invitation to Tender, as shown below.Study ObjectivesThe objectives of this study are to:Summarise and evaluate available knowledge on shale gas extraction technologiesand practises and the related GHG emissions;Analyse the suitability of EU legislation and propose EU wide policies that couldenforce the use of the most advanced technologies and practices to reduce GHGemissions;On the basis of the evaluation of the available data, provide an estimate of life cycleGHG emissions of electricity production using shale gas, taking into account all pre-production and production phases of shale gas extraction, and specifying both directGHG emissions, indirect emissions from fossil fuels used to extract and transport thegas as well as fugitive emissions and venting. The life cycle GHG emissions should bebased on current and future European power generation efficiencies as compared withlife cycle emission estimates using other fossil fuels;Provide an assessment of the adequacy of GHG emissions reporting frameworks tocover fugitive emissions of the production of shale gas and, if needed, proposemeasures for its improvement.The study does not have an objective to explore the potential role of shale gas in the future energysupply mix, or any potential implications of the exploitation of indigenous shale gas resources on thedevelopment of renewable or other energy sources in Europe. These issues are importantconsiderations for energy and climate policy makers, but are beyond the scope of this study.However, the results provided here can be used as inputs to any discussions around these issues.

2.2 Overview of shale gas productionConventional gas refers to gas trapped in multiple, relatively small, porous zones in rock formations.This gas is often difficult to find but, once discovered, is typically the easiest and most cost-effective toextract. Conventional reservoirs (rock formations where gas is found) are typically in sandstone,siltstone and carbonate (limestone) (British Geological Survey, 2011).Shale gas, along with tight gas and coal bed methane, is an example of unconventional natural gas.The term “unconventional” in this context refers to the characteristics of the reservoir, or bearing rockformation, from which the gas is extracted. The term does not refer to the characteristics orcomposition of the gas itself which is similar in composition to “conventional” natural gas. Figure 1schematically illustrates the location of these different types of natural gas deposits.Figure 1: Schematic cross-section of the subsurface illustrating types of natural gas deposits(From: U.S. DOE, Energy Information Administration, 2011b)

2.3.1.2DrillingAs outlined in Section 2.1 the extraction of shale gas requires both vertical drilling and horizontaldrilling. The vertical drilling process is very similar to drilling for conventional fossil fuels. A temporarydrill head is brought to the site and erected over the well head. Typically compressed air or freshwatermud is used as the drilling fluid. The depth of drilling will depend on the geology, but may reachdepths of 2km. Horizontal drilling requires a larger temporary drilling rig and may extend from the well3head for more than 1km (NYSDEC, 2011). This will generate cuttings in excess of 140 m (Brodericket al, 2011). This amounts to approximately 40% more drill cuttings compared to a vertical well(NYSDEC, 2011).Once the well is drilled it is cased to seal it from the surrounding rock. Typically the casing is in theform of, depending on depth, one or more steel pipes lining the inside of the drilled hole which arecemented in place. The well is then fitted with a well head which is suitably designed and pressurerated for the hydraulic fracturing operations.

2.3.1.3Hydraulic fracturingHydraulic fracturing (fracking) is the process used by gas producers to stimulate wells and recovernatural gas from sources such as coal beds and shale gas formations. During hydraulic fracturing,fluids (usually consisting of water and chemical additives) together with a ‘proppant’ are pumpeddown the well at high pressure. When the pressure exceeds the rock strength the fluids open orenlarge fractures. These fractures can extend a few hundred metres away from the well. As thefractures are created the propping agent enters the fractures. This prevents them from closing whenthe pumping pressure is released.The fracturing fluids are primarily water-based fluids mixed with additives. Chemical additives aremixed with base fluids. This modifies the fluid mechanics to increase performance of the fracturingfluid but also to prevent corrosion to the well pipes. The composition of fracturing fluids vary, King(2012) states that the proppant makes up 1% to 1.9% of the total volume. NYSDEC (2011) gives theproppant between 8% and 15%. Fracturing fluid performance can be measured by several differentstandards, but most typically, is measured by the ability of the fluid to place proppant into thefractures.The proppant is needed to ‘prop’ open the fractures once the pumping of fluids has stopped and thepumping pressure is reduced. Sand is commonly used as the proppant, but in the U.S. there has4been a move away from sand into specialised fracturing beads and propping agents .Once the fracture has initiated additional fluids are pumped into the wellbore to continue thedevelopment of the fracture and to carry the proppant deeper into the formation. The additional fluidsare needed to maintain the downhole pressure necessary to accommodate the increasing length of

2.3.1.4Flow back and waste water treatmentAfter hydraulic fracturing is completed a proportion of the injected fracturing fluid, depending on thegeological formation, rises to the surface. This recovered fluid is called flow back fluid (flow back). Inaddition to flow back, naturally occurring water, termed Produced Water, flows to the well head. Thisliquid, combining flow back and produced water, is collected and sent for treatment and disposal orre-use where possible.Specifically flowback fluid refers to fluid returned to the surface after a single hydraulic fractureprocess has occurred, but before the well is placed into production. It typically consists of returnedfracturing fluids in the first few days following hydraulic fracturing. This is progressively replaced byproduced water.Within the flowback fluid there is a varying content of water. As this is returned to the surface it can beclassified either as water, i.e. that which will be used in further hydraulic fracturing stages, or as wastewater, i.e. that which is unsuitable for reuse and is discharged from the site for treatment or recycling.The volume of water that can be recycled is variable. Yoxtheimer (2012) states that 77% of flow backwater is estimated to have been recycled in the U.S. in 2011, however in the Barnett shale,approximately 1% - 2% of water is recycled; in the Fayetteville shale where there is only 10%flowback, most of that is re-used but that is atypical. The flow back fluid, in addition to water, containsa combination of sand, hydrocarbon liquids and natural gas (see Section 2.2.1.3). Where the waterwithin the flow back fluid cannot be reused, it requires disposal. The waste water may be disposeddirectly by injection into a used well, or transported for treatment at a waste water treatment facility.Produced water is fluid displaced from the shale formation, and can contain substances that are foundin the formation. This may include dissolved solids (e.g. salt), gases (e.g. methane, ethane), tracemetals, naturally occurring radioactive elements (e.g. radium, uranium), and organic compounds,Produced water will typically begin to flow to the well head following an initial hydraulic fracture andmay continue to flow to the well head for the duration of gas extraction. Because of the nature, andcontent, of produced water it is typically collected in tanks for later treatment.

2.4 Comparison of high volume hydraulic fracturing andconventional hydrocarbon extraction practicesTable 2 sets out the stages of a high volume hydraulic fracturing activity and summarises thedifferences between this and conventional hydrocarbon production (adapted from U.S. EnvironmentalProtection Agency (U.S. EPA, 2011a and NYSDEC, 2011).Table 2: High Volume Hydraulic Fracturing: Stages, Steps, and Differences from ConventionalHydrocarbon PracticesDevelopme StepDifferences from Conventional Hydrocarbon practicesnt &ProductionStageSiteSelectionandPreparationSite identificationSite selectionNoneNoneNoneNoneNoneMore space required during hydraulic fracturing for tanks / pitsfor water / other materials required for fracturing process(NYSDEC, 2011).More lorry movements during hydraulic fracturing thanconventional production sites due to need to transportadditional water, fracturing material (including sand / ceramicbeads) and wastes.Obtaining large volumes of water (9,000 to 29,000 m per well)(NYSDEC, 2011).Disposing of large volumes of contaminated water (9,000 to3

25,000 m per well) (Derived from Broderick et al, 2011).Storage of large volumes of water (9,000 to 29,000 m perwell).Will require sufficient trucks / tanks onsite to manage flow back3(e.g. 250 - 625 trucks at 40 m per truck) (derived fromNYSDEC, 2011).Site preparationInstallation of additional tanks / pits sufficient to accommodate3up to 29,000 m of make-up water.6 - 10 wells / pad (NYSDEC, 2011) compared to 1 well / padfor conventional production.Fewer well pads / hectare: 1 multi-stage horizontal well padcan access c. 250 hectares, compared to c.15 hectares for avertical well pad (NYSDEC, 2011).Well Design, Selection ofConstruction horizontal vs.andvertical wellDevelopmentWell drillingBoth conventional and unconventional wells are drilled throughwater bearing strata and require same well design standards.Horizontal drilling produces longer well bore (vertical depthplus horizontal leg) requires more mud and produces morecuttings / well. Typically 40% more mud and cuttings forhorizontal well, depending on depth and lateral extent(NYSDEC, 2011).Horizontal drilling requires specialist equipment: larger dieselengines for the drill rig uses more fuel and produces moreemissions. Equipment is on site for a longer time (typically 25days for horizontal well compared to 13 days for vertical well;NYSDEC, 2011).However, horizontal wells provide a more efficient means toaccess gas reserves than conventional vertical wells, otherfactors being equal (U.S. EPA, 2011a). Consequently,horizontal drilling from a limited number of well heads would inprinciple be preferable to vertical drilling from a larger numberof well heads. In practice horizontal drilling techniques arenormally used to open up reserves, which would not otherwisebe viable with vertical drilling techniques, and so thiscomparison is not directly relevant.CasingCasing material must be compatible with fracturing chemicals(e.g., acids).Casing material must also withstand the higher pressure fromfracturing multiple stages.3

3.2 Compilation of the evidence baseMuch of the current evidence base originates from the U.S. There is little European evidence assignificant shale gas operations are, with the exception of limited exploration activities, not yetoperational in Europe and typical practices are yet to be established.Most studies estimating the GHG emissions from shale gas production are relatively recent, with thenumber of studies growing steadily over the past 2 years. As far as possible, the analysis presentedrepresents the state of research at the time of writing. It is important to note that certain limitationsand uncertainties in the evidence base remain. These are discussed further below.In practice, there are a small number of LCA studies that are regularly referenced by the widerliterature. These include the studies by Broderick et al (2011); Howarth et al (2011); Jiang et al(2011), Santoro et al (2011); and Stephenson et al (2011). With the exception of Santoro et al (2011),all of these papers have been published in peer-reviewed journals or publications. Other studies havebeen prepared by government agencies. For example, Skone et al (2011) is a report prepared by theU.S. Department of Energy National Energy Technology Laboratory. These studies form the basis ofthe review conducted for this report.The LCA studies reviewed draw upon a wider pool of primary research and data on specific shale gasoperations and practices. These sources are used to support the assumptions that are made by thestudy authors in their emissions modelling. The source of these primary studies is diverse, andincludes industry estimates, as well as estimates by governments and their agencies. Some of themain studies were referenced in the previous chapter, including reports from the U.S. EPA (2011b)and NYSDEC (2011). These studies have typically not been independently peer-reviewed, although inthe case of the government studies may have been subject to formal consultation with stakeholders.The estimates also frequently originate from specific sites or regions, so may not be fully applicable toother locations.The following sections describe our findings for each of the process stages described in Section 2.2.As with the original LCA studies the GHG emissions have only been considered from the perspectiveof normal state operating conditions, therefore fault conditions have not been considered.

CO2, averaged over 100 years. The 4 Assessment report of the IPCC (IPCC, 2007) gives a value of25 (on a mass basis) for this 100-years GWP, revised up from their previous estimate of 21. Thisvalue is relevant when looking at the long-term relative benefits of eliminating a temporary source ofmethane emissions versus a CO2source (IEA, 2012).Averaged over 20 years, the GWP, estimated by the IPCC, is 72. This figure can be argued to bemore relevant to the evaluation of the significance of methane emissions in the next two or threedecades, which will be the most critical to determine whether the world can still reach the objective oflimiting the long-term increase in average surface temperatures to 2 degrees Celsius (IEA, 2012).Moreover, some scientists have argued that interactions of methane with aerosols reinforce the GWPof methane, possibly bringing it to 33 over 100 years and 105 over 20 years (Shindell, 2009). Theserecent analyses are under review by the IPCC.Since different studies may apply different GWP values for methane when expressing the results incarbon dioxide equivalents (CO2eq), it is important to make this clear when making comparisons. Inthe results presented below emissions are presented in CO2eq using GWP (100 years) of 25. Somefurther exploration of the potential influence on the assumed GWP on the overall results is presentedin the summary section at the end of this chapter.

3.3 Pre-production stagePre-production comprises a number of subsidiary activities. These include:Site preparation (access road and well pad production);Drilling;Hydraulic fracturing.Well completion and waste water treatment.GHG emissions can arise from each of these activities. The main sources of emissions and therelative scale of emissions are discussed further below. The estimates are based upon publishedliterature. Where possible comparisons between different studies have been made and differences inthe results explained. However, due to a lack of transparency in the calculations or differences inapproach, it has not been possible to make direct comparisons in all cases.For each of the sub-stages a summary of the estimates is provided in the tables that follow. Inpresenting the results the emissions estimates have been calculated as absolute values in consistentunits (per well pad). This corrects for the different assumptions that have been made in the studiese.g. the productivity of the wells.

3.3.2 Energy use in drilling and pumping3.3.2.1Emission sourcesEmissions arise from the energy used in the drilling of the well bore, and in the pumping of water andother material during hydraulic fracturing.During the drilling phase a temporary drilling rig is brought to the well pad and erected on site. Energyfor the drilling operation (and all ancillary support activities such as well pad lighting and crewhousing) is normally provided by large, diesel-fired internal combustion engines. In some instancesthe drilling rig may be powered by the local electric grid instead of diesel engines. The drilling rigengines are a source of combustion-related pollutants including CO2. The quantity of fuel consumed,and the associated emissions, will depend upon the length of the well bore. Each horizontal wellboremay be around 1,000 to 1,500 metres in lateral length but can be more (NYSDEC, 2011). This step ofthe process is the same for conventional and unconventional gas wells, with the exception ofhorizontal drilling, which is specific for shale gas wells.Hydraulic fracturing is essential for shale gas production. It involves the high pressure injection of thefracturing fluid into the well. The process is typically powered by large, diesel-fired internal combustionengines.The fracturing phase requires significantly more energy to fracture the formation than required to drillthe wellbore. Depending on the number of fracturing phases involved in stimulating the formation thisstep may last from several days to several weeks. For example a multi-stage fracturing operation for a1200 metre lateral well typically consists of eight to thirteen fracturing stages (NYSDEC, 2011).

3.3.2.2Emission estimatesExisting estimates of emissions from drilling and hydraulic fracturing are based upon bottom upestimates of the quantity of fuel required, or total power requirements, which is then applied to anappropriate emissions factor. The most important assumption in this calculation is therefore theassumed fuel and / or power requirements, which in turn relate to the specific characteristics of thesite (e.g. depth and lateral length of the well and number of wells).In Table 4 existing estimates of the emissions from drilling and hydraulic fracturing are compared. Toease comparison, results are presented as absolute emissions per well.Table 4: Existing estimates of emissions associated with drillingSourceEmissions estimate(per well) (tCO2eq)Relevant assumptions and methodologyEmissions from drilling:Vertical drilling depth 2,600metres, Horizontal drilling length 1,200 metres.610 - 1,100Power of drilling rig assumed to be 2,500 to 6,600 HP, will adrilling time of 210 to 380 hours.Lifecycle diesel engine emission factor of 635 g CO2eq perHP–hr.Emissions from pumping:Pumping energy multiplied byemission factor.230 - 690Power of pumping equipment assumed to be 34,000 HP,with a pumping time of 10 to 30 hours.Lifecycle diesel engine emission factor of 635 g CO2eq perHP–hr.

Total well length of 3,878 metres, consisting of 2,678 metresdepth and 1,200 metres of lateral length.Energy use based on a single well.Santoro et al(2011)1,426Emissions from drilling:Includes prime movers - thedrilling rig's main power source. Drilling time is assumes tolast 4 weeks with engines running 24hr/day.Emissions from pumping:Use of pumps with power of9,300 HP. Fracturing time is assumed to last 70 hours ofpump engine time.Emissions from drilling:Assumed to be the same asconventional wells. Assumes 15 days at 12 hours operationper day.Emission calculated on basis of 4,500 HP engines, with fuelconsumption of 250g/kWh.Emissions from pumping:Assumes 2 hours per operationand 15 operations per well.Emissions calculated on basis of 12,250 HP engines, withfuel consumption of 250g/kWh.Emissions from drilling:Horizontal drilling of 1,000 –1,500 metres. Vertical drilling is excluded from the estimate.49 to 74Fuel use of 18.6 litres of diesel per metre drilled, whichequates to an emission factor of 49kgCO2/m.Diesel emission factors of 2.64 kg CO2/litre.Broderick etal (2011)*Emissions from pumping:Based on average fuel usagefrom hydraulic fracturing on a horizontally drilled well in theMarcellus Shale.295Assumes total fuel use of 109,777 litres of diesel fuel perwell.Diesel emission factors of 2.64 kg CO2/litre.Notes: * Estimate for Marcellus Shale used for consistency with other studies.With the exception of the Broderick et al (2011) study the estimates of emissions from drilling andpumping are of a similar order. The estimates from Santoro et al (2011) are within the range providedby Jiang et al (2011). The estimates from Stephenson et al (2011) are just below the lower rangeprovided by Jiang et al (2011). The range in the estimates appears to be driven by the assumptions5relating to the HP and time required for drilling and pumping (hours).The estimate from Broderick et al (2011) is lower than the other estimates, particularly for drilling. Thiscan, in part, be explained by methodological differences. For example, Broderick et al (2011) onlylook at additional impacts so only included horizontal drilling and not vertical drilling. However, evenallowing for this adjustment, the estimates appear a little low in comparison with the other estimates.

Original water source 50% surface water and 50% watertreatment plant. Water transported by truck from a localpublic water system 8 km – 16 km (5-10 miles) from thesite.Jiang et al(2011)64Assume a recycling rate for drilling mud of 85%. Theestimated truckloads for taking water to the sites, and7waste water from the site is 315,671 kg per km (560 ton-mile per) well.Trucking load is 35,513,003 kg per km (63,000 ton-mile) fortransport of fracturing water to the site, and 140,924,615 kgper km (250,000 ton-mile) for transportation of waste fluid.Uses lifecycle emission factor of 0.094 gCO2eq/kJ.Assumes 321 km (200 miles) per truckload for drilling andcompletion equipment and an average of 201 km (125miles /per truckload) for water chemicals and wastes.Assumes 280 truckloads for drilling and completionequipment and 1,069 truckloads for fresh water, chemicalsand wastes. Truckloads are doubled for round trips and50% load factor assumed.Emission factor of 0.455 litres per km (0.161 gallons / mile)for diesel trucks.Assumes water use of 22,700m per well for hydraulicfracturing. 40% of water brought to well is assumed to berecycled, so water and waste truckloads reduced accordingAssumes 60 km round trip.Assumes 485 to 750 truck visits per well (of which 90%attributed to fracturing) for water deliveries.Assumes a water volume of 9,000 m to 29,000 m per well.HGV emission factor of 983g CO2/km.Analysis based on the assumption of 25,331 km (15,740miles) to 37,079 km (23,040 truck miles) for a 1 wellproject.Stephensonet al (2011)224Assumes 18,160 m of water per well, and that 50% of thewater is sent for treatment.Water transported by truck with a round trip distance of 241km (150 miles) by road.33338

For the two studies that estimated the emissions associated with waste water treatment the variationin the estimates is significant, with the Jiang et al (2011) study estimating emissions of the order of 30times greater than those estimated by Broderick et al (2011). This difference can be explained by theuse of different methodological approaches. The Broderick et al (2011) study used an emission factorthat was based on the CO2emissions associated with waste water treatment in the UK, as reportedby the water industry. In the Jiang et al (2011) study, emissions were estimated based on cost data,and the estimated emissions from ’support activities for oil and gas’. It is not clear what the scope ofthese support activities is and therefore how comparable the estimates are with the Broderick et al(2011) study.Stephenson et al (2011) also included an estimate for the energy use associated with wastewatertreatment, based upon an energy intensive reverse osmosis and evaporation or freeze–thawevaporation technology. However, the value reported for the estimated energy use per well does notreconcile with estimated energy use for the treatment process that is quoted in the same paper. It hastherefore not been included in the table above. However, even with this uncertainty, the estimatedenergy use appears closer to that implied in the estimate by Broderick et al (2011), rather than theestimate by Jiang et al (2011).

3.3.6 Well completion3.3.6.1Emission sourcesUpon completion of hydraulic fracturing a combination of fracturing fluid and water is returned to thesurface (flow back). The flow back contains a combination of water, sand, hydrocarbon liquids andnatural gas. Where the water within the flow back fluid cannot be reused, typically the producedwater, it requires disposal. The waste water may be disposed directly by injection into a used well, ortransported for treatment at a waste water treatment facility.Equipment used at an existing gas well under production conditions, including the piping, separator,and storage tanks, are not designed to handle this initial mixture of wet and abrasive fluid that comesto the surface. Standard practice has been to vent or flare the natural gas during this step, and directthe waste water into ponds or tanks (Armendariz, 2009). However, the temporary installation ofequipment designed to handle the high initial flow of waste water, including gas - as part of aReduced Emission Completions (see Section 2.3.1.4), is becoming more commonplace.. ReducedEmission Completions have been used by some companies to reduce methane emissions in Texas’Barnett Shale in the U.S. since 2004 (Devon Energy, 2012). In addition, the States of Colorado andWyoming and the City of Fort Worth require the use of ‘green completions’ on all hydraulicallyfractured wells.After some time, the mixture coming to the surface will be largely free of the water and sand, and thenthe well will be connected to the permanent gas collecting equipment (Armendariz, 2009).Emissions from the well completion stage are short-term, typically occurring over a period of severaldays (U.S. EPA, 2011b). The level of emissions will depend upon the volumes of methane in thewater flow back, the quantities of water flow back, the length of the flow back period and themanagement practices that are applied.

3.3.6.2Emission estimatesWell completion is the most important step in the pre-production phase of shale gas exploitation, interms of the associated GHG emissions. However, the level of emissions is highly uncertain andsubject to current debate.During the course of this study, the evidence base on the emissions associated with unconventionalwell completions has evolved. In particular, the U.S. EPA carried out a detailed review of theseemissions as part of the derivation of a series of emission factors to underpin GHG reporting in theU.S. An emissions factor for gas well completions with hydraulic fracturing was published in 2011, foruse in the 1990-2009 U.S. GHG inventory (U.S.EPA, 2011b). Following further consultation of thesefactors, and additional research, the emission factors were updated in 2012 (See box below).In the intervening period, separate estimates have been published by other authors. Some of themain estimates are summarised below. This is then followed by a discussion of the latest U.S. EPA(2012b) analysis, which included a review of reported estimates from a wide range of sources, andtherefore represents the most comprehensive examination of emissions from well completion.The estimated gas release rate during the well completions stage, as used in a number of publishedstudies, is provided in Table 8. A brief description of the basis for the estimates is also provided.Since the assumed management practices will influence the net release of emissions, these havebeen separated out and where possible the emissions are presented on an unmitigated basis. Inpractice, this may not represent the actual emissions from the well, since mitigation measures such asReduced Emissions Completions, may have been employed.It is also important to note that the estimates are not restricted to shale gas formations in all cases,with other unconventional gas formations (tight gas, coal bed methane) also taken into account insome of the estimates.

Table 8: Existing estimates of emissions associated with flow backGas release rate3(thousand m )Unmitigatedemissions (t CO2eq)ApproachData from four industrypresentations at a technologytransfer workshops (greencompletions). Together thepresentations represented datafrom over 1,000 wellcompletions, for a range offormation types, with hydraulicfracturing. For each datasource, EPA calculated theaverage gas release per gaswell completion. The four datasources were arithmeticallyaveraged to determine the finalemission factor for gas wellcompletions with hydraulicfracturing.Data on methane capture forfour site (all emissions assumedto be vented in study), and theprojected releases for the fifth(and largest) site.Calculated gas leakage (usingEPA 2011 calculationmethodology) during thecompletion of 98 (shale gas ortight sand) new gas wells fromdata provided by 5 (self-selected) companies. Averageemissions were calculated bycompany and by shale gasbasin. Only non-greencompleted wells were includedin the sample.Release per flow back event,based on a modelled releaserate and flaring rate.

The Howarth et al (2011) estimate was based on information on five unconventional gas sites. Two ofthe sites were shale gas wells, and three were tight gas. For four of the sites the gas release rate wasbased on data from sites that had employed reduced emission completion technologies (RECs), sothe gas release rates were essentially estimated from gas capture rates. The estimate for the fifth siteat Haynesville, and the largest of all five estimates, was based upon gas flow rates data for 10 welltests. The use of the Haynesville data has been criticised by some authors. Cathles et al (2011) arguethat the assumption by Howarth et al (2011), that the gas flow rate data can be assumed to representto the gas venting rates during the well completion, is incompatible with the basic physics of gasproduction and the economic incentives of gas production. Cathles et al (2011) claim that becauseinitial production is the highest flow achievable, and flow back occurs when the well still containssubstantial water, flow back gas recoveries cannot exceed initial production recoveries as assumedby Howarth et al (2011) for the Haynesville site. It is also argued that the volumes of gas vented bythis site represent $1,000,000 worth of gas and present a fire / explosion hazard that no companywould countenance (Cathles et al, 2011). Further criticism is made by IHS (2011), whose report wascited by Howarth as the source of the Haynesville data. IHS (2011) state that Howarth made an“improper calculation of the average of the individual well flow rates” and an “improper attribution ofthe (improperly calculated) average flow rates from all the wells as occurring during flow-backoperations”. More specifically, the average flow rate stated in the Howarth study was based upon anaverage of eleven well tests. However, this included the double counting of data for the most prolificwell, which increased the calculated average. In addition, only one of the ten wells reported wasmeasured during flow-back. The others were measured while the wells were being completed(capped and connected to pipelines).The release rates published in Jiang et al (2011) are lower than those from the Howarth et al (2011)study but are not based on actual site data. Instead a modelling approach is used to estimate therelease rate, which in part explains the large variations in emissions, even though it represents asingle site.The estimates presented in URS (2012), which was a report prepared for America’s Natural GasAlliance (ANGA) and the American Exploration and Petroleum Council (AXPC), are much lower thanthe other sources. This source captures industry data from 98 new wells that were non-greencompleted (i.e. completions without Reduced Emission Completions). The emissions were calculatedby URS (2012) using the U.S. EPAs calculation methodology. The authors concluded that theemission factor quoted in U.S. EPA (2011b) was potentially overestimated by 1200%. However, inreviewing the URS (2012) results, the U.S. EPA (2012b) found a miscalculation in the analysis.3Correcting this error, the U.S. EPA (2012b) calculated an emission factor of 1,400 m (50,000 Mcf),10which is a factor of 6,400% greater than the value reported in the original URS (2012) study .Derivation of defaultfactors for Unconventional Well Completionsemission factors in thelatestU.S. EPA GHG Reporting ProtocolThe U.S. EPA has compiled a series of GHG estimation methodology and reporting protocols foroperators to use as guidance to underpin GHG reporting under new mandatory reporting systems inthe U.S.; operators in the oil and gas sector must start to report their GHG emission estimates to theU.S. EPA from the year 2010 onwards, under the new mandatory reporting rule.The text in the U.S. EPA guidance (Appendix B) that outlines the process of deriving the factors issummarised below:The U.S. EPA derives a series of emission factors for unconventional well completions based ondata from eleven U.S. gas industry studies; the studies include well completion emissionestimates from a number of different geological formation types (shale, tight gas, coal bedmethane) and present emission estimates for unmitigated well completions and reduced wellcompletions;The analysis includes a critical review of all of the industry sources and identifies wheresubmissions by industry are evidently incorrect in their application of the (agreed) U.S. EPAemission estimation equations for well completions;The U.S. EPA document presents five different approaches to deriving an aggregate emissionfactor from the industry source data: weighted average by well completion from all eleven studies10

(across all formation types), un-weighted average by data source, weighted average by wellcompletion by formation type (shale, tight gas and coal bed methane), weighted average by wellcompletion across all formation types using total national data on well completions by type (i.e. torepresent the U.S. data on numbers of well completions by formation type rather than just fromthe data available within the eleven studies), and a weighted average across tight gas and shalegas formation types (as these show similar levels of emissions);The U.S. EPA then assessed the various outcomes from these approaches as derived a “finalemission factor” for all unconventional gas well completions to be 9,000 Mcf per completion3(254,700 m ), whilst the factor derived specifically for tight gas and shale gas formations3(discounting the much lower estimates from coal bed methane) was 11,025 Mcf (312,007.5 m )per completion.The weighted average factor for tight gas and shale gas formations of 11,025 Mcf (312,007.5 m ) isregarded by the study team as the “best” factor to use as a central estimate within this study, but itmust be noted that there is a high degree of reporting variability and uncertainty from across theindustry studies. This factor equates to approximately 312,000 m3 per completion (unmitigated), or167 tCH4(3,503 t CO2eq).3

In the existing estimates of emissions from well completion in the preparation of a technical supportdocument for the oil and gas industry’s reporting of GHG emissions (U.S. EPA, 2012b). Thedocument provides further details on the industry estimates used in the draft technical supportdocument (U.S EPA, 2011b), as well as reviewing additional evidence supplied by industry andenvironmental organisations as part of the consultation on the new Performance Standards that thedocument supports. Analysis was carried out of different ways to combine the data sets, and theassociated emission factors. In addition, a statistical analysis was carried out to explore the variabilityin the emissions data. This level of uncertainty is highlighted by Pétron et al (2012), who applieddispersion modelling analysis techniques to estimate overall methane loss to the atmosphere arounda U.S. shale gas field and estimated emissions at a level double that estimated by the U.S. EPAmethodology.As a result of this analysis the U.S. EPA recommended a default emission factor for emissions of gas3per unconventional gas well completion of 9,000 Mcf (thousand cubic feet) (254,700 m ) percompletion. Further details on the derivation of the default factor is summarised in the box above.A further important consideration is the management practices that are used for managing the gasesin the flow back liquid. In the estimates provided above the emissions were assumed to beunmitigated. However, in practice flow back gases will not be simply vented, with flaring of emissionsand gas capture techniques employed. This, of course, has an important influence on the results ofthe LCA.Evidence from the U.S. EPA Gas Star programme suggests that Reduced Emissions Completionsmay achieve mitigation of fugitive / vented methane from well completions of around 90%. Applyingthe 90% reduction estimate to the recalculated U.S. EPA factor for shale and tight gas formations (i.e.311,025 Mcf per completion, 312,007.5 m ) provides an emission factor of Reduced Emission3Completions of 31,000 m per reduced emission completion, or 350 tCO2eq per completion.

3.5 Transportation and distributionMethane (CH4) emissions, due to leakage, during this stage are a significant proportion of the totallifecycle emissions. However once the gas has entered the distribution pipelines leakage rates, andtherefore emissions, are the same whether the gas has been supplied from conventional or shale gasreserves. For example Howarth et al (2011) estimate that for both sources the fugitive emissions ofmethane are between 1.4% and 3.6% of the methane produced over the lifecycle of a well. HoweverStephenson et al (2011) estimate that losses would be lower, suggesting based in the 2009 APIcompendium that 0.066% of gas is lost to fugitive emissions over 1440 km (which was taken as atypical distance for transmission to a power station in the U.S). The report notes that data from theU.S. EPA (2011) inventory report suggests that over the whole industry this could be higher, withlosses from transmission and storage accounting for roughly 0.52% of total gas production. Howevereven this value is much lower than the lower limit suggested by Howarth et al (2011).Stephenson et al (2011) also estimate that about 1.4% of gas would be consumed by compressorstations along the pipeline, again assuming a distance of 1440 km.

3.7 SummaryThe life cycle emissions estimated in the studies reviewed above, plus those of Skone (2011) andLechtenbohmer (2011), are summarised in Table 11. The table sets out values for the base casesassumed, plus where numerical values are available, the results of sensitivity analysis. Results arepresented for 100 year GWP for methane (CH4)and nitrous oxide (N2O).The different boundaries assumed in the studies need to be taken into account in comparing resultsfrom the studies: Stephenson et al (2011) did not estimate emissions from the construction phase;and Broderick et al (2011) has only examined emissions which are additional to those fromconventional gas extraction, so has not examined well construction, and has only considered thehorizontal element of drilling. Howarth et al (2011) only included fugitive emissions, so the resultspresented have been combined with those from Santaro et al (2011), as suggested in the Howarth etal (2011) paper in order to capture the full range of emission impacts. One further factor to bear inmind is that Howarth et al (2011) has used a 100 year GWP for methane of 33 in calculating theCO2eq of methane emissions, whereas all of the other studies have used the GWP for methane of 25,as set out in the IPCC Fourth Assessment Report (2007). Howarth et al (2011) justifies the use of thisRef: AEA/ED57412/Issue 2

higher GWP on the basis that more recent modelling (Shindell et al, 2009 as referenced in Howarth etal, 2011) which better accounts for the interaction of methane with aerosols. However as Broderick etal (2011) note, these processes are not yet well supported by a robust set of computer models.Emissions from pre-production stages are compared in Figure 4. It is clear that the greatestcontribution to emissions comes from the well completion stage, whether this is assumed to happenonly once at the beginning of the production cycle, or several times as the well is worked over (asassumed in Skone et al, 2011). Estimates of emissions from this stage vary significantly between thestudies, with that from Howarth et al (2011) being considerably higher than in the other studies, evenafter allowing for the use of a higher GWP, which will increase the methane contribution to totalemissions by about a third compared to the other studies. Assumptions about the type of completionalso have an influence, as can be seen from the Stephenson et al (2011) values, where the basecase assumes 51% of the gas produced during flow back (that which is contained within the flow backliquid) is flared, compared to 98% in the low case and 0% in the high case where all the gas is vented.Similarly the high case in Broderick et al (2011) assumes that all methane produced during flow backis vented. The range in Broderick et al (2011) is in fact based on the other studies shown in Figure 4,but in the case of Howarth et al (2011) the value has been adjusted to a GWP of 25. Even so, thisvalue (at 15.3 g CO2eq/MJ) is still considerably higher than values reported in the other studies (0.3 to7.1 g CO2eq/MJ).The second most significant source in this stage is drilling and hydraulic fracturing, where emissions(which range from 0.6 to 2.8 g CO2e/MJ (for the base cases). The emissions arise from a range ofenergy using source including: powering drilling equipment; transport of water to site and waste wateraway from site; processes to supply water and treat waste water, and ‘embedded carbon’ in theproppant and chemicals used in the hydraulic fracturing fluid. The relative importance of theseactivities varies from study to study, reflecting both site characteristics (e.g. transport distances), andmethodological choices (e.g. approach to estimating emissions from waste water treatment).Emissions from land clearing, site preparation and construction of well pad, access roads and wellcasings, including emissions associated with transport and production of materials are smaller (0.1 to0.6 g CO2eq/MJ for the base cases).The importance of assumptions about the productivity of the well are shown clearly in the results fromJiang et al (2011), and this is to be expected, as emissions from this preproduction stage aregenerally independent of lifetime gas production, so their contribution per MJ of gas declines directlyas gas production increases.Similarly the results from Skone et al (2011) indicate the importance of assumptions about the11emissions associated with re-fracturing, as reflected in the relative contribution from workovers , at60% of total emissions estimated.

Figure 5 compares total life cycle emissions from the combustion of shale gas, for studies which havealso examined emissions associated with gas treatment and gas transmission. For studies wherecombustion was not estimated; Skone et al (2011); Howarth et al (2011) and Lechtenbohmer (2011) avalue of 58.1 g CO2eq/MJ from Stephenson et al (2011) has been assumed. A breakdown ofemissions between gas treatment, transmission and combustion is not available from Jiang et al(2011), so these are shown only in total in the Figure 5. In all cases, except Howarth et al (2011), theemissions from the pre-production stage, where emissions will differ from conventional natural gasproduction, are 3% to 12% of total life cycle emissions. Where flaring rates for gas produced duringwell completion are high or the well has a very high productivity, then the contribution may be reducedto 1.4% or less. In the case of Howarth et al (2011), the contribution of the pre-production stage tooverall life cycle emissions is 23%. This is because of the high methane emissions assumed duringwell completion and higher GWP factor used for methane. Fugitive losses of methane during pipelinetransmission of the gas are also assumed to be higher in Howarth et al (2011) than other studies,which together with the higher GWP assumed, means that the estimated contribution fromtransmissions is much higher in the Howarth et al (2011) study than other studies leading to a muchhigher overall emissions of 100 g CO2eq /MJ of gas compared to values of 65 to 76 g CO2eq/MJ forthe other studies.

4 Best available techniques forreducing GHG emissions4.1 IntroductionThis chapter summarises and evaluates the available knowledge on shale gas extraction technologiesand practices and the related GHG emissions.As the most significant difference in GHG emissions from shale gas production compared toconventional gas production arises in the pre-production phase the analysis is focussed on thisprocess. However we note that, in particular for the production phase, there are significant emissionsfrom conventional equipment. For example pumps and compressors, and will note that improvedtechnologies for these that could contribute to an overall reduction in GHG emissions from shale gasproduction. Reductions from the emissions due to leakage from gas distribution pipes will requireimprovements to the gas supply infrastructure off-site and, except for new pipes laid to connect thewell head to the gathering, treatment and distribution system are likely to be outside the scope of theshale gas producers.The U.S. EPA’s Natural Gas STAR programme is a voluntary partnership which encourages oil andnatural gas companies to adopt cost effective technologies and practices to both improve operationalefficiency and reduce methane emissions. The U.S. EPA has recently finalised New SourcePerformance Standards (NSPS) for the Oil and Natural gas sector (U.S. EPA, 2012a). The U.S. EPAproposal for NSPS (U.S. EPA, 2011b) and the background technical support documents for the rule(U.S. EPA, 2012c) and the proposal (U.S. EPA, 2012b) provide a review of best practice which couldbe applied in the oil and gas sector. In particular these provide best practises for: well completionsand recompletions; pneumatic controllers; compressors; storage vessels and equipment leaks. Thedata in the next sections use this as a basis which is supplemented from other sources.

4.2 Pre-production4.2.1 Site preparationAppropriate site selection and preparation may reduce GHG emissions, and in particular CO2,fromcombustion emissions by reducing fuel consumption. Preparation of the well pad requires resources,for example to level the site, prepare well cellars and install impermeable membranes. Use of existingroads, water resources and other infrastructure can minimise such work and the associated emissionsfrom their construction. Provision of on-site storage of water and hydraulic fracturing fluids is oftenachieved through use of mobile tanks but some sites install reservoirs or lagoons for water and drilling/ hydraulic fracturing fluids, but these have to be removed and land restored on completion. Use oftransportable tanks will generally require less site preparation but this will depend on the site andavailability of water, quantity of generated materials and treatment facilities. Consideration of drillingand well completion requirements during site selection will avoid or minimise situations wherecombustion or recovery of flow back gas (or accidental releases) might be constrained by proximity tobuildings or other amenity space.The NYSDEC (2011) report suggests the following measures which could be included to reduce theseemissions:Drilling as many wells as possible using one rig move;Optimising the well spacing for efficient recovery of natural gas;Planning for efficient rig and fracturing equipment moves from one pad to another.Site selection may also be important in reducing transport emissions which could be further reducedby:

4.2.2 DrillingAs outlined in Section 3.2.2.1, during the drilling phase, a temporary drilling rig is brought to the wellpad and erected on site. Energy for the drilling operation (and all ancillary support activities such aswell pad lighting and crew housing) is provided by large, diesel-fired internal combustion engines. Asmentioned previously this step of the process is the same for conventional and unconventional gaswells. Horizontal drilling is required for shale gas and may also be used for conventional gas (and oil).Drilling is not a significant source of methane emissions, but the drilling rig engines are a source ofcombustion-related pollutants such as nitrogen oxides (NOx), carbon monoxide (CO), carbon dioxide(CO2), and unburned hydrocarbons (HC). Three-way catalytic oxidizers may be used on drilling rigengines to reduce non-CO2emissions. Use of gas engines or engines powered from the localelectricity grid may also be possible if supplies are available at the site.Appropriate well design and supervision, including choice and depth of casings, seals and monitoringare essential to assure safety, avoid gas / fluid migration and maintain well integrity during the drillingphase.

A reduced emission completion involves the temporary installation of equipment designed to handlethe high initial flow of water, sand, and gas. A sand trap is used to remove the solids, and is followedby a three phase separator which separates the water from the condensate (liquid hydrocarbons) andgas. The gas is then sent to a sales pipeline (or to other processing facilities where needed). Wherethe pipeline infrastructure is not yet in place to receive saleable gas, the gas stream may be routed tosuitable storage before treatment and transfer offsite or a temporary flare.While not currently required in the U.S. at the national level, green completions have been used bysome companies to reduce methane emissions in Texas’ Barnett Shale since 2004 (Devon Energy,2012). In addition, the States of Colorado and Wyoming and the City of Fort Worth require the use ofgreen completions on hydraulically fractured wells. The U.S. EPA has recently finalised regulationsthat will require the use of reduced emission completions including the recovery of gas for sale on allnew hydraulically fractured gas wells, as well as on re-fractured gas wells from 1 January 2015. Priorto this date completion will be by flaring or capture plus flaring. Green completions are not requiredfor:new exploratory wells or wells used to define borders of a natural gas reservoir;hydraulically fractured low pressure wells (such as coal bed methane wells).However emissions must be reduced using combustion unless combustion is a safety hazard orprohibited by local regulation.

4.2.4.2.1LimitationsLimitations include:Availability of pipelines to transport the gas for sale or of equipment for other forms of naturalgas utilisation (e.g. small scale power production).During the exploratory phase the sales pipelines may not have been constructed.Pressure of the produced gas.If pressure is too low then it may be difficult to displace the hydraulic fracturing fluid -compressed natural gas or inert gas may need to be pumped down the well to help displacethe hydraulic fracturing fluid. Low pressure may limit effectiveness of any treatment stages (itmay not be possible to produce sales or pipeline quality gas) and will limit the amount of gasthat can be recovered into a storage vessel (without additional compression).oIf the concentration of inert gases, such as CO2or N2,is too high then it may not bepossible to economically recover the natural gas and as above it may be necessary toflare the gas until the composition of the gas is acceptable. Furthermore, a source ofcontinuous ignition may be required until the energy content of the gas is sufficient tosustain a flame.

4.3.1 Gas treatment (sweetening)The processes used to remove CO2, N2and sulphur compounds from shale gas are the same asused in conventional gas wells. It is anticipated that gas will not be treated at the wellhead or well pad(although this is possible) but would be brought to a central gathering and refining station to providegas which is suitable for compression and transfer to the gas transmission infrastructure. Typicallythis will require reduction in moisture (dehydration), inert gases (CO2, N2) and might requireseparation of natural gas liquids and non-methane hydrocarbons, recovery of helium, reduction ofhydrogen sulphide and mercury.Where natural gas terminals / refineries are already in place (for conventional gas) this may beachieved by some initial processing of the gas at the field’s gathering / compression to allow transport(by pipeline) to the terminal. In other instances, the gathering station will need to undertake treatmentof gas to the national or regional transmission pipeline requirements. In the latter case, the installationmay be considered to be a refinery and a regulated activity under Directive 2010/75/EU (IEDDirective) and hence best available techniques would be applied.

4.3.5 Compressors4.3.5.1DescriptionNatural gas compressors may be installed at a wellhead to assist in natural gas extraction during thelater stages of well life to increase pressure from an individual well to a gathering station. Typicallycompressors will be located at gathering / processing stations to allow gas treatment and to enableexport to the transmission pipeline. Two types of compressors can be used, centrifugal compressorsand reciprocating compressors. These compressors are typically powered by natural gas-firedengines or turbines, which emit combustion by-products such as NOx, CO, CO2, and hydro carbons.In some urban oil and gas fields in the U.S. these compressors may be powered off of the localelectrical grid, eliminating these local, combustion-related emissions. In addition to the combustion-related emissions, natural gas and methane may be emitted from wet seals in centrifugalcompressors and from the rod packing seals of reciprocating compressors. The methane emissionsfrom reciprocating compressors are significantly less than for centrifugal compressors. For centrifugalcompressors the use of dry seals (rather than wet seals) can be used to mitigate the methaneemissions (U.S. EPA, 2006c). For reciprocating compressors the emissions can be reduced by theperiodic replacement of the rod packing systems on reciprocating compressors (U.S. EPA, 2006d).

procedure by local inspectors. The requirements in these regulations have evolved to replace a rangeof historic drilling and plugging techniques and to avoid future environmental issues arising from wellswhich had been abandoned.Offshore, in the North East Atlantic and North Sea, the 1998 OSPAR decision 98/3 which mandates aclean seabed approach (with some derogations) and, the 2010 U.S. Interior Department BOEMRE‘Idle Iron’ regulations which requires permanent plugging and abandonment of wells and associatedfacilities if out of use for 5 years apply. However, these instruments are for protection andmanagement of the marine environment and do not apply onshore. There are industry guidelines forthe suspension and abandonment of offshore wells.Ideally, planning and development of the well needs to recognise that the well will have to beabandoned at some stage. Failure to consider abandonment at the design stage will make eventualabandonment more complex (and expensive).Plugging generally involves determining where barriers are needed within the well bore and aroundthe liners. Typically, cement is used to seal the surface, aquifer and hydrocarbon (production) zonesof the well (including ensuring a seal between the outer casing and surrounding ground). Other plugmaterials are available (expanding cement, resins, silicone rubber, clay gels and soft metal alloy).Tubing and other downhole equipment may need to be removed from the zones of the well where theplug(s) will be installed to avoid potential leak paths and hence failure. Casings will need to bebridged, cleaned and perforated to ensure effective seals (particular across annular spaces and withthe geology outside the casing). Casings may need to be penetrated to allow free movement ofcement for the seal. Offshore UK requirements are for two concrete plugs enclosing a non-cementpacking with the integrity of the plugs verified before removal and sealing of the top of the well (toabout 9 metres below the seabed) and restoration of the seabed.Onshore, multiple plugs may be required to provide isolation from the surface and avoid movement ofgas, hydrocarbons and / or water between different levels of the well bore.

4.4.3 CostCosts for onshore plugging and abandonment have not been established. In the U.S. a bond isrequired in the event that an operator fails to plug and abandon a well. Bonding is required underfederal regulations for oil and gas lease operations to ensure that operators comply with variousrequirements including plugging, abandonment and remediation / clean-up. The minimum bond is14$10,000 (or $25,000 for state-wide operation or $150,000 nationally ).State regulations also apply, for example Kentucky requires a bond of between $500 and $5,000 (thevalue paid depends on the depth of the well) with a higher value bond payable if the depth is greater15than 1219.2 metres and site conditions warrant a higher bond. The bond is held until all conditionsfor abandonment are met by the operator. Bonds for multiple wells are available and the value of themultiple-well bond is risk-related as multiple-well bonds for ‘qualified’ well operators are cheaper.Qualification is dependent on demonstrated compliance with Kentucky regulations and auditable proofof financial ability to plug and abandon wells.

4.5.1 Exploration and productionThe technologies described in the previous sections include measures which have beendemonstrated, and which are a regulatory requirement, in certain regions in North America (and willbe a regulatory requirement in the U.S. from 2015). Much of the concern regarding GHG emissionsrelates to well development and in particular completion and re-fracturing processes. Other activitiesare similar or identical to the development of conventional gas wells.Application of these practices for well completion and re-fracturing in Europe may however beconstrained by a number of factors:Geology: will wells in Europe have sufficient gas pressure to allow application of greencompletion (as opposed to combustion / flaring).Processing infrastructure for captured gas on well completion: at least initially any gas whichdoesn’t meet the sales gas specification would need to be processed further. This may be aconstraint if the pipeline or processing infrastructure is not in place and suitable connectionsavailable for transferring captured gas.Availability and experience in equipment / technology to capture the gas released on wellcompletion and re-fracturing activity: this is likely to be an issue in initial stages ofdevelopment until vendors develop suitable solutions.

During initial development of a well or reservoir there may be limited infrastructure. For example nogathering pipelines, no receiving / refining station (to modify sulphur / inerts / moisture contents),condensate removal and gas compression prior to connection to the gas grid. During re-fracturing,such infrastructure should be in place.The flow back period during well completion and re-fracturing generates flow back fluid whichcontains a mixture of sand, waste water, hydraulic fracturing liquids and gas (see Section 2.3.1.4)These phases need to be separated and, for green completion, the gas (and condensate) recovered.The gas may not be suitable for despatch to a distribution pipeline (sales quality) but even ifcompletion gas composition is sales quality there is likely to be a need for further processing (for16example moisture removal) before it can be introduced to a distribution pipeline .Treatment of the completion gas before entry into national or regional gas transmission pipelines willbe dependent on:

Availability of a gas processing / refining station capable of making gas meet the transmissionspecification;Transport to the refining facility, connection via a local gathering pipeline or tanker transfer.The recovery process for completion gas in the U.S. is not clear and it may be that recovery can beachieved by simply blending with gas from production wells and treating in on-field processing units.If completion gas is close to sales quality and needs fairly minor treatment then this may be achievedby storing the gas for a short period and then mixing (diluting) with production gas locally. Similarly, ifthe production gas goes to an on-field or near field gathering and refining facility then mixing withproduction gas may be a viable approach.There are existing European gas refineries but these may have limited capability (at present) toreceive off-specification gas. They may be some distance from the unconventional gas field andwould require connection to the unconventional gas fields.Many European countries do not have gas refineries (gas is transferred at sales quality from otherregions). In countries with conventional gas reserves, natural gas refineries are located at or near thegas reserves (or where pipelines to offshore reservoirs make landfall) and similarly LNG terminals arelocated at locations which are convenient for LNG import.

4.5.2 Downstream processingE&P are not prescribed activities under the Industrial Emissions Directive (IED) (IED Directive2010/75/EU) or preceding instruments (in particular Directive 2008/1/EC on integrated pollutionprevention and control, IPPC). However, gas refining and associated activities are prescribedactivities under the IED. The relevant prescribed activities under IED are:1.2 refining of mineral oil and gas.1.1 Combustion of fuels in installations with a total rated thermal input of 50 MW or more.These activities are common to ‘downstream’ processing and transport of natural gas from bothconventional and unconventional sources. Refining of gas from unconventional sources would besubject to IPPC / IED provisions which requires application of best available techniques for refineries(IPPC bureau, 2003) including (with an emphasis on measures which can influence GHG emission):Reducing VOC emissions (for example best available techniques includes quantifyingsources and using LDAR campaigns);Implementation and adherence to an Environmental Management System;Application of good practise for maintenance and cleaning;Implementation of a monitoring system;Improve energy efficiency.Many of these are management techniques rather than specific technologies.

5 Hypothetical estimation of thelifecycle greenhouse gas (GHG)emissions from possible future shalegas exploitation in Europe5.1 IntroductionIn this chapter we estimate the lifecycle GHG emissions of electricity production from shale gas,taking into account the direct and indirect GHG gas emissions associated with gas extraction,transportation and use, including pre-production and production phases (excluding the explorationstage). Direct emissions are those that occur during operations, e.g. from venting of gas, or from thecombustion of fuels used to provide power or transport; indirect emissions are those associated withproduction of materials used in construction and operation of the wells. This exercise is largelyhypothetical, considering the need for further data and the uncertainties regarding EU shale gasdevelopment in comparison with North America.The emissions from shale gas are then compared to lifecycle GHG emissions of electricity productionfrom conventionally extracted natural gas, from liquefied natural gas and from coal. In all of the LCAs,we have only considered emissions arising from normal operations, as it is standard practice in anLCA to exclude emissions related to accidents and spills etc. (JRC-IES, 2010). For gas production,the main source of potential emissions from accidents is fugitive emissions from blowouts, theuncontrolled release of gas from a well when pressure control systems fail. Emissions from potentialblowouts are excluded from both the shale gas and conventional gas LCAs.

5.2 Modelling the shale gas life cycleIn developing the LCA for shale gas we have modelled a hypothetical shale gas site located inEurope, as not enough data was available for a particular site to produce a site-specific LCA. Wehave therefore made use of mainly U.S. based data, drawn from a number of background studies(e.g. NYSDEC, 2011) and also information used in the LCAs reviewed in Section 3. Where everpossible we have compared this with information on likely practices in Europe (e.g. based oninformation provided in planning applications by Cuadrilla for their UK developments).It is important to note that the analysis is hypothetical, and represents an illustration of the potentialscale and significance of emissions from shale gas exploitation in Europe, based upon experiencesfrom the U.S. In practice the actual emissions from shale gas operations in Europe will be influencedby site-specific characteristics, and by the management practices and technologies employed. In thehypothetical analysis the relative influence of these factors has been explored as part of the sensitivityanalysis, wherever data is available to do so.The lifecycle GHG emissions factors for materials, fuels, transport, and water supply have all beentaken from the EcoInvent database and other lifecycle studies.As in other studies, we have assumed that after well completion, emissions associated withprocessing and transmission of the gas will not differ significantly from conventional gas processingand transmission. We have therefore adopted common assumptions for these stages for both shalegas and natural gas from conventional sources. This is based upon data for operations relevant forEurope. It is important to note that as with the pre-production stage there will also be uncertainties inthe emissions associated with these other stages in the lifecycle. These have been explored in lessdetail within this current report as we have focussed on what is specific to shale gas.

As with gas from conventional sources, shale gas comprises a mix of methane, other heavierhydrocarbons such as ethane, propane and butane, and CO2. The literature offers differing opinionsas to whether there are any systematic differences between the composition of shale gas andconventional gas. For example, Wood et al (2011) note that there is conflicting commentary on this17issue. They cite INGAA (2008), who note that natural gas production from the Barnett fields tendsmainly to be ‘wet’ (i.e. has a high ratio of heavier components to methane) and a low CO2content,although this varies significantly across the field. On the other hand, ALL Consulting (2008) suggestthat shale gas is typically dry gas composed primarily of methane (90% or more methane), and thatwhile there are some shale gas formations that do produce gas and water, they are the exceptionbased on data from those plays with active development. Stephenson et al (2011) concluded, basedon data from the 2011 U.S. EPA Inventory report, that there was no systematic variation in the CO2content of conventional and unconventional gas production, and therefore used a single gascomposition (typical of average U.S. gas composition) to model both conventional and unconventionalproduction. Jiang et al (2011) give no information on what assumptions were made about gascomposition. No data was available in the literature on the composition of shale gas in Europe, andwhether this is likely to differ significantly from conventional gas composition. We have thereforeadopted the approach of Stephenson et al (2011), and assumed a typical conventional gascomposition for shale gas. As the UK is one of the key potential areas for shale gas production in theEU, as well as being a significant producer of natural gas, we have taken the gas composition for UKnatural gas, as assumed in the LCA for conventional gas, as the composition of the shale gas in theLCA.It is clear from the previous LCAs that the main factors affecting estimates of life cycle GHGemissions are:Overall lifetime shale gas production of the well;Methane emissions during well completion which are dependent on the quantity of methane inthe flow back liquid and the treatment of this methane (e.g. venting, flaring or greencompletion);Number of re-fracturing events and the associated increase in productivity that result fromthese.We have therefore conducted sensitivity analyses on each of these aspects. We have alsoconsidered how the location of the site could affect the distances that materials, water and wastewater must be transported to and from the site and have examined the impact that this may have onoverall emissions.We have considered emissions of the three main GHGs, CO2, CH4and N2O and for our main analysishave applied 2007 IPCC Fourth Assessment Report GWPs of 25 for CH4and 289 for N2O. As afurther sensitivity we have also examined the impact of using the GWPs from the Second AssessmentReport (21 for CH4and 310 for N2O) as currently used in national inventories for reporting under theKyoto Protocol, and of using of the higher GWP for CH4(of 33) utilised in the LCA by Howarth et al(2011).

5.2.1 Modelling conventional gas and coal life cycle GHG emissionsIn order to have a comparison with electricity generation from conventional natural gas and coal, lifecycle GHG data for gas and coal from countries which are a key source of imports into the EU havebeen produced. The EU currently produces 20% of the total volume of natural gas consumed by the27 Member States. The two main EU producers are currently the Netherlands and the UK, who alsopossess by far the largest proven, ‘discovered potential’ and ‘undiscovered potential' reserves in theEU27. The other 80% is imported, 85% of which stems from Russia, Norway, Algeria and liquidnatural gas (LNG) producers in the Middle East.As a basis for comparison with the shale gas supplies, the conventional natural gas sources whichwere modelled are the UK, Norway, Netherlands, Russia and Algeria, plus LNG from the Middle Eastand Algeria.For coal based generation, the three main sources of imported coal into the EU which were modelledare Russia, South Africa and South America.

5.2.2 Exploration phaseEmissions from the exploration phase have not been considered in existing LCAs of conventionalnatural gas. This is because the emissions are considered small in comparison to other stages of thelifecycle, which in turn relates to the large amounts of energy extracted per well. A further reason isthe large uncertainty concerning the amount of natural gas to which the environmental impacts relatedto exploration (see below) and well preparation has to be allocated to.In the case of shale gas, similar arguments apply about how exploration emissions should beallocated to a well. In some cases, the exploration phase for shale gas may result in a considerablenumber of wells, and more than might be expected from conventional gas. However, the way theseemissions should be allocated to the final shale gas that is delivered is a matter of debate. However, amore important difference between shale and conventional gas is that the productivity of the well istypically much lower than conventional gas wells, meaning that during the exploration phase (whichalso involves hydraulic fracturing and pilot production testing) emissions will be higher per unit ofenergy delivered.The exploration phase is not considered in any of the LCAs of shale gas which were reviewed for thisstudy, and therefore due to a lack of data this phase has not been included in our LCA. Similarly,published LCAs of the conventional gas cycle have not considered the exploration phase, and so it isexcluded from the LCA of the conventional gas cycle in this study.Exploration for conventional gas reservoirsAlthough exploration is a core business for gas producing companies it cannot be categorically linkedto production. Some exploration will lead to production, some will not. This means that it is hard toinclude exploration in a life cycle approach that tries to assess environmental impacts associated witha unit of natural gas. An additional complication is that exploration for gas is often tied to explorationfor oil. At the exploration stage, there is no knowledge of the yield of either gas or oil and if it sohappens that only oil is found, allocation to gas is impossible, although the exploration was targetinggas as well as oil. Therefore it is common practice to exclude exploration from the life cycle inventoryand assessment (not only for fossil fuels, but also for mineral ores, see e.g. MSD2001).

5.3 Gas Life Cycle5.3.1 Preproduction stage –Shale Gas5.3.1.1Site preparationThe trend in the U.S. is increasingly towards the use of multi-well well pads. This effectively reducesthe above surface footprint of the site compared to single-well sites. We have therefore assumed, asin Jiang et al (2011) and based on the NYSDEC report (2011), 6 wells to a well pad. This is consistentwith Broderick et al (2011) who state that 6 to 8 wells per pad is typical.Based on data in NYSDEC (2011), it is assumed that 3 ha of land would need to be cleared for asingle multi-well pad. This estimate includes land for access roads, the well pad itself, water andelectrical lines, gas gathering lines, and a compression facility (shared with other well pads). This isslightly higher than the value assumed in Jiang et al (2011) of 2.6 ha and Santoro et al (2011) of 2.4ha. The most detailed breakdown of equipment required to clear and prepare the site is given inSantoro et al (2011) and we have therefore used these assumption: i.e. 6 bulldozers and 1 excavator(with a power of 335 HP and 159 HP respectively) are used to prepare the site, and that these canprepare about a hectare per day.Land use change emissions due to removal of vegetation are estimated as 167 tCO2/ha, based on theemission factor for land clearance quoted in Santoro et al (2011) of 167.5 tCO2/ha. Once again this ispotentially a conservative estimate, being significantly higher than the factor implied by Jiang et al(2011) of 12 tCO2/ha.

prime mover i.e. drilling rig is considered). Based on NYSDEC (2011), it is assumed that drilling a wellwill take about 4 weeks (about 2 weeks for vertical drilling and 2 weeks for horizontal drilling), and thatplant operates 24 hours per day at 50% load. The drills are assumed to be diesel powered, as is thecase in most of the U.S. studies.The length of the well is assumed to be 2678m vertically and 1200m horizontally, which is arepresentative figure for Marcellus shale gas well from Chesapeake (2009) as quoted in Santoro et al(2011). These characteristics are assumed to provide a reasonable representation of conditions inEurope, based on current evidence. For example, shale gas beds in Poland and the Baltic states areat a depth of more than 2 km although shallow beds do exist (e.g. the Allum shale in Sweden). In theUK, the IEA (2012) suggest the Bowlands shale is relatively shallow, with an average depth of only1,600m. However, Cuadrilla (2010), on the basis of their planning application, indicate the depth ofwells could be up to 3000m.Other emissions are associated with material used in the drilling phase. This includes water required3 18for the drilling mud, which is assumed to be 455mper well, and 13,000 kg bentonite, which is the3main component of drilling mud (based on 20 kg bentonite needed per m of water). These estimatesare based on information in Jiang et al (2011). This aspect was not considered in the other LCAstudies reviewed in Section 3.Water for drilling can be sourced from nearby surface water, brought in by pipeline from the utilitywater supply, or bought in by tanker. Most of the U.S. studies assume water is brought to the site bytruck. However, there is evidence that the transportation of water by pipeline is becoming increasinglycommon (NYSDEC, 2011). The choice of water sources will be site specific as it depends on anumber of factors (distance to the water abstraction source or water distribution network, the easewith which approval can be obtained for abstraction and construction of pipelines, and the ease andcost of constructing pipelines). Emissions from water provision are generally highest when the wateris tankered in and we have therefore assumed in our base case that all water is tankered in. We havealso conducted a sensitivity analysis, where we examine the reduction in emissions if all water was tobe delivered by pipeline rather than tanker.It is assumed that water, bentonite and the drilling equipment itself has to be transported a distance of100km to the site. We have also examined the sensitivity of the results to this assumption, by alsomodelling cases where the transport distance is lower (50km) and higher (250km).

5.3.1.4Hydraulic fracturingFor the hydraulic fracturing of a well, the pumping requirements suggested in Santoro et al (2011) areassumed, i.e. that pumps with a total HP of 9300 operate for 70 hours per well at full load to completea series of 15 hydraulic fracturing events. This running time is based on data from NYDEC (2009) andis for average injection rates and pressure ranges found in Marcellus shale. The updated NYDEC(2011)study reports no change in these typical running times. In addition it is assumed that a 1200 HPgenerator operates at 50% load for a similar period of time. The estimate of running time may beconservative, as other studies, e.g. Jiang et al (2011), assume that 15 hydraulic fracturing events willonly require 30 hours of running time.Water required for the hydraulic fracturing of one well is assumed to be 18,184 m as used by Jiang et3al (2011). This is within the range suggested by NYCDEC (2011) of 9,000 to 29,000 m . Stephenson3et al (2011) also assume a water requirement of 18,184 m , Santoro et al (2011) assume a slighter1819

5.3.1.5Well completionThe emissions arising from well completion are based on the U.S. EPA’s Background SupplementalTechnical Support Document for Standards of Performance for Crude Oil and Natural GasProduction, Transmission, and Distribution (2012b). As described in Chapter 3 this documentprovides a detailed review of emissions from unconventional gas completions, taking into accountevidence gathered as part of the consultation on the draft document.The updated U.S. EPA document provides a range of estimates that could potentially be applied inthe emissions analysis:31) 9,000 thousand cubic feet (Mcf) (254,700 m ) of gas per completion is given as the defaultvalue for unmitigated emissions from unconventional gas completions (i.e. shale, tight andcoal bed methane (CBM)).32) 6,123 Mcf (173,281 m ) of gas per completion is given as a lower value based on (similar to)95% confidence interval for unmitigated emissions from unconventional gas completions (i.e.shale, tight and coal bed methane).33) 11,676 Mcf (330,431 m ) of gas per completion is given as an upper value based on (similarto) 95% confidence interval for unmitigated emissions from unconventional gas completions(i.e. shale, tight and coal bed methane).34) 11,025 Mcf (312,006 m ) of gas per completion is provided as an estimate for just shale/tightgas based on the weighting of data by two formation categories (CBM and tight sands / shale)based on the number of completions in formation categories.In the LCA an emissions factor of 11,025 Mcf (312,008 m ) of gas per well completion has beenapplied, since this latter estimate reflects the fact that emissions may vary by formation type (i.e.emissions from shale and tight gas may differ from CBM). It is also similar to the upper value acrossall formation types. This is an unmitigated value. For our base case we assume that 15% of theseemissions are flared (with a combustion efficiency of 98%), with the remaining (85%) vented. We alsoconducted sensitivity analyses to establish the reduction in emissions resulting from a higher flaringrate (90%) and from green completion, and the increase in emissions if all of the gas is vented.We also constructed a pessimistic scenario, where well completion emissions are assumed to be3higher at 14,000 Mcf (396,200 m ), and are all assumed to be vented. Since a 95% confidence level3for the value of 11,025 Mcf (312,008 m ) was not calculated in the EPA (2012b) report, we haveestimated what might be a realistic upper limit for this estimate by taking the ratio between the centralvalue and upper values stated for all unconventional completions.203

trend towards reuse and that operators plan to maximise reuse, although this can be constrained byhigh levels of contaminants in the flow back water, or a lack of other wells close enough for the waterto be reused.Jiang et al (2011) suggests that 30% to 60% of water which has flowed back can be reused;suggesting that overall (for a central estimate of 45% reuse) about 17% of the water used forhydraulic fracturing ends up as waste water which must be treated. Stephenson et al (2011) makes amore pessimistic assumption that 50% of the water used for hydraulic fracturing ends up as wastewater which must be treated. We have adopted this latter, more conservative assumption in ouranalysis.Flow back water can be disposed of in several ways, by tankering the water off site to dispose of bydeep well injection, disposal in municipal sewage treatment works, or in a specialised industrial wastewater treatment plant. An alternative practice in the U.S. is to store the waste water in open pits; thisoption has also been utilised at the Lebien LE-SH well in Poland. Such water would still requiretreatment before it could be disposed of. However, NYSDEC (2012) reports that operators proposingto drill in New York State would not routinely propose to store flow back water either in reserve pits onthe well pad or in centralized impoundments.Previous studies have assumed either disposal in municipal waste water treatment facilities(Broderick et al, 2011) or in specialised waste water treatment facilities (utilising reverse osmosis andevaporation or freeze – thaw evaporation) (Stephenson et al, 2011), or deep well injection (Jiang et al,2011). NYSDEC (2011) highlights that some contaminants which are likely to be present in flow backwater may not be properly treated in a standard sewage treatment facility, and that treatment in amunicipal sewage treatment plant can affect the plant due to the salt content of the water, which if notproperly handled, can reduce the overall effectiveness of the sewage works. We therefore do notconsider that disposal to standard sewage treatment facilities is likely to be a viable option fordisposal of flow back water. Instead we assume that more advanced treatment e.g. involving reverseosmosis (RO) is required, and base emissions associated with this on an electricity consumption for3RO of 4 kWh/m (Vince et al, 2007). It is assumed that the waste water is transported 100km to sucha facility, with the sensitivity to this assumption analysed in the transport sensitivity analysis.Injection to deep well for disposal of waste water is not discussed in the literature for extraction ofshale gas in Europe, and is therefore not considered. Storage in open pits would still requiretreatment of the water (potentially on site) before it can be discharged to surface waters, but couldremove the need to tanker the water off site. Our assumptions for waste water treatment cantherefore be considered to be conservative.Drilling mud is assumed to be transported 100km for disposal in a landfill.

5.3.1.7Productivity of wellThe overall productivity of the well is assumed to be 2 Bcf (56.6 million m ) based on Stephenson et al(2011). This is based upon a survey of production data published for unconventional gas fields in the3U.S. which gave an average productivity of 3.8 Bcf (107.54 million m ), and data from the U.S.Geological Survey which showed that the range for horizontal wells was 0.9 to 2.6 Bcf (25.47 million33m – 73.58 million m ) per well. Our assumed productivity is lower than that assumed in Jiang et al3(2011), of 2.7 Bcf (76.41 million m ). Broderick et al (2011) quote a lower range of 0.2 to 1.8 Bcf (5.6633million m – 50.94 million m ) although this is based on 2006 data. We have also carried out a3sensitivity analysis assuming that productivity in the wells is lower (1 Bcf / 28.3 million m ) and higher3(3 Bcf / 84.9 million m ); in both these sensitivity studies we have made the simplifying assumptionthat the well completion emissions are independent of the lifetime productivity of the wellA further consideration is the influence of re-fracturing on the overall productivity, and the associated21emissions. ICF (2009) suggest that re-fracturing can frequently restore the well’s production rateclose to between 75% and 100% of the initial rate, although the post-fracture production rate would beexpected to be lower with each subsequent re-fracturing treatment. The same report suggests that re-fracturing the well can increase the cumulative amount of gas recovered by 80% to 100%, but it is notclear how many re-fractures of a given well are required in order to deliver this return. Likewise, it isnot clear how frequent such events are. Due to the levels of these uncertainties we have not carried3

5.3.2 Preproduction stage – Conventional gasAs discussed earlier, emissions from the preproduction stage for natural gas (of both exploration anddrilling) have not typically been considered in existing LCAs of natural gas, and the exploration phasehas been excluded from our LCA of both shale gas and conventional gas. In order to ensure that theboundaries of the LCA for conventional and shale gas are equivalent, it is however necessary toestimate the emissions associated with well preparation i.e. drilling for conventional gas as this stageis included in the shale gas life cycle.Our estimate is taken from Stephenson et al (2011) which estimates the emissions associated withdiesel use for well drilling are 0.3 g CO2eq/MJ, assuming 15 days of 12 hour operation of 4500 HP3engines, and a productivity of the well of 2 bcf (56.6 million m ). In addition, we have used an estimatefrom Stephenson et al (2011) of 0.35 g CO2eq/MJ for methane emissions on well completion; this isbased on an estimate from the API compendium of 25.9 t CH4 per completion day, assuming that 2days are required to complete the well and that 51% of the methane emissions are flared. Theproportion of well completion emissions flared is based on data from the EPA. Values fromStephenson et al (2011) are used as this is the only LCA study reviewed which included estimates forthis stage for conventional gas.

5.3.3 Production stage5.3.3.1Pipeline gas productionExtraction of non-associated natural gas gives a mixture of raw gas, condensed higher hydrocarbons,free water and entrained particles. The raw gas is isolated from solids and fluids by flashing (alsoknown as primary separation), and must then be further processed to separate the methane fractionfrom co-products or pollutants such as:Water vapour;Acid gases (CO2, sulphurous compounds);Nitrogen (N2);Condensable hydrocarbons (C5+).Ethane, propane and butane may also be separated out where there is a use for them, e.g. apetrochemical industry which can utilize them as a feedstock in steam cracking. Which processes areapplied to treat the gas depends on the quality of the raw gas as well as the required standard for theprocessed gas. In the Netherlands, for instance, a high percentage of N2is still present afterprocessing.Most treatment processes require electricity for valves, pumps, etc. The electricity is often producedon site in the case of off-shore production and treatment or fields located in remote areas. For on-shore production in less remote areas electricity may be taken from the grid. Other inputs to thetreatment process include methanol, which may be added before dehydration, but is mostly recoveredand recycled, and activated carbon and glycol, involved in the desulphurization and dehydrationsteps.Based on publicly available data, it is assumed that the percentages of gas throughput shown inTable 12 are used to supply energy to treat the gas, or are vented or flared. This equates to thevalues shown in Table 13, for emissions per GJ of gas delivered to the power station.For Norwegian, Dutch, UK and Algerian pipeline gas, gas turbine consumption is associated withsubsea pipeline transport from either off shore gas fields (Norway, UK, Netherlands) or from one sideto the other of a sea (Algeria). Further discussion on the potential variation in the estimates isprovided in Section 5.3.4.1.Ref: AEA/ED57412/Issue 2

The applied data concerns country or operator averages and has been derived from EcoInvent(2007), ExternE reports and from company reports for operators in the Netherlands. EcoInvent data isin turn based on reports from operators and permitting authorities.For environmental impacts related to natural gas production in the EU and Norway data fromEcoinvent was taken. This data is somewhat older and does not necessarily reflect the current statusof technology and emissions.The data has been allocated to natural gas production, which means that the total impact related tonatural gas production or, in the case of the majority of Norwegian gas production, production of oiland associated gas has been divided over oil, gas, condensate and other products.In practice energy consumption related emissions and fugitive emissions will differ from well to well ortreatment plant to treatment plant, depending on:Level of depletion of the gas reservoir and associated requirements for depletioncompression;Composition of raw gas and processing required to clean the gas up to pipelinespecifications;Equipment applied and level of energy integration realized.This also explains the variations in alternative estimates. For example, in EcoInvent (2007) specificenergy consumption for gas treatment in Siberia is indicated to be 1% of produced and transmittedgas, while in the Austrian ExternE report a specific energy consumption of 0.65% of transmitted gas isindicated.Given the focus of the study and the size of the emissions it is beyond the scope of this study toconduct an in-depth analysis of the variations in GHG emissions for gas treatment. However, forillustration, the ranges demonstrated by the results for different regions in the table below, provides anindication of the relative uncertainty in these estimates.For the shale gas base case, we have assumed that gas use for treatment and fugitive emissions areat the same level as for UK conventional gas. We have also conducted a sensitivity analysis wherewe have assumed the higher levels of gas use for treatment associated with Norwegian conventionalgas.Table 12: Gas use for treatment and fugitive emissions (% of gas throughput)NetherlandsUsed to supply energyOf which:gas turbinedrying0.77%0.40%0.25%0.39%0.64%0.36%0.94%0.36%1.17%UK1.00%Russia0.64%Algeria1.00%Norway1.30%

5.3.3.2LNG productionLiquid natural gas (LNG) is natural gas cooled to a low temperature (-162 C) so it becomes a liquidoccupying a much smaller volume. It can then be transported over long distances without the need forfixed infrastructure. The LNG process consists of several steps: processing; liquefaction; transport;storage and regasification.The processing step for LNG is essentially the same as described above. The undesirablecomponents (H2O, CO2, etc.) are removed, and then the higher hydrocarbon fractions are removedduring the liquefaction process. Cooling down to condensation temperature is done in industrialinstallations, typically with a number of cooling stages, which can produce up to 5 Mton per year ofLNG. LNG often consists of both methane and ethane; liquefied ethane is re-added to fluid methaneafter methane liquefaction (as ethane liquefies before methane does). The by-products of LNGproduction are liquefied petroleum gas (LPG) and gasoline, the heavier fractions of the raw naturalgas.The LNG is stored in a full containment tank normally consisting of a concrete outer tank and an innertank of 9% nickel steel. The boil-off gas and pre-cooling and loading vapours are compressed andused as fuel gas for the liquefaction units or flared. Transportation to and from storage is driven bypumps. Storage may also take place at other stages in the LNG chain (after international transport orbefore regasification). Again, boil-off gas is mostly put to use, but may be vented in emergencies.o

5.3.4 Transmission stage5.3.4.1Pipeline transmissionAfter processing, gas is often transported over large distances, mostly through a pipeline systemconsisting of the pipeline, compression stations, import / export stations and metering. Gas iscompressed to pressures of approximately 70 bar before transport, and intermediate compressorstations along the pipeline compensate for the pressure loss that arises from the friction between thegas and pipeline wall. Compressors are almost always driven by natural gas, as this is obviouslyeasily available. In the case of undersea pipelines, the initial pressure may be higher (more than 200bar) since intermediate compression is not possible.Upon ’arrival’ at the receiving end, blending stations, metering and pressure-regulation stations aswell as export / import stations take care of the connection between the long-distance transmissiongrid and the regional distribution grid. Quality control, pressure (and temperature) control andodorisation take place at these points.Apart from energy consumption for the transport itself, maintenance and check-up activities,especially in remote areas, may require energy. Another source of gas ‘consumption’ during transportis leakage of the gas from the pipeline.The estimated consumption of gas for compression, and also the estimated leakage of gas frompipeline transmissions systems, is shown as a percentage of gas throughput in Table 17 and in termsof kg per GJ of gas delivered in Table 18. Emissions are based on transport from the gas field to theNetherlands (as a representative European location).For shale gas, we have assumed in the base case that gas is transported 500 km (giving an energyuse of 0.9% of gas through-put and diffuse emissions of 0.013% of gas throughput). We have alsoconducted a sensitivity analysis where it is assumed the gas is transported a distance of 1,000 km.Table 17: Emissions from Pipeline transmission (% of gas throughput)NetherlandsUsed to supply energyDiffuse emissions0.18%0.003%UK0.45%0.01%Russia11.60%0.68%Algeria7.02%0.10%Norway1.62%0.02%

Estimates of the GHG emissions related to pipeline transportation in Russia have been taken from a2005 study which made an inventory of GHG emissions within the Russian transmission system.Gazprom is however actively mitigating environmental impacts and current emission rates may beless than those included in the table above. Data for pipeline transportation within the EU were takenfrom the Marcogaz inventory and reflect country averaged data provided by the national transmissiongrid operators.In general, energy consumption will depend on demand on the pipeline and the velocity of the gas,and will change between seasons. For example, in the Netherlands during the summer, demand is atsuch a low level that gas injected in the transmission system can be transported to the customerwithout any intermediate compression, while in winter intermediate compression stations operate atnear full capacity (Sevenster and Croezen, 2005) Apart from the level of demand, the other maininfluence on emissions is the efficiency of the technologies used e.g. the driver for the transmissioncompressor, and also the level of mitigation measures taken to reduce fugitive emissions.

5.3.4.2LNG transportLong distance transport of LNG takes place primarily by cargo ships with an insulation system to keepthe temperature at -162�C. Boil-off gas provides a large fraction of the fuel needs for the ship, also onthe return journey when some LNG is left in the tanks to ensure that the gas concentration in thetanks is above the upper explosion limit (UEL).At the arrival port LNG is stored, pressurised with a pump, regasified and injected into the gas grid.Regasification consists of increasing the LNG temperature using (sea) water at roughly ambienttemperature as a heat transfer medium. After quality control, the gas is then ready to be transportedin the regular distribution network.The main processes leading to GHG emissions in this part of the life cycle are combustion emissionsfrom shipping, power consumption for pumping and re-liquefaction and combustion emissions relatedto regasification.During the voyage part of the LNG evaporates (boils off). The boil-off ratio (BOR) depends on theambient temperature, size and age of the ship, its speed and the level of insulation, and is minimizedby cell isolation. Typical values for existing tankers are about 0.2% of the full contents per day withnew designs having a guaranteed maximum BOR of 0.13%/day - 0.15%/day; BORs of < 0.1%dayhave been reported, but there are also data suggesting a boil off ratio of approximately 0.3%/day in22practice . Until recently, LNG carriers have been equipped with steam turbines powered by heavyfuel oil (HFO) and / or LNG boil off gas. The thermal efficiency of the boiler and steam turbineconfiguration in these vessels is approximately 30%. An alternative and new development is theapplication of diesel / LNG dual fuel engines. At present approximately 15 vessels with this newpropulsion system are on order. The engines can run on MDO (medium diesel fuel), HFO or boiled offLNG. A second new development is the re-introduction of a boil-off gas reliquefaction facility on-boardthe LNG carriers. In the current analysis we taken into account the first development, but not thesecond.The energy consumption and GHG emissions from LNG are determined by the:Travelling distance;Vessel size;Whether boil off is utilized as a fuel or not;The applied power generator for propulsion (boiler, engine, electric).There are no fugitive emissions since all vapour is collected to be used as a fuel.In the table below a comparison is made of the energy consumption and associated emissions per1,000km transport distance (with data from various sources).Table 19: Comparison of emissions estimates from LNG transport from alternative sources.Yoon &Yamada(Japan)Some study specific detailsTrip distance, one way (km)Cargo load (ton)One way or return trip considered?BOR- loaded voyage0.32%0.15%0.12%0.12%5,54052,977Not knownEcoInventMAN B&W + own calculation

The consumption data taken from Yoon & Yamada (2005) is based on information for 44 shipsshuttling between Japan and four of the major LNG production locations supplying Japan: Indonesia,Brunei, Australia and the Middle East. These figures may be considered reliable. The figures concernapproximately 40% of LNG transported. Emissions include the contributions of fuel oil utilization. InEcoInvent the total fuel requirement of the LNG tanker is assumed to be covered by boil off. However,this is not the case in most practical situations, as shown in the other studies.The figures given in the columns with the title ‘MANB&W + own calculation’mainly refer to a paperfrom MAN B & W (MAN, 2005) in which an economic comparison is made between a conventionalLNG tanker with steam turbine propulsion and an LNG tanker with a dual fuel engine. The analysis ismade for a new design (see low BOR and large volume) and is made applying rules of thumb.The emissions given in the columns with the title ‘MANB&W + own calculation’concern results ofown calculations. These are based on the assumed composition of LNG, heavy fuel oil and mediumfuel oil. The presented figures do not refer to a practical situation and can be qualified as estimates.The specific fuel consumption however does correspond well with the practical data given in (Yoon&Yamada, 2005).The similarity demonstrates that a good estimation can be made on the basis of rulesof thumb.Total estimated GHG emissions from LNG transport are shown in Table 20 as a percentage of gasthroughput and in Table 21 as kg of gas emitted per GJ of gas consumed. The transport relatedemissions assume shipping to the Netherlands and then 100km transport by pipeline.Emissions have been calculated assuming the specific average energy consumptions of 102kJ/tonne¶km of boil off gas and 205 kJ/tonne¶km of heavy fuel oil (MAN B&W average). Distances tothe North West EU amount to 5,000 km for Algerian LNG and 20.000 for Middle Eastern LNG.Table 20: Emissions from LNG transport (% of gas throughput)AlgeriaFor energy (shipping)For energy (regasification and pipeline)Diffuse emissions (pipeline)1.03%0.55%0.003%Middle East4.14%0.55%0.003%

5.3.6.1Shale gasAcross a range of scenarios, the emissions from the use of shale gas to produce electricity areestimated to be in the range of 409gCO2eq to 472gCO2eq per kWh of electricity generated. As forconventional sources of gas, emissions are dominated by the combustion at the electricity generationplant, which typically represents around 90% of the total emissions impact.A range of scenarios have been explored. There is no preferred scenario, although a base case hasbeen developed for the purposes of comparison. The base case is based on the assumptionsdescribed earlier and primarily assumes characteristics on the performance and management ofshale gas exploitation which is in-line with current practice in the U.S. Exceptions are transportdistances, which are lower reflecting the fact that exploitation sites in Europe are likely to be lessremote from utilities such as water supply, waste water treatment and sources of materials requiredfor site preparation than many U.S. sites. Whilst it is not necessarily the case that this represents abase case for practices in Europe, it provides a reasonable basis for comparison. A series ofscenarios are then explored which examine circumstances that deviate from the base caseassumptions including the management of emissions arising from flow back, the productivity of thewell and assumptions around transport impacts.The scenarios can be defined as follows.Base Case: this scenario assumes 15% of the emissions from well completion are flared and3the remainder are vented. It assumes a well productivity of 2 bcf (56.6 million m ), and atransport distance of 100km.The following scenarios take the characteristics of the base case and then test the sensitivity of one ofthe variables:High Productivity: the productivity of the well is 50% greater than in the base case.Low Productivity: the productivity of the well is 50% lower than in the base case.23

Re-fracturing: in addition to the initial hydraulic fracturing stage, the well is re-fractured onefurther time. It is assumed that this additional hydraulic fracture will increase the volume ofrecovered gas by 25%.Flaring: 100% of emissions from well completion are flared.Green Completion: 90% of emissions from well completion are captured and utilised and theremainder (10%) are vented.Venting: 100% of emissions from well completion are vented.Low transport: transport distances are at the lower end of range identified (50km).High transport: transport distances are at the high end of range identified (250km).Higher emissions from flow back: unmitigated well completion emissions are 14,000 Mcf3(396,200 m ), and are all assumed to be vented.Piped water: it is assumed that all fresh water required is piped rather than tankered in.Higher emissions from gas treatment and transmissions: transmissions distance for shale gasis increased from 500 to 1000 km and energy use for gas treatment is higher.‘Worst’ case scenario: this most pessimistic scenario combines all of the assumptions whichgive higher emissions i.e. low productivity, higher emissions from flow back gases, all ofwhich are vented, higher transport distances and higher gas transmissions distances.Details of how the parameters were varied are given in Table 22.Table 22: Parameters varied in each scenarioWellProduct-ivity overlifetime(bcf)Base CaseHigh ProductivityLow ProductivityRe-fracturingHigh transportLow transportUse of PipedwaterFlaringGreen CompletionVentingHigh flow backemissionsHigher Energygas treatment andtransport“Worst Case”2312.52222222WellProduct-ivity overlifetime(mil3lion m )56.684.928.370.7556.656.656.6No. ofWellWellTransporthydrauliccompletion completiondistance*fracturingemissions emissions(km)cyclesflaredvented

All of the results from the above scenarios are calculated based on using 100 year GWPs for CH4andN2O of 25 and 289 respectively as set out in the IPCCs most recent (fourth) Assessment Report.However GHG reporting in national inventories and under the Kyoto protocol uses 100 year GWPs of21 for CH4and 310 for N2O (as set out in the IPCC’s Second Assessment Report. We have thereforecarried out a sensitivity study to see the impact on lifecycle emissions of using these GWPs tocalculate the CO2eq emissions. Similarly we have looked at the impact of using the higher GWP of 33for CH4as used by Howarth et al (2011). Table 24 shows the impact of the different GWPs on thebase case, and on the scenario with the highest methane emissions – venting. Use of the GWP usedfor reporting under the Kyoto Protocol, reduces overall emissions by just under 1%, and use of thehigher GWP suggested by Howarth et al (2011), increase the estimate of overall emissions by 1.6% inthe base case and 1.8% in the venting scenario where methane emissions are higher.Table 24: Influence of GWP for methane on lifecycle emissions for electricity generation fromshale gas (g CO2/kWh electricity)GWP of 25g CO2 eq/kWhBase CaseVentingWorst case422.4424.7472.3GWP of 21g CO2 eq/kWh419.0420.9464.0GWP of 33g CO2 eq/kWh429.3432.4489.1

It is also interesting to compare the results from this study with the results from those studiesreviewed in Chapter 3.The results for the base case for the pre-production stages are shown in Figure 9, alongside theresults for the base cases in the other studies reviewed in Chapter 3. This study estimates lifecycleemissions for these stages which are within the range of those forecast in other studies. There arehowever some differences:Emissions from site preparation are larger than in some studies, and similar to others. Thisreflects the conservative assumptions that have been applied (e.g. on emissions from landclearance).Emissions from transport are comparable, but at the lower end of other studies. This is due partlyto the shorter transport distances assumed in the current study, based on the premise thatexploitation sites in Europe are likely to be less remote than in the U.S.Emissions from waste water treatment are comparable with one study (Broderick et al, 2011), butlower than the other (Jiang et al, 2011). Overall the contribution of this stage is small in all studies,although further research may be needed on emissions associated with treatment.

In the case of natural gas from the Middle East, the gas needs to be further processed to produceliquid natural gas requiring additional energy. Also, the impacts of transport are quite high as the LNGneeds to be transported via LNG tanker around Africa to Europe.The emissions associated with Russian gas are also quite high, largely due to the high contribution oftransport. This is primarily due to transport over long distances at high pressure in combination withpipeline leakages, more leakages occur due to poorly maintained compression stations and turbinesin combination with the fact that Russian gas requires more drying to prevent pipe corrosion.Natural gas from the Netherlands originates primarily from onshore wells in the province ofGroningen, which borders the North Sea. The processing of the natural gas has relatively low GHGimpacts compared to other countries as a result of energy savings achieved through a national longterm agreement for efficient industry and mining. Transportation impacts are relatively small due tolow compression energy demands and short transport distances. The high methane content of thenatural gas also results in fewer GHG emissions from combustion.Norwegian natural gas wells are located along the coastline in the North Sea. Similarly to natural gasfrom the Netherlands, Norwegian natural gas is processed using efficient best available technology.This results in relatively low GHG emissions per kWh. The transport distances, however, are greaterfor the supply of natural gas to continental Europe and as such the GHG impacts for transportationare greater. Norwegian natural gas also results in slightly more combustion emissions per kWh thanDutch natural gas as a result of different gas composition.Algerian natural gas is pumped from onshore wells throughout the country. The processing of naturalgas occurs fairly efficiently compared to that of natural gas from other non-European countries.However, the transportation of natural gas through pipelines has a relatively high GHG impact due tothe underwater pipeline, which requires high pressures to compensate a lack of compression stationsalong the Mediterranean Sea portion of the pipeline. As with Norwegian pipeline gas and MiddleEastern LNG, the GHG emissions per kWh from combustion are quite high.

5.4.1 Mining, preparation and shippingCoal is mined in both opencast and underground mines. In underground mines associated methanerich mine gas is partly utilized in mining processes for onsite heat and power generation. Anotherfraction is vented to air as part of ventilation air from the mine.Mined coal is ground and upgraded in the vicinity of the mine. Coal directly from the mine (also knownas ROM - run-of-mine) contains unwanted ingredients such as pyrite and gangue. For the removal ofthese deficiencies and in order to meet power plant client specifications the ROM is broken andseparated by screening into different fractions. The different fractions are purified applying gravityseparation technologies such as jigging, gravity separation baths and cyclones. The purified particlesare dewatered applying screens and centrifuges.After transport to the port by truck (sometimes pipeline or train), the coal is shipped with bulk carriersto the customer.The main GHG emission sources in mining and transport include diffuse methane emissions and CO2emissions from combustion of fuels for onsite heat and power generation and transports of run-of-mine coal and upgraded coal.At the power station, the coal is micronized and pneumatically injected with combustion air into theboiler. Radiation and sensible heat of the combustion is used for production of super critical or ultrasuper critical steam, which is next utilized for driving a sequence of steam turbines before beingcondensed.

Source: based on the EcoInvent databaseSouth American coal has the lowest GHG impact of three two types of coal. The non-combustionimpacts are practically negligible compared to those for other coal types. Coal mining in Columbia(the highest coal producing country in South America) in practice takes place in both undergroundmines and open-pit mines (approximately 50% of total production). The Included EcoInvent datahowever include only data for underground mines. These mines produce little mine gas as half of thegas is captured for use as fuel. The transport of coal from South America is very efficient and resultsin a low GHG impact. The coal is transported in bulk carrier ships with an average capacity of 60kton.The GHG emissions resulting from the combustion of South American coal is high, as a result of ahigh carbon intensity.South African coal has a slightly larger overall GHG impact than (underground) South American coaland the non-combustion GHG impacts are greater. Half of the mine gas is captured in South Africancoal mines, however due to greater methane emissions the GHG impact of the mining phase isrelatively large. The transportation of coal from South Africa takes place very efficiently, by means ofbulk carrier ship.Russia has the largest coal impact, mostly due to the extraction phase of the lifecycle. The high GHGemissions are as a result of two-thirds of the coal being underground. For this reason, a large amountof mine gas is produced. In addition, the processing of Russian coal has quite high impacts as a resultof a high energy use. Since Ecoinvent was used as a source for GHG impacts, it is unknown why theenergy use is so high.

with well drilling and gas transmission, both of which account for about 10% of emissions in the basecase.Figure 12 shows the range of lifecycle emissions estimated for shale gas, against those forconventional pipeline gas (from within and outside Europe) and for LNG.For the base case considered for shale gas, the GHG’s per unit of electricity generated are around4% to 8% higher than for electricity generated by conventional pipeline gas from within Europe. Ifemissions from well completion are mitigated, through flaring, or capture and utilisation then thisdifference is reduced (1% to 5%). This finding is broadly in line with those of other U.S. studies, whichfound that generation from shale gas had emissions between 2% to 3% higher than conventionalpipeline gas generation.This study also considered sources of gas outside of Europe, which make a significant contribution toEuropean gas supply. Based on this hypothetical exercise, and drawing upon existing LCA studies forconventional sources, the analysis suggests that that the emissions from shale gas generation (basecase) are 2% to 10% lower than emissions from electricity generated from sources of conventionalpipeline gas located outside of Europe (in Russia and Algeria), and 7% to 10% lower than electricity25generated from LNG imported into Europe .However, this conclusion is far from clear-cut. Under the ‘worst’ case scenario, where all flow backgases at well completion are vented, emissions from electricity generated from shale gas would be ata similar level of the upper emissions level for electricity generated from imported LNG, and for gasimported from Russia. This suggests where emissions from shale gas are uncontrolled, there may beno GHG emission benefits from utilising domestic shale gas resources over imports of conventionalgas from outside the EU. In fact, for some pipeline sources, emissions from shale gas may exceedemissions from importing conventional gas.Emissions from shale gas generation are significantly lower (41% to 49%) than emissions fromelectricity generated from coal. This is on the basis of methane having a 100 year GWP of 25. Thisfinding is consistent with those in most other studies.These conclusions are based on experiences largely drawn from the U.S. Whilst attempts have beenmade to take into account the different circumstances in Europe, and how this may influence theoverall emissions, this comparison is still largely hypothetical. Where the shale gas industry developsin Europe, this information should be used to update the results of the analysis.These results can also be used to inform future discussions on the potential role of shale gas in thefuture energy supply mix. It has not been the aim of this study to explore this issue specifically, orrelated issues surrounding the potential implications of exploitation of indigenous shale gas resourceson the development of renewable or other energy sources in Europe. These issues are importantconsiderations for energy and climate policy makers, but are beyond the scope of this study.

In the future, the electrical efficiency of new gas and coal power stations is expected to improve, asdescribed in the previous sections. Improvements in efficiency will reduce the relative emissions fromthe combustion of gas and coal in these power stations. Efficiency improvement in gas-fired powerstations will affect emissions from shale and conventional sources equally, as only the combustionstep is affected. In Figure 13 the lifecycle emissions from coal and gas fired electricity generation arecalculated on the basis of the high electrical efficiencies (65% for gas, 50% for coal) that might bepossible in the future. The estimates do not take into account any other technology improvements,such as the application of carbon capture technologies. Clearly the application of abatementmeasures of the kind will have a significant impact on the overall GHG emissions (from thecombustion stage) from both conventional and unconventional sources.Figure 13: Lifecycle emissions from coal and gas fired electricity generation, with futureimprovements in electrical efficiency

6 Legislation controlling GHGemissions from shale gas production6.1 IntroductionThis chapter builds upon previous sections within this report to provide an examination of thesuitability of different EU legislation for controlling the potential GHG emissions from shale gasproduction. Specific attention is given to policies which could enforce the use of most advancedtechnologies and practices designed to minimise potential GHG emissions.The analysis has included the following:An initial review of existing legislation relevant to the exploitation of shale gas reserves. Abrief overview is given for a range of relevant legislation and more detailed analysis carriedout for a narrower set of the most relevant legislation.An exploration using case studies of the implementation of key directives within selectedMember States (Poland, the UK and France).For both of these activities the focus is on the well completion stage given the relative importance ofthis in terms of GHG emissions.The analysis also includes a brief summary of the precedents set for emissions related to activitiessuch as flaring and vented CO2emissions from enhanced hydrocarbon recovery in the EU EmissionTrading System (EU ETS).

6.2 Initial review of existing legislationThis overview of the existing EU legislation relevant to exploitation of shale gas reserves focuses onEU legislation identified as relevant in two other documents, as detailed below. It should be noted thatthe documents have only been used for the selection of relevant EU legal acts and not for theanalysis itself as they do not directly cover GHG emissions at a level of detail necessary for this work:Source 1: “European Commission Guidance note on the applicable EU environmental legislation tounconventional hydrocarbon projects using advanced technologies such as horizontal drilling andhigh volume hydraulic fracturing.This guidance document identifies eight pieces of EU environmental legislation applicable to shalegas projects, and provides a brief commentary on these with the European Commission’sinterpretation. It has a direct relevance for applicable EU environmental legislation, therefore many ofthe identified pieces of legislation may have relevance to GHGs and thus to this project. The list ofeight is:EIA Directives (85/337/EC and 2011/92/EU): Council Directive of 27 June 1985 on theassessment of the effects of certain public and private projects on the environment,1985L0337and Directive 2011/92/EU of The European Parliament and of The Council of 13December 2011 on the assessment of the effects of certain public and private projects on theenvironment,OJ L 26/1, 28.1.2012.Mining Waste Directive: Directive 2006/21/EC of The European Parliament and of TheCouncil of 15 March 2006 on the management of waste from extractive industries andamending Directive 2004/35/EC,OJ L 102/15, 11.4.2006.Water Framework Directive: Directive 2000/60/EC of the European Parliament and of theCouncil of 23 October 2000 establishing a framework for Community action in the field ofwater policyOJ L 327, 22.12.2000.REACH Regulation: Regulation (EC) No 1907/2006 of the European Parliament and of theCouncil of 18 December 2006 concerning the Registration, Evaluation, Authorisation andRef: AEA/ED57412/Issue 2

Restriction of Chemicals (REACH), establishing a European Chemicals Agency [etc],OJ L396, 30.12.2006.Biocidal Products Directive: Directive 98/8/EC of the European Parliament and of the Councilof 16 February 1998 concerning the placing of biocidal products on the market,OJ L 123,24.4.1998.SEVESO II Directive: Council Directive 96/82/EC of 9 December 1996 on the control of major-accident hazards involving dangerous substances,OJ L 010, 14/01/1997.Habitats Directive: Council Directive 92/43/EEC of 21 May 1992 on the conservation ofnatural habitats and of wild fauna and flora,OJ L 206, 22/07/1992.Environmental Liability Directive: Directive 2004/35/CE of the European Parliament and of theCouncil of 21 April 2004 on environmental liability with regard to the prevention andremedying of environmental damageOJ L 143, 30/04/2004.Source 2: The Final report on Unconventional Gas in Europe prepared by Philippe and PartnersNovember 2011.This report provides information, based on a sample of four Member States (France, Germany,Poland and Sweden) on current shale gas related licensing and permitting procedures. It has a muchwider scope than just GHGs. Most national legislation originates at EU level. The potentially importantEU legislation identified in Source 2, in addition to those listed in Source 1 is:Directive 94/22/EC of the European Parliament and the Council of 30 May 1994 on theconditions for granting and using authorisations for the prospection, exploration andproduction of hydrocarbons, OJ L 164, 30.06.1994.Directive 2001/81/EC of the European Parliament and of the Council of 23 October 2001 onnational emission ceilings for certain atmospheric pollutants, OJ L 309, 27.11.2001.Council Directive 92/91/EEC of 3 November 1992 concerning the minimum requirements forimproving the safety and health protection of workers in the mineral- extracting industriesthrough drilling OJ L 348, 28.11.1992.In addition to the above we have also considered the application of the Industrial Emissions Directiveth2010/75/EU, which entered into force on 6 January 2011. This has to be transposed into nationalthlegislation by Member States by 7 January 2013.The review in this chapter serves two main aims:To identify those texts / policy instruments which are relevant to GHG emissions from shalegas exploitation (i.e. the topic of this study);To provide focus for the case studies, which look at the implementation of certain relevant EUlegislation in three Member States: France, Poland and the UK. The case studies focus onthe national arrangements for regulation of GHGs as they apply to shale gas. It highlightscorresponding differences between Member States and certain pieces of EU Legislation(mentioned below). It is not a detailed assessment of the transposition of that EU legislation.Section 6.2.1 presents a brief overview of the directives and regulations identified above. Section6.2.2 reviews three directives in more detail, which have been considered as particularly relevant orpotentially relevant as regards GHG emissions: the EIA Directive, the Industrial Emissions Directiveand the Health and Safety of Workers in the Mineral Extracting Industries through Drilling Directive.The EU ETS directive is also reviewed from the perspective of the examples it sets for the regulationof venting and flaring. It is noted that direct emissions from shale gas projects would not be coveredby the EU ETS. The final part of this section presents the main conclusions relevant for the countrycase studies.

amount of gas extracted exceeds 500,000 m� per day). For projects below this threshold (e.g. thosementioned in Annex II.2.d or II.2.e), a screening is required, in accordance with Articles 2(1), 4(2)-(4)and Annex III of the EIA Directive. Projects related to the exploration of unconventional / shale gasare also subject to the requirements of the EIA Directive (European Commission, 2011). The EIADirective does not contain any provisions relating specifically to GHG emissions. However, thesewould be considered to be part of the identification and assessment of particular estimates ofexpected emissions.Industrial Emissions Directive (2010/75/EU)The Industrial Emissions Directive does not explicitly mention that it covers shale gas exploration andexploitation activities. However, these activities could generate hazardous waste and thus fall underSections 5.1 5.5 or 5.6 to Annex I to the Directive, or would potentially be covered by Section 1 to26Annex I under specific circumstances related to their combustion capacity . This would mean that thegeneral requirements of this Directive could apply to these activities. The Directive requires thatmeasures are set in the permit on emission limit values for certain polluting substances listed inAnnex II, and for other polluting substances which are likely to be emitted from the installationconcerned in significant quantities, having regards to their nature and their potential to transferpollution from one medium to another. Substances listed in Annex II do not include methane. Methanecould however be considered as a polluting substance which is likely to be emitted from theinstallation concerned in significant quantities that would require specific emission limit measures.National Emission Ceilings Directive (2001/81/EC)The NEC Directive set upper limits for each Member State for the total emissions in 2010 of the fourpollutants responsible for acidification, eutrophication and ground-level ozone pollution (sulphurdioxide, nitrogen oxides, volatile organic compounds and ammonia). The Directive requires MemberStates to draw up programmes in order to reduce these emissions, to ensure that the limits arecomplied with and that emission ceilings for these pollutants are not exceeded in any year after 2010.The Directive leaves it largely to the Member States to decide which measures (on top of Communitylegislation for specific source categories) to take in order to comply with these limits.The EU legislation that could apply to unconventional / shale gas projects, but that are not directlyrelevant to regulate GHG emissions as they do not include any provision specific to GHGs, aresummarised below:REACH Regulation (1907-2006/EC)Operators of shale gas projects are considered downstream-usersof chemical substances under REACH. To that end they must beprovided with a safety data sheet that includes information on howthey must use these substances.Shale gas projects would be prohibited in special areas ofconservation unless it is demonstrated that here are imperativereasons of overriding public interest.Only biocidal products authorised under the Biocidal ProductDirective can be used for shale gas exploration and exploitation.

abstraction of fresh surface water and groundwater andimpoundment of fresh surface water. This Directive prohibitsdischarges of pollutants into groundwater and the injection of waterfrom exploration and extraction of hydrocarbon or mining activities(provided that such injections do not contain substances other thanthose resulting from such operations) is subject to authorisationsby Member States. The application of this to flowback water isbeyond this report, since it does not significantly affect the GHGemissions from shale gas exploitationThe Hydrocarbons Directive sets common rules among MemberStates to ensure non-discriminatory procedures for grantingauthorisations for access to the activities of prospection,exploration and production of hydrocarbons, which include shalegas activities.This Directive sets requirements to protect workers from harmfuland explosive atmospheres. These requirements can indirectly andpotentially control the air emissions of methane at the project siteeven though it is not the aim of this Directive.

The EIA Directive requires that public and private projects likely to have significant effects on theenvironment should be subject to an EIA. The main requirement of an EIA is to identify, describe andassess the direct and indirect effects of the project on different factors of the environment, includingair and climate, and the interaction between those factors (Article 3).The Directive distinguishes between those projects subject to a mandatory EIA and those projectswhich are determined by Member States as requiring an EIA (Art 4). A mandatory EIA is required forall projects listed in Annex I, which are considered as having significant effects on the environment.These include unconventional / shale gas projects which fall within Annex I.14 (extraction of naturalgas where the amount of gas extracted exceeds 500,000 m� per day).Other projects, listed in Annex II are not required to be automatically assessed. Instead, MemberStates are required to screen such projects, to determine whether an EIA should be carried out. Thedetermination must be made either on a case by case basis or according to thresholds or criteria,taking into account specific selection criteria, including the project’s characteristics (e.g. size,pollution), location (including environmental sensitivity of the local area) and potential impact (e.g.geographical area affected and duration). Projects falling within Annex II include those associatedwith the extractive industry (e.g. "deep drillings" (Annex II.2.d) and surface industrial installations forthe extraction of natural gas (Annex II.2.e)), the energy industry (e.g. industrial installations forcarrying gas, and surface storage of natural gas and fossil fuels) and infrastructure projects (e.g. oiland gas pipeline installations).The European Commission has confirmed that the EIA Directive would apply to those unconventional/ shale gas activities falling within Annex I.14 and that, where such projects fall below the threshold inAnnex I.14, a screening would be required in accordance with Articles 2(1), 4(2)-(4) and Annex III ofthe Directive. It also confirmed that projects related to exploration or unconventional / shale gas wouldRef: AEA/ED57412/Issue 2

be subject to the requirements of the Directive, noting that Annex II.2 refers to“deep drillings”andprovided the view that the list of activities associated with deep drillings, which does not include shalegas extraction, is non-exhaustive. The European Commission also underlined the need for theprecautionary principle to be taken into account in deciding whether an EIA is needed, indicating thatshale gas projects would be subject to an EIA if it could not be excluded (on the basis of objectiveinformation) that the project would have significant environmental effects. It concluded that theprecautionary principle implied that in case of doubts as to the absence of significant effects, an EIAmust be carried out (European Commission, 2011).The study commissioned by the European Parliament has expressed concern over the threshold setby the EIA Directive, noting that current exploitation of shale gas is considerably lower than theminimum threshold required for a mandatory EIA to be carried out. It recommends that projectsincluding hydraulic fracturing should either be added to Annex I independently of a productionthreshold or else the threshold value should be lowered in order to close the gap.It is also important to note that the EIA Directive does not contain specific provisions relating to GHGemissions from projects. Instead, it requires Member states,inter alia,to ensure that developerssupply certain information, such as a description of estimated air emissions and significantenvironmental impacts resulting from the project, including air and climatic factors in the framework ofa full EIA. Furthermore, the Directive provides for competent authorities to give an opinion on theinformation supplied, which, as a minimum should include,inter alia,a description of the measuresenvisaged in order to avoid, reduce and if possible, remedy significant adverse side effects. These,along with other requirements, will be considered in more detail below.Impact AssessmentsPursuant to Article 5(1), in the case of a full EIA, Member States are required to adopt necessarymeasures to ensure that project developers supply specific information as listed in Annex IV. Thisinformation includes an estimate of expected emissions (including air emissions) resulting from theoperation of the proposed project; and a description of the aspects of the environment likely to besignificantly affected by the proposed project (including climatic factors and interrelationships betweenall factors considered). It also includes a description of the direct and indirect, secondary, cumulative,short, medium and long-term, permanent and temporary, positive and negative effects of the project,using forecasting methods which must be described by the developer.Member States should adopt these measures to the extent that such information is relevant,inter alia,to the specific characteristics of the environmental features likely to be affected; and they considerthat a developer may reasonably be required to compile this information having regard,inter alia,to‘current knowledge and methods of assessment’. Due to its uncertainty this wording may createproblems as far as consideration of impact on GHG emissions is concerned.Technology requirementsWhile the EIA Directive does not provide for specific technological requirements, Article 5(2) providesfor Member States to ensure that, if the developer so requests before submitting an application fordevelopment consent, the competent authority shall give an opinion on the information to be suppliedby the developer in accordance with Article 5(1). As a minimum the supplied information must include,inter alia,a description of the measures envisaged in order to avoid, reduce and if possible, remedysignificant adverse side effects, as well as the main alternatives studied by the developer. Thesecould potentially include technological solutions as are deemed necessary to reduce GHG emissions.Consultation processArticle 6 of the EIA Directive provides that authorities likely to be concerned by a project must begiven an opportunity to express their opinion on the information supplied by the developer underArticle 5 and on the request for development consent. This could potentially include those authoritiesconcerned with GHG emissions and climate change. Article 6 also provides for public consultationearly in the environmental decision-making procedures. Furthermore, Article 11 requires MemberStates to ensure that members of the public, who have “sufficient interest” or are “maintaining theimpairment of a right”, have access to a review procedure to challenge the substantive or procedurallegality of decisions, acts or omissions. What constitutes “sufficient interest” and “maintaining theimpairment of a right” is to be determined by Member States. This, arguably, leaves scope forinterpretation. Access to review procedures should be open to the general public and NGOs whichpromote environmental protection and meet the requirements under national law.

Article 7 provides that where a Member State is aware that a project is likely to have significant effectson the environment in another Member State, or where a Member State is likely to be affected, theMember State shall send a description of the project including,inter alia,available information on itstrans-boundary impact. Article 7 also requires the Member States concerned to arrange for thatinformation to be sent to the authorities specified in Article 6 (as mentioned above).Licensing / authorisation requirementsAs stated above, EIAs are an inherent part of the development consent process and for applicableactivities, consent must not be granted until all necessary measures are taken to identify, describeand assess the direct and indirect effects of the project on the environment.Other issuesConfidentialityArticle 10 provides that competent authorities must respect the limitation imposed by national laws,regulations and accepted legal practices with regard to commercial and industrial confidentiality. Thismay have important consequences with regard to information which may be relevant to GHGemissions.6.2.2.2Industrial Emissions Directive 2010/75/EU

Directive 2010/75/EU lays down rules on integrated prevention and control of pollution arising fromindustrial activities. This Directive is a recast of the following Directives:Directive 2000/76/EC on the incineration of waste;Directive 2001/80/EC on the limitation of emissions from large combustion plants;Directive 2008/1/EC concerning integrated pollution and prevention and control;Directives 78/176/EEC, 82/883/EEC and 92/112/EEC on waste from the titanium dioxideindustry.The purpose of this Directive is to achieve a high level of protection of the environment taken as awhole from the harmful effects of industrial activities. To that end it sets some requirements that mustbe applied to industrial installations set in Annex I to the Directive and specific measures forcombustion plants and waste (co)-incineration plants.Operators of industrial activities listed in Annex I to the Directive must obtain an integrated permitfrom relevant national authorities prior to operation. All of the related environmental impacts of theseactivities (e.g. pollution caused, generation of waste, energy efficiency, and emissions to air) must betaken into consideration for the issuance of the permit. Furthermore the permit conditions (e.g.emission limit values) must be based on the Best Available Techniques as defined in Article 3(10) ofthe Directive.Annex I to this Directive does not explicitly refer to unconventional hydrocarbon exploration andexploitation activities as it does not refer to mining activities in general.Section 5.1 of Annex I covers disposal or recovery of hazardous waste with a capacity exceeding 10tonnes per day involving several types of activities (e.g. surface impoundment), Section 5.5 of thatAnnex covers temporary storage of hazardous wastes listed under Section 5.1 with a total capacityexceeding 50 tonnes, excluding temporary storage pending collection on the site where the waste isgenerated and Section 5.6 of the Annex refers underground storage of hazardous waste with a totalcapacity exceeding 50 tonnes.The criteria to define hazardous waste are set under Annex III to the Waste Framework Directive.

— liquid substances and preparations having a flash point below 21 �C (including extremelyflammable liquids); or— substances and preparations which may become hot and finally catch fire in contact with air atambient temperature without any application of energy; or— solid substances and preparations which may readily catch fire after brief contact with a source ofignition and which continue to burn or to be consumed after removal of the source of ignition; or— gaseous substances and preparations which are flammable in air at normal pressure; or— substances and preparations which, in contact with water or damp air, evolve highly flammablegases in dangerous quantities.H 3-B ‘Flammable’: liquid substances and preparations having a flash point equal to or greater than21 �C and less than or equal to 55 �C.H 4 ‘Irritant’: non-corrosive substances and preparations which, through immediate, prolonged orrepeated contact with the skin or mucous membrane, can cause inflammation.H 5 ‘Harmful’: substances and preparations which, if they are inhaled or ingested or if they penetratethe skin, may involve limited health risks.H 6 ‘Toxic’: substances and preparations (including very toxic substances and preparations) which, ifthey are inhaled or ingested or if they penetrate the skin, may involve serious, acute or chronic healthrisks and even death.H 7 ‘Carcinogenic’: substances and preparations which, if they are inhaled or ingested or if theypenetrate the skin, may induce cancer or increase its incidence.H 8 ‘Corrosive’: substances and preparations which may destroy living tissue on contact.H 9 ‘Infectious’: substances and preparations containing viable micro-organisms or their toxins whichare known or reliably believed to cause disease in man or other living organisms.H 10 ‘Toxic for reproduction’: substances and preparations which, if they are inhaled or ingested or ifthey penetrate the skin, may induce non-hereditary congenital malformations or increase theirincidence.H 11 ‘Mutagenic’: substances and preparations which, if they are inhaled or ingested or if theypenetrate the skin, may induce hereditary genetic defects or increase their incidence.H 12 Waste which releases toxic or very toxic gases in contact with water, air or an acid.H 13 ‘Sensitizing’: substances and preparations which, if they are inhaled or if they penetrate the skin,are capable of eliciting a reaction of hypersensitization such that on further exposure to the substanceor preparation, characteristic adverse effects are produced.H 14 ‘Ecotoxic’: waste which presents or may present immediate or delayed risks for one or moresectors of the environment.According to several studies on hydraulic fracturing in the U.S. , certain chemicals used are knownto be carcinogens, mutagens or are listed as hazardous pollutants under the U.S. Clean Air Act.Furthermore, methane is a gaseous substance which is flammable in air at normal pressure.Therefore it would be possible that hazardous waste is generated during shale gas exploration andexploitation activities and that provided the threshold is fulfilled (disposal capacity exceeding 10 tonsper day, capacity exceeding 50 tons for temporary storage and 50 tons for underground storage) theirwaste water disposal installations could thus fall under Annex I to the Industrial Emissions Directive.However shale gas activities would not fall under Sections 5.1, 5.5, 5.6 of Annex I if the storage ofhazardous waste is temporary prior to being transferred to a waste treatment facility.Furthermore it can also be interpreted that the Industrial Emissions Directive could apply to shale gasexploration and exploitation activities if a combustion plant of at least 50 MW or another activity (e.g.gas refinery) listed in Annex I of the Industrial Emissions Directive (i) would be directly associated to27

shale gas exploration and exploitation, (ii) would have a technical connection with shale gasexploration and exploitation and (iii) would be operated in situ.Permits must be granted to Annex I installations subject to the compliance with certain conditionswhich include measures on emission limit values for polluting substances listed in Annex II to28Directive 2010/75/EU and for other polluting substances, which are likely to be emitted from theinstallation concerned in significant quantities, having regards to their nature and their potential totransfer pollution from one medium to another (Article 14(1) (a)). Substances listed in Annex II do notinclude methane. Methane could however be considered as a polluting substance which is likely to beemitted from the installation concerned in significant quantities that would thus require specificemission limit measures.Overall the application of Directive 2010/75/EU to shale gas exploration and exploitation activities issubject to interpretation and requires a case by case approach. Furthermore it is not clear whether theemission limit value measures required under this Directive would apply to methane contained withinflow back from these activities.6.2.2.3Directive concerning minimum requirements for improving health and safety ofworkers in the mineral-extracting industries through drilling (Directive 92/91/EEC)

Directive 92/91/EEC details the minimum requirements for improving the safety and health protectionof workers in the mineral-extracting industries through drilling i.e. extraction of minerals (onshore andoffshore) and preparation of extracted materials for sale. While the Directive does not contain anyprovisions specifically relating to GHG emissions it requires employers to take the necessarymeasures to ensure,inter alia,that workplaces are designed, constructed, equipped, commissioned,operated and maintained so that workers can perform their work without endangering their health andsafety and those of others. It also requires employers to prevent the occurrence of health endangeringatmospheres. It is an individual directive within the meaning of Directive 89/391/EEC (on theintroduction of measures to encourage improvements in the safety and health of workers at work), forwhich Article 6 places a general obligation on employers to take measures necessary for the healthand safety protection of workers.Article 10, in conjunction with the Annex to the Directive, sets minimum requirements for health andsafety in the workplace. These include the requirement for Member States to take measures forassessing the presence of harmful and / or potentially explosive substances in the atmosphere andfor measuring the concentration of such substances. Paragraph 6.1 of the Annex requires thatadditional measures for monitoring devices measuring gas concentrations at specific places, as wellas alarms and devices to cut off power, must also be provided but only “where required by the safetyand health document”. Paragraph 6.2 requires “appropriate measures” to be taken to ensurecollection at source and removal of harmful substances where they accumulate or may accumulate inthe atmosphere, also requiring the system to be capable of dispersing such substances in such a waythat workers are not at risk. Furthermore, appropriate and sufficient breathing and resuscitationequipment must be available in areas where workers must be exposed to atmospheres which areharmful to health.This Directive does not define what covers harmful and / or potentially explosive substances.Methane, which is a flammable gas, could however be considered as a potentially explosivesubstance. The Directive’s focus is however on the protection of workers from harmful and / orexplosive substances. It does not regulate the air emissions of methane even though the measures toprotect workers from harmful and / or explosive substances could potentially and indirectly control theair emissions of methane. Pursuant to Annex Part B paragraph 2 of this Directive, systems for theisolation and blowdown of wells, plant and pipelines must be capable of remote control at suitablelocations in the event of an emergency. This would limit the accidental air emissions and wouldpotentially have an influence on the control of GHG emissions. This is however not relevant for thisproject, which does not cover abnormal situations.

This Directive establishes a system for GHG emissions trading, which began in 2005 and which hasundergone several revisions since then. The Directive covers stationary installations and aircraftoperators and is described here in the context of the former since this has the most direct potentialrelevance to shale gas exploitation sites.The Directive covers stationary installations that carry out any activity listed in Annex I. Suchinstallations must hold a GHG emissions permit (Article 4), monitor, have verified and report theirGHG emissions (Articles 14 and 15), and acquire and surrender emissions allowances equal inquantity to the number of tonnes of carbon dioxide equivalent that they emit (Article 12).Annex I does not contain any activities that would directly relate to the extraction of natural gas. Theonly potential means by which shale gas sites could be included in the system would be through theinclusion of the combustion of fuels in installations with a total rated thermal input exceeding 20MW.In this context Annex I states that the determination of total rated thermal input is to include,inter alia,engines and flares. Consequently a shale gas installation could in principle be included in the systembecause of these activities, although whether in practice the combustion capacity is likely to exceedthat level is not known. Notably there is no mention in the Directive of including installations due to theGHG emissions arising from the venting of natural gas.It is therefore assumed unlikely that shale gas extraction would be covered by the EU ETS, and thediscussion below is intended to describe the EU ETS approach to venting and flaring as this may setexamples for future regulation of shale gas emissions (either within or outside of the EU ETS).In a similar way that flaring must be taken into account in determining whether an installation must beincluded in the system, it must also be reported as applicable for those that are included. To the endof December 2012 the rules for monitoring and reporting of emissions are set out in the Monitoringand Reporting Guidelines. However, from January 2013 two new Regulations for Monitoring andReporting (M&RR) and for Verification and Accreditation will apply. The M&RR contains rules forflaring under the combustion processes activity (Annex IV subsection D). This requires the calculationof emissions from routine flaring and operational flaring, with a reference emission factor for lowervolume flaring (lower emissions) and the requirement for an installation emission factor for highervolume flaring. Venting of certain process emissions are included for some activities, but it is notrequired to be monitored for combustion installations.From the above, it can be seen that the EU ETS contains provisions for the inclusion of combustioninstallations including flaring, but not for venting of GHG emissions at those installations. With regardsto a potential model for the regulation of fugitive emissions from hydraulic fracturing, examples can betaken from the Directive’s treatment of capture and geological storage of carbon dioxide.The Directive includes geological storage of GHGs in a storage site permitted under Directive2009/31/EC. For pipelines for the transport of CO2and for storage the M&MR require thedetermination of fugitive and vented emissions as well as those from leakage events. For the storagesite, vented and fugitive emissions must also be included. In cases of enhanced hydrocarbonrecovery operations, emissions sources must also include oil-gas separation units and the flare stackand associated CO2purge systems. Whilst predominantly CO2sources, the treatment of emissionsfrom venting, flaring, fugitive emissions and gas processing operations under the EU ETS couldprovide relevant examples for systems to regulate emissions arising at hydraulic fracturing sites.

and climatic factors. Furthermore the Directive provides for competent authorities to give an opinionon the information supplied which, as a minimum, should include a description of the measuresenvisaged in order to avoid, reduce and if possible, remedy significant adverse side effects.However, despite these requirements, many uncertainties remain as to whether Member States wouldrequire an EIA for shale gas operations, and if so how Member States should implement the EIA, forexample the methodology to be used to quantify GHG emissions baseline scenarios.Directive 92/91/EEC concerning minimum requirements for improving health and safety ofworkers in the mineral-extracting industries through drillingdoes not contain any provisionsspecifically relating to GHG emissions from these activities. It does however set requirements toprotect workers from harmful and / or explosive substances that would primarily apply to methanepresent in such concentration that it can represent a risk in terms of flammability for workers.With regard tothe Directive on Industrial Emissions (2010/75/EU)it is not clear in whichcircumstances it would apply to shale gas exploration and exploitation activities and whether itsmeasures on air emissions would cover methane contained within flow back.It is beyond the scope of the report to make specific recommendations on how to overcome thepotential shortfalls identified above.Finally,the EU ETS Directive (Directive 2003/87/EC)could provide precedents for the regulation ofshale gas emissions, through its treatment of venting and flaring and emissions related to carboncapture and storage processes.The legislation described above could provide an approach with which to enforce best shale gastechnologies, although this would likely need to be supplemented by BAT reference documents,guidance specific to shale gas technologies and clarification on the applicability of key directives. Inparticular:Under the EIA Directive 85/337/EEC; 2011/92/EU (codified), the competent authority must, ifrequested, give an opinion on the measures envisaged in order to avoid, reduce and ifpossible, remedy significant adverse side effects. These could potentially includetechnological solutions as are deemed necessary to reduce GHG emissions, in line with bestavailable technologies;Directive 92/91/EEC, concerning health and safety of workers in mineral extracting industriesrequires “appropriate measures” to be taken to ensure collection at source and removal ofharmful substances where they accumulate or may accumulate in the atmosphere. These arenot required to be BAT, but the legislation does appear suitable for prescribing use of certaintechnologies;The Industrial Emissions Directive 2010/75/EU requires permiting of eligible installations, forwhich conditions necessary to achieve a high level of environmental protection should be seton the basis of best available techniques. However, it is not clear if the directive would alwaysapply to methane emissions from shale gas installations and there is no BAT referencedocument specific to shale gas extraction technologies.As described above, there are approaches within existing legislation that are well aligned withapplying best available technologies to shale gas technologies. Alternatives, such as voluntaryagreements, could also be considered but additional measures would be required to ensure they arerigorously applied.

constitute an assessment of the appropriateness of the transposition of the EU legislation into nationallaw.They also examine the associated national legislation for three countries, insofar as they could relateto GHG emissions. The UK, France and Poland were selected due to the contrast in their differingapproaches and potential for shale gas production. Germany was also considered as a potentialcountry but, due to the complexity of the legislation, it was decided it would not be included.As part of the development of the case studies we approached at least one representative for eachMember State to ask for an interview. In some instances they preferred to provide a written responseto a pre-prepared interview questionnaire. The Member State representatives whose contribution isincluded in the case studies are:CountryFrancePolandUKNational regulatorDirection générale de la prévention des risques, Ministère de l'Ecologie:Ms Sophie DehayesPolish Environment Ministry department on mining concessions: MrBartosz ArabikEnvironment Agency of England and Wales: Martin DiaperDepartment of Environment Northern Ireland: Mark Livingstone

There is no specific mention of shale gas, or unconventional gas, in the UK legislation. Rather, shalegas drilling in the UK is covered by the general provisions for oil and gas exploration and developmentactivities. Furthermore, there are no requirements within these general provisions which specificallyaddress GHG emissions. The regulation and control of GHG emissions from the production ofunconventional gas is covered (albeit indirectly) by separate regimes for environmental control, healthand safety and petroleum exploration and development. There are also local controls through landuse planning. In addition, there are a number of legislative variations in the regulation ofunconventional gas within each of the three main jurisdictions: (i) England and Wales; (ii) Scotlandand (iii) Northern Ireland. This report will consider the main legislative and regulatory requirementswithin each of these jurisdictions.GHG emissions related considerations in the oil and gas licencing in England, Scotland andWalesOil and gas licensing in England, Scotland and Wales is governed by the Petroleum Act 1998 (“the1998 Act”), the Petroleum (Production) (Landward Areas) Regulations 1995 (“The 1995 Regulations”),and the Hydrocarbon Licensing Directive Regulations 1995 (“the Hydrocarbon Regulations”). The1998 Act vests all rights and ownership of petroleum resources (oil and gas) to the UK government,which then grants a Petroleum Exploration and Development licence (PEDL) in competitive offering

(licensing rounds) for the exclusive exploration, development, production and abandonment ofhydrocarbon in the licence area. This licence, issued by DECC, only allows a company to carry outvarious oil and gas exploration and exploitation activities, subject to all necessary drilling /development consents, planning permissions, health and safety and environmental requirements, asset out below. Before a licence can be awarded, the applicant must satisfy DECC of the technicalcompetence and environmental awareness of its proposed operator, and each member of theapplicant group must satisfy DECC of its financial viability and financial capacity. It should be notedthat GHG emissions are not specifically taken into account in the licensing process.As part of the licence application, applicants must submit an “Environmental Awareness Statement”.Information to be provided in the Environmental Awareness Statement:applicant’s understanding of the UK’s onshore environmental legislation relevant to theexploration, development and production stages of the project;applicant’s understanding of the particular sensitivities associated with operational planning(e.g. Special Areas of Conservation (SACs), Special Protection Areas (SPAs), MarineConservation Zone (MCZs), Marine Protected Areas ( MPAs));details of their pollution liability arrangements and their commitment to environmental policyand management;details of any previous failure to comply with environmental standards or requirements withinthe previous five years (e.g. any civil or criminal action against the operator, or any convictionsfor breaches of environmental legislation.It should be noted that DECC’s criteria for assessing licence applications are published and do notinvolve assessment of the impacts of the proposed activities on the environment. So far as theseimpacts can be assessed at the stage of the issue of licences, they are covered by a “strategicenvironmental assessment” (SEA) which is carried out before applications for licences are invited. Inaccordance with Directive 2001/42/EC (“the SEA Directive”), the Environmental Assessment of Plansand Programmes Regulations 2004 and the Environmental Assessment (Scotland) Act 2005 requirean environmental assessment to be carried out, which should include the preparation of anenvironmental report (regulation 12; Article 5 of the SEA Directive). The matters to be included in theenvironmental report are specified in Schedule 2 to the Regulations (Article 5.1 of, and Annex II to,the SEA Directive), details of which are set out below. At the licensing stage the impacts are only tobe assessed at a generic level. It will however be noted that more detailed assessment of the possibleimpacts of the specific activities which the licensee may in due course wish to carry out will beperformed at the stage of seeking planning permission for these activities, in those cases in which anEIA is required.Matters to be included in the environmental report pursuant to the Environmental Assessmentof Plans and Programmes Regulations 2004 and the Environmental Assessment (Scotland) Act2005:An outline of the contents and main objectives of the plan or programme, and its relationshipwith other relevant plans and programmes;The relevant aspects of the current state of the environment and the likely evolution thereofwithout implementation of the plan or programme;The environmental characteristics of areas likely to be significantly affected;Any existing environmental problems which are relevant to the plan or programme including,in particular, those relating to any areas of a particular environmental importance, such asareas designated pursuant to Council Directive 79/409/EEC on the conservation of wild birdsand the Habitats Directive;The environmental protection objectives, established at international, Community or MemberState level, which are relevant to the plan or programme and the way those objectives andany environmental considerations have been taken into account during its preparation;

GHG emissions related considerations in the planning permissions in England, Scotland andWalesOn being issued with a PEDL by DECC, the operator must obtain all relevant planning permissionsand landowners’ permissions before exploration in respect of any hydrocarbon development(s) cancommence. Pursuant to Section 57 of the Town and Country Planning Act 1990 (England and Wales)as amended by the Planning Act 2008, planning permission is required from the Local PlanningAuthority (LPA) for the carrying out of any development of land. ‘Development’ includes the carryingout of building, engineering, mining or other operations in, on, over or under land. This includesdrilling for the purposes of shale gas exploration and exploitation.As part of the planning permission process, the LPA must determine if an EIA is required. The Town& Country Planning (Environmental Impact Assessment) Regulations 2011 and the Town & CountryPlanning (Environmental Impact Assessment) (Scotland) Regulations 2011 require an EIA to becarried out for developments in Schedule 1 of the Regulations and certain developments underSchedule 2 of the Regulations (’EIA Developments’) where they are likely to have a significant impacton the environment. According to these Regulations an EIA is compulsory in case of extraction ofpetroleum and natural gas for commercial purposes, where the amount extracted exceeds 500 tonnes3per day in the case of petroleum and 500,000 m per day in the case of gas (schedule 1) and can berequired after an environmental screening for any type of drilling where the area of the works exceeds1 hectare (Schedule 2).It is most likely that shale gas drilling operations would fall within the Schedule 2 category of ‘deepdrilling’. If the development falls within the criteria set out in Schedule 2 (drilling the area of the worksexceeds 1 hectare), the development would be screened to assess whether or not it is likely to havesignificant effects on the environment and thus whether an EIA is required. The selection criteria forthis screening process includes; consideration of the characteristics of the development (e.g. size,use of natural resources production of waste, pollution and nuisances); location of the development(e.g. existing land use and absorption capacity of the natural environment) and characteristics of thepotential impact (e.g. extent, magnitude and complexity).Information required in the Environmental Impact Assessment (Environmental Statement):A description of the development (including physical characteristics, production processesand an estimate of expected residues and emissions);An outline of the main alternatives and an indication of the main reasons for the choice made,taking into account the environmental effects;A description of those environmental aspects likely to be significantly affected by thedevelopment, including population, flora, fauna, soil, water, air and climatic factors;A description of the likely significant effects of the development on the environment, includingdirect, indirect, temporary and permanent effects.GHG emissions relevant requirements for the drilling authorisation in England, Scotland andWalesOnce the minerals planning authority has granted permission to drill, DECC will consider anapplication to drill; and at least 21 days before drilling is planned, the Health and Safety Executive(HSE) must be notified of the well design and operational plans to ensure that major accident hazardrisks to people from well and well-related activities are properly controlled, subject to the sameregulation as any other industrial activity. HSE regulations also require verification of the well designby an independent third party. Once DECC checks the geotechnical information and that the EA /SEPA and HSE are aware of the scope of the well operations, they may consent to drilling. If the wellneeds more than 96 hours of testing to evaluate its potential to produce hydrocarbons, the operator

can apply to DECC for an extended well test of up to 60 days (once all other consents andpermissions have been granted) which limits the quantities of gas to be produced and saved or flared.If the operator wishes to drill an appraisal well or propose a development, they start again with theprocess described above; obtaining the landowner permissions and planning consents, EA or SEPAconsultation and HSE notification before DECC would consider approving the appraisal well fordevelopment. The minerals planning authority will also consider whether an EIA is required.The operator should also consult with the EA in England and Wales, or SEPA in Scotland, which arealso statutory consultees in the planning process. In Scotland, the Town and Country Planning(Scotland) Act 1997 as amended by the Planning etc. (Scotland) Act 2006 provide for planningprovisions, while SEPA is a statutory consultee.All drilling operations in England, Scotland and Wales are subject to notification to the HSE and eachsite is assessed by the EA in England and Wales, (and SEPA in Scotland) which regulate dischargesto the environment through the environmental permitting regimes. Pursuant to the EnvironmentalPermitting (England and Wales) Regulations 2010 (EPR), an environmental permit may also berequired from the EA where fluids containing pollutants are injected into formations that containgroundwater, which could be the case for shale gas exploration and exploitation. An environmentalpermit may also be needed if the activity poses a risk of mobilising natural substances that could thencause pollution. The permit, if granted, will specify limits on the activity and any requirements formonitoring. While the EA will not issue a permit if the activity poses an unacceptable risk to theenvironment, a permit may not be necessary if it decides that the activity will not affect groundwater.The information to be provided in the application for a permit will depend on the type of activity andpermit required but may include: the type of facility and activity; the type of discharge and source; howeffluent will be treated; monitoring arrangements; the technical ability and financial capacity of theoperator; planning status of the installation / activity and a risk assessment. There is no requirementto include any information on specific measures to reduce GHG emissions. The EA may also requirefurther controls where there are discharges into controlled waters under the Water Resources Act1991, as amended. For example, notification of an intention to drill has to be served on theenvironmental regulator under Section 199 of the Water Resources Act. In Scotland, the WaterEnvironment (Controlled Activities) (Scotland) Regulations 2011 sets environmental permitrequirements for discharges of pollutants into controlled waters. SEPA is the regulating authorityresponsible for issuing permits. It should be noted that the water legislation does not contain anyspecific requirements with regard to GHG emissions, for example, possible methane migration intowaters.Other GHG emissions relevant measures in England, Scotland and WalesIt should be noted that under the Energy Act 1976, as amended by the Gas Act 1986, the Secretary ofState's consent is required for the disposal of natural gas (whether at source or elsewhere) by flaringor unignited release into the atmosphere.The Environmental Protection Act 1990, Part III allows for measures to be taken in the event of,interalia,statutory nuisance (i.e. non-regulated activities), noise or odour which may emanate from shalegas exploration.GHG emissions related considerations in the oil and gas licencing in Northern IrelandIn Northern Ireland, oil and gas licensing is primarily governed by the Petroleum (Production) Act(Northern Ireland) 1964 ('the 1964 Act') and the Petroleum Production Regulations (Northern Ireland)1987 ('1987 PP Regulations') as amended by the Petroleum Production (Amendment) Regulations(Northern Ireland) 2010 ('2010 PP(A) Regulations'). The 1964 Act vests the rights in petroleum inNorthern Ireland in the Department of Enterprise, Trade and Investment (DETI) and enables it to grantlicences that confer exclusive rights for the exploration, development, production and abandonment ofhydrocarbons in the licence area. In awarding licences, regard must also be given to theHydrocarbons Licensing Directive Regulations (Northern Ireland) 2010.As is the case in England, Scotland and Wales, applicants must have the necessary financial andtechnical capacity and appropriate environmental awareness before a licence will be granted by DETI.Information to be provided in the Environmental Awareness Statement:Understanding of Northern Ireland’s environmental legislation which is relevant to the

exploration, development and production stages of the project;The broad environmental sensitivities of the area applied for and how the applicant wouldaddress those sensitivities in operational planning.DETI assesses the applicant's understanding of environmental issues, including relevantenvironmental legislation, the broad environmental sensitivities of the area applied for and how theapplicant would address those sensitivities in operational planning. As a result of this assessment,DETI will give a ’Pass’ or ’Fail’ mark for the applicant. It should be noted that this assessment doesnot specifically take into account GHG emissions.According to DETI, when granting licences for shale gas operations in Northern Ireland, theenvironmental impacts of proposed activities on the environment could theoretically be used ascriteria to decide between two or more applications of equal merit (and would have merit,particularly where shale gas was the hydrocarbon target). However, DETI noted that such a situationis unlikely to arise in Northern Ireland for the following reasons:i.Northern Ireland operates an 'open door' or 'first come, first served' policy, rather than alicensing round system for petroleum licensing and competing applications are unlikely toarise because of this.Petroleum licence applications only specify a work programme for the Initial Term (five years)which corresponds to the exploration phase. Development programmes / plans are onlysubmitted in the Second Term and DETI approval and planning permission (including EIA)are among the pre-requisites for production to take place.

GHG emissions considerations in the planning permissions in Northern IrelandIn Northern Ireland, the EIA process is governed by the Planning (Environmental Impact Assessment)Regulations (Northern Ireland) 2012 (the ‘EIA Regulations’). An EIA is compulsory in case ofextraction of petroleum and natural gas for commercial purposes where the amount extracted3exceeds 500 tonnes per day in the case of petroleum and 500,000 m per day in the case of gas(Schedule 1). Any type of drilling for which the area of the work exceeds 1 hectare, or if it is in asensitive area (e.g. Area of Special Scientific Interest (ASSI), Area of Outstanding Natural Beauty(AONB), European site etc.) (Schedule 2) is subject to screening to assess whether it requires anEIA. It should be noted that while the EIA process requires certain environmental information, such asclimatic factors, to be taken into account there is no specific requirement to include GHG emissions.Information required in the Environmental Impact Assessment in Northern Ireland:A description of the development (including physical characteristics, production processesand an estimate of expected residues and emissions);An outline of the main alternatives and an indication of the main reasons for the choice made,taking into account the environmental effects;A description of those environmental aspects likely to be significantly affected by thedevelopment, including population, flora, fauna, soil, water, air and climatic factors;A description of the likely significant effects of the development on the environment, includingdirect, indirect, temporary and permanent effects.

At the exploration stage, it is expected that companies exploring for shale gas will seek permission foran “extended well test”, which allows production for a sufficient length of time, often 90 days, toestablish commerciality. As production facilities would not at that stage be in place the gas has to beflared or vented. DECC confirmed that it will not normally consent to venting unless flaring is nottechnically possible.While no field development plans for shale gas have yet been submitted in the UK, DECC wouldexpect all such plans to demonstrate compliance with good production practices that currently applyfor conventional hydrocarbon exploitation. However it should be noted that there is currently no BREF(European IPPC Bureau Best Available Techniques Reference Document) for the hydraulic fracturingindustry.Health and Safety of workersA number of requirements on health and safety of workers are also applicable to shale gasexploration and exploitation.The UK Health and Safety Executive (HSE) is the regulatory body responsible for regulating thesafety of workers from drilling operations, which would include shale gas exploration and exploitation.As regards requirements applicable to health and safety at work, the UK has implemented Directive92/91/EEC via the following Regulations, which cover both offshore and onshore activities:Offshore:The Offshore Installations (Safety Case) Regulations 1992 and 2005: primary aim is to reducethe risk from major accident hazards to the health and safety of the workforce employed onoffshore installations or in connected activities. They required every operator, or owner, of anoffshore installation to prepare a safety and health document (safety case) and submit it toHSE for acceptance. This will cover the principles of risk prevention, the assessment of risksand the preventative and protective measures selected. Operators are also required to set upa verification scheme and seek input from an independent competent person;The Offshore Installations and Pipeline Works (Management and Administration) Regulations1995: these set out requirements for the safe management of offshore installations, such asthe appointment of installation managers, the use of permit-to-work systems and healthsurveillance;The Offshore Installations (Prevention of Fire and Explosion, and Emergency Response)Regulations 1995: these provide for the protection of people from fire and explosion, and forsecuring effective emergency response. They require the necessary assessment of risks andthe introduction of appropriate control measures to address these risks;Offshore Installations and Pipeline Works (First-aid) Regulations 1989: These Regulationsoutline the offshore first aid and basic health care provision requirements;Offshore Installations (Safety Representatives and safety Committees) Regulations 1989:These regulations cover requirements related to consulting and informing workforcerepresentatives and on the responsibilities and powers of safety representatives.Onshore:The Borehole Sites and Operations Regulations 1995 and the Borehole Sites and OperationsRegulations (Northern Ireland) 1995 (BSOR Regulations): As shale gas operations areconcerned with the extraction of “petroleum” (oil and gas), Regulation 6(1) requires theBorehole Site Operator to notify HSE of these operations a minimum of 21 days before theycan commence. The Borehole Site Operator must supply the information as detailed inSchedule 1, Part 1. The Regulations also require the operator to ensure, inter alia, thatworkplaces on a borehole site are designed and built to a certain standard (Regulation 8).Furthermore, they prohibit commencement of a borehole operation unless the operatorensures that a health and safety document has been prepared, specifies the matters whichthe document must contain, requires that the operator ensures that it be kept up to date, andrequires employers to have regard to it (Regulation 7). The health and safety document mustcontain specific information including: a demonstration that the risks to which persons at theborehole site are exposed whilst they are at work have been assessed, an escape plan foremployees, a plan for the prevention of fire and explosions and any uncontrolled escape of

flammable gases and for detecting the presence of flammable atmospheres and a fireprotection plan.An assigned OSD Wells Inspector will inspect the notification to ensure that it complies with,among other regulations, the Offshore Installations and Wells (Design and Construction, etc)Regulations 1996 (DCR) and industry good practice. If the inspector has any concerns orrequires further information they will contact the Borehole Site Operator as part of theinspection process. No consent is given to commence operations by HSE and the BoreholeSite Operator can start operations after the 21 day period has elapsed. HSE would have toserve a prohibition notice to stop operations. The DECC as issuer of the licence do run aconsents scheme.Regulation 9(1) also requires the Borehole Operator to ensure suitable well control equipmentsuch as blow out preventers are provided and deployed on the well when the conditionsrequire it;The Health and Safety at Work etc Act 1974 also applies to shale gas operations, as do morespecific regulations focused on general occupational health and safety, borehole operationsand well integrity.Onshore and offshore:The Offshore Installation and Wells (Design & Construction etc.) Regulations 1996 and theOffshore Installation and Wells (Design & Construction etc.) Regulations (Northern Ireland)1996 are applicable to all wells drilled with a view to the extraction of petroleum regardless ofwhether they are onshore or offshore. These regulations are primarily concerned with wellintegrity and there are no specific obligations with regard to fugitive methane or GHGemissions. Regulation 13 places a general duty on the well-operator to ensure that the well isdesigned, modified, commissioned, constructed, equipped, operated, maintained, suspendedand abandoned, that so far as is reasonably practicable, there can be no unplanned escapeof fluids (which could be interpreted as including methane – the regulation is not specificabout this) from the well and risks to the health and safety of persons from the well, includinganything from within the well or from the strata to which the well is connected, so far as isconsidered as low as is reasonably practicable (ALARP). Regulation 14 requires the welloperator to assess the conditions below ground through which the well will pass during thedesign phase of the well and while the well is being drilled. Regulation 18 requires the welloperator to set up a well examination scheme and appoint a well examiner. The WellExamination Scheme and involvement of the well examiner is for the complete lifecycle of thewell from design through to abandonment. The well examiner is an independent competentperson who reviews the proposed and actual well operations to confirm they meet the welloperators policies and procedures, comply with the Regulations and follow good industrypractice. Regulation 19 requires the well operator to submit a weekly report to HSE on thepast weeks operations on the well. This enables the wells inspector to monitor progress onthe well and determine if the well operator is conducting their operations as per the wellnotification submitted to HSE. Regulation 21 requires the well operator to ensure that allpersons working on the well are suitably informed, instructed, trained and supervised so thatthe risks to them are as low as is reasonably practicable;Reporting of Injuries Diseases and Dangerous Occurrences Regulations 1995 (RIDDOR):Regulation 3 of The Reporting of Injuries Diseases and Dangerous Occurrences Regulations1995 (RIDDOR) has a specific set of Wells Dangerous Occurrences contained in Schedule 2,Part I that the Well Operator has to report to HSE. These include a blowout i.e. anuncontrolled flow of well fluids; the unplanned use of blow out prevention equipment; theunexpected detection of H2S; the failure to maintain minimum separation distance betweenwells; mechanical failure of any safety critical element of a well;The Control of Major Accident Hazards Regulations 1999 (as amended), and the Control ofMajor Accident Hazards Regulations (Northern Ireland) 2000 (as amended) imposerequirements with regard to the control of major accident hazards involving dangeroussubstances. These Regulations are made under the Health and Safety at Work Act 1974 andimplement EC Directive 2003/105/EC amending Directive 96/82/EC. It should be notedhowever that according to DECC, conventional onshore fields to which the Regulations applyare unlikely to store hydrocarbon products in sufficiently large volumes so as to warrant

control under the COMAH Regulations. Furthermore, there is nothing in these regulationswhich deals specifically with GHG emissions such as methane.The health and safety framework in the UK does not require environmental risks associated withdrilling to be assessed, but it is assumed by UK regulators that the very high well integrity standardsrequired to protect lives and the safety of workers will in practice ensure that most environmental risksfrom well integrity are also addressed.General requirements applicable to well completion and GHG emission limits – England,Scotland and WalesThere are no general emission control regimes over GHG gases as such. However, according to theDECC, in addition to those provisions noted above, a number of regulatory regimes will have theeffect of restricting or controlling methane emissions from oil and gas activities including shale gas, asfollows:Environmental Permitting;According to The EA it is considering the implications of the European Commission's interpretation onthe applicability of the Industrial Emissions Directive and the Mining Waste Directives in determiningits regulatory stance. It has started a full review of the regulations and controls it may require toensure effective regulation of shale gas.Health and Safety of Workers;The Offshore Installations and Wells (Design and Construction, etc.) Regulations 1996 (DCR) alsoinclude goal setting requirements which place the responsibility on those who create risks todemonstrate that they have adequately assessed the risks associated with their work activities andput in place appropriate measures to control these. These Regulations have the flexibility to requireoperators to consider new standards or best practice as they emerge and to drive them to continuallyimprove.6.3.1.3Institutional framework

As noted above, there are a number of different authorities in the UK responsible for overseeing shalegas activities, each of which will enforce its own legislation and, where appropriate, place reportingrequirements on operators. The main authorities are as follows:The Department of Energy and Climate Change (DECC): is the UK government departmentresponsible for licensing, exploration and regulation of oil and gas developments on the UKcontinental shelf. In Northern Ireland, the Department of Enterprise, Trade and Investment (DETI) isresponsible for issuing licences.The Environment Agency (EA): is the environmental regulator responsible for advising governmentand regulating discharges to the environment in England and Wales. In Scotland this function iscarried out by the Scottish Environmental Protection Agency (SEPA), in Northern Ireland theDepartment of the Environment (DOE) and the Northern Ireland Environment Agency (NIEA).The Health and Safety Executive (HSE): is the UK non-departmental public body responsible forregulating the process safety risks (including workplace health and safety) of shale gas activities, andcontributing to the mitigation of environmental risks. In particular, the HSE is responsible for ensuringthe appropriate design and construction of a well casing for any unconventional gas borehole. It is theoperator’s responsibility to assess the risks and ensure that appropriate controls are put in place. Inthe UK risks to health and safety, including those associated with shale gas operations, operatorsmust take appropriate action to reduce the risks to as low as is reasonably practicable. For health andsafety, HSE as the regulatory agency will oversee this process and take enforcement action whennecessary. The HSE regulates shale gas wells using the same regulations (e.g. DCR) and standardsas are applied to other onshore oil and gas wells.EnforcementIn terms of enforcement, both HSE and the EA have to be consulted and / or notified before anydrilling operations take place, and have powers to halt operations if they have concerns. HSE is theenforcing authority for the health and safety aspects of shale gas operations and the EA regulatesenvironmental aspects. HSE, EA and DECC work closely together to share relevant information onsuch activities, ensure that there are no material gaps and that all material concerns are addressed.

In Northern Ireland, these functions are primarily carried out by the DETI, DOE (and its agency theNIEA).ReportingAccording to UK authorities, only one well has been hydraulically fractured to date and that requiredno environmental permit. There was no potable aquifer present and the flow back was tankered awayto a licensed waste water treatment facility. Since October 2011 the flow back has been storedpending disposal to a site which is suitable to take it on account of its naturally occurring radioactivematerial content. This disposal requires permitting. For future operations, should a permit be required,then the EA will require monitoring by the operator of environmental aspects appropriate to thepermitted activity. The EA is reviewing its regulatory approach, as mentioned above.The British Geological Survey is conducting a survey of baseline methane concentrations ingroundwater. For this they have approached the EA for borehole access and any past records. Thepurpose is to set a baseline of measurement across areas of the country where shale gas may bepresent in exploitable quantities to facilitate comparisons after any hydraulic fracturing.For the health and safety aspects of shale gas operations HSE wells group inspectors inspect wellnotifications submitted to HSE as per the requirements of BSOR Regulation 6(1). All well notificationsare inspected upon submission. This inspection process is conducted in the design phase of the wellwhere the vast majority of issues likely to have an impact on well integrity will be identified andaddressed by the well operator.Monitoring of the well operations is conducted by the wells group inspectors, inspecting all the weeklyoperations reports submitted to HSE as per the requirements of DCR Regulation 19.As part of the well notification process inspection meetings may be held with the well operator both attheir office and at HSE offices. Further meetings may be held as required. On-site inspections may beconducted at the borehole site.General conclusions on current legal requirements – UKIn the UK, shale gas activities are covered by the general provisions for conventional oil and gasexploration and development and there are no general control regimes which deal specifically withGHG emissions and methane flow back. A number of regulatory regimes in the UK have the indirecteffect of restricting or controlling methane emissions from oil and gas activities including shale gas.These include the regimes relating to petroleum licensing, environmental permitting and health andsafety. Licenses for shale gas exploration and exploitation are issued by the relevant authority (eitherDECC or DETI), who must be satisfied with the technical competence and environmental awarenessof its proposed operator, but GHG emissions are not specifically taken into account. Furthermore,where a shale gas development falls within the scope of EIA, applicants may be required to supplyinformation, including a description of estimated emissions and environmental impacts (such as airand climatic factors) as part of an environmental statement. However, there is no specific requirementto include information on GHG emissions in this statement.In light of the early stage of development of shale gas activities in the UK, the authorities confirmedthat the regulatory position for some aspects of on-shore unconventional gas is currently underreview. In Northern Ireland consideration is currently being given by DOE to the existing regulatoryregimes which could be used, either in their current form or amended, to control emissions to air fromshale gas production and to establish whether these need to be supplemented. DOE is working withits counterparts in the rest of the UK in a similar review, although neither has yet progressedsufficiently to have reached any conclusions. In anticipation of any future application for hydraulicfracturing, NIEA have drafted an environmental regulatory framework that would apply. However, theyindicated that the specific suite of regulations that will apply will be on a case by case basis specific toeach individual operations proposed working practices and location.

General principlesArticle 1 of the Law 2005-781 of 13 July 2005 setting the strategy of the French energy policyprovides that this policy must contribute to the national energy independency, guarantee the energysecurity and the social and territorial cohesion by ensuring access to energy for all and to preservehuman health and the environment, particularly through the fight against GHG emissions. Article 2 ofthis law stipulates that the State must, amongst other actions, promote the reduction of GHGs andpollutants during energy extraction and production.Mining legal regimeThe exploration and exploitation of shale gas is regulated by the Mining Code. Article L-111-1 statesthat underground mineral deposits such as gaseous hydrocarbons, which includes shale gas, mustfall under the general mining legal regime. The Mining Code sets two types of authorisationprocedures. The first one involves the award of mining rights (titres miniers) for the exploration stage(permis exclusifs) and the exploitation stage (concession) and the second decides on the opening ofthe exploration or exploitation activities (ouverture des travaux). It should be noted that the legislativepart of the Mining Code has been very recently subject to a full revision.GHG emissions related considerations in the award of mining rightsMining rights for the exploration stage are granted for a maximum period of five years and can berenewed twice. The award of mining rights for the exploration stage is carried out through a publictender procedure, where applicants must, among other information, provide an environmental impactassessment indicating the potential impacts of mining works on the environment and the measurestaken to mitigate this impact. This is a general requirement that does not specifically address GHGemissions.Mining rights for the exploitation stage are granted for a maximum period of 50 years and must berenewed every 25 years in this time period. The award of mining rights for the exploitation stage isalso done through a public tender procedure where applicants must provide an environmental impactassessment indicating the potential impacts of mining works on the environment and the measurestaken to mitigate this impact. In addition, the environmental impact is subject to public consultation inwhich observations and comments can be provided to the Prefect (the State representative in theregions).GHG emissions related considerations in the permit procedure for shale gas exploration andexploitation mining worksDecree 2011-2019 entered into force on 1st June 2012, reforming the environmental impactassessment legislation such that the start of drilling works for mining exploration and exploitation ofmore than 100 metres depth (which include shale gas exploration and exploitation drilling works) has30to be subject to an environmental impact assessment and a risk study . Furthermore, the permitapplication for these mining works is subject to a public enquiry where the public and stakeholders are31consulted . This involves public consultation concerning the environmental impact assessment andof the risk study proposed by the permit applicants.

Before first June 2012 the start of mining works for shale gas exploration activities was subject to thedeclaration procedure as mentioned under Article L.162-10 of the Mining Code read in conjunction with Article 8of the Decree 2006-649 as modified. Pursuant to these provisions applicants did not have to provide anexhaustive environmental impact assessment but had only to include in their declaration a note indicating thepotential impact on the environment of the mining works and how the activity will meet the environmentalconcerns and a document on the impact of mining works on water resources and if relevant its compatibility withthe river basin management plans. As of first of June 2012 both the grant of a permit for the start of theexploration and exploitation mining works are subject to an environmental impact assessment.31Before first of June 2012 the permit application for the opening of exploration mining works was not subject toa public enquiry. The new public enquiry requirements are encompassed in Decree 2011-2018 reforming thepublic enquiry for projects with a potential impact on the environment(Décret n� 2011-2018 du 29 décembre2011 portant réforme de l'enquête publique relative aux opérations susceptibles d'affecter l'environnement).Ref: AEA/ED57412/Issue 2

Information to be provided in the environmental impact assessment (Article R122-4 of theEnvironmental Code) as of first of June 2012:Information on the design and dimensions of the project including a description of thephysical characteristics of the whole project and the technical land-use requirements duringthe construction and operational phases;Where relevant a description of the main characteristics of the processes of storage,production and manufacturing, including the ones implemented during the operation phase,such as the nature and quantity of materials used and an estimate of types and amounts ofexpected residues and emissions resulting from the operation of the proposed project;An analysis of the initial state of the environment likely to be affected by the project, includingpopulation, wildlife, natural habitats, material assets, sites and landscape, the ecologicalcontinuity, ecological balance, climatic factors, cultural and archaeological heritage, soil,water, air, noise, the natural, agricultural, forestry, marine and leisure areas, as well as theinterrelationships between these elements;An analysis of negative and positive, direct and indirect, temporary (including during theconstruction phase) and permanent, short, medium and long term impacts of the project onthe environment, and on energy consumption, the convenience of the neighbourhood (noise,vibration, odor, light emissions), hygiene, safety, public health, as well as the addition and theinteraction of these impacts;An analysis of the cumulative effects of the project with other known projects;An outline of the main alternatives studied by the applicant and the reasons why, given theeffects on the environment or human health, the proposed project was selected;The information needed to assess the project's compatibility with land use requirements;The measures provided by the applicant:ooto avoid the significant adverse effects on the environment or human health andreduce the effects that cannot be avoided;to compensate, where possible, the project's significant adverse effects on theenvironment or human health that could not be avoided or not sufficiently reduced. Ifit is not possible to compensate these effects, the applicant must justify why.

The description of these measures must be accompanied by the corresponding expenditureestimates, the presentation of the expected effects of these measures with respect to projectimpacts and how they will be monitored;An overview of methods used to assess the initial state of the environment and evaluate theproject's effects on the environment and, when several methods are available, an explanationof the reasons that led to the choice made;A description of any technical or scientific difficulties, encountered by the applicant for thisstudy.Information to be provided in the risk study(Article L-512-1 of the Environmental Code)Information on the risks and hazards for the convenience of the neighbourhood, or for publichealth and safety, or for agriculture, or for the protection of nature and the environment, or forthe conservation of sites and monuments or elements of the archaeological heritage, in caseof accidents, which cause is internal or external to the activity;Where needs be a risk analysis which takes into consideration the probability of an accidentoccurring and the kinetics and gravity of potential accidents, in accordance with amethodology which is explained in the said analysis;Appropriate measures to reduce the probability and effects of such accidents.The EIA procedure under French legislation requires certain environmental information, such asclimatic factors to be taken into account, but there is no specific requirement to include information onGHG emissions.

Furthermore authorisations of shale gas activities, provided that there is no use of the hydraulicfracturing technique (see section below on the law 2011-835), can be granted subject to theapplication of specific conditions such as, among others, the control by the operator of the impact of32the activity on water and the environment .Reporting on mining worksPursuant to Article 37 of the Decree 2006-649 the holder of liquid or gaseous hydrocarbonexploitation rights (including shale gas exploitation) must submit to the Prefect an annual programmeof the future mining works to be carried out in the calendar year, together with a study on the finalrecovery of the products contained in the deposit. This document must include all the necessaryinformation to assess the technical and economic conditions for the exploitation. The Prefect canorder supplementary works if necessary. There is no specific mention of requirements in relation toenvironmental impacts or GHG emissions.The law 2011-835 of 13 July 2011Following a very active public campaign from civil society and environmental associations the law2011-835 of 13 July 2011 was passed to prohibit the exploration and exploitation of oil and shale gasusing hydraulic fracturing technology. This prohibition is based on the application of the principle ofpreventive and corrective action encompassed in Article L-110-1 of the Environmental Code.This law also established a national commission responsible for assessing the environmental risksdue to hydraulic fracturing and alternative techniques. This Commission is entitled to issue publicopinions and to propose to the Ministries with responsibility for mining, industry, energy, ecology andsustainable development actions to assess any questions related to the exploration and exploitationof shale oil and gas. The commission can also be consulted by these Ministries on:The implementation of pilot projects using hydraulic fracturing technology or any alternativetechnologies;Any proposed regulation to reduce the environmental impacts and risks for the test of newtechnologies;Any research programme or study on the impact of hydraulic fracturing technologies oralternative technologies, notably concerning climate change impacts of the potential34exploitation of shale gas .Article 2 of 2011-835 stipulates that within a timeframe of 2 months from its promulgation, the holdersof mining rights for shale gas explorations were required to submit to the relevant administrativeauthority a report specifying the technology used or envisaged for their exploration and researchactivities. These reports were made available to the public. Mining rights were to be withdrawn if thereports were not submitted or if it mentions that hydraulic fracturing technology is used or planned tobe used. As a consequence of these provisions three exploration mining rights were withdrawn by anOrder of 12 October 2011.Requirements for Health and safety of workers under the Decree 80-331The Decree 80-331 regulating extractive industries applies to all drillings from the surface of the earthor executed at sea, to extract substances covered by Article L-111-1 of the Mining Code, whichinclude shale oil and gas. This Decree sets specific health and safety requirements to protect workersfrom the hazards and risks inherent to this activity under a Title called ‘exploration by drilling,exploitation of fluids by wells and treatment of these fluids’. This title transposes Directive 92/91/EECconcerning the minimum requirements for improving the safety and health protection of workers in themineral extracting industries through drilling. It sets general requirements that apply to all drillings,such as the employer obligation to produce a security and health document, to set a monitoringprogramme of the installations, measures against the corrosion of the canalizations and machines, on32

lightning, emergency routes and exits, equipment to use in rescue and emergency situations or theobligation to regularly carry out security exercises at the workplace.It also provides for more specific health and safety requirements in cases of exploitation of gaseousand liquid fluids that are flammable, under pressure or likely to release toxic gases. Thesecharacteristics would apply for the exploitation of shale gas. The requirements are summarized below.Summary of the OHS provisions on the exploitation of gaseous and liquid fluids, flammable orunder pressure or likely to release toxic gases under the Decree 80-331 regulating extractiveindustries (see Title F0-1P-2-R).Protection against explosion and noxious atmosphere;(health and safety documents must take into account the risk of accidental eruptions andflows, measures to prevent the occurrence and accumulation of explosive atmospheres,monitoring of the concentration of gas in the atmosphere).Measures to secure wells;(specific measures to secure flowing wells and sleeping wells).Measures to limit the risk of fire;(prohibition to store easily flammable or explosive products in the exploitation zone except forthe fuel for the engines).Specific measures during drilling works and significant interventions inside wells;(specific training for workers, security exercise, preventive and protection measures againstexplosions, fire and noxious atmosphere, measures during the leak-off test or formationintegrity test, monitoring of potential surge or flow of hydrocarbons, measures for flared gasequipment and to control kicks and prevent blow-out).

At the State level, three authorities have responsibility for the exploration and exploitation of shalegas.The Legislation Office on Mine and Raw MaterialThis office has responsibility for the regulation and legislation on mines under the General Directorateon planning, housing and nature of the Ministry of Ecology, Sustainable Development, Transport andHousing (Ministry of Sustainable Development).The Office of Soil and UndergroundThis office is part of the General Directorate on the prevention of risks of the Ministry of SustainableDevelopment. This Office has responsibility for mining inspection (police des mines) and of theenforcement of the Regulation on mining extractive industries.The Office of Exploration and Production of HydrocarbonsThis Office is part of the General Directorate of Energy and Climate. It has responsibility for theelaboration of the policy on the exploration and production of hydrocarbons and the award ofhydrocarbon mining rights.At the Regional level, mining inspection is under the control of Prefects with the support of theRegional Directions on the Environment, Planning and Housing. The enforcement powers for mininginspection concerning the exploration and exploitation of hydrocarbons are regulated under Articles30 to 34 of the Decree 2006-649.General conclusions on current legal requirements – FranceWith the entry into force of the law 2011-835 of 13 July 2011 the exploration and exploitation of oiland shale gas using hydraulic fracturing technology is prohibited in France, mainly because of thepotential impact on groundwater. The GHG emissions from shale gas activities were not the mainconcern of the French legislator. Indeed the French legislation on mining activities that would apply toshale gas exploration and exploitation does not set specific requirements for methane flow back andresulting GHG emissions.Ref: AEA/ED57412/Issue 2

6.3.3 Case Study: Legal requirements on the climate change impact of shalegas: POLAND6.3.3.1Background informationOn March 20 2012 the Polish Geological Institute released a report on shale gas potential in Poland.The methodology was based on U.S. GS practice and data was gathered from archives of PGI33(historic drills of 1950-1990). According to this report there may be up to 2 trillion m (1,920 billion m )3of recoverable shale gas reserves, although it is more likely to be in the range 346 to 768 billion m .This is as much as 5.3 times more than the conventional deposits documented to date (which in3Poland are of the size of circa 145 billion m ). With the current annual demand for natural gas in3Poland (ca. 14.5 billion m ), this is enough to satisfy the demand for natural gas of the Polish marketfor almost 65 years. According to our discussions with the Polish authorities this is also equivalent toup to 200 years of natural gas production in Poland at the current level (without changing the leveland ratios of supply from imported and national sources). The Ministry of the Environment expectsthat the amount of gas prospected in the Polish Geological Institute report will be adjusted after35collecting new drilling data from works being currently executed.Poland is very dependent on Russian’s carriers and has experienced problems of energy supply inthe past. Therefore the development of shale gas is considered by the Polish authorities as a keycomponent of its strategy to diversify its energy mix and to improve its energy security. Shale gasdeposits are located in a zone stretching from the north-west to the south-east of Poland withauthorisations for exploration already granted in most of this zone. In the EU, Poland has until thedate of publication granted the highest number of authorisations with around 50 drillings foreseen in2012. According to the work schedule, by the end of 2017, the Concession’s holders are obliged todrill 121 exploration wells (with options to drill another 127).6.3.3.2Legal framework for the exploration and exploitation of shale gas

General legal regimeThe exploration and exploitation of shale gas in Poland is mainly regulated by the new Geological andMining Law of 9 June 2011 (GML). Pursuant to this law companies that were dualy registered incompliance with the Freedom of Economic Activity Act may apply for an exploration or productionconcession (koncesja) issued by the Ministry of the Environment, to prospect, explore or exploithydrocarbons including shale gas. Concessions are granted for three to fifty years. In addition to thegrant of a concession, since deposits of hydrocarbons are the property of the State Treasury,companies must conclude a mining usufruct agreement with the State Treasury which gives them theright to undertake exploration and production activities in these deposits. In cases like: geologicalworks and the use of explosives; performance of activity by underground method; performance ofactivity by drilling holes with the depth more than 1000 m or when a concession concerns a seaterritory of Poland, the decision on the environmental conditions is required as part of the applicationfor concession. The start of shale gas mining works is subject to approval by the regional miningauthorities of a mining work program proposed by companies. Finally the mining plant operationsmust proceed on the basis of an operation plan to be approved by the competent mining supervisionauthority.The Act of 3 October 2008 on the Provision of Information on the Environment and its Protection,Public Participation in Environmental Protection and Environmental Impact Assessments transposesDirective 85/337/EC. Following the same approach of the Directive, this law sets two legal regimes forprojects based on their potential environmental impacts. For projects in Annex I an environmentalimpact assessment is compulsory. Shale gas explorations outside Annex I that fulfil certain criteria(see table below) are considered ‘Annex II’ projects. These require an environmental impactassessment only if, after a mandatory examination it is demonstrated that the exploration activitieshave a significant impact on the environment. The circumstances where there is a need for a full EIAin relation to shale gas explorations, following this screening, are described below The application forconcessions must contain a decision on environmental conditions at the site. The decision onenvironmental conditions is granted after the EIA procedure.

Information required in the environment impact assessment:description of the project comprising information on the site, design and size of the project;description of the measure envisaged in order to avoid, reduce, and, if possible, remedysignificant adverse effects;the data required to identify and assess the main effects which the project is likely to have onthe environment;an outline of the main alternatives studied by the developer and an indication of the mainreasons for his choice; andA non-technical summary of the information listed above.Shale gas explorations are subject to a mandatory screening that must conclude whetherthere is a need or not for a full EIA in case it involves:geological works and the use of explosives;performance of activity by underground method;performance of activity by drilling holes with the depth more than 1000 m;operation in the sea territory of Poland.Shale gas exploitation is subject to an environmental impact assessment where:Exploitation of the deposits of the natural gas is more than 500 000 m per day;An exploitation takes place in the marine areas of Poland.GHG emissions related conditions decision and the award of exploration and exploitationconcessionsGML sets out the conditions for undertaking and terminating activities in the field of geologicaldevelopment works and extraction of minerals from deposits. Special regulations have been appliedto the issues of prospecting and exploration of hydrocarbon deposits and extraction of hydrocarbonsfrom deposits.GML sets out conditions to be fulfilled by applicants to be entitled to participate to the tenderprocedure, which among others, are:conditions for environmental protection, and the rational use of mineral deposits;requirements necessary to ensure public security;the conditions of the security claims when needed for its establishment; andthe award of a decision on the environmental conditions.Therefore the award of concessions for the exploration and exploitation through a public tenderprocedure is likely to be subject to the decision on environmental conditions issued by competentauthorities (local authority with the consent of Regional Director for Environmental Protection orRegional Director for Environmental Protection that details for each specific site the environmental36requirements that must be followed by companies, see below) .Requirements to be detailed in the decision on environmental conditions:In a decision on the environmental conditions the competent authority must define:a) the type and place of the implementation of the project;b) the conditions for the use of the area at the stages of the implementation and operation or useof the project, with particular consideration given to the need to protect special natural values,natural resources and cultural heritage sites and to reduce the annoyances for the adjacent3

areas;c) the requirements of environmental protection which must be taken into account in thedocumentation required for the issue of the decision;d) the requirements to prevent the effects of industrial accidents, in the case of projectsclassified as plants which represent major-accident hazards;e) the requirements to reduce the transboundary impact on the environment in the case ofprojects for which the procedure for the transboundary impact on the environment has beencarried out.The competent authority must also impose the operator:a) to compensate the effect on the environment and to state the need to perform suchcompensation;b) to prevent, reduce and monitor the environmental impact of a project – impose the obligationto carry out these actions;c) in particular cases referred in other legal acts state the need to establish a restricted usearea;d) may impose on the applicant the requirement to present a follow-up analysis, setting out itsscope and the date of its presentation.Over all the Polish legislation (EIA and environmental decision requirement) does not set specificrequirements or conditions with regard to GHG emissions of shale gas exploration and exploitation.The geological work programmePursuant to the Geological and Mining Law of 9 June 2011, the start of hydrocarbon prospecting andexploration works, including shale gas, must be subject to a geological work programme approved bythe relevant administrative authorities.Information to be provided in the geological work programme inter alia:a) The objective of the works planned and the way of achieving that objective, together with thespecification of the type of geological documentation required;b) The works schedule;c) The space within the boundaries of which the geological works are to be carried out;d) Undertakings necessary for the protection of the environment, including particularlygroundwater protection and the manner of closing down excavations and boreholes as wellsas land reclamation and measures to prevent damage.Under the geological work programme, measures to protect the environment must be provided butthey do not refer to GHG emissions (the focus is on groundwater protection).The mining plant operation plansPursuant to the Geological and Mining Law of 9 June 2011, mining plants operations plans preparedby operators must be approved by the relevant national authorities.Mining plants operations plan must specify detailed measures necessary to secure inter alia:a)b)c)d)e)f)General safety;Fire safety;Work safety and health for employees of the mining plant;Correct and efficient management of the deposit;Protection of the environment and of building facilities;Prevention of damage and its remedy.

Detailed requirements set by Ministerial OrdinanceAccording to the GML the minister responsible for the economy shall specify by way of an Ordinance,in consultation with the ministers responsible for labour affairs, internal affairs and environmentaffairs, the detailed requirements related to inter alia:work health and safety, assessment and documentation of professional risks;fire protection;management of mineral deposits during the extraction;environment protection;preparation of the extracted deposits for sale;facilities, machinery and equipment of the mining plant associated with operations ofparticular types of deposit, and;cases in which the entrepreneur must have proof of the verification of technical solutions bythe expert of mining plant operations.General requirements applicable to well completion and air emissionsFor each well of hydrocarbon prospecting and exploration, plans are prepared for the geologicalworks and operation. These documents determine the construction of the well and requirements forwell drilling, taking into account the minimization of the work’s negative impact on the environment aswell as issues concerning processes from the preparation of the well to the extraction of gas(production) and its liquidation (closure).The operation plan is authorized by way of a decision by the appropriate mining supervision authority.The operator presenting the operation plan for authorization must also enclose decisions(permissions) concerning the impact on the environment, including those on waste management andair emissions. The conditions of those decisions (permits) should be reflected in the content of theoperation plan.Independent of the rules set in the documents for the project concerning geological works andoperational plans, the ordinance of the Ministry of Economy requires operators of projects (approvedby the manager of the plant) to determine detailed technical and technological issues related todrillings, processes and exploitation of a deposit. In those drafts the minimization of the negativeimpact on the environment is required, particularly the minimization of air emissions including gasesdescribed in the environmental decisions i.e. through keeping relevant technical condition of headsand technological tools. This requirement applies to air emissions from wells in general and wouldindirectly cover methane emissions from shale gas exploration and exploitation.Requirements on Health and safety of workersRequirements on safety and hygiene at work related to mining works and drilling of deposits(production) are determined by the Ordinance of the Ministry of Economy of 28 June 2002 on safetyand health at work, performance of the operation and specialized fire-protection in plants extractingdeposits by wells. The provisions on such issues are also included in the draft Ordinance of theMinistry of Economy on detail requirements concerning operation of plants extracting deposits bywells.In those regulations thresholds are set for concentrations of methane in the atmosphere (rooms) inthe plant as well as rules of hazard prevention and monitoring. The general principles are to maintainsealing of gas installations and to set hazard zones for installations which could be gas emitters. Theprevention concerns the application of installations with special construction criteria (for example to beexplosion proof) and monitoring in the areas of potential hazard occurrence.The responsible body for issues such as supervision of geological and mining operations andsupervision of work and health safety are the State Mining Authority / Regional Mining Authorities.Requirement on methane emissionsIn Poland a permit for emitting gases to the air (including methane) is required for 10 years. Apartfrom this general requirement the Polish legislation does not specifically address methane emissionsfrom shale gas exploration and exploitation.

There is more than one authority in Poland involved in preparing and supervising shale gas activitiesincluding:Ministry of the Environment(grants concessions and supervision of concessions);General Directorate for Environmental Protection / Regional Directorates for EnvironmentalProtection(supervision of environmental decisions procedures, management of Natura 2000sites, impacts of projects on Natura 2000 sites);Chief Inspectorate of Environmental Protection and regional inspectorates(permits compliancecheck and environmental monitoring);State Mining Authority / Regional Mining Authorities(supervision of geological and miningoperations, supervision of work and health safety);Relevant regional and local competent authorities (according to the legal provisions) –(responsibilityfor implementing legal provisions; granting different kind of environmental permits).The mining supervision organisations responsible for surveillance of the operation of mining plants(mining companies) and plants performing geological works (operators) also control the fulfilment ofthe rules prescribed in the above mentioned legal regulations. The Act on Geological and Mining Lawdetermines sanctions in case of the infringement of law.There are two stages of monitoring for projects that may have significant impact on the environmentand were subject to an EIA procedure. The Regional Inspectorates for Environmental Protection haveto be notified about the start of the project 30 days ahead and control the site before the operationsbegin. It is also authorized to monitor the site during the operations. The operator should submitdocumentation of works and all necessary permits, as well as enable the site for inspection andsampling.The Ministry of the Environment, as an organisation responsible for granting concessions, monitors ifgeological works done by the entities are made according to the granted concession. Concessionholders send information about quantity and the stage of geological works mentioned in theconcession. In case of failure with the concession, the concession can be withdrawn.General conclusions on current legal requirements – PolandPoland does not apply any specific requirements to control or reduce GHG emissions from shale gasexploitation and exploration. Both the mining legislation and the EIA legislation refer to measures toprotect the environment in general, or require general information on the environmental impact ofthese activities, or on air emissions. There are no specific requirements in the Polish legislation thatfocuses on the emission of GHG from shale gas explorations and exploitations.

6.3.4 Conclusions from case studiesThis section presents General findings from the country studies on the legal requirements on theclimate change impacts of shale gas exploration and exploitation in France, Poland and UK. On thebasis of desk-research and questionnaires to competent authorities, the following general conclusionscan be drawn.Reliance on general mining legislation and relevant EU requirements:Poland, France and the UK rely on their existing mining legislation on hydrocarbons and on thecurrent EU requirements transposed in their legal order (e.g. EIA Directive) to control the GHGemissions of shale gas exploration and exploitation. None of these countries have set specific legalrequirements to control and reduce GHG emissions from shale gas activities.France has until now taken the most stringent approach since it prohibits the exploration andexploitation of shale gas using hydraulic fracturing, mainly because of its potential impact on waterresources. The French authorities mention that this technology is also responsible for the methaneflow-back during exploration and exploitation.None of the countries assessed clearly mention that shale gas exploration and exploitation must beautomatically subject to an Environmental Impact Assessment. The requirements for EIA are shownRef: AEA/ED57412/Issue 2

in the table below. In the UK (after a screening procedure) and France it is most likely that an EIAwould be required for shale gas drilling under the current criteria since these types of drillings are37usually more than 100 metres depth and the area of works should exceed 1 hectare. In Poland thecriteria are less stringent since the screening to decide whether an EIA is required is compulsory for38drillings of more than 1000 metres depth .Table 26: EIA relevant for shale gas exploration and exploitationEIA requirements relevant for shale gas exploration and exploitationFranceDrilling works for miningexplorationandexploitation of more than100 metres depth issubject to a compulsoryEIA.Opening of exploitationmining works for theextraction of liquid orgaseous hydrocarbons issubject to a compulsoryEIA.UKDrillings the area ofthe work exceeds 1hectare is subject toscreening to assesswhether the projectrequires an EIA or not.Extractionofpetroleum and naturalgas for commercialpurposes, where theamountextractedexceeds 500 tonnesper day in the case ofpetroleumand3500,000 m per day inthe case of gas issubjecttoacompulsory EIA.PolandExploration stage:geological works andthe use of explosives,performance of activitybyundergroundmethod; performanceof activity by drillingholes with the depthmore than 1000 m,operation in the seaterritory of Poland aresubject to screening toassess whether theyrequire an EIA or not.Exploitation stage:Where exploitation ofthe deposits of thenatural gas is more3than 500,000 m perday and / or in themarineareasofPoland a compulsoryEIA is requiredEIA DirectiveDeep drilling is subjectto screening to assesswhether the projectrequires an EIA or not.Surfaceindustrialinstallations for theextraction of coal,petroleum, natural gasand ores, as well asbituminous shale issubject to screening toassess whether theproject requires an EIAor not.Extractionofpetroleum and naturalgas for commercialpurposes where theamountextractedexceeds500tonnes/day in the caseofpetroleum,and3500,000 m per day inthe case of gas, issubjecttoacompulsory EIA.

GHG emissions criteria in the EIAIn France, the UK and Poland the EIA must contain general information on emissions resulting fromthe operation of the proposed projects and the climate impact of the project (no further details arespecified). In France, the EIA must also contain measures to compensate, where possible, theproject's significant adverse effects on the environment or human health that could not be avoided ornot sufficiently reduced, which would be relevant in the case of GHG emissions from shale gasexploitation and exploration (e.g. GHG off-set measures). Similar measures also apply in Poland butthey are less detailed. Therefore the EIA requirements in these three countries do not really gobeyond the general EU requirements set in Directive 2011/92/EU (EIA Directive).It should be noted that the Polish government is working on a guideline to be applied for EIA dealingwith shale gas exploration and exploitation projects. No information is available on the extent to whichit will cover GHG emissions.

Findings:It would be relevant that detailed requirements should be set with regard to GHG emissions.For example:Developers should detail how methane flow back would be controlled and reduced during theexploration and exploitation stage;Off-setting measures with regard to GHG emissions should be proposed;Study on technologies limiting GHG emissions from methane flow back.Best practice for well completionIn these three countries, general well completion requirements apply to all hydrocarbon miningactivities. However, no specific requirements or guidance have been set with regard to wellcompletion of shale gas exploitation activities.Requirements for Health and safety of workersNone of the three countries assessed set specific occupational health and safety (OHS) requirementsfor the exploration and exploitation of shale gas. They rely on the general OHS requirements thatapply to the extraction and exploitation of hydrocarbons, mainly transposing the EU legal acts onthese issues (e.g. Directive 92/91/EEC concerning the minimum requirements for improving the safetyand health protection of workers in the mineral extracting industries through drilling).6.3.4.1Conclusion / Recommendations

The three countries do not set specific requirements to control GHG emissions from shale gasexploration and exploitation. They instead rely on the application of their mining and environmentallegislation. The analysis of EU legislation and a limited number of country studies have shown that theapplicability of some EU legal acts e.g. the EIA and the Industrial Emissions Directives, is uncertainand subject to interpretation. In addition the EU requirements relating directly to GHG emissions areoften worded in a very general manner, in the EU legislation itself, but also in the national transposingact. In order to adequately regulate GHG emissions from shale gas the following could be furtherinvestigated:Consideration of the issues identified related to the scope of the EIA Directive with regard toshale gas exploration and exploitation activities (Annex I or II);Consideration of information requirements on measures taken by developers to limit GHGemissions under the EIA Directive or possibly other pieces of legislation;Consideration of the need for measures to limit GHG emissions for shale gas exploration andexploitation;Consideration of the issues identified related to the scope of the Industrial Emissions Directivewith regard to shale gas exploration and exploitation activities;Consideration of the application of the emission limit values requirements under the IndustrialEmissions Directive to methane emissions from exploration and exploitation activities..

7 Assessment of current GHGemissions reporting framework7.1 IntroductionThis chapter analyses the adequacy of the current GHG emissions reporting framework under theauspices of the UNFCCC and IPCC, and proposes any improvements needed, in relation to shale gasproduction.The development of shale gas represents unconventional natural gas production. This implies thatconventional GHG emissions reporting frameworks may not be fully adequate to account for the GHGemissions of shale gas. This analysis therefore aims to give the European Commission insight intothe adequacy of the UNFCCC reporting framework and IPCC inventory compilation and reportingguidelines to enable the reporting of accurate and complete estimates of shale gas lifecycle GHGemissions.Shale gas production is in its infancy in Europe, and presents specific challenges for estimation andreporting of releases of GHGs from E&P activities. The research has sought to identify any existingdata and emission estimation methods that address these specific challenges, notably with regard tothe release of fugitive methane during exploration phases and to well completion.

7.2 Study ApproachThe analysis seeks to assess current GHG data reporting practices in the unconventional gas E&Psector, reviewing data reporting at the operator, sector and national level, in order that national GHGinventory data from EU Member States is complete, consistent, comparable, transparent andaccurate. In order that the national GHG inventory data from Member States are useful to assess EU-wide implications of unconventional gas E&P, sufficient detail in reported national GHG emissions isneeded. Furthermore, without detailed data on unconventional gas E&P GHG emissions by MemberState, it will be extremely difficult to assess the data quality reported within the EU and to ensure thatthe EU-level evidence base for policy decision-making is evolving and improving to reflectdevelopments in scientific understanding of the emission sources and impacts of mitigation actions.The study has included:Review of the UNFCCC Common Reporting Format (CRF) for national GHG inventorysubmissions;Review of the 2006 IPCC Guidelines for National GHG Inventories and the 2000 IPCC GoodPractice Guidance (GPG), for the fugitive emissions from energy sector;Review of the National Inventory Reports (NIRs) for a number of countries whereunconventional gas extraction is known / thought to occur, to review the data and methodsused for the gas E&P sector and identify anything specific to unconventional gas E&P. NIRsfor 1990-2009 submissions to the UN have been reviewed for: Canada, U.S., Poland,Germany;Consultation (via phone and email) with national GHG inventory sector experts for the fugitiveemissions from fuels sector from several countries, to research any more detailed availabledata that underpins the NIR data, and to identify (and consult with) industry regulators thatmay hold more detailed data specific to unconventional gas E&P emission sources. We havealso contacted the lead author of the fugitive emissions from energy chapter of the 2006 IPCCGuidelines and 2000 IPCC GPG (Dave Picard of Clearstone Engineering in Canada) andmembers of the IPCC Emission Factors Database expert panel (Dr Keith Brown) to seek anyadditional insight into international efforts to improve the detail and accuracy of nationalinventory guidance materials (i.e. emission estimation methodological options and emissionfactors);

Review of available documentation that the research has identified that has been developed(either by industry regulators and / or national inventory agencies) to provide industryguidance on GHG emission estimation methods for the unconventional gas E&P sector.The scope of the study encompasses all of the GHG emission sources associated withunconventional gas E&P activities to ensure that a complete overview of GHG reporting is presented.However, the study team has focussed resources on the specific challenges for GHG emissionestimation and report from shale gas E&P sources. Many emission sources from shale gasproduction, flaring, transmission and distribution are already accounted for through guidancedeveloped for other gas production technologies. The research has focussed on sources whereuncertainty in GHG measurement, accounting and reporting are highest, to research detailedinformation and data on the sources of GHG emissions that are specific to unconventional gas E&Pactivities, including:Fugitive methane losses to atmosphere during the initial phases of exploration, drilling, wellwork-overs and well development to completion, including methane released from hydraulicfracturing flow back water;Fugitive gas composition and impacts on flaring emissions of GHGs;Accidental releases due to abnormal activities such as loss of integrity of well casings.The focussing of research effort reflects the lack of a comprehensive evidence base, and hence highuncertainty, for these sources that are specific to unconventional gas E&P activities; whilst reportingof downstream gas treatment, transmission, distribution and combustion sources, as well as ancillaryactivities such as transport and waste water treatment are well documented and understood withinexisting reporting frameworks (for conventional gas and other activities). The sources specific tounconventional gas E&P present a new challenge to Member State regulators and inventorycompilers. This research seeks to identify the key knowledge gaps and provide recommendations onhow the EU may seek to address them.All emission sources in the shale gas lifecycle have been mapped against the current UNFCCCreporting framework and IPCC guidance (Appendix 2) to assess how the framework incorporatesemissions from all sources through the shale gas lifecycle, and whether the IPCC guidance providescomprehensive methodological approaches, particularly regarding fugitive emissions.

7.3 Evaluation of UNFCCC GHG Emission ReportingFrameworks and IPCC Guidelines7.3.1 Introduction to UNFCCC GHG Reporting and IPCC GuidanceThe basic principles that inform the design and development of the UNFCCC reporting framework fornational GHG inventories and the IPCC reporting guidance are to ensure that national GHGinventories are accurate, complete, consistent, transparent and comparable.The UNFCCC GHG inventory reporting system provides:Over-arching guidance to inventory compilers via the IPCC Guidelines and Good PracticeGuidance, as well as via technical working groups and an Emission Factors Database(EFDB);A Common Reporting Format (CRF) to ensure that countries deliver directly comparablenational inventory estimates;Guidance on the structure and detail of National Inventory Reports (NIRs) to ensuretransparency of estimation methods;An annual review process to manage global GHG inventory data quality and promotecontinual improvement in national inventories.We have reviewed the available reporting guidance, current practice in countries that report shale gasactivity emissions and the evolving dataset on shale gas emissions to assess where development ofIPCC guidance and UNFCCC reporting formats may be beneficial to augmenting the detail,transparency and accuracy of national GHG emission estimates.

7.3.2 UNFCCC Common Reporting FormatAll Member States are required to report annual national GHG inventory data to the EU MonitoringMechanism (MMD) and the UNFCCC using the Common Report Format (CRF) tables that all Annex 1countries use for annual submissions to the UN.The UNFCCC reporting framework is designed such that GHG estimates are reported according todefined, broad source activities from across the economy. It is designed to be flexible enough toaccommodate new sources and activities, but is not prescriptive with regards to the detailed sub-sources evident within a specific economic sector, nor with regard to specific technologies.The reporting structure for GHG sources related to oil and gas E&P is summarised in the table below,with the range of emission sources from activities pertinent to shale gas E&P activities mapped ontothe UNFCCC CRF categories.Key aspects of the UNFCCC CRF and National Inventory Reports reporting system that affect theinformation available on emissions specific to shale gas E&P are:The structure of the CRF tables does not require the reporting of emissions and activity datathat are explicitly for shale gas production. Emissions data for shale gas E&P activities areaggregated within the CRF tables with emissions data from conventional gas E&P emissions;The details of the estimation methods and source data used to derive emission estimates arerequired to be reported within the NIR that are submitted together with the CRF tables, butthere is a degree of discretion regarding the detail of data and information provided, andissues of commercial confidentiality may be cited to suppress release of supporting datasetssuch as production data;The CRF tables allow for detailed reporting of emissions from different stages in gasextraction, including separate categories for exploration, production, transmission anddistribution. In many CRF submissions, this level of detail is not presented, but emissions areaggregated across the various sources, and sometimes emissions from across oil and gasproduction are aggregated due to limitations in source data granularity at associated oil andgas production facilities.

7.3.3 IPCC Reporting Guidelines (1996, 2006), Inventory Estimation Methodsand the Inventory Review / Improvement ProcessThe IPCC guidance provides generic methodological advice and it is the responsibility of inventorycompilers to generate representative estimates for GHG emissions based on available activity data,emissions factors and (where available) emissions data from site operators or regulatory agencies.The accuracy of estimates submitted to the European Commission and UNFCCC will vary accordingto information available to inventory compilers, but across the EU all Member States should haveimplemented robust National Inventory Systems (institutional arrangements, regulations, contractsetc. to secure data provision to the inventory agency) that enable a high degree of accuracy tonational estimates for any high-emitting source categories.Emission estimation methodologies for all sources are presented within the IPCC guidance to provideoptions at three levels of detail, to enable inventory agencies to adopt a methodological approach thatmatches the available national data:Tier 1methods are associated with the highest uncertainty, and typically apply internationaldefault emission factors to national activity data, for sources where there are very limited countryspecific data to use in deriving emission estimates;Emission = National Activity Data x International Default Emission Factor[e.g. Emission = gas production (Mth)39

Emission = National Activity Data x Country-specific Emission Factor[e.g. Emission = gas production (Mth) x National factor (CH4per Mth gas production)]Tier 3methods are applicable where more detailed data is available, and typically involve theaggregation of emissions data reported by operators at the installation level. Within the EU, theexisting data reporting systems of EPR, PRTR and EU ETS provide a wealth of detailed site-specific emission estimates that are derived based on a combination of emission monitoring dataand emission estimates based on the best available local data. The Tier 3 estimates areassociated with lower uncertainty than Tier 1 or Tier 2.Emission = ∑Site-specific emission estimatesThe review of National Inventory Reports indicates that there are examples of both Tier 2 and Tier 3methods evident for the countries where unconventional gas E&P occurs:Tier 2:Country-specific studies / factors used in the derivation of oil and gas sector GHGinventory estimates for Germany, Poland and Canada;Tier 3:Shale gas basin-specific reporting used in the U.S. (which may include installation-specific data but none that are publicly available).

Furthermore, based on consultation with environmental regulators and GHG inventory compilers:A study has been commissioned by Environment Canada (the GHG Inventory Agency forCanada) to overhaul the Upstream Oil and Gas (UOG) sector estimates, which will includeconsideration of the shale gas sources in Canada. This study is due to report its findingsduring 2013;Work is on-going in Germany to overhaul the GHG inventory estimates, to update theestimation methods and factors available for national inventory reporting in time for the nextinventory reporting cycle. The outcome is expected to be a Tier 2 reporting method that isbased on the latest available data. Note that there is currently very little shale gas E&Pactivity in Germany, but around 300 hydraulic fractures have been conducted in around 30years for tight gas;The U.S. EPA has recently finalised its GHG Reporting Protocol guidance note for theupstream oil and gas sector (U.S. EPA, 2011b), and this provides equations and defaultfactors for site operators to derive well-specific fugitive methane estimates, for unconventionalshale gas E&P sources. It is anticipated that once the company reporting of well-specificestimates develops in the U.S., that these estimates will be used to inform the nationalinventory estimates, to further develop the Tier 3 estimation method currently employed.The annual review process of national inventories by UNFCCC Expert Review Teams may requireadditional, more detailed information to be demanded of inventory agencies. This may lead toimprovements in inventory detail and transparency over time. Through existing EUMM Working Groupmeetings for GHG inventory compilers, transparent and detailed descriptions of emission estimationdata sources and methods could be promoted amongst the inventory community.

7.3.4 Shale Gas E&P GHG Emission Sources: New ChallengesThe development of GHG inventory estimation and reporting systems to accommodate additionalsources pertinent to shale gas E&P presents a number of new challenges to GHG inventorycompilers. The shale gas E&P sources fall into three broad categories when considering the need fordevelopment of new data sources and GHG inventory methods:No new data or methods needed:For several emission sources from shale gas E&Pactivities the existing national inventory data and methods should adequately cover the shalegas industry emissions, such as: transport, manufacture of chemicals used in hydraulicfracturing manufacture. No inventory data / method development should be needed, and noadditional guidance required.New gas compositional data is needed to derive emission factors representative ofshale gas:For emission estimates that require gas compositional data to inform emissionfactors, the development of shale gas resources will infer a need for new, more frequent andbasin-specific or well-specific gas sampling and analysis, in order to derive emission factorsthat are representative of shale gas composition, which is more variable than conventionalgas composition. Examples include: fugitive releases from equipment (e.g. flanges,Ref: AEA/ED57412/Issue 2

compressors, pipelines), gas flaring, gas venting (where used, and where measured volumesare available), shale gas combustion, gas processing and gas leakage from the transmissionand distribution networks. There should be no need for any additional method development orguidance, other than the development of a resource of shale gas composition data that couldbe applied in estimation methods where no such compositional analysis is available to theinventory compilers. In addition to these sources, the national inventory methods forestimating emissions from waste water treatment and disposal may need to be reviewed.Specific work to derive emission estimates from this source may be needed, to reflect theincreasing demand for waste water treatment and the removal of specific chemicals andcontaminants from flow back fluids. Once again, though, no fundamental requirement for newmethodological guidance is required.New source emission estimation methods / guidance and additional data (e.g. newemission factors) will be required:There are a number of emission sources that are uniqueto shale gas E&P, for which entirely new estimation methods / guidance and source data willneed to be developed in order that inventory estimates can be made. The method options forMS inventory agencies will be determined by the scope, detail and accuracy of any industry-sourced estimates (typically through operator reporting to environmental regulatory agenciesunder regulations such as EPR / IPPC) for site-specific annual emission estimates. Ideally,where new emission estimates from operators that are specific to shale gas sources becomeavailable, this data will provide the basis for complete, consistent and transparent inventoryestimates. However, in the event that installation-specific, source-specific emissions data donot become available, that are comprehensive, transparent and consistently provided for allshale gas E&P sources / sites, then the inventory agency will need to seek alternative datasources (perhaps periodic industry studies) to supplement any available activity data (e.g. ongas venting and flaring, or perhaps numbers of well completions, well work overs or overallshale gas production). The main emission source in this category is fugitive / vented releasesof gas from drilling, exploration to well completion, including the management of methane-containing hydraulic fracturing flow back fluids. U.S. information sources indicate that this is asource of high methane emissions during the period of hydraulic fracturing and wellcompletion. This source will need to be the focus of specific research within the EU, in orderthat gas operator reporting to MS environmental regulators is sufficiently detailed andaccurate to develop a suitable evidence base for inventory reporting and policy development.The table below illustrates how shale gas emission sources map onto the existing reportingframeworks and IPCC guidelines. The table seeks to highlight where guidance or reporting detail iseither missing, or it is unclear whether existing UNFCCC and IPCC systems fully cover the matters ofconcern, as well as summarising where the existing reporting guidance and frameworks aresatisfactory for sources associated with shale gas.

Key findings from the review of the IPCC guidelines and Good practice guidance are:Key finding 1:The 2006 IPCC Guidelines do not specify how to calculate emissions from shalegas activities. Methods and emission factors are outlined for conventional gas extraction.Recommendation:The development of emission factors, estimation protocols and data on typicalshale gas composition is needed to provide operator and inventory guidance on estimating emissionsfrom sources that are specific to shale gas E&P. Whilst this could be implemented at the IPCC leveland any factors put forward for inclusion within the IPCC Emission Factors Database (IPCC EFDB). AtEU level, any research into methods and emission factors for calculation of shale gas emissionscarried out by Member States or by industry or other research bodies, could be shared betweencountries at relevant Working Group meetings. This would help encourage consistent working acrossthe EU.Key finding 2:Fugitive / vented methane from hydraulic fracturing, well completions and wellwork overs are a new source of additional GHG emissions for EU inventory compilers to manage,and therefore a new emission estimation methodology and emission factors will need to bedeveloped to cover these sources. Estimating these fugitive emissions from shale gas E&Pactivities is the main challenge to reporting complete and accurate GHG emissions. Availabledatasets on gas composition, activity data and factors affecting fugitive methane levels isdisparate. Many emissions arising from the different processes are very site specific and can becomplicated by many factors. For example, gas produced from flow-back fluids may becontaminated with carbon dioxide or nitrogen injected as part of the hydraulic fracturing or wellcompletion. Methane may not only return in the gas phase but also dissolved in the flow-backfluid, under high pressure, and the guidelines provide no method applicable to this source. Openpit collection will allow the methane to be released, whilst enclosed tanks facilitate collection forrecovery or flaring.Recommendation:Methods for oil / water / gas separation plant which are already included in theIPCC guidelines for inventory compilation may provide an option that can be modified for shale gas,whilst U.S. sources do provide some emission estimation methodologies and default factors forestimating the GHG emissions from unconventional well gas completions and work-overs. Furtherresearch into appropriate emission estimation methods and emission factors from fugitive emissionsare required.Key finding 3:The composition of shale gas differs from conventional gas; U.S. sources indicatethat shale gas exhibits a wider range of gas composition (e.g. hydrocarbon and carbon dioxidecontent) compared to conventional gas. The composition of shale gas differs according to the localbasin geology.Recommendation:Research is needed to assess shale gas composition and emission factors forshale gas basins under development in Europe. The variability of the shale gas composition observedin U.S. sources indicates that in order to ensure representative emission factors, shale gascompositional analysis will need to be conducted with greater frequency and at a more detailedgeographical level (e.g. at least gas basin-specific, if not well-specific), and that emission estimationmethods will need to reflect the local composition of the shale gas to minimise uncertainties. Use of“default” emission factors will introduce greater uncertainty for shale gas sources than would be thecase for conventional gas sources.Key finding 4:Many of the emission sources pertinent to conventional gas E&P are also sourcesfrom unconventional gas E&P. Therefore methods outlined for conventional gas extraction can beapplied, provided that new emission factors to represent the shale gas composition are developedand applied at the well- or basin-level (as shale gas composition, including hydrocarbon andcarbon dioxide content, differs from conventional natural gas and exhibits more variabilityaccording to local geological conditions). Combustion and fugitive emissions arising fromcomponents (valves, flanges, compressors etc.) during well construction, drilling and fracturingand completion are also covered by existing methodological guidance and reporting. However,there will be a need to develop shale gas specific emission factors to reflect shale gascomposition, where shale gas is used directly to fuel equipment.Recommendation:Whilst estimation methods developed for conventional gas extraction can be usedfor shale gas E&P sources, caution needs to be applied. For example, when estimating emissionsfrom gas flaring, there are operational issues specific to shale gas E&P that may inhibit the estimationaccuracy, where more inconsistent or low flow rate of gases may make it difficult to sustain a flame ona traditional flare stack. Therefore, whilst pilot flames or periodic venting may be operational solutions,Ref: AEA/ED57412/Issue 2

these may require additional detail of reporting by operators (e.g. of flaring and venting volumes, offlare gas composition) to ensure a complete, accurate emission estimate is reported.Emissions from components arise from engines that power the process of blending fracturingmaterials, pumping from storage vessels (water, chemicals and sand), compression and injection ofthe fracturing material into and out of the well. No additional guidelines or revisions to reportingstructure are recommended, but as outlined already, some work to derive shale gas compositionaldata will be needed where the gas is used to fuel the engines.Key finding 5:The UNFCCC reporting framework is aligned with the final fuel type (e.g. oil, gas,coal etc.), and is not technology-specific.Recommendation:Further disaggregation of reported emissions and the provision of tailoredemission estimation methods would be needed to deliver data specific to unconventional gas E&Psources. However, so long as estimates of fugitive emissions are transparent, accurate and reliablethere would be no need to add a separate source category to the CRF tablesKey finding 6:High volumes of waste water are produced during shale gas extraction, whichcontain chemicals and flow back contaminants. Contaminated waste water and othercontaminants (such as heavy metals, NORMs from the shale formations) will need to be treated33 36and disposed. One report from the U.S. EPA (2011) suggests that 9092m – 18,184mof waterare typically needed per well during the fracturing process. This report also indicates that, based3 40on a total fracturing fluid volume of 13,638 m, the total volume of chemical additives in3 36fracturing fluids range from 68.19 – 72.74 m(0.5% - 2% by volume). The additional burden ofwater treatment may lead to higher direct GHG emissions (waste water is a source of methanewhen treated or disposed of anaerobically, and nitrous oxide emissions can also occur from thewaste water treatment process). (e.g. of methane and nitrous oxide and VOCs at the treatmentworks, to process higher volumes of waste water). The higher volumes of waste water to betreated will increase the significance of this source in the national inventory context and MS mayneed to review their waste water treatment and disposal inventory method as a consequence. Forexample, if new higher emissions for this source lead it to be assessed as a new Key SourceCategory in the national inventory, then the accuracy of the method will come under greaterscrutiny and the MS will be required to prioritise improvements to the method.Recommendation:Whilst the guidelines provide methodological information to support estimatesfrom waste water treatment and disposal, this is potentially an area where additional research isneeded to develop guidance and factors to apply to the estimates for treatment of the (typically veryhigh volumes of) shale gas waste water that needs to be treated. Through the treatment of shale gaswaste water, additional direct emissions of methane, nitrous oxide and VOC can be expected;research is recommended to assess the level of additional emissions that this waste water treatmentwill lead to, and whether the characteristics of the waste water and in particular of the hydraulicfracturing chemical and methane content of this waste water has a notable impact on the emissions ofGHGs per unit volume of water treated.

Tables in the Canada NIR provide a series of component average emission factors for estimating totalhydrocarbon emissions from fugitive equipment leaks at natural gas production and processingfacilities, which are applicable to unconventional gas E&P.Information from the Canadian state regulators of oil & gas E&P provides useful examples of activitydata and emissions data that help to underpin shale gas E&P emission estimates; it would bebeneficial to the GHG emission inventory compilation methods within the EU if site operators wereobliged to report activity data and emissions data to a similar level of detail. The regulator reports fromthe Oil & Gas Commission in British Columbia are available at:www.bcogc.ca/publications/reports.aspxAnnual reporting by operators in Canada for both conventional and unconventional natural gas E&P,includes:Total flared gas volume and solution gas flaring volume (which is primarily aimed at gasproduced at oil wells, but could be applied to unconventional gas well flow back fluids);Annual gas production (by well, by installation);Well clean-up and well testing flaring (including information on well work-overs and re-fracturing activity in unconventional production);Total gas vented volume;Number of wells drilled;Incident types / causes (e.g. blowouts due to hydraulic fracturing, unplanned gas releases,fires etc.);Other reports require activity data useful for inventory compilation, including;Number of hydraulic fracturing activities (Number of fracturing stages per well; volume of fluidused for each stage);Number of well completions and well work-overs;Volume of waste water treated and hydraulic fracturing flow back fluid volumes;Description of Reduced Emissions Completion mitigation techniques employed.

7.3.6.2U.S.There are a range of sources from the U.S. that provide data and emission estimation methods forshale gas E&P sources, and specifically the U.S. information sources do provide examples ofestimation methods and factors to estimate the fugitive methane emissions from unconventional gaswell completions, well work-overs and handling of flow back fluids. The study team has reviewed theNational Inventory Report method description, reviewed recent methods and factors developed by theU.S. EPA for their GHG Reporting Protocol programme and also researched industry informationpublished via the U.S. EPA Natural Gas STAR (voluntary reporting) programme, and we haveconsulted with a number of U.S. experts on shale gas emissions.There are a wide range of emission factors and estimates in recent U.S. literature, and there isevidently a high degree of variability and uncertainty in estimates of fugitive methane from shale gaswell completions. During 2011, the U.S. EPA finalised a “clean” version of emission estimationmethods and emission factors for oil and gas operators to use for reporting under the (new) GHGReporting Protocol. The U.S. EPA published a supplementary technical guidance document in April2012 to summarise their findings following a review of industry literature to derive an emission factorfor unconventional gas well completions. The guidance note and emission factors were developed inconsultation with industry, and these U.S. EPA resources appear to be the most detailed informationavailable to support estimation of fugitive methane emissions from shale gas E&P sources:The GHG Reporting Protocol provides a detailed estimation methodology for operators to useto derive emission estimates from unconventional gas well completions, taking account ofdifferent variables such as flow rates and duration of hydraulic fracturing fluid flow back.Estimation calculation equations are provided for instances where mass flow is measured /estimated, or where mass flow rate is measured / estimated.The U.S. EPA technical documentation to support the GHG Reporting Protocol providesemission factors for unconventional well completions and work-overs.Several methods have been explored by the U.S. EPA to derive a recommended emission factor forunconventional gas well completions; a factor for shale and tight gas formations is cited as 11,025 Mcf3per well completion, which equates to 312,007.5 m /completion (unmitigated), or 167 tCH4

(3,503 tCO2eq). The U.S. National Inventory Report (2011 ) includes an insight into the data andestimation methods that are available to the inventory agency in the U.S., on the basis of operator-reported data to regulators, which could provide a template for development in the EU. The NIRpresents emission factors and methods for the calculation of emissions from unconventional gas wells.Data is available at a high level of detail with factors provided for:leaks from specific components (heaters, separators, metremetres, piping, compressorsetc.);flaring and venting;periodic sources such as drilling, well completions, well work-overs and well clean-ups.Regional emission factors are presented, giving an insight into the range of shale gas compositionsfrom fields across the U.S. “Typical” emission factors for unconventional gas E&P sources include:Table 28: Typical emission factors for unconventional gas E&PSourceGas well completion flaringUnconventional gas wellcompletion (nomitigation)Unconventional gas wellwork-over (nomitigation)Gas well drillingGas well clean-ups (LPwells)U.S. NIR factor (Table A-120)21.84 m of gas / completion3342

*Conversion to mass basis assumes 78.8% mole fraction of methane in gas.The U.S. National Inventory Report also presents the emission compilation approach, combining theregional gas compositional data with detailed bottom-up gas-field estimates, component inventoriesand activity data for specific activities (such as number of wells drilled per year, number ofunconventional well completions per year, number of unconventional well work-overs per year).National inventory estimates of fugitive methane emissions from oil and gas sources are presentedaccording to activity, to a level of detail that includes:Unconventional gas well completions;Unconventional gas wells work-overs;Component fugitives;Well clean-ups (LP wells).The U.S. NIR therefore provides the most detailed presentation of fugitive emission estimates fromshale gas E&P sources from the NIRs reviewed in this study. The U.S. approach is an IPCC Tier 3methodology that applies field-specific gas compositional data and local activity data, combined usingdocumented industry methodological guidance. The level of detail provided in the NIR reflects thecommensurate high degree of detail in installation-level reporting guidance in the U.S. for the industry,which reflects the length of time that the technology has been utilised in the U.S.The data is transparent and consistently reported across all regions, although the accuracy of theemission factors is subject to on-going scrutiny and the reporting uncertainty is high. We also note thatthe data in the NIR is based on emission factors that date back to earlier studies (U.S. EPA 2004,2006); new emission factors have subsequently been derived and published within the 2011 U.S. EPAGHG Reporting Protocol Sub-Part W for the oil and gas sector.

estimates of fugitive emissions within submissions for co-located combustion activities which indicatessome degree of variable interpretation of the scope of PRTR reporting within the EU; some operatorsand regulators may consider that shale gas E&P sources fall within “Mining and undergroundactivities” within PRTR national reporting.In theNetherlands,the GHG inventory compilers for fugitive releases from the energy sector (PBL)has provided an industry-wide protocol that is used by all operators in the sector, including onshoregas operators. Although this is useful to understand the overall approach to emission estimation andreporting, the protocol does not provide details of emission factors for specific sources. We have notidentified evidence to suggest that there has been any significant unconventional shale gas E&Pactivity in the Netherlands to date; the Dutch protocol does not cover any estimates of emissions fromshale gas well completions and handling of flow back fluids. A consultee from PBL stated that:“The ten Dutch Oil and Gas operators all use the electronic annual environmental report (e-MJV) toprovide their emission and production data. They are not obliged to fill in the PRTR reporting modulebut use a special Oil and Gas module. The e-MJV data of all operators are controlled and approved bythe Ministry of Economic affairs, Agriculture and Innovation (Directorate Energy market), theircompetent authority. We use the approved emission- and production data to report in the CommonReporting Format. So yes, the operators do use detailed data of their installations to calculate theiremissions but unfortunately the emissions and production data are only available in aggregated form”.Review of the operator reporting guidance and periodic industry publications has provided an insightinto the level of detail at which emission calculations are performed by Dutch oil and gas companies,and therefore the level of data granularity (e.g. of activity or emissions data for specific sources) thatmay be available to the companies in deriving the estimates. Although there are no publishedestimation methods and emission factors for the reporting of fugitive methane sources from onshoregas sources, the detailed source-specific analysis that is presented within energy conservation plansfrom Dutch oil and gas companies indicates that individual companies have developed their ownapproaches to estimating fugitive emissions from specific equipment types, to combine with theirinventories of their operational equipment; for example, these plans / publications identify potentialsavings or changes to practices for specific pieces of equipment, such flares, vents or furnaces.Consultation with national GHG inventory experts and PRTR regulatory contacts inGermanyhasidentified that there are no shale gas E&P sites in Germany reporting under PRTR and the dataavailable from operators are aggregated by site with no detail on source-specific emissions. Hydraulicfracturing has been used in Germany since the 1960s; around 300 fractures have been conductednationally in that time, indicating the relatively low uptake of this extraction technology to date. Inaddition, these fracturing jobs were not using high volume hydraulic fracturing, which is used for shalegas projects. Activity data and inventory estimates in Germany are not available at a level of detail toenable specific technologies to be identified, or even to present explicit emission estimates forupstream oil and upstream gas activities separately. The current national inventory method does notprovide any data specific to shale gas E&P, but there is an on-going study due to report later in 2012(UBA, 2012) that is aiming to derive country-specific emission factors for oil and for gas E&P sub-sectors. The Association of Oil and Gas Producing (WEG) in Hannover is the lead organisation in thedevelopment of operator guidance.Review of the National Inventory Report forPolandindicates that emission estimates used in thenational GHG inventory are derived from a country study, but the details of the emission factors usedat the source-specific level are not available.

regulators in Canada and the U.S. provide estimation methods and indicative emission factors forthese sources that are specific to shale gas E&P, which could be developed for application in the EU.IPCC Guidelines do not provide emission estimation methodology details or emission factors that areapplicable to calculate emissions from sources specific to shale gas E&P such as well completions,well work-overs and the related management of flow back fluids.The UNFCCC reporting format (CRF) does not require that countries specify GHG emissions fromshale gas E&P, or from any other specific technology or sub-sector. Emissions and activity data aretypically reported by countries at an aggregated level across all gas E&P sectors, with additionalmethodological detail provided within National Inventory Reports (NIRs). The level of detail providedregarding emission estimations within the NIRs is subject to the discretion of the inventory agency,although this can be influenced through UNFCCC Expert Review Team feedback.Several process stages in shale gas E&P, including processing and compressing the gas fordistribution, require the same steps as with conventional gas. Therefore, the current IPCC Guidelinesand national GHG inventory methodologies should be adaptable to allow inventory agencies to derivecomplete and accurate estimates for these sources. Development of appropriate emission factors(ideally at the gas-basin level) through gas sampling and compositional analysis will be required toensure that emission factors reflect the local shale gas composition, which is typically more variablethan that exhibited by conventional gas. The shale gas content of methane, other hydrocarbons andcarbon dioxide varies between shale gas basins, which implies a need for more routine gascompositional analysis in deriving emission factors and developing the evidence base for shale gasemission factors in the EU.Fugitive methane emissions from hydraulic fracturing and management of flow back waters aresources of GHG emissions that do not arise from conventional extraction. Information on emissionestimation methodologies and indicative emission factors for shale gas well completions and work-overs are only evident from U.S. industry and U.S. EPA information sources. As shale gas E&P growsin the EU, these are expected to be the most significant new sources of GHGs for Member State GHGinventories to cover, and they also present the biggest challenge methodologically.There are industry-specific, source-specific emission estimation protocols and factors developed bythe U.S. oil and gas industry and the U.S. EPA, and a final “clean” version of GHG Reporting Protocoldocuments for the U.S. oil and gas sector was published in December 2011. Shale gas E&P withhydraulic fracturing is an established technology in the U.S. but despite this there remains a lack ofclear, detailed data to provide the evidence base for determining emission factors for specific sources.The high level of uncertainty in emission factors for shale gas well completions is reflected by the on-going challenges to published data, protocols and emission factors by the U.S. oil industry and otherstakeholders. This level of uncertainty is highlighted by Pétron et al (2012), who applied dispersionmodelling analysis techniques to estimate overall methane loss to the atmosphere around a U.S.shale gas field and estimated emissions at a level double that estimated by the U.S. EPAmethodology.There is a high degree of uncertainty in the existing dataset for estimating fugitive methane emissionsfrom shale gas E&P sources, which present challenges to all regulatory and reporting agencies.Investment is needed in regulatory development, measurement and reporting protocols and guidancethat promotes a high degree of transparency and accuracy to emission estimates, together with arobust programme of data checking, benchmarking and verification by regulators and inventoryagencies.Development of GHGI Estimation Methods for EU MS Inventory AgenciesThe growth of shale gas E&P in the EU introduces new challenges to inventory compilers acrossEurope, with new sources of GHGs for inclusion in national GHG inventories. For many emissionsources associated with shale gas E&P, it is expected that current data provision and estimationmethods will enable inventory agencies to compile comprehensive and accurate national estimates.The main new challenges to inventory agencies will arise for:fugitive and vented methane emissions from well drilling to well completion, and from wellwork-overs;collating new data on shale gas composition, to develop more representative emission factorsfor sources where existing estimation methods could be applied to shale gas E&P sources(such as flaring, gas leakage and fugitive releases from site components);

Emissions = Activity Data x Emission FactorIt is anticipated that the on-going studies in Canada and Germany may help to derive options tosupport such methodological developments. We also note that in applying this proposed inventorycompilation approach, uncertainties would be reduced if the data were available to distinguishbetween different groups of sources (such as sources with or without reduced emissions completions,or sources from different producing basins), and carry out the calculations separately for these groupsfollowed by aggregation of the estimated emissions.In all cases, local gas compositional data will need to be obtained through gas sampling and analysis,to ensure that emission estimates or factors are representative of the shale gas quality in that basin.The level of additional GHG emissions from waste water (flow back) treatment and disposal areuncertain, and further research into this source is one of the recommendations of this study; based onthe limited information from review of literature, the additional waste water emissions from shale gasE&P activities are expected to be modest in comparison to fugitive methane sources from wellcompletions. We also note from UK GHGI experience that the research and resourcing of inventoryestimation methods reflect the historic significance of that source nationally.Therefore, it is anticipated that the potentially large increase in demand for waste water treatment dueto the need to treat high volumes of hydraulic fracturing flow-back fluid will test the rigour of nationalmethods already in place for this source. Typically, within EU MS inventories this is a low priorityemission source. A shift in activity levels due to shale gas production could elevate waste water tobecoming a Key Source Category in some MS inventories. If countries find that this is the case, it maybe that they will need to invest resources into improving their estimates and moving to a higher tier ofreporting for this source category. Higher tier methods are presented in the IPCC guidelines, but mayrequire an extra level of investment in the development of emission factors and estimation methods. Ifthis is the case, then it is expected that there will be extra demands placed on some inventoryagencies within the EU.New Research StudiesEnvironment Canada has recently commissioned a new study to improve national estimates from oiland gas including consideration of shale gas E&P, which will report in 2013. In addition the Germaninventory agency has an on-going study to improve the detail and accuracy of national estimates forthe oil and gas sector. Both of these studies may provide useful, new information, to help inform theRef: AEA/ED57412/Issue 2

It is recommended to promote research within Europe to support Member State development of dataand reporting for shale gas exploration and production to ensure consistent, comparable, accurate andtransparent GHG reporting.Working Group meetings (such as WG1 for inventories) could be used as a systematic way ofpromoting harmonisation of methods across EU MS. Although the EU has no mandatory powers inplace to enforce methods of ‘best practice’ discussed at these meetings, they can still be used as aforum for MS to discuss common issues and gain support and advice from others in solving anyproblems.In the development of industry-specific guidance on operator reporting and regulation design, the EUshould consider the approach developed in Canada including: consideration of the range of operatordata reported within British Columbia; the findings of the Jurisdictional regulatory review conducted bythe Government of Alberta.Further useful lessons could be learned by consulting with shale gas experts in the U.S. EPA thathave developed the GHG Reporting Protocol “sub-part W” guidance for the upstream oil and gassector, which includes detailed estimation methods and factors for fugitive methane emissions fromshale gas well completions and work-overs. The presentation of detailed tables and methods in theU.S. National Inventory Report provides a high level of transparency to the emission estimates specificto the shale gas exploration and production industry; the U.S. NIR could therefore be used as anexample of good practice for Member States to consider as they develop shale gas emissionsreporting within National Inventory Reports for submission to the EU and UN.The EU should also consider engaging with Environment Canada and the German inventory agencyto gain an insight / support the on-going studies into upstream oil and gas emission estimates, in orderthat the study outputs may be of use for the future development of EU-wide guidance or regulation.7.5.1.3GHG Emission Sources, new challenges

The technical improvements should be prioritised based on the analysis presented in Table 27.To provide the most accurate and detailed source data for national inventory compilers to work with,environmental regulators within the EU should consider the development of regulatory reportingspecific to the oil and gas sector. For example, it may be appropriate to develop new industry, andsource specific guidance for operators to use in their annual submissions under EPR / IPPC and / orPRTR. The development of such guidance and protocols should build upon good practice, augmentedusing U.S. based resources to cover the new (to the EU Member States) emission sources specific toshale gas.Gas E&P operators and national gas network operators should be encouraged to conduct moreregular gas compositional analysis for shale gas, in order to develop a more robust evidence base forthe development of emission factors for shale gas E&P sources in the EU. Ideally the evidence baseshould at least target the development / compilation of gas compositional data at the gas-basin level, ifnot at the well-level.

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U.S. EPA, 2006c. Natural Gas STAR Program, Replacing Wet Seals with Dry Seals in CentrifugalCompressors, Accessed March 2, 2012, Internet address:http://www.epa.gov/gasstar/documents/ll_wetseals.pdfU.S. EPA, 2006d. Natural Gas STAR Program, Reducing Methane Emissions From Compressor RodPacking Systems, Accessed March 2, 2012, Internet address:http://www.epa.gov/gasstar/documents/ll_rodpack.pdfU.S. EPA, 2010 Greenhouse gas emissions reporting from the Petroleum and Natural Gas Industry.Background technical documentUS EPA (2011a) Office of Research and Development, “Planto Study the Potential Impacts ofHydraulic Fracturing on Drinking Water Resources,”November 2011, available viahttp://www.epa.gov/hfstudy/U.S. EPA, 2011b. Oil and Natural Gas Sector: New Source Performance Standards and NationalEmission Standards for Hazardous Air Pollutants Reviews, Proposed Rule. Federal Register,Volume 76, No. 163, August 23, 2011.U.S. EPA, 2011c, EPA-453R-11-002, Oil and natural gas sector: Standards of performance for crudeoil and natural gas production, transmission and distribution: Background technical supportdocument for proposed standards.U.S. EPA, 2011d. Natural Gas STAR Program, Reduced Emissions Completions for HydraulicallyFractured Natural Gas Wells, Accessed March 2, 2012, Internet address:http://www.epa.gov/gasstar/documents/reduced_emissions_completions.pdfU.S. EPA, 2012a Oil and Natural Gas Sector: New Source Performance Standards and NationalEmission Standards for Hazardous Air Pollutants ReviewsU.S. EPA, 2012b. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and NaturalGas Production, Transmission and Distribution: Background Supplemental Technical SupportDocument for the Final New Source Performance Standards (April 2012).U.S. Department of Energy, Energy Information Administration, 2011a, Annual energy outlook 2011DOE/EIA-0383(2011)http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pdfU.S. Department of Energy, Energy Information Administration, 2011b, “WorldShale Gas Resources:An Initial Assessment of 14 Regions Outside the United States”U.S. Department of Energy, Energy Information Administration, 2012, Annual energy outlook 2012DOE/EIA-0383(2012) http://www.eia.gov/forecasts/aeo/pdf/0383(2012).pdfU.S. Forestry Service - Surface Operating Standards and Guidelines for Oil and Gas Exploration andDevelopment “The Gold Book”, 4th Edition 2007.U.S.NIR: Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009 (April 2011) EPA, EPA430-R-11-005.http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.htmlUstawa z dnia 27 kwietnia 2001 r. Prawo ochrony środowiska.Wuppertal, 2005. S. Lechtenböhmer et al. Greenhouse gas emissions from the Russian natural gasexport pipeline system. Wuppertal Institute and Max Planck Institute: Wuppertal / Mainz,February 2005.“What the Frack?” The Economist, 1 October 2011 p.34.Yoon and Tamada, 2005. S.Y. Yoon, T Yamada, Life Cycle Inventory Analysis of Fossil Energies inJapanYoxtheimer D 2012, “Flowback Management Trends and Strategies,” presentation at Shale Gas WaterManagement Initiative, March 29, 2012, Canonsburg, PAhttp://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2007:229:0001:0085:EN:PDFhttps://www.og.decc.gov.uk/upstream/licensing/shale gas.pdfDECC 2010http://og.decc.gov.uk/assets/og/licences/licappenvironmentalguidance.dochttp://og.decc.gov.uk/en/olgs/cms/licences/licensing_guid/types_of_licen/methane/methane.aspxRef: AEA/ED57412/Issue 2

9 GlossaryGlossary adapted in part from NYSDEC (2011). The majority of terms in this glossary are referred to inthe report. Some additional terms are included to assist in wider discussion of unconventional gasoperations.Useful TerminologyAquifer: A zone of permeable, water saturated rock material below the surface of the earth capable ofproducing significant quantities of water.Annular Space or Annulus: Space between casing and the wellbore, or between the tubing and casingor wellbore, or between two strings of casing.Anticline: A fold with strata sloping downward on both sides from a common crest.Abandonment: To permanently close a well, usually after either logs determine there is insufficienthydrocarbon potential to complete the well, or after production operations have drained thereservoir. An abandoned well is plugged with cement to prevent the escape of methane tothe surface or nearby aquifers.Best Management Practice: Current state-of-the-art mitigation measures applied to oil and natural gasdrilling and production to help ensure that development is conducted in an environmentallyresponsible manner. This is also known as Best Available Technique.Blowout: An uncontrolled flow of gas, oil or water from a well, during drilling when high formationpressure is encountered.Casing: Steel pipe placed in a well.CO2eq: Carbon dioxide equivalent, a measure used to compare the emissions from variousgreenhouse gases based upon their global warming potential. For example, the globalwarming potential for methane over 100 years is 21. This means that emissions of onemillion metric tons of methane is equivalent to emissions of 21 million metric tons of carbondioxide.Completion: the activities and methods of preparing a well for production after it has been drilled to theobjective formation. This principally involves preparing the well to the requiredspecifications; running in production tubing and its associated down hole tools, as well asperforating and stimulating the well by the use of hydraulic fracturing, as required.Compressor Station: A facility which increases the pressure of natural gas to move it in pipelines orinto storage.Condensate: Liquid hydrocarbons that were originally in the reservoir gas and are recovered bysurface separation.Conventional reserve: a high permeability formation (greater than 1 milliDarcy) containing oil and / orgas, which can be more readily extracted than hydrocarbons from unconventional reservesDehydrator: A device used to remove water and water vapours from gas.DIAL: Differential absorption light detection and ranging.Directional drilling: Deviation of the borehole from vertical so that the borehole penetrates a productiveformation in a manner parallel to the formation, although not necessarily horizontally.Disposal Well: A well into which waste fluids can be injected deep underground for safe disposal.Drilling Fluid: Mud, water, or air pumped down the drill string which acts as a lubricant for the bit and isused to carry rock cuttings back up the wellbore. It is also used for pressure control in thewellbore.E&P: Exploration and Production.

Economically recoverable reserves: technically recoverable petroleum for which the costs ofdiscovery, development, production, and transport, including a return to capital, can berecovered at a given market price.Ecosystem: The system composed of interacting organisms and their environments.EIS: Environmental Impact Statement.Fault: A fracture or fracture zone along which there has been displacement of the sides relative toeach other.Field: The general area underlain by one or more pools.Flash tank separator: As well as absorbing water from the wet gas stream, a glycol solutionoccasionally carries with it small amounts of methane and other compounds found in thewet gas. In order to recover this methane, a flash tank separator-condenser can be used toremove these compounds before the glycol solution reaches the boiler. The pressure of theglycol solution stream is reduced, allowing the methane and other hydrocarbons tovaporize ('flash') and be captured.Flow back Fluids: Liquids produced following drilling and initial completion and clean-up of the well.Fold: A bend in rock strata.Footwall: The mass of rock beneath a fault plane.Formation water: See Production water.Formation: A rock body distinguishable from other rock bodies and useful for mapping or description.Formations may be combined into groups or subdivided into members.Fossil methane / fossil fuel: A natural fuel such as coal or gas, formed in the geological past from theremains of living organisms.Fracking or Fracing (pronounced “fracking”): informal abbreviation for "Hydraulic Fracturing".Friction Reducer / Friction Reducing Agent: A chemical additive which alters the hydraulic fracturingfluid allowing it to be pumped into the target formation at a higher rate & reduced pressure.Gas Metre: An instrument for measuring and indicating, or recording, the volume of natural gas thathas passed through it.Gas-Water Separator: A device used to separate undesirable water from gas produced from a well.GEIS: Generic Environmental Impact Statement.GHG: Greenhouse Gas.GHGI: Greenhouse gas inventory.GHGRP: Greenhouse gas reporting protocol.Girdler Process: A widely used method for removal of hydrogen sulphide from natural gas by reactingthe H2S with amine compounds.Glycol dehydration: a process in which a liquid desiccant dehydrator is used to absorb water vapourfrom the gas stream. A glycol solution, usually either diethylene glycol or triethylene glycol,is brought into contact with the wet gas stream. The glycol/water solution is put through aspecialised boiler to vaporise the water, and enable glycol to be recovered for re-use.GNBPA: Greater Natural Buttes Project Area.GPS: Global positioning system.Green Completion: see Reduced Emissions Completion.Groundwater: Water in the subsurface below the water table. Groundwater is held in the pores ofrocks, and can be connate (that is, trapped in the rocks at the time of formation), frommeteorological sources, or associated with igneous intrusions.GWP: Global warming potential. A measure of how much a given mass of greenhouse gas isestimated to contribute to global warming.

HAPS: Hazardous Air Pollutants as defined under the Clean Air Act (seehttp://www.epa.gov/ttn/atw/188polls.html).High Volume Hydraulic Fracturing: The stimulation of a well (normally a shale gas well using horizontaldrilling techniques with multiple fracturing stages) with high volumes of fracturing fluid.3Defined by New York State DEC (2011) as fracturing using 300,000 gallons (1,350 m ) ormore of water as the base fluid in fracturing fluid.Horizontal Drilling: Deviation of the borehole from vertical so that the borehole penetrates a productiveformation with horizontally aligned strata, and runs approximately horizontally.Horizontal Leg: The part of the wellbore that deviates significantly from the vertical; it may or may notbe perfectly parallel with formational layering.Hydraulic Fracturing Fluid: Fluid used to perform hydraulic fracturing; includes the primary carrier fluid,proppant material, and all applicable additives.Hydraulic Fracturing: The act of pumping hydraulic fracturing fluid into a formation to increase itspermeability.Hydrocyclone: A device to classify, separate or sort particles in a liquid suspension based on thedensities of the particles. A hydrocyclone may be used to separate solids from liquids or toseparate liquids from different density.Hydrogen Sulphide: A malodorous, toxic gas with the characteristic odour of rotten eggs.Igneous Rock: Rock formed by solidification from a molten or partially molten state (magma).Iron Inhibitors: Chemicals used to bind the metal ions and prevent a number of different types ofproblems that iron can cause (for example, scaling problems in pipe).KML file: Computer file used in the Google Earth system.LDAR: Leak detection and repair.LEL: Lower explosive limit.Limestone: A sedimentary rock consisting chiefly of calcium carbonate (CaCO3).Make-up water: water in which proppant and chemical additives are mixed to make fracturing fluids foruse in hydraulic fracturing.Manifold: An arrangement of piping or valves designed to control, distribute and often monitor fluidflow.NAAQS: National Ambient Air Quality Standard.NDIR: Non-Dispersive Infra-Red.NESHAPs: National Emission Standards for Hazardous Air Pollutants.NORM: Naturally Occurring Radioactive Materials. Low-level radioactivity that can exist naturally innative materials, like some shales, and may be present in drill cuttings and other wastesfrom a well.Operator: Any person or organization in charge of the development of a lease or drilling and operationof a producing well.Perforate: To make holes through the casing to allow the oil or gas to flow into the well or to squeezecement behind the casing.Perforation: A hole created in the casing to achieve efficient communication between the reservoir andthe wellbore.Permeability: A measure of a material’s ability to allow passage of gas or liquid through pores,fractures, or other openings. The unit of measurement is the Darcy or millidarcy.Petroleum: In the broadest sense the term embraces the full spectrum of hydrocarbons (gaseous,liquid, and solid).Pneumatic: Run by or using compressed air.Polymer: Chemical compound of unusually high molecular weight composed of numerous repeated,linked molecular units.Ref: AEA/ED57412/Issue 2

Pool: An underground reservoir containing a common accumulation of oil and / or gas. Each zone of astructure which is completely separated from any other zone in the same structure is apool.Porosity: Volume of pore space expressed as a percent of the total bulk volume of the rock.Primary Carrier Fluid: The base fluid, such as water, into which additives are mixed to form thehydraulic fracturing fluid which transports proppant.Primary Production: Production of a reservoir by natural energy in the reservoir.Product: A hydraulic fracturing fluid additive that is manufactured using precise amounts of specificchemical constituents and is assigned a commercial name under which the substance issold or utilized.Production Casing: Casing set above or through the producing zone through which the well produces.Production water: Liquids co-produced during oil and gas wells production.Proppant or Propping Agent: A granular substance (sand grains, aluminium pellets, or other material)that is carried in suspension by the fracturing fluid and that serves to keep the cracks openwhen fracturing fluid is withdrawn after a fracture treatment.Proved reserves: The quantity of energy sources estimated with reasonable certainty, from theanalysis of geologic and engineering data, to be recoverable from well established orknown reservoirs with the existing equipment and under the existing operating conditions.PRTR: Pollutant Release and Transfer Register.REC: Reduced Emissions Completion.Reduced Emissions Completion (also known as green completion): a term used to describe a practicethat captures gas produced during well completions and well workovers following hydraulicfracturing. Portable equipment is brought on site to separate the gas from the solids andliquids produced during the high-rate flow back, and produce gas that can be delivered intothe sales pipeline. RECs help to reduce methane, VOC, and HAP emissions during wellcleanup and can eliminate or significantly reduce the need for flaring.Reservoir (oil or gas): A subsurface, porous, permeable or naturally fractured rock body in which oil orgas has accumulated. A gas reservoir consists only of gas plus fresh water that condensesfrom the flow stream reservoir. In a gas condensate reservoir, the hydrocarbons may existas a gas, but, when brought to the surface, some of the heavier hydrocarbons condenseand become a liquid.Reservoir Rock: A rock that may contain oil or gas in appreciable quantity and through whichpetroleum may migrate.Sandstone: A variously coloured sedimentary rock composed chiefly of sand like quartz grainscemented by lime, silica or other materials.Scale Inhibitor: A chemical substance which prevents the accumulation of a mineral deposit (forexample, calcium carbonate) that precipitates out of water and adheres to the inside ofpipes, heaters, and other equipment.Sedimentary rock: A rock formed from sediment transported from its source and deposited in water orby precipitation from solution or from secretions of organisms.SEIS: Supplemental Environmental Impact Statement.Seismic: Related to earth vibrations produced naturally or artificially.Separator: Tank used to physically separate the oil, gas, and water produced simultaneously from awell.SGEIS: Supplemental Generic Environmental Impact Statement.Shale gas: Shale Gas is natural gas that is formed from being trapped within shale (fine grainedsedimentary rock) formations.Shale oil: Oil shale, also known as kerogen shale, is an organic-rich fine-grained sedimentary rockcontaining kerogen (a solid mixture of organic chemical compounds) from which liquid

hydrocarbons called shale oil can be produced. Crude oil which occurs naturally in shalesis referred to as “tight oil”.Shale: A sedimentary rock consisting of thinly laminated claystone, siltstone or mud stone. Shale isformed from deposits of mud, silt, clay, and organic matter.Show: Small quantity of oil or gas, not enough for commercial production.Siltstone: Rock in which the constituent particles are predominantly silt size.Slickwater Fracturing (or slick-water): A type of hydraulic fracturing which utilizes water-basedfracturing fluid mixed with a friction reducing agent and other chemical additives.Spudding: The breaking of the earth’s surface in the initial stage of drilling a well.Squeeze: Technique where cement is forced under pressure into the annular space between casingand the wellbore, between two strings of pipe, or into the casing-hole annulus.Stage Plug: A device used to mechanically isolate a specific interval of the wellbore and the formationfor the purpose of maintaining sufficient fracturing pressure.Stage: Isolation of a specific interval of the wellbore and the associated interval of the formation for thepurpose of maintaining sufficient fracturing pressure.Stimulation: The act of increasing a well’s productivity by artificial means such as hydraulic fracturingor acidizing.Stratum (plural strata): Sedimentary rock layer typically referred to as a formation, member, or bed.Surface Casing: Casing extending from the surface through the potable fresh water zone.Surfactants: Chemical additives that reduce surface tension; or a surface active substance. Detergentadded to hydraulic fracturing fluid is a surfactant.Target Formation: The reservoir that the driller is trying to reach when drilling the well.Technically recoverable reserves: The proportion of assessed in-place petroleum that may berecoverable using current recovery technology, without regard to cost.Tight Formation: Formation with very low (less than 1 milliDarcy) permeability.Tight gas: Natural gas obtained from a tight formation.UIC: Underground Injection Control.Unconventional gas: Gas contained in rocks (which may or may not contain natural fractures) whichexhibit in-situ gas permeability of less than 1 millidarcy.USDW - Underground Source of Drinking Water: An aquifer or portion of an aquifer that supplies anypublic water system or that contains a sufficient quantity of ground water to supply a publicwater system, and currently supplies drinking water for human consumption, or thatcontains fewer than 10,000 mg/L total dissolved solids and is not an exempted aquifer.Vapour Recovery Unit: A system to which gases from gas collection and processing operations arecharged to separate the mixed gases for further processing. The vapours are suckedthrough a scrubber, where the liquid trapped is returned to the liquid pipeline system or tothe tanks, and the vapour recovered is pumped into gas lines.Viscosity: A measure of the degree to which a fluid resists flow under an applied force.VOC: Volatile Organic Compound.VRU: Vapour Recovery Unit.Water Well: Any residential well used to supply potable water.Watershed: The region drained by, or contributing water to, a stream, lake, or other body of water.Well pad: A site constructed, prepared, levelled and / or cleared in order to perform the activities andstage the equipment and other infrastructure necessary to drill one or more natural gasexploratory or production wells.Well Pad: The area directly disturbed during drilling and operation of a gas well.

Well site: Includes the well pad and access roads, equipment storage and staging areas, vehicleturnarounds, and any other areas directly or indirectly impacted by activities involving awell.Wellbore: A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open(uncased); or part of it may be cased, and part of it may be open.Wellhead: The equipment installed at the surface of the wellbore. A wellhead includes such equipmentas the casing head and tubing head.Wildcat: Well drilled to discover a previously unknown oil or gas pool or a well drilled one mile or morefrom a producing well.Workover: Repair operations on a producing well to restore or increase production. This may involverepeat hydraulic fracturing to re-stimulate gas flow from the well.Zone: A rock stratum of different character or fluid content from other strata.Relevant OrganisationsAERMOD: AMS/EPA Regulatory MODel.ANGA: America’s Natural Gas Alliance.API: American Petroleum Institute.AXPC: American Exploration and Production Council.BCOGC: British Columbia Oil and Gas Commission.BLM: United States Federal Bureau of Land Management.CFR: Code of Federal Regulations.CGA: Canadian Gas Association.EPA: The (U.S.) Environmental Protection Agency.KMG: Kerr-McGee Oil & Gas Onshore LP.NYSDEC: New York State Department of Environmental Conservation.TCEQ: Texas Commission on Environmental Quality.U.S. EPA: United States Environmental Protection Agency.U. S. GS: United States Geological Survey.Common UnitsBarrel: A volumetric unit of measurement equivalent to 42 U.S. gallons or 0.159 mbbl/yr: Barrels per year.bbl: Barrel.Bcf: Billion cubic feet. A unit of measurement for large volumes of gas. 1 bcf is equivalent to 28.3million cubic metres.Darcy: A unit of permeability. A medium with a permeability of 1 darcy permits a flow of 1 cm�/s of afluid with viscosity 1 cP (1 mPa¶s) under a pressure gradient of 1 atm/cm acting across an2area of 1 cm .gpd: Gallons per day.gpm: Gallons per minute.Mcf: Thousand cubic feet (equivalent to 28.3 cubic metres).md: Millidarcy.MDL: Minimum Detection Limit.Methane: Methane (CH4) is a greenhouse gas that remains in the atmosphere for approximately 9-15years. Methane is also a primary constituent of natural gas and an important energy source.Millidarcy: A unit of permeability, equivalent to one thousandth of a Darcy.Ref: AEA/ED57412/Issue 23.

ppb: Parts per billion.ppm: Parts per million.Tcf: Trillion cubic feet, equivalent to 28.3 billion cubic metres.tpy: Tonnes per year.Chemistry / biologyBactericides: Also known as a "Biocide." An additive that kills bacteria.Biocides: See "Bactericides".Breaker: A chemical used to reduce the viscosity of a fluid (break it down) after the thickened fluid hasfinished the job it was designed for.BTEX: Benzene, Toluene, Ethylbenzene, and Xylene. These are all aromatic hydrocarbons.Buffer agent: A weak acid or base used to maintain the pH of a solution at or close to a chosen value.CAS Number: Chemicals Abstract Service number, assigned by Chemical Abstracts Service.CBM: Coal bed methane.CEAS: Cavity enhanced adsorption spectroscopy.CFR: Code of Federal Regulations.CGA: Canadian Gas Association.CH4: Chemical formula of methane.Chemical Additive: A product composed of one or more chemical constituents that is added to aprimary carrier fluid to modify its properties in order to form hydraulic fracturing fluid.Chemical Constituent: A discrete chemical with its own specific name or identity, such as a CASNumber, which is contained within an additive product.CO: Chemical formula of carbon monoxide.CO2: Chemical formula of carbon dioxide.Coal bed methane: A form of natural gas extracted from coal beds. The term refers to methaneadsorbed onto the solid matrix of the coal.Gelling Agents: Polymers used to thicken fluid so that it can carry a significant amount of proppantsinto the formation.Corrosion Inhibitor: A chemical substance that minimizes or prevents corrosion in metal equipment.H2O: chemical formula for water.H2S: Chemical formula for hydrogen sulphide.NOx: Abbreviation for “oxides of nitrogen” made up primarily of nitrogen dioxide (NO2) and nitric oxide(NO).NSPS Regulations: New Source Performance Standard Regulations.O2: Chemical formula for oxygen.O3: Chemical formula for ozone.NH3: Chemical formula for ammonia.SO2: Chemical formula for sulphur dioxide.

Appendix 1: Literature for GHG emissions fromshale gas productionThis appendix describes in more detail the studies that have been examined as part of the literaturereview of existing studies on the GHG emissions from shale gas production. The results from thesestudies were described in Chapter 3. In order to compare the studies on an equal basis, the results, aspresented in the original studies, have been converted into consistent units. The main studies, and theassociated conversions, are described briefly below.Stephenson et al (2011)Results are presented and described by process stage, and for a range of scenarios. The results arepresented as well to wire emissions in grams of CO2equivalents per kWh of electricity production. Theestimates are modelled at an aggregated level, and represent the shale gas sector as a whole ratherthan a specific site or location. However, certain site data is used as the basis of the modellingcalculations. Estimates are made of the diesel use during drilling/hydraulic fracturing and during3transport in m per well. These were converted into tonnes of CO2equivalents on the basis ofemission factor for diesel consumption reported in the paper (250 gCO2/kWh). The assumed methaneemissions from well completions are reported in tonnes of methane per well, and were based on thefactors reported in EPA (2011).Jiang et al (2011)Results are presented in the main paper, with additional information in the supplementary informationdocument. The results are presented and described by process stage. Estimates are provided for wellpad preparation, well drilling, hydraulic fracturing and well completion.In the main paper the results are presented as gCO2eq/MJ. In the supporting information, estimatesare also provided in tonnes of CO2eq per well, as well as gCO2eq/MJ natural gas. Estimates areprovided for an illustrative well pad on the Marcellus shale. Table 9 of the supplementary informationdocument summarises the GHG emissions by process stage in terms of the metric tonnes of CO2e.g.per well. However, not all of the values reported in the table are consistent with the analysis presentedelsewhere in the supplementary information document. The ranges described in the text of thesupplementary information document were therefore assumed to supersede those in the summarytable. For emissions from well completion the methane releases reported in Section 4 of the mainpaper were used.Santaro et al (2011)Results are presented for Marcellus shale as a case study. Emissions are estimated by activity, andinclude land clearing, resource consumption, and diesel consumed in internal-combustion engines(mobile and stationary) during well development. Energy consumed once the gas well is brought intoproduction (i.e. that consumed in production, processing, and transmission/distribution streams) areassumed to be similar to previously published estimates; therefore, emission intensities from theliterature are used for these sources. Excluded from the analysis are emissions from venting andflaring of emissions.Table 3 of the technical report presents the results by activity, with the primary calculations andassumptions presented elsewhere in the report. The results are presented in grams of carbon per MJof natural gas (g C MJ-1), and for both a Low Heating Value (LHV) and High Heating Value (HHV) forthe gas. These values were converted into an estimate of the emissions per well (g C) based on thelifetime wellhead production, accounting for losses (with processing), quoted in the technical report fora representative Marcellus shale gas well. This production data is provided in Table 2.3 of thetechnical report.Broderick et al (2011)Emissions are estimated for each of the stages in the extraction. The estimates are based on dataassociated with the extraction at the Marcellus Shale in the U.S. This includes drilling, fracturing,energy production, chemical production, water transportation and wastewater treatment. The resultsare presented per well in tonnes of CO2for a single fracturing process. The results represent theadditional emissions over and above conventional gas extraction approaches. These results havebeen used directly in the current study, without any further conversion required.

For well completion, Broderick et al used estimates of the volume of methane released from studies byJiang et al (2011), Howarth et al (2011), Skone et al (2011) and EPA (2010).Skone et al (2011)Estimated emissions were based upon modelling of the full lifecycle impacts from cradle to gate.Results were presented as lbs CO2eq per MMBtu. For well completions the estimated emissions drawupon the values reported in EPA (2011). However, there is apparent misinterpretation of the emissionsfactor (where the factor is assumed to represent million cubic feet of methane, rather than natural gas)which leads to slight overestimate of the emissions compared to the original EPA (2011) study.Lechtenbohmer (2011)The emissions reported in this study are essentially based on the estimates presented in Santaro et al(2011) and Howarth et al (2011). However, an adjustment has been made to the emissions associatedwith well completions to allow for a greater proportion of flaring than in the original Howarth study. Thisexplains the lower emissions for this stage in the cycle than those reported in the original study.Howarth et al (2011)The report focusses on fugitive methane emissions. It includes emissions from the well completionstage, routing venting and equipment leaks, processing and the transportation and distribution. Theresults are presented as a percentage of the total production of the well. The results from the wellcompletion stage have been converted into absolute emissions on the basis of the gas release ratesreported in table 1 of the report. The methane content of the gas was assumed to be 78.8%, asreported in EPA (2011).U.S. EPA (2012)This is a guidance document for the oil and gas industry reporting to the GHG Reporting Protocol, anew mandatory reporting system in the U.S., which outlines the range of information from industrysources across the U.S. The recommended U.S. EPA default emission factor for emissions of gas forunconventional gas wells. The U.S. EPA recommended emission factors for well completion havebeen subject to significant industry scrutiny and some criticism. The U.S. EPA has responded bypublishing a document to outline the various industry data sources, assumptions and options forderiving emission factors.NYSDEC (2011)This document, published by the New York State Department of Environmental Conservation(NYSDEC) is the most recent draft Supplementary Guidance for Environmental Impact Statement forHorizontal drilling and hydraulic fracturing operations. This has been produced following extensiveconsultation and public review. It provides an extensive review of the available evidence for potentialenvironmental impacts including GHG emissions

This section includes a summary of information from the following sources:U.S. EPA 40 CFR Part 98: GHGRP for GHG reporting for Natural gas systems;API Compendium on GHG emission estimation methods for the oil & gas industry;U.S. EPA voluntary reporting programme for oil and gas emission mitigation, Natural GasSTAR;The UK reporting guidance to offshore oil & gas operators, for the EEMS reporting system.A2.1.1 U.S. EPA 40 CFR Part 98: GHGRP for GHG reporting for Natural gas systemsThis reference source from December 2011 is the final set of GHG estimation and reporting protocolsthat have been established by the U.S. EPA for operators of oil and gas installations to use under thenew mandatory GHG reporting system for installations over a certain threshold emissions level in theU.S. The document has gone through several iterations during 2011 with periodic consultation with theindustry and has had many improvements through review by leading industry experts. The emissionfactors quoted in the U.S. EPA guidance are quite uncertain and subject to on-going challenges fromthe industry and other stakeholders. However, in researching available protocols that could providethe basis for future EU reporting guidance, the U.S. EPA GHGRP provides a detailed description ofestimation methods, equations and insight into the level of granularity of data required to be reportedby U.S. gas operators.The document provides estimation method options for:Gas venting emissions during unconventional gas completions and work-overs where thebackflow rate is measured or calculated (Equation W-10A);Gas venting emissions during unconventional gas completions and work-overs where thebackflow vent or flare volume is measured (Equation W-10B).The information below is a transcript of the relevant section of the U.S. EPA’s latest guidance to oiland gas operators, providing emission estimation methods and emission factors, including forunconventional gas exploration and production.

Source: U.S. EPA (December 2011), “GREENHOUSE GAS EMISSIONS REPORTING FROM THEPETROLEUM AND NATURAL GAS INDUSTRY BACKGROUND TECHNICAL SUPPORTDOCUMENT”, Part 98.233(g).“Gas well venting during completions and work overs from hydraulic fracturing”.Calculate CH4, CO2and N2O annual emissions from gas well venting during completions involvinghydraulic fracturing in wells and well work overs using Equation W-10A or Equation W-10B of thissection. Equation W-10A applies to well venting when the backflow rate is measured or calculated,Equation W-10B applies when the backflow vent or flare volume is measured. Use Equation W-10A ifthe flow rate for backflow during well completions and work overs from hydraulic fracturing is knownfor the specified number of wells per paragraph (g) (1) in a sub-basin and well type (horizontal orvertical) combination. Use Equation W-10B if the flow volume for backflow during well completions andwork overs from hydraulic fracturing is known for all wells in a sub-basin and well type (horizontal orvertical) combination. Both CH4and CO2volumetric and mass emissions shall be calculated fromvolumetric total gas emissions using calculations in paragraphs (u) and (v) of this section.W

Where:Es,n=Annual volumetric total gas emissions in cubic feet at standard conditions from gaswell venting during completions or work overs following hydraulic fracturing for each sub-basin andwell type (horizontal vs. vertical) combination.W=Total number of wells completed or worked over using hydraulic fracturing in a sub-basin and well type (horizontal vs. vertical) combination.Tp=Cumulative amount of time of backflow for the completion or work over, in hours, foreach well, p, in a sub-basin and well type (horizontal vs. vertical) combination during the reportingyear.FRM =Ratio of backflow during well completions and work overs from hydraulic fracturing to30-day production rate from Equation W-12.PRp=First 30-day average production flow rate in standard cubic feet per hour of each wellp, under actual conditions, converted to standard conditions, as required in paragraph (g)(1) of thissection.EnFp=Volume of CO2or N2injected gas in cubic feet at standard conditions that was injectedinto the reservoir during an energized fracture job for each well p. If the fracture process did not injectgas into the reservoir, then EnFpis 0. If injected gas is CO2then EnFpis 0.SGp=Volume of natural gas in cubic feet at standard conditions that was recovered into aflow-line for well p as per paragraph (g) (3) of this section. This parametre includes any natural gasthat is injected into the well for clean-up. If no gas was recovered, SGpis 0.FVp=Flow volume of each well (p) in standard cubic feet per hour measured using arecording flow metre (digital or analog) on the vent line to measure backflow during the completion orwork over according to methods set forth in §98.234(b).(1) The average flow rate for backflow during well completions and work overs from hydraulicfracturing shall be determined using measurement(s) for calculation methodology 1 or calculation(s)for calculation methodology 2 described in this paragraph (g)(1) of this section. If Equation W-10A isused, the number of measurements or calculations shall be determined per sub-basin and well type(horizontal or vertical) as follows: one measurement or calculation for less than or equal to 25completions or work overs; two measurements or calculations for 26 to 50 completions or work overs;three measurements or calculations for 51 to 100 completions or work overs; four measurements orcalculations for 101 to 250 completions or work overs; and five measurements or calculations forgreater than 250 completions or work overs.

(i) Calculation Methodology 1. When using Equation W-10A, for each measured well completion(s) ineach gas producing sub-basin category and well type (horizontal or vertical) combination and for eachmeasured well work over(s) in each gas producing sub-basin category and well type (horizontal orvertical) combination, a recording flow metre (digital or analog) shall be installed on the vent line,ahead of a flare or vent if used, to measure the backflow rate according to methods set forth in§98.234(b).(ii) Calculation Methodology 2. When using Equation W-10A, for each calculated horizontal wellcompletion and each calculated vertical well completion in each gas producing sub-basin category andfor each calculated well horizontal work over and for each calculated vertical well work over in eachgas producing sub-basin category, record the well flowing pressure upstream (and downstream insubsonic flow) of a well choke according to methods set forth in §98.234(b) to calculate the wellbackflow during well completions and work overs from hydraulic fracturing. Calculate emissions usingEquation W-11A of this section for subsonic flow or Equation W-11B of this section for sonic flow. Usebest engineering estimate based on best available data along with Equation W-11C of this section todetermine whether the predominant flow is sonic or subsonic. If the value of R in Equation W-11C isgreater than or equal to 2, then flow is sonic; otherwise, flow is subsonic:

Where:FRM =Ratio of backflow rate during well completions and work overs from hydraulicfracturing to 30-day production rate.FRp=Measured backflow rate from Calculation Methodology 1 or calculated flow rate fromCalculation Methodology 2 in standard cubic feet per hour for well(s) p for each sub-basin and welltype (horizontal or vertical) combination. You may not use flow volume as used in Equation W-10Bconverted to a flow rate for this parametre.PRp=First 30-day production rate in standard cubic feet per hour for each well p that wasmeasured in the sub-basin and well type combination.W=Number of wells completed or worked over using hydraulic fracturing in a sub-basinand well type formation.(iv) For Equation W-10A, the ratio of backflow rate during well completions and work overs fromhydraulic fracturing to 30-day production rate for horizontal and vertical wells are applied to allhorizontal and vertical well completions in the gas producing sub-basin and well type combination andto all horizontal and vertical well work overs, respectively, in the gas producing sub-basin and welltype combination for the total number of hours of backflow for each of these wells.(v) For Equation W-10A, new flow rates for horizontal and vertical gas well completions and horizontaland vertical gas well work overs in each sub-basin category shall be calculated once every two yearsstarting in the first calendar year of data collection.(2) The volume of CO2or N2injected into the well reservoir during energized hydraulic fractures will bemeasured using an appropriate metre as described in 98.234(b) or using receipts of gas purchasesthat are used for the energized fracture job.(i) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section.(ii)[Reserved](3) Determine if the backflow gas from the well completion or work over from hydraulic fracturing isrecovered with purpose designed equipment that separates natural gas from the backflow, and sendsthis natural gas to a flow-line (e.g., reduced emissions completion or work overs).(i) Use the factor SGPin Equation W-10A of this section, to adjust the emissions estimated inparagraphs (g)(1) through (g) (4) of this section by the magnitude of emissions captured usingpurpose designed equipment that separates saleable gas from the backflow as determined byengineering estimate based on best available data.(ii) [Reserved](iii) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section.(4) Both CH4and CO2volumetric and mass emissions shall be calculated from volumetric totalemissions using calculations in paragraphs (u) and (v) of this section.(5) Calculate annual emissions from gas well venting during well completions and work overs fromhydraulic fracturing to flares as follows:(i) Use the total gas well venting volume during well completions and work overs as determined inparagraph (g) of this section.(ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine gaswell venting during well completions and work overs using hydraulic fracturing emissions from theflare. This adjustment to emissions from completions using flaring versus completions without flaringaccounts for the conversion of CH4to CO2in the flare.

Estimate the Emission Factor for Unconventional Well CompletionsThe emission factor for unconventional well completions was derived using several experiencespresented at Natural Gas STAR technology transfer workshops.One presentation reported that the emissions from all unconventional well completions wereapproximately 45 Bcf using 2002 data. The emission rate per completion can be back-calculated using2002 activity data. API Basic Petroleum Handbook lists that there were 25,520 wells completed in2002. Assuming Illinois, Indiana, Kansas, Kentucky, Michigan, Missouri, Nebraska, New York, Ohio,Pennsylvania, Virginia, and West Virginia produced from low-pressure wells that year, 17,769 of thosewells can be attributed to onshore, non-low-pressure formations. The Handbook also estimated that73% (or 12,971 of the 17,769 drilled wells) were gas wells, but are still from regions that are notentirely low-pressure formations. The analysis assumed that 60% of those wells are high pressure,tight formations (and 40% were low-pressure wells). Therefore, by applying the inventory emissionfactor for low-pressure well clean-ups (49,570 scf/well-year11) approximately 5,188 low-pressure wellsemitted 0.3 Bcf.40% × 12,971 wells × 49,570 scf/well × (1 bcf / 109 scf) ≈ 0.3 BcfThe remaining high pressure, tight-formation wells emitted 45 Bcf less the low-pressure 0.3 Bcf, whichequals 44.7 Bcf. Since there is great variability in the natural gas sector and the resulting emissionrates have high uncertainty; the emission rate per unconventional (high-pressure tight formation) wellswere rounded to the nearest thousand Mcf.(44.7 bcf / 60% × 12,971 wells) × (106 Mcf / 1 Bcf) ≈ 6,000 Mcf/completionThe same Natural Gas STAR presentation provides a Partner experience which shares its recoveredvolume of methane per well. This analysis assumes that the Partner recovers 90% of the flow back.Again, because of the high variability and uncertainty associated with different completion flow backsin the gas industry, this was estimated only to the nearest thousand Mcf – 10,000 Mcf/completion.A vendor / service provider of “reduced emission completions” shared its experience later in that samepresentation for the total recovered volume of gas for 3 completions. Assuming that 90% of the gaswas recovered, the total otherwise-emitted gas was back-calculated. Again, because of the highvariability and uncertainty associated with different completion flow backs in the gas industry, this wasrounded to the nearest hundred Mcf – 700 Mcf/completion.The final Natural Gas STAR presentation with adequate data to determine an average emission ratealso presented the total flow back and total completions and re-completions. Because of the highvariability and uncertainty associated with different completion flow backs in the gas industry, this wasrounded to the nearest 10,000 Mcf – 20,000 Mcf/completion.This analysis takes the simple average of these completion flow backs for the unconventional wellcompletion emission factor: 9,175 Mcf/completion.► Estimate the Emission Factor for Unconventional Well Work overs (“re-completions”)The emission factor for unconventional well work overs involving hydraulic re-fracture (“re-completions”) was assumed to be the same as unconventional well completions; calculated in theprevious section.”

EPA has revised the emission factor for non-hydraulic fracture well workover venting from 2,454 scfCH4/workover to 3,114 scf gas/workover. Comment: API has reviewed this correction and confirmedthat EPA is adjusting the emission factor of 2,454 scf CH4/workover to a natural gas basis, based on78.8 mol% CH4. This conversion does result in 3,114 scf natural gas/workover, as shown below,where standard conditions are 60 �F and 14.7 psia.A2.1.2 American Petroleum Institute Compendium of GHG Emission Methodologies for the Oiland Natural Gas Industry, August 2009The API compendium is widely used by the oil and gas sector as the primary source of information onemission estimation methods for releases from oil and gas operations. Within many of the regulatoryguidance notes and operator reporting systems evident within the EU, references to API methods formany sources are widespread. The compendium provides the basis for many of the emissionestimation methods for sources from unconventional gas E&P sources. The compendium includes asection specifically on approaches to estimating emissions from well completions, which referencesthe options for mitigation, and summarises activities such as well work overs. The references in the2009 compendium for these sources are acknowledged as being somewhat dated and based on alimited dataset. (Note that this information on well completions does not specifically mentionunconventional well completions, however).Table 5-23, on page 5-91 provides onshore gas well completion factors of 1,712,000 scf/completion-day, which in mass terms is cited as 25.9 tonnes/completion day.

Section 5.7.2 Production Related Non-Routine EmissionsWell work overs refer to activities performed to restore or increase production. Work over activitiesinvolve pulling the tubing from the well to repair tubing corrosion or other down-hole equipmentproblems. If the well has positive pressure at the surface, the well is “killed” by replacing the gas andoil in the column with a heavier fluid, such as mud or water, to stop the flow of oil and natural gas. Asmall amount of gas is released as the tubing is removed from the open surface casing. Derivation ofthe GRI / EPA emission factors for well work overs was based on data from a limited number ofproduction fields collected by Pipeline Systems Incorporated (PSI, 1990). Well completions areassociated with the final step of the well drilling. After a well is drilled, the well bore and reservoir nearthe well have to be cleaned. This is accomplished by producing the well to pits or tanks where sand,cuttings, and other reservoir fluids are collected for disposal. This step is also useful to evaluate thewell production rate to properly size the production equipment. The vented gas well completion CH4emission factors were derived based on the initial rates of production in 2000 (EIA, 2001). Actual dataon the volume of gas vented due to completion activities would provide a more rigorous emissionestimate. The emission factors from Table 5-23 may be used when producing the wells to pits or tanks

A2.1.3 U.S. EPA Programme: Natural Gas STARThe U.S. EPA’s Natural Gas STAR programme is a voluntary industry reporting programme for thedissemination of information pertaining to GHG mitigation in the oil and gas sector. The programmedocuments contain data that relate to unconventional gas E&P fugitive methane emissions and theapproaches to minimise these releases; the data are provided by the industry and are NOT verified bythe U.S. EPA or state-level regulators and therefore the data are provided here for indicative purposesonly.http://www.epa.gov/gasstar/tools/recommended.htmlThe publications available on the Gas STAR website provide information on a range of mitigationoptions for emissions sources from the oil and gas industry, some of which are applicable tounconventional gas E&P sources, including:Compressors / Engines;Deydrators;Directed Inspection and Maintenance;Pipelines;Pneumatics / Controls;Tanks;Valves;Wells.A number of these options will be directly applicable to the mitigation of fugitive methane emissionsfrom unconventional gas E&P:Install Flares:$10,000-$50,000http://www.epa.gov/gasstar/documents/installflares.pdfThe applicability of installing flares to unconventional gas E&P systems is limited due to thevariable pressure of the initial well venting / flow back phase which is the period in which thelargest fugitive emissions are produced.Reduced Emission Completions for Hydraulically Fractured Natural Gas Wells:>$50,000http://www.epa.gov/gasstar/documents/reduced_emissions_completions.pdfThe technology involves installation of sand trap and fluid separator systems to capture flowback fluid and entrained methane (and other) gas, and separate the water, condensate andrecover the gas which may be recoverable via a dehydrator to the sales line. Overall theinstallation costs are estimated at around $620,000, and payback is estimated at 3-6 monthsusing various scenarios for gas price.It is recommended that the EU considers more detailed research into the fugitive methane emissionsand mitigation options for shale gas E&P. Any such research should include a system of independentdata checking to validate the information from industry, reduce data uncertainties and ensure thatstudy outputs are at a level of detail commensurate with the requirements for GHG data reporting byemission source.

A2.1.4 UK Guidance to Offshore Operators: EEMS Atmospheric Emissions Calculations (UKOil & Gas and DECC, 2008)The EEMS guidance provides methodological information on emission estimation options, providingdefault emission factors for some sources, and outlining methods for operators to use fuelcompositional analysis to derive source-specific emission factors:“Most operators have compositional analyses for fuel gas, it is less commonly available for flare andvent gas. Compositions are given in the form of component mole percentages (Cmol) from analysis bygas chromatography. Component mole percentages can be used to calculate emission factors fordirectly vented or fugitive and certain combustion emissions. For direct emission sources thecomponent weight percentages (Cwt) lead directly to the emission gas factors.”The guidance includes a section on Scientific Background, outlining the Ideal Gas Law, mole,Absolute Temperature, Atomic and molecular weights, and then a section on reporting to standardconditions:“Mass is the preferred physical quantity for reporting gas emissions because of its independence oftemperature and pressure. All gas amounts reported to EEMS are masses, usually in tonnes (t).However, most gas measurements made in the field are volumes at non-standard temperatures andpressures. Commonly used in the oil and gas industry are the API standard conditions, which differfrom the European definition of ‘standard’. The following guidelines should be used when convertingnon-standard volumes to reported masses…”The guidance note provides example calculations for operators to use to convert emission estimatesto a mass basis (p16-19).Emission calculations and factors are provided for combustion, direct emissions (venting, loading /unloading) and fugitives, advocating the use of source-specific gas compositional data whereavailable. The estimation method for fugitive releases only covers the fugitives from component leaks.The method is outlined thus: “componentnumbers including joints, valves and pumps, and theapplication of a fugitive emission factor for each category of component. This gives a total emissionfigure, and the gas composition is used to calculate individual components”.Calculations are presented for each type of source, p23-46, including venting on p37, fugitive on p41.These could form the basis for future onshore gas operator guidance, although they do not cover thesources specific to shale gas E&P such as fugitive emissions from unconventional well completions.The EEMS General Guidance Note gives a useful overview of reporting requirements, outlining thescope of supplementary information (i.e. as well as emissions data) that operators must provide aspart of the site regulatory regime, see:http://og.decc.gov.uk/en/olgs/cms/environment/eems/technical_docs/technical_docs.aspx

*Conversion to mass basis assumes 78.8% mole fraction of methane in gas.The emission factors presented in the U.S. NIR are based on a detailed industry study using data from1992 (EPA/GRI 1996), with some factors updated by later studies such as:Gas well clean-ups (EPA 2006, HDPI 2009);Condensate storage tanks (EPA 1999, HPDI 2009, TERC 2009);Centrifugal compressors (EPA 2006b, WGC 2009);Gas well completions and work overs (re-completions) with hydraulic fracturing (i.e.unconventional) (EPA 2004, 2007).The U.S. NIR includes an overview of how the emission estimates are compiled based on regional gascompositional data, detailed bottom-up gas-field estimates using component inventories and activitydata for specific activities (e.g. number of wells drilled / year, number of unconventional wellcompletions / year, number of unconventional well work-overs / year etc.).The (oil and) gas industry estimates of fugitive methane emissions are then presented in total for theU.S. inventory, with total emissions by activity to a level of detail that includes:Unconventional gas well completions;Well work-overs for unconventional gas wells;Normal fugitives;Well clean-ups (LP wells);

Pneumatic device vents.This is the most detailed presentation of the fugitive emissions data that we have come across within aNational Inventory Report, using a Tier 3 methodology using field-specific or regional gascompositional data together with documented industry methodological guidance. The level of detail inthe NIR reflects the commensurate high degree of detail in installation-level reporting guidance in theU.S. for the industry over many years. The data are transparent and appear to be consistentlyreported across all regions. The veracity of quoted emission factors may be challenged and thereported uncertainty of estimates may remain relatively high, but the basis for the estimates is clearand detailed, and any new research to improve the emission factors would lead to directimprovements to the data.[We note that the data in the NIR are based on emission factors that date back to earlier studies (U.S.EPA 2004, 2006) and that new emission factors have since been decided upon within the 2011 U.S.EPA GHG Reporting Protocol Sub-Part W for the oil & gas sector.]Annex 3 of the U.S. NIR goes on to provide details of the calculation methods and emission factorsused for each component, and then presents tables that summarise all of the regional gas fieldestimates, including emission estimates at the source-specific level, which are then aggregated up toprovide the national totals for the U.S. inventory.Section 3.4 of the Annex contains information relating to calculation of emissions from unconventionalgas wells:“Emissions for gas well completions and work overs (re-completions) with hydraulic fracturing (i.e.unconventional) (EPA 2004, 2007)…..have…been added.”Table A-120 then presents the emission factors and activity data for 2009 estimates of CH4emissions(in Mg) for all sub-sectors of the “Natural Gas Production Stage”, including regional emission factorsfor methane leaks from specific components / sources, such as:Field Separation EquipmentHeaters 15.13 scfd/heaterSeparators 0.96 scfd/sepDehydrators 23.15 scfd/dehyMetreMetres/Piping 9.59 scfd/metreGathering CompressorsSmall Reciprocating Compressors 284.95 scfd/compLarge Reciprocating Compressors 16,182 scfd/compLarge Reciprocating Stations 8,776.43 scfd/stationPipeline Leaks 56.57 scfd/mileDrilling and Well CompletionCompletion Flaring 780 scf/compUnconventional Gas Well Completions 7,694,435 scf/comp (NE)Unconventional Gas Well Completions 7,672,247 scf/comp (midcontinent)Unconventional Gas Well Completions 7,194,624 scf/comp (Rockies)Unconventional Gas Well Completions 7,387,499scf/comp (SW)Unconventional Gas Well Completions 8,429,754 scf/comp (West coast)Unconventional Gas Well Completions 8,127,942 scf/comp (Gulf)Well Drilling 2,706 scf/well (NE)Well Drilling 2,699 scf/well (Midcontinent)Well Drilling 2,531 scf/well (Rockies)Well Drilling 2,598 scf/well (SW)

Well Drilling 2,965 scf/well (West Coast)Well Drilling 2,859 scf/well (Gulf)Normal OperationsPneumatic Device Vents 367 scfd/deviceChemical Injection Pumps 264 scfd/pumpWell WorkoversConventional Gas Wells 2,612 scf/w.oUnconventional Gas Wells 7,694,435 scf/w.o (NE)Well Clean Ups (LP Gas Wells) 1,361,786scfy/LP wellA2.2.2 Information from the Canada NIR, 1990-2009Section 3.3.2 of the NIR presents the overview of fugitive emissions from the Oil and Natural gascategory (IPCC 1B2). Fugitive emissions are based on a 2005 study by the Canadian Association ofPetroleum Producers (CAPP): “ANational Inventory of Greenhouse Gas (GHG), Criteria AirContaminant (CAC) and Hydrogen Sulphide (H2S) Emissions by the Upstream Oil and Gas Industry”.In Section 3.3.2.2, the NIR states that:“For the year 2000, emissions were identified at the facility level for over 5000 facilities. Theseestimates were then extrapolated to approximately 370 000 primary sources from flaring, venting,equipment leaks, formation CO2venting, storage losses, loading / unloading losses and accidentalreleases.Natural gas systems, gas production and gas processing are considered to be part of the upstreampetroleum industry, and the emissions for these sections were included. A multitude of data werecollected and used in the study. These included activity data from the facilities, such as process andequipment data. Emission factors were obtained from a variety of sources: published reports, such asthe U.S. EPA (1995a, 1995b); equipment manufacturers’ data; observed industry values; measuredvent rates; simulation programs; and other industry studies. The 1990–1999 and 2001–2009 fugitiveemissions were estimated using annual industry activity data from conventional UOG production andthe 2000 emission results.”Annex 3.1 of the Canada NIR presents more information on the estimation methodology for fugitivereleases. The methodology for the 2000 estimates is described thus:“The 2000 UOG emissions estimates were developed using a bottom-up approach, beginning withindividual facilities and their equipment. To fulfil this, the study drew on official data from the producingprovinces, supplemented by survey information on 1500 facilities provided by oil and gas producers.The following fugitive emissions sources were estimated:• flaring;• formation CO2, releases;• venting; and• fugitive and other unintentional releases (equipment leaks, storage and handling losses, andaccidental releases).The resulting emissions were then aggregated to determine overall emissions by facility type, activitytype and geographic area. The basic methods used to estimate GHG emissions are the following:• emission monitoring results;• emission source simulation results;• emission factors; and• destruction and removal efficiencies.The following data was collected from the facilities and used to develop the 2000 inventory:• measured volumes of natural gas taken from the process;• vented and flared waste gas volumes;Ref: AEA/ED57412/Issue 2

• fuel purchases (propane, diesel fuel, etc.);• fuel analyses;• emission monitoring results;• process operating conditions that may be used to infer the work being done by combustion devices(gas compositions, temperatures, pressures and flows, etc.); and• spill and inspection reports.Other required data included the following:• types of processes being used;• equipment inventories;• emission source control features;• sulphur content of the fuels consumed and waste gas flared; and• composition of the inlet and outlet streams.”The methodology for the 2001-2009 estimates, drawing on the 2000 estimates as its basis, andapplying scaling factors for specific activities, is described thus:“Emissions for 2001 to 2009 were estimated by extrapolating the 2000 UOG emission data usingactivity data for each emission source in each subsector. There are 12 activity parametremetres foreach province/territory and year; these were used to pro-rate the 2000 estimates from the UOG studyfor the years 2001–2009:• gas production;• conventional oil (CO);• heavy oil (HO);• crude bitumen (CB);• fuel gas;• flared gas;• wells drilled;• spills;• total wells;• CO + HO + CB;• HO + CB; and• shrinkage.”Hence the Canadian inventory approach is effectively a Tier 2 method that uses national emissionfactors and applies them to annual activity data, as outlined above. An on-going study due to report in2013 is expected to overhaul the approach and look in more detail at sub-sectors of the gas E&Pindustry; to date, this Environment Canada study has not identified any data specific to unconventionalgas E&P, however.A2.2.3 Information from the German NIR, 1990-2009The German NIR outlines the method for estimating upstream oil and gas emissions in Section 3.3.2.4for natural gas, which directs the reader to the equivalent section for oil (Section 3.3.2.3) as theupstream E&P activities in Germany are not available at a level that disaggregates oil for gasproduction.The NIR states that:“emissions consist of emissions from activities of drilling companies and of other participants in theexploration sector. Gas and oil exploration takes place in Germany. In 2009, 17 successful drillingoperations, with a total drilling distance of 66,201 m, were carried out (the annual report of the WEGassociation of oil and gas producers (Wirtschaftsverband Erdöl- und Erdgasgewinnung - WEG 2010):

Table on drilling success, p. 58). The underlying exploration statistics do not differentiate betweendrilling for oil and drilling for gas.”Emission estimates from drilling and oil and gas production are based on international factors fromIPCC guidance, and is hence are Tier 1 methods. However, an external assessment (Muller-BBM,2009) conducted a source category analysis and determined that the international factors areapplicable to Germany, and we note that there is an on-going study in Germany to further refine andimprove the oil and gas sector GHG emission estimates, which is expected to inform nationalestimates in the 1990-2011 inventory submission in April 2013.A2.2.4 Information from the Polish NIR, 1990-2009The Poland NIR provides very limited insight into the estimation methods for gas E&P sources, and noinformation specific to unconventional gas E&P. Section 3.9.2.2 outlines the emission estimates fromfugitive sources in the natural gas E&P sector. The NIR states that:“Estimation of CO2and CH4emissions from systems of high‐methane and nitrified natural gases wascarried out based on Tier 1 method [IPCC 2000]. Activity data for 1990‐2009 come from [EUROSTAT].For year’s 1988‐1989 activity data come from [IEA] database…. Emission factors for both gas systemswere taken from country study [Steczko K. 1994] for production, processing and distribution and from[Steczko 2003] for transmission and underground storage (only CH4).”Table 3.9.4 then provides the emission factors for methane emissions from natural gas E&P sourcesin the high-methane gas system in Poland, which includes:0.1008 Gg/PJ for gas production0.0551 Gg/PJ for gas transmission0.0014 Gg/PJ for underground gas storage; and0.3099 Gg/PJ for gas distributionThe data presentation is therefore not very detailed and provides very little transparency to theemission estimates.A2.3IPCC GUIDELINESThe summary of IPCC guidance and its coverage / applicability to shale gas E&P sources is includedwithin the main body of the report. In this annex, we have merely summarised the main relevantsections of the IPCC guidance documents.The text below outlines the main sources of emissions, gives top-level guidance on estimationmethods, but then goes on to detail the type of activity data that are needed to facilitate a “Tier 3”estimation method, which is the most rigorous type of method that sues installation-specific data andis subject to lower uncertainty than more generic industry-wide estimation methods that may useeither country-specific emission factors (“Tier 2”) or even international default emission factors (“Tier 1”methods, which are the most uncertain approach to compiling national inventory estimates).The IPCC guidelines also provide default emission factors on the basis of volume of gas produced, forconventionalgas extraction, covering (i) fugitives and (ii) flaring from all gas production. Uncertaintyis cited as +/-100%, even for conventional gas E&P sources. Emission factors are also provided for:gas processing, gas transmission and storage, gas distribution.[Note that we have also consulted with the lead author of the 2006 IPCC GL chapter on fugitiveemissions from energy sector, and also the lead author of the relevant chapter in the 2000 GoodPractice Guidance (Dave Picard of Clearstone Engineering, Canada), and he has confirmed that thereare currently no default factors available for sources specific to unconventional gas E&P such as wellcompletions.]

potential distribution of fugitive emissions by subcategory are provided in the API (2004)Compendium.The sources of fugitive emissions on oil and gas systems include, but are not limited to, equipmentleaks, evaporation and flashing losses, venting, flaring, incineration and accidental releases (e.g.,pipeline dig-ins, well blow-outs and spills). While some of these emission sources are engineered orintentional (e.g., tank, seal and process vents and flare systems), and therefore relatively wellcharacterised, the quantity and composition of the emissions is generally subject to significantuncertainty. This is due, in part, to the limited use of measurement systems in these cases, and wheremeasurement systems are used, the typical inability of these to cover the wide range of flows andvariations in composition that may occur. Even where some of these losses or flows are tracked aspart of routine production accounting procedures, there are often inconsistencies in the activities whichget accounted for and whether the amounts are based on engineering estimates or measurements.Throughout this chapter, an effort is made to state the precise type of fugitive emission source beingdiscussed, and to only use the term fugitive emissions or fugitive emission sources when discussingthese emissions or sources at a higher, more aggregated, level.TABLE 4.2.1 DETAILED SECTOR SPLIT FOR EMISSIONS FROM PRODUCTION ANDTRANSPORT OF OIL AND NATURAL GAS1 B 2 b Natural GasComprises emissions from venting, flaring and all other fugitive sources associated with theexploration, production, processing, transmission, storage and distribution of natural gas (includingboth associated and non-associated gas).1 B 2 b i VentingEmissions from venting of natural gas and waste gas/vapour streams at gas facilities.1 B 2 b ii FlaringEmissions from flaring of natural gas and waste gas/vapour streams at gas facilities.1 B 2 b iii All OtherFugitive emissions at natural gas facilities from equipment leaks, storage losses, pipeline breaks, wellblowouts, gas migration to the surface around the outside of wellhead casing, surface casing ventbows and any other gas or vapour releases not specifically accounted for as venting or flaring.1B 2 b iii 1 ExplorationFugitive emissions (excluding venting and flaring) from gas well drilling, drill stem testing and wellcompletions.1B 2 b iii 2 ProductionFugitive emissions (excluding venting and flaring) from the gas wellhead through to the inlet of gasprocessing plants, or, where processing is not required, to the tie-in points on gas transmissionsystems. This includes fugitive emissions related to well servicing, gas gathering, processing andassociated waste water and acid gas disposal activities.1 B 2 b iii 3 ProcessingFugitive emissions (excluding venting and flaring) from gas processing facilities.1 B 2 b iii 4 Transmission and StorageFugitive emissions from systems used to transport processed natural gas to market (i.e., to industrialconsumers and natural gas distribution systems). Fugitive emissions from natural gas storage systemsshould also be included in this category. Emissions from natural gas liquids extraction plants on gastransmission systems should be reported as part of natural gas processing (Sector 1.B.2.b.iii.3).Fugitive emissions related to the transmission of natural gas liquids should be reported underCategory 1.B.2.a.iii.31 B 2 b iii 5 DistributionFugitive emissions (excluding venting and flaring) from the distribution of natural gas to end users.1 B 2 b iii 6 Other

Fugitive emissions from natural gas systems (excluding venting and flaring) not otherwise accountedfor in the above categories. This may include emissions from well blowouts and pipeline ruptures ordig-ins.Fugitive emissions from oil and natural gas systems are often difficult to quantify accurately. This islargely due to the diversity of the industry, the large number and variety of potential emission sources,the wide variations in emission-control levels and the limited availability of emission-source data. Themain emission assessment issues are:• The use of simple production-based emission factors introduces large uncertainty;• The application of rigorous bottom-up approaches requires expert knowledge and detailed data thatmay be difficult and costly to obtain;• Measurement programmes are time consuming and very costly to perform.The ability to use a Tier 3 approach will depend on the availability of detailed production statistics andinfrastructure data (e.g. information regarding the numbers and types of facilities and the amount andtype of equipment used at each site), and it may not be possible to apply it under all circumstances.Where a country has estimated fugitive emissions from oil and gas systems based on a compilation ofestimates reported by individual oil and gas companies, this may either be a Tier 2 or Tier 3 approach,depending on the actual approaches applied by individual companies and facilities.On a small scale, fugitive emissions are completely independent of throughput. The best relation forestimating emissions from fugitive equipment leaks is based on the number and type of equipmentcomponents and the type of service, which is a Tier-3 approach.TIER 3Tier 3 comprises the application of a rigorous bottom-up assessment by primary type of source (e.g.,venting, flaring, fugitive equipment leaks, evaporation losses and accidental releases) at the individualfacility level with appropriate accounting of contributions from temporary and minor field or well-siteinstallations. It should be used for key categories where the necessary activity and infrastructure dataare readily available or are reasonable to obtain. Tier 3 should also be used to estimate emissionsfrom surface facilities where EOR, EGR and ECBM are being used in association with CCS.Approaches that estimate emissions at a less disaggregated level than this (e.g., relate emissions tothe number of facilities or the amount of throughput) are deemed to be equivalent to a Tier 1 approachif the applied factors are taken from the general literature, or a Tier 2 approach if they are country-specific values.The key types of data that would be utilized in a Tier 3 assessment would include the following:Facility inventory, including an assessment of the type and amount of equipment or processunits at each facility, and major emission controls (e.g., vapour recovery, waste gasincineration, etc.).Inventory of wells and minor field installations (e.g., field dehydrators, line heaters, well sitemetreing, etc.).Country-specific flare, vent and process gas analyses for each subcategory.Facility-level acid gas production, analyses and disposition data.Reported atmospheric releases due to well blow-outs and pipeline ruptures.Country-specific emission factors for fugitive equipment leaks, unaccounted/unreportedventing and flaring, flashing losses at production facilities, evaporation losses, etc.The amount and composition of acid gas that is injected into secure underground formationsfor disposal.TABLE 4.2.6 TYPICAL ACTIVITY DATA REQUIREMENTS FOR EACH ASSESSMENT APPROACHFOR FUGITIVE EMISSIONS FROM OIL AND GAS OPERATIONS BY TYPE OF PRIMARY SOURCECATEGORYProcess Venting / FlaringReported Volumes, Gas Compositions, Proration Factors for Splitting Venting from Flaring.

Solution Gas Factors, Liquid Throughputs, Tank Sizes, Vapour Compositions.Equipment LeaksFacility / Installation Counts by Type, Processes Used at Each Facility, Equipment ComponentSchedules by Type of Process Unit, Gas/Vapour Compositions.Gas-Operated DevicesSchedule of Gas-operated Devices by Type of Process Unit, Gas Consumption Factors, Type ofSupply Medium, Gas Composition.Accidental Releases & Third-Party DamagesIncident Reports / Summaries.Gas Migration to the Surface & Surface Casing Vent BlowsAverage Emission Factors & Numbers of Wells.DrillingNumber of Wells Drilled, Reported Vented / Flared Volumes from Drill Stem Tests, Typical Emissionsfrom Mud Tanks.Well ServicingTally of Servicing Events by Types.Pipeline LeaksType of Piping Material, Length of Pipeline.Exposed Oils ands / Oil ShaleExposed Surface Area, Average Emission Factors.Venting and Flaring from Oil ProductionGas to Oil Ratios, Flared and Vented Volumes, Conserved Gas Volumes, Re-injected Gas VolumesUtilised Gas Volumes, Gas Compositions.