Final Report for European Commission DG CLIMA by AEA is a business name of AEA Technology plc under contract to DG Climate Action dated 21/12/2011 [30 July 2012]
Estimated shale gas recoverable resource for select basins in Europe
Disclaimer : The views expressed in this report are purely those of the writer and may not in any circumstances be regarded as stating an official position of the European Commission.
As readily accessible oil and gas reserves are becoming progressively limited the energy supply industry is increasingly turning to unconventional reserves which were previously too complex or too expensive to extract. In particular there has been a growing interest in Europe in the exploitation of gas 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 health risks which need to be understood and addressed. In particular the potential contribution of shale gas production to greenhouse gas (GHG) emissions is a key area of interest. These impacts are the subject of this report. Finally the report provides an examination of the current GHG emissions reporting framework and explores the extent to which emissions from shale gas operations would be captured within the existing reporting requirements.
Shale gas exploitation
Despite there being significant shale gas reserves in Europe, with technically recoverable shale gas resources estimated at approximately 18 trillion cubic metres (m3), exploitation of shale gas to date has been limited and there is no commercial production at present. SO, The recent combination of higher natural gas prices, and the development of shale gas production in the U.S., has increased interest in shale gas exploitation within Europe. A number of the key processes involved in the extraction of shale gas reserves are similar to conventional natural gas BUT the extraction of shale gas typically involves a process known as hydraulic fracturing (fracking) where water, chemicals and proppants are pumped at high pressure into the well in order to open fractures in the rock and release the shale gas AND additional drilling is required for horizontal wells, along with much greater volumes of water required in the hydraulic fracturing process.
GHG emissions from shale gas production
Some studies, which have received a lot of media attention, have concluded that the lifecycle GHG emissions from shale gas may be larger than conventional natural gas, oil, or coal when used to generate 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 conventional gas, based on other assumptions. These estimates are discussed further in this report. Differences in the estimated emissions frequently arise from the interpretation by the authors of the primary data, in addition to the different underlying assumptions used in their GHG assessments. Overall, the emissions from shale gas are dominated by the combustion stage. Emissions from exploration have not been taken into account in any previous studies. But in our base case, which does not represent a preferred scenario, we have estimated the GHG emissions per unit of electricity generated from shale gas to be around 4% to 8% higher than for electricity generated by conventional pipeline gas from within Europe. These additional emissions arise in the pre-combustion stage, predominantly in the well completion phase when the fracturing fluid is brought back to the surface together with released methane. If emissions from well completion are mitigated, through flaring or capture, and utilised then this difference is reduced to 1% to 5%. This finding is broadly in line with those of other U.S. studies which found that generation from shale gas had 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 to European gas supply. However, this conclusion is far from clear-cut. Under our ‘worst’ case shale gas scenario, where all flow back gases at well completion are vented, emissions from electricity generated from shale gas would be similar to the upper emissions level for electricity generated from imported LNG and for gas imported from Russia. This suggests, where emissions from shale gas are uncontrolled, there may be no GHG emission benefits from utilising domestic shale gas resources over imports of conventional gas from outside the EU1. In fact, for some pipeline sources emissions from shale gas may exceed emissions from It requires Member States to ensure that developers supply certain information, such as a description of estimated air emissions and significant environmental impacts It requires Member States to ensure that developers supply certain information, such as a description of estimated air emissions and significant environmental impacts techniques will be applicable in Europe with the following caveats:
- Geology: the effectiveness of certain techniques requires sufficient gas pressure, which may not be the case at all locations in Europe.
- Infrastructure: at least initially any captured gas which doesn’t meet the required natural gas specification would need to be processed further. This may be a constraint if the pipeline or processing infrastructure is not in place and suitable connections available for transferring captured gas do not exist.
- · Availability and experience in equipment / technology: to capture the gas released on well completion and re-fracturing activity. This may be an issue in initial stages of development until vendors develop suitable solutions.
With respect to emissions resulting from flow back from well completions, the application of Reduced Emissions Completions has the potential to reduce emissions by around 90%. While there are some restrictions on the sites where these measures can be used, in principle, they have the potential to deliver significant reductions in emissions from this stage in the process AND further emissions reductions can be achieved The overview analysis of the EU legal acts identified as relevant to shale gas has shown that there are very few requirements applicable specifically to GHG emissions from shale gas projects.
Legislation controlling GHG emissions from shale gas production
The EIA Directive [85/337/EEC (Directive 85/337/CEE du Conseil concernant l'évaluation des incidences de certains projets publics et privés sur l'environnement); [2011/92/EU (codified) Directive 2011/92/UE du Parlement européen et du Conseil concernant l’évaluation des incidences de certains projets publics et privés sur l’environnement)] is the most relevant as it sets requirements as to the consideration of climate change effects and air emissions as part of a full EIA. at other stages in the gas cycle. It requires Member States to ensure that developers supply certain information, such as a description of estimated air emissions and significant environmental impacts, including air and climatic factors.
However, despite these requirements, many uncertainties remain as to whether Member States would require an EIA for shale gas operations and if so how Member States should implement the EIA. For example the way in which they would implement the methodology to be used to quantify GHG emission baseline scenarios. Directive 92/91/EEC [Directive Européenne n°92-91 du 3 novembre 1992 CONCERNANT LES PRESCRIPTIONS MINIMALES VISANT A AMELIORER LA PROTECTION EN MATIERE DE SECURITE ET DE SANTE DES TRAVAILLEURS DES INDUSTRIES EXTRACTIVES PAR FORAGE (ONZIEME DIRECTIVE PARTICULIERE AU SENS DE L'ARTICLE 16 PARAGRAPHE 1 DE LA DIRECTIVE CEE 89391)] concerning minimum requirements for improving the health and safety of workers in the mineral-extracting industries through drilling does not contain any provisions specifically relating to GHG emissions. It does, however, set requirements to protect workers from harmful and / or explosive substances. This would primarily apply to methane present in such concentration that it could represent a risk in terms of flammability for workers.
With regard to the Directive on Industrial Emissions [2010/75/EU(Directive 2010/75/UE du Parlement européen et du Conseil relative aux émissions industrielles (prévention et réduction intégrées de la pollution)] it is not clear in which circumstances it would apply to shale gas exploration and exploitation activities and whether its measures on air emissions would cover methane contained within flow back. Finally, the EU ETS Directive [Directive 2003/87/EC / Directive 2003/87/CE du Parlement européen et du Conseil établissant un système d'échange de quotas d'émission de gaz à effet de serre dans la Communauté et modifiant la directive 96/61/CE du Conseil (Texte présentant de l'intérêt pour l'EEE] could provide precedents for the regulation of shale gas emissions, through its treatment of venting and flaring, and emissions related to carbon capture and storage processes. In order to encourage the application of best available techniques the following could be further investigated:
- Consideration of the issues identified related to the scope of the EIA Directive with regard to shale gas exploration and exploitation activities (Annex I or II);
- Consideration of information requirements on measures taken by developers to limit GHG emissions under the EIA Directive, or other pieces of relevant legislation;
- Consideration of the need for measures to limit GHG emissions for shale gas exploration and exploita
- Consideration of the issues identified related to the scope of the Industrial Emissions Directive with regard to shale gas exploration and exploitation activities;
- Consideration of the application of the emission limit values requirements under the Industrial Emissions Directive to methane emissions from exploration and exploitation activities
- Consideration could also be given to the application of emission limit values for methane emissions from exploration and exploitation activities.
Estimated shale gas recoverable resource for select basins in Europe
France : 5.10 Tcm / / Poland : 5.30 Tcm/ UK : similar (Cuadrilla Resources Ltd, 2011) / Germany, Netherlands, Norway, Denmark, Sweden, Turkey, Lithuania, Lithuania : non significant (NDLR)
However in Poland Climate impact of potential shale gas production in the EU, recent estimates suggest that recoverable shale gas reserves represent a much lower volume than previously thought, and potentially as much as 85% less than U.S. Energy Department estimates2, with some companies ending exploration activities.
1.2 Objectives of the study : provide state-of-the-art information to the European Commission
1.3 Report Structure
Chapter 2: Shale gas exploitation, provides an overview of shale gas production and the processes involved;
As outlined in Section 2.1 the extraction of shale gas requires both vertical drilling and horizontal drilling
220.127.116.11 Hydraulic fracturing
During hydraulic fracturing, fluids (usually consisting of water and chemical additives) together with a ‘proppant’ [8 à 15% : NYSDEC (2011) needed to ‘prop’ open the fractures] are pumped down the well at high pressure. When the pressure exceeds the rock strength the fluids open or enlarge fractures. These fractures can extend a few hundred metres away from the well. As the fractures are created the propping agent enters the fractures. This prevents them from closing when the pumping pressure is released. The fracturing fluids are primarily water-based fluids mixed with additives. Chemical additives are mixed with base fluids. In terms of the quantities of water required, NYSDEC (2011) suggest that each stage in a multi-stage fracturing operation requires 1,100 - 2,200 m3 of water, so that the entire multi-stage fracturing operation for a single well could requires around 9,000 - 29,000 m3 of water. Industry sources INGAA Consulting (2008) and Naturalgas.org (2010) suggest up to 13,200 m3 of water is required per well for hydraulic fracturing with existing technologies. In addition to the initial hydraulic fracturing stage, the process may over time be repeated several times to extend the economic life of the well.
18.104.22.168 Flow back and waste water treatment
This recovered fluid – rising to the surface after fracking - is called flow back fluid (flow back) : it’s called waste water. Produced water is fluid displaced from the shale formation, and can contain substances that are found in the formation (e.g. salt), gases (e.g. methane, ethane), trace metals, naturally occurring radioactive elements (e.g. radium, uranium), and organic compounds.
2.3.2 Production and processing
Installing well head
22.214.171.124 Production timescales
Shale gas wells initially produce a large amount of gas (the free gas in the rock) but this reduces rapidly, typically over a period of several years. For the Marcellus shale gas industry, it is estimated that the production rate will decrease by 80% in the first five years and by 92% by 10 years, falling another 3% per year thereafter (NYSDEC, 2011).
NDLR : A previous report :
tells a more rapide Decline curve analysis : “Production from shale gas wells declines continuously and rapidly within a month or two of initial production (IP)”
methane (CH4), heavier hydrocarbons and carbon dioxide (CO2).
2.3.3 Transport and distribution : in pipelines
2.3.4 Well plugging and abandonment
At the end, the well must be properly decommissioned and plugged in order to protect the surroundings and subterranean environment
Différences from Conventional Hydrocarbon practices :
- Horizontal drilling produces longer well bore (vertical depth plus horizontal leg) requires more mud and produces more cuttings / well (Typically 40% more)
- Obtaining large volumes of water (9,000 to 29,000 m3 per well) (NYSDEC, 2011).
- Disposing of large volumes of contaminated water (9,000 to 25,000 m3 per well) (Derived from Broderick et al, 2011).
- 6 - 10 wells / pad (NYSDEC, 2011) compared to 1 well / pad for conventional production
- Both conventional and unconventional wells are drilled through water
- ‘Flow back’ of fracturing fluid and produced water containing residual fracturing chemicals, together with materials of natural origin: brine (e.g., sodium chloride), gases (e.g., methane, ethane, carbon dioxide, hydrogen sulphide, nitrogen, helium), trace elements (e.g. mercury, lead, arsenic), naturally occurring radioactive material (e.g. radium, thorium, uranium), and organic material (e.g. acids, polycyclic aromatic hydrocarbons, volatile and semi-volatile organic compounds) (U.S. EPA, 2011a).
Hydraulic fracturing has the potential to damage cement: may pose a higher risk during re-fracturing, although unclear at present (U.S. EPA, 2011a).
- The composition of fracturing fluids to be used in the EU is uncertain
- More chemical storage required
- The amount and extent of perforations may be greater for high volume hydraulic fracturing.
- More equipment required, much greater intensity of activity
- Larger volume of flow back and sand to manage (Derived from Broderick et al, 2011).
Chapter 3: Greenhouse gas emissions from shale gas production, provides a review of existing estimates of emissions from shale gas operations;
3.2 Compilation of the evidence base
Most studies estimating the GHG emissions from shale gas production are relatively recent [2 years] Some of the main 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 in the case of the government studies may have been subject to formal consultation with stakeholders [NDLR : détenteurs d’intérêts]
3.2.1 Methodological basis
One important assumption that is important to correct for is the assumed Global Warming Potential (GWP) of methane. Methane is a more potent GHG than CO2 but has a shorter lifetime in the atmosphere, a half-life of about fifteen years, versus more than 150 years for CO2. One way to compare is to evaluate the GWP of methane : can be argued to be more relevant to the evaluation of the significance of methane emissions in the next two or three decades, which will be the most critical to determine whether the world can still reach the objective of limiting the long-term increase in average surface temperatures to 2 degrees Celsius (IEA, 2012).
126.96.36.199 Emission estimates [Based on a Marcellus shale gas well pad.]
Well pad : 5 ha per site
Disturbances: Combustion emissions are based on 1,235 GJ ha for bulldozers and 98 GJ ha for excavators
GHG emissions from this sub-stage are dominated by carbon dioxide
The main uncertainties relate to the representativeness of results from one site to the next.
188.8.131.52 Emission sources
Each horizontal wellbore may be around 1,000 to 1,500 metres in lateral length but can be more (NYSDEC, 2011). Hydraulic fracturing is essential for shale gas production.
Emissions from drilling: Vertical drilling depth 2,600 metres, Horizontal drilling length 1,200 metres
Emissions from pumping: Power of pumping equipment assumed to be 34,000 HP, with a pumping time of 10 to 30 hours
Total well length of 3,878 metres, consisting of 2,678 metres depth and 1,200 metres of lateral length.
Broderick et al (2011)* :
Emissions from drilling: Horizontal drilling of 1,000 – 1,500 metres /
Fuel use of 18.6 litres of diesel per metre drilled, which equates to an emission factor of be different (and Member State regulations covering Marcellus shale /Assumes total fuel use of 109,777 litres of diesel fuel per well / Diesel emission factors of 2.64 kgCO2/litre
Existing also estimates of emissions associated with transport of materials :
Estimated emissions from transportation are strongly influenced by the assumed mass of material transported and the transport distance
Caution will therefore be needed in extrapolating U.S. context where the availability and location of water will extraction may be different).
184.108.40.206 Applicability of estimates to the EU
Due to the site specific nature of these emissions there may be significant differences, for example, in the distances required to collect water and the availability and regulations concerning the use of ground water on site. Caution will therefore be needed in extrapolating U.S. data to the European context where the availability and location of water will be different.
Existing estimates of emissions associated with resource use
Production of hydraulic fracturing fluid (e.g CHEMICALS, SAND) and drilling mud : detailed cost estimate used to inform an EIO-LCA model [100 - 300 tCO2eq per well)
Resource consumption: Includes steel, cement, chemicals, gravel and asphalt production (1,188 tCO2eq per well)
3.3.5 Treatment of the wastewater
Existing estimates of emissions associated with treatment of waste water
Assumes the waste water will be disposed of via deep well injection :
15% of the 454 m3 of water used for drilling, and 20% of the water used for hydraulic fracturing / Emissions estimated : 300 tCO2eq per well)
Based on 15% – 80% recovery of 9,000 – 29,000 m3 of water : 0.3 to 9.4 tCO2eq per well)
220.127.116.11 Applicability of estimates to the EU
The methodology is applicable to the EU context but needs to reflect current practice in the EU with respect to waste water treatment
3.3.6 Well completion
18.104.22.168 Emission sources
Upon completion of hydraulic fracturing a combination of fracturing fluid and water is returned to the surface (flow back). The flow back contains a combination of water, sand, hydrocarbon liquids and natural gas. Where the water within the flow back fluid cannot be reused, the waste water may be disposed directly by injection into a used well or transported for treatment at a waste water treatment facility. Reduced Emission 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 and Wyoming and the City of Fort Worth require the use of ‘green completions’ on all hydraulically fractured wells. Emissions from the well completion stage are short-term, typically occurring over a period of several days (U.S. EPA, 2011b).
22.214.171.124 Emission estimates
Well completion is the most important step in the pre-production phase of shale gas exploitation, in terms of the associated GHG emissions. During the course of this study, the evidence base on the emissions associated with unconventional well completions has evolved. In particular, the U.S. EPA carried out a detailed review of these emissions as part of the derivation of a series of emission factors to underpin GHG reporting in the U.S. An emissions factor for gas well completions with hydraulic fracturing was published in 2011, for use in the 1990-2009 U.S. GHG inventory (U.S.EPA, 2011b). Following further consultation of these factors, and additional research, the emission factors were updated in 2012.
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 in some of the estimates.
Derivation of default factors for Unconventional Well Completions emission factors in the latest U.S. EPA GHG Reporting Protocol
The U.S. EPA has compiled a series of GHG estimation methodology and reporting protocols for operators to use as guidance to underpin GHG reporting under new mandatory reporting systems in the U.S.; operators in the oil and gas sector must start to report their GHG emission estimates to the U.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 is summarised below:
The U.S. EPA derives a series of emission factors for unconventional well completions based on data from eleven U.S. gas industry studies; the studies include well completion emission estimates from a number of different geological formation types (shale, tight gas, coal bed methane) and present emission estimates for unmitigated well completions and reduced well completions;
The analysis includes a critical review of all of the industry sources and identifies where submissions by industry are evidently incorrect in their application of the (agreed) U.S. EPA emission estimation equations for well completions;
The U.S. EPA document presents five different approaches to deriving an aggregate emission factor from the industry source data: weighted average by well completion from all eleven studies
(across all formation types), un-weighted average by data source, weighted average by well completion by formation type (shale, tight gas and coal bed methane), weighted average by well completion across all formation types using total national data on well completions by type (i.e. to represent the U.S. data on numbers of well completions by formation type rather than just from the data available within the eleven studies), and a weighted average across tight gas and shale gas formation types (as these show similar levels of emissions);
The U.S. EPA then assessed the various outcomes from these approaches as derived a “final emission factor” for all unconventional gas well completions to be 9,000 Mcf per completion (254,700 m3), whilst the factor derived specifically for tight gas and shale gas formations (discounting the much lower estimates from coal bed methane) was 11,025 Mcf (312,007.5 m3) per completion.
The weighted average factor for tight gas and shale gas formations of 11,025 Mcf (312,007.5 m3) is regarded by the study team as the “best” factor to use as a central estimate within this study, but it must be noted that there is a high degree of reporting variability and uncertainty from across the industry studies. This factor equates to approximately 312,000 m3 per completion (unmitigated), or 167 tCH4 (3,503 t CO2eq).
3.4 Production and Processing Stage
3.4.3 Estimates of emissions
First year : 321 tonnes of methane (CH4) between 3,524 and 5,346 tonnes of CO2 (Carbon Dioxide)
4 Best available techniques for reducing GHG emissions
The NYSDEC (2011) report suggests the following measures which could be included to reduce these emissions:
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.
4.4 Well Plugging and Abandonment
Failure to consider abandonment at the design stage will make eventual abandonment more complex (and expensive).
4.4.3 Cost : The minimum bond is $10,000 (or $25,000 for state-wide operation or $150,000 nationally).
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