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Oil and gas wells and their integrity: Implications for shale and unconventional resource exploitation

Figure 1. Schematic diagram of typical well design, showing (A): structure of an exploration well; and (B): a production well. Depths to which different casings are used vary according to geology and pressure regime of drill site. Well diameter exaggerated to show sections more clearly.

Many wells have been drilled in areas where there are highly productive aquifers (Fig. 12a) and there is a good spatial correspondence between potential shale reservoirs and highly productive aquifers (Fig. 12b). In the USA, many shale gas wells have also been drilled where there are active aquifers (King and King, 2013).

Figure 12. (a) Map of UK showing location of onshore wells drilled for exploration or production and productive aquifers. (b) Map of UK showing location of potential shale gas and oil reservoirs and productive aquifers.

Figure 12. (a) Map of UK showing location of onshore wells drilled for exploration or production and productive aquifers. (b) Map of UK showing location of potential shale gas and oil reservoirs and productive aquifers. Aquifer base map reproduced with the permission of the British Geological Survey. ©NERC. All rights Reserved.

Surface identification of wells in the UK

A surface identification study of the 2152 UK onshore hydrocarbon wells was carried out. 128 wells were not included because: (a) the wells were younger than the available satellite imagery and so could not be located using this method (114 wells); (b) the wells were listed in the onshore well database (DECC, 2013) but were not present on the UKOGL map (5 wells); or (c) the wells were listed as ‘offshore’ in the DECC onshore well database (9 wells).

The remaining 2024 wells were categorised as follows:

  1. Cleared area of land present, consistent with site being used as well pad; machinery present and site apparently in use;
  2. Indications that well had once been present on site, but clearly not active.
  3. No well pad or machinery visible; no indication that well had ever been present on site;

Of the well sites included in our study (Table 5), 33.7% were clearly visible (i.e. the well pad and associated equipment could be seen; Fig. 13a), 5.5% showed evidence of prior on-site drilling activity without the current presence of drilling production, drilling equipment or a well head (Fig. 13b), and 65.2% were not visible (Fig. 13c). For 1.1% of sites it was unclear as to whether a well pad existed. These sites mainly comprise industrial locations where it could not be determined visually whether the infrastructure present was related to a well site. It is likely that the reason that 65.2% of wells are not visible is that UK regulations state that, after abandonment, the well should be sealed and cut and the land reclaimed.

Table 5. Statistics on visibility and accessibility of UK onshore wells.

Table 5. Statistics on visibility and accessibility of UK onshore wells.

Figure 13. Examples of wells locations taken from UKOGL imaged with Google Earth, illustrating range of surface manifestations of UK onshore wells: (a) cleared area of land with appearance of being a maintained well pad;

Figure 13. Examples of wells locations taken from UKOGL imaged with Google Earth, illustrating range of surface manifestations of UK onshore wells: (a) cleared area of land with appearance of being a maintained well pad; (b) cleared area of land with appearance of poorly maintained and potentially disused well pad. (c) Location of well drilling in which no well pad or machinery is visible.


To provide context for the statistics on well barrier failure reviewed above, comparative data are reported from other industrial processes, primarily mining in the UK and geothermal energy abstraction. The number of wells that may be required to produce shale gas is also considered.

Coal mining

There are estimated to be ∼250,000 lost mining shafts in the UK (Chambers et al., 2007) and many coal exploration boreholes. During mine operation, the potential for cross-contamination between mined coal horizons and overlying potable aquifers is relatively low due to the fact that mine workings are dewatered (often at a regional scale, comprising several interconnected pits) to facilitate access by the workforce. However, following mine abandonment and the cessation of dewatering, groundwater rebound occurs over 10–20 years and has the potential to contaminate overlying aquifers.

This process is driven by the hydraulic head in the coal workings exceeding that of the overlying aquifer (Younger et al., 2002). In northern England, cessation of pumping for mine dewatering in part of the Durham Coalfield led to pollution of the overlying Magnesian Limestone aquifer, used for public water supply. As a consequence, this led to the aquifer failing an EU Water Framework Directive (WFD) environmental objective for groundwater quality (Neymeyer et al., 2007). More broadly, the 2009 River Basin Management Plans, required as part of the implementation of the EU WFD, reported that 34 out of 304 groundwater bodies in England and Wales had failed ‘good’ status environmental objectives due to groundwater pollution by rising waters following mine abandonment (including coal and metal mines). In some areas, abandoned mine workings also liberate methane, and emissions from abandoned UK coal mines were estimated to be ∼14 million m3 of methane in 2008 (UNFCCC, 2010).

Geothermal energy

Environmental concerns linked to the exploitation of geothermal energy include the mobilisation of contaminants from the surrounding rock that could lead to the contamination of aquifers by geothermal fluids. In the Balcova Geothermal Field in Turkey, there has been thermal and chemical contamination of the overlying aquifer by elements such as arsenic, antimony and boron. Aksoy et al. (2009) recommended that regular inspection and maintenance of geothermal wells should be carried out.

Summers et al. (1980) characterised geothermal fluids and investigated the possible sources of well barrier and integrity failure and the potential for contamination. Based on their analysis, they proposed a methodological framework for identifying groundwater contamination from geothermal energy developments. Possible sources of well barrier and integrity failure of geothermal wells include loading from the surrounding rock formation, mechanical damage during well development, corrosion and scaling from geothermal fluids, thermal stress, metal fatigue and failure, and expansion of entrapped fluids (Southon, 2005).

The mixing of deep geothermal fluids with shallow groundwaters can occur via natural mechanisms, such as natural upward fluid convection along fault lines (e.g. within the Larderello geothermal field, Italy; Bellani et al., 2004), and by anthropogenic activities, including uncontrolled discharges to surface waters, faulty injection procedures (e.g. Los Azufres, Mexico: Birkle and Merkel, 2000), and accelerated upward seepage from failed casings within wells and boreholes.

Casing failures related to inconsistencies in casing cementation have been cited as one common cause of failure (Snyder, 1979). The major failures of several geothermal wells on the island of Milos, Greece, were attributed to thermal stresses on the well casing that were exacerbated by poor cementation (Chiotis and Vrellis, 1995). There is little published literature on failure rates of geothermal wells, and failure rates are expected to vary due to the wide range of geological settings from which geothermal energy can be exploited, with volcanically active regions carrying higher levels of risk than more tectonically quiescent regions.

Number of wells for shale gas exploitation

The number of wells that could be drilled to exploit shale gas in Europe depends on various factors, including geological conditions, social acceptance and economics. Based on data from shale gas plays in the USA, the estimated ultimate recovery (EUR) of a shale gas well varies from 1.4 BCF (0.0392 BCM) to 5.9 BCF (0.165 BCM) (Table 6; Baihly et al., 2010). If similar recoveries are assumed for wells in European shale plays, between 169 and 714 wells would be required for every 1 TCF (0.028 TCM) of total production. In comparison, it has been calculated (Gluyas et al., unpublished data) that conventional gas wells in the Rotliegend, which is a gas-bearing sandstone reservoir in the Southern North Sea, have EURs of between 1 and 100 times more gas per well.

Table 6. Estimated Ultimate Recovery (EUR) for 5 shale gas provinces in the USA (from Baihly et al., 2010).

Table 7. Crude oil pollution incidents within 1 km of 143 well pads active in UK at start of year 2000.

Table 7. Crude oil pollution incidents within 1 km of 143 well pads active in UK at start of year 2000.

Shale exploitation and water contamination

As shale reservoirs have very low permeability compared to conventional sandstone or carbonate reservoirs (typically between 3.9 × 10−6 and 9.63 × 10−4 mD: Yang and Aplin, 2007), fluid movement through and from shales is likely to be extremely slow. Therefore the potential for shales at depth to be the source of pollutants in the near-surface environment under natural conditions is low. Geological timescales would be required for significant quantities of hydrocarbons to migrate from a shale reservoir that has not been artificially hydraulically fractured.

The drilling of wells to access gas-bearing shales requires the penetration of geological formations close to the surface that will often contain freshwater. Where there is sufficient permeability and storage capacity, these formations will form aquifers (Fig. 12) that may be exploited for drinking water or industrial uses, such as agriculture. Even where aquifers are not currently utilised, they have the potential to be, and therefore require protection.

Consideration also needs to be given to protecting groundwater that supports base flow to rivers and wetland ecosystems. Protection is achieved through preventing hazardous pollutants or limiting non-hazardous pollutants entering groundwater (European Commission, 2000). Of the 2152 hydrocarbon wells drilled in the UK, the well heads of 428 (20%) of these are located above highly productive aquifers (likely to be exploited for public water supply) and a further 535 (25%) are above moderately productive aquifers, likely to be exploited for both public and private drinking water supplies (Fig. 12a).

Evidence from conventional hydrocarbon fields shows that hydraulic fracturing due to the injection of fluids can, in very exceptional circumstances, lead to fracture propagation to the surface or near-surface, if it takes place at relatively shallow depths. In the Tordis Field of offshore Norway, for example, the average rate of water injection was 7000 m3 day−1 for 5.5 months (total volume = ∼1,115,000 m3). Hydraulic fractures propagated from a depth of ∼900 m to the surface through Cenozoic (Tertiary) strata.

The volume of fluid used in these operations, however, was more than 120 times greater than that typically used for hydraulic fracture stages in shale gas reservoirs and took place over a time period hundreds of times longer. There are several factors in shale fracking operations, including the relatively low volumes of fluid and the short pumping times that make the upward propagation of very tall fractures unlikely (Davies et al., 2012). To date, water contamination caused directly by the upward propagation of hydraulic fractures remains unproven (Davies, 2011), although the possibility cannot be totally ruled out.

As argued by Davies (2011) and Jackson et al. (2013), poor well integrity is a far more likely cause of elevated concentrations of thermogenic methane in shallow groundwater and water supplies than pathways induced solely by hydraulic fracturing. Examples of leaks in shale gas wells have been reported and fines imposed (Roberts, 2010).

Implications and recommendations

As with our study, King and King (2013) addressed statistics on well barrier and integrity failure. They compared the data with that of other polluting activities in the USA, such as storage tanks, septic tanks and landfills, and made the point that the number of reports of pollution from oil and gas wells was insignificant in comparison. Nevertheless, for the more than 4 million wells drilled in Australia, Austria, Bahrain, Brazil, Canada, Netherlands, Poland, UK and USA alone, there is scarce published or online data on well integrity or barrier failure.

Improved monitoring is crucial for a better understanding of chances of hydrocarbon well barrier and integrity failure and the impact of this. There are examples of good practice. The DEP database for Pennsylvania, USA, was used by Considine et al. (2013) to carry out a detailed breakdown of the types of well infringements and their severity. The Alberta Energy Resources Board (ERCB) database of well integrity failure for 316,439 wells reported by industry dating back to 1910 is not in the public domain, but the data summary is available (Watson and Bachu, 2009). In Alberta wells are checked for well integrity and barrier failure within 60 days of the drill rig being removed (Watson and Bachu, 2009).

In the UK there have been a small number of reported pollution incidents associated with active wells and none with inactive abandoned wells. This could therefore indicate that pollution is not a common event, but one should bear in mind that monitoring of abandoned wells does not take place in the UK (or any other jurisdiction that we know of) and less visible pollutants such as methane leaks are unlikely to be reported. It is possible that well integrity failure may be more widespread than the presently limited data show.

Surveying the soils above abandoned well sites would help establish if this is the case. In terms of monitoring, abandoned wells could be checked 2–3 months after cement plugging for sustained casing pressure and gas migration. If the well has no evidence for barrier or integrity failure, it could be cut and buried as per regulations. Soils above well sites could be monitored every 5 years for emissions that are above a predetermined statutory level. As there are 2152 wells in UK at present, only 430 would need to be checked each year. Monitoring could be intensified or scaled down based upon the results of the first complete survey. Monitoring a proportion of future abandoned shale gas and oil wells should also be feasible. A mechanism may need to be established in the UK and/or Europe to fund repairs on orphaned wells, and an ownership or liability survey of existing wells would be timely.


Well barrier and integrity failure is a reasonably well-documented problem for conventional hydrocarbon extraction and the data we report show that it is an important issue for unconventional gas wells as well. It is apparent, however, that few data exist in the public domain for the failure rates of onshore wells in Europe. It is also unclear which of the datasets used in this study will be the most appropriate analogues for well barrier and integrity failure rates at shale gas production sites in the UK and Europe.

Only 2 wells in the UK have recorded well integrity failure (Hatfield Blowout and Singleton Oil Field) but this figure is based only on data that were publicly available or accessible through UK Environment Agency and only out of the minority of UK wells which were active. To the best of our knowledge and in line with other jurisdictions (e.g. Alberta, Canada) abandoned wells in the UK are sealed with cement, cut below the surface and buried, but are not subsequently monitored. This number is therefore likely to be an underestimate of the actual number of wells that have experienced integrity failure.

A much tighter constraint on the risks and impacts would be obtainable if systematic, long-term monitoring data for both active and abandoned well sites were in the public domain. It is likely that well barrier failure will occur in a small number of wells and this could in some instances lead to some form of environmental contamination. Furthermore, it is likely that, in the future, some wells in the UK and Europe will become orphaned. It is important therefore that the appropriate financial and monitoring processes are in place, particularly after well abandonment, so that legacy issues associated with the drilling of wells for shale gas and oil are minimised.


We thank Chris Green (GFrac Technologies) and an anonymous reviewer for their reviews which helped improve the paper. Dr Paul Choate (Choate Technology Services Ltd.) and Dr Will Fleckenstein (Colorado School of Mines) are also thanked for reading and commenting on the manuscript. This research was carried out as part of the ReFINE (Researching Fracking in Europe) consortium led by Durham University and funded by the Natural Environment Research Council (UK), Total, Shell and Chevron. We thank Alkane Energy, BP, Chevron, Department of Energy and Climate Change, Humbly Grove Energy Ltd., IGas, Perenco, Shell, Total for comments. The US National Science Foundation (EAR-#1249255) funded some of the US analyses and the Environment Agency (UK) is thanked for providing pollution incident data.

We are grateful to the Durham University Faculty of Science Ethics Committee and the UK Research Integrity Office for their time in providing advice on research ethics. We thank the ReFINE Independent Science Board ( for spending time prioritising the research projects undertaken by ReFINE. This paper is published with the permission of the Executive Director of the British Geological Survey and the results and conclusions are solely those of the authors.


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Article history:

Corresponding author. Tel.: þ44 1913342346.

E-mail address: [email protected] (R.J. Davies).

Received 8 December 2013 -Received in revised form 28 February 2014 -Accepted 1 March 2014 -Available online 25 March 2014

© 2014 The Authors. This is an open access article under the CC BY-NC-ND license (


Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo. In an independent way he’s researching about shale gas & tight oil and building this website to spread the scientist knowledge of the shale industry.

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