51ÁÔÆæ submitted the report ‘Recent scientific advances in the understanding of induced seismicity from hydraulic fracturing in shales’ to the UK Government on 5 July 2022. This was in response to a Government request for a review of new scientific evidence focusing on the period from November 2019 until the present.

The report has been externally peer-reviewed by independent experts both within and outside the UK. The report draws on existing peer-reviewed data and research from academic journals, as well as on information from relevant technical reports from regulators and public bodies.

The UK Government requested BGS address six questions related to recent scientific research on the hazard and risk from induced seismicity during hydraulic fracturing of shale rocks. For more information about these questions, please refer to the . 

This report concludes that forecasting the occurrence of large earthquakes and their expected magnitude is complex and remains a scientific challenge. As a result, our ability to evaluate and mitigate risks from hydraulic fracturing-induced seismicity and predict the occurrence of larger earthquakes during hydraulic fracturing operations is also a challenge.

This report also concludes there are new seismic data analysis methods that could help to manage the risk of seismic activity from hydraulic fracturing in shales. Further work is needed to develop these methods and incorporate them in risk assessments.

If you have any enquiries on the findings of the scientific report, please email our Press Office.

If you have any other queries then please contact the BEIS press office.

Further information about our research is also available on our website:

• earthquakes and seismology research

• shale gas extraction

Frequently asked questions

51ÁÔÆæ is the lead organisation in a 16-partner consortium to deliver the — €8.5million of EU-funded research focused on subsurface evaluation of carbon capture and storage (CCS) and unconventional hydrocarbon risks.

The three-year project has been funded from the European Union Horizon 2020 research and innovation programme and brings together world-leading expertise from research and commercial organisations across seven European countries. It has gathered impartial scientific evidence relating to environmental monitoring and risk mitigation that will guide subsurface geoenergy development.

The project has produced a set of best-practice recommendations for establishing environmental baseline conditions for unconventional hydrocarbon production and the geological storage of anthropogenic carbon dioxide (CO₂). This includes outputs addressing how to develop effective communication strategies with different stakeholder groups.

The project has published its recommendations in a series of nine factsheets. Each recommendation is also underpinned by research and technical reports, with more than 41 published to date. The reports include:

• risk assessment for:
  • leakage from CO₂ storage and unconventional hydrocarbon extraction (UHE) sites
  • induced seismicity
• environmental baseline and monitoring strategies
• advanced monitoring and sensor technologies
• impact mitigation and remediation
• development and exchange of best practice associated with CO₂ storage and UHE sites

The importance of participatory monitoring

As CO₂ storage occurs at significant depths, monitoring data and the knowledge developed from these observations require significant expertise to aid their interpretation and make value judgments about the safety and efficiency of the storage processes.

Developing innovative monitoring tools and participative monitoring methods can support the understanding of the subsurface by non-expert stakeholders and give them more insight into the impact of the activities on the environment and the way potential risks are being managed.

SECURe has developed improved participatory monitoring tools that, although focused on CCS and shale gas activities, are also relevant for other subsurface activities, such as geothermal projects or the storage of heat and gases — for example, hydrogen.

Ed Hough, SECURe coordinator.

Project recommendations

The risk framework developed by SECURe identified four principal hazards associated with geological CO₂ storage and CCS, and five associated with unconventional hydrocarbon extraction.

The project employed the ’bow tie’ risk assessment approach, which identifies a series of barriers that prevent a principal hazard from occurring. These events were identified through a literature review of hazards, threats, consequences and barriers associated with CO₂ storage.

Each factsheet addresses a principal hazard that can occur if control of a hazard is lost and provides recommendations to help with mitigation. The recommendations can be considered to inform preventative or mitigative strategies for risk management. They can also be used to inform site development and management strategies from the perspective of multiple stakeholders.

Development of innovations within the SECURe project

Over its three-year lifespan, the project has advanced a number of monitoring and remediation techniques using ‘technology readiness levels’ (TRL), a type of measurement system used to assess the maturity level of a particular technology.

Examples of innovations advanced during the SECURe project include:

• methodology optimisation for methane and higher hydrocarbon concentrations/isotopic ratio measurements in groundwater and soil gas
• an unpiloted aerial vehicle-based CO₂ sensor was progressed to TRL 6
• methods for the field sampling and preparation of material suitable for analysis for gas-source based microbial sensors were advanced to TRL 3
• a tool for the detection of potential leakage (rate) of high heavy-metal concentrations (progressed to TRL 4) was refined to analyse elemental mobilisation during the interaction of the (a principal shale gas exploration target in the UK) with simulated hydraulic fracturing fluids
• a noble gas downhole sensor (progressed to TRL 8) was field tested and improved within the SECURe project to successfully analyse gas/water ratios and volumes of inert gas

Involving local communities in participatory monitoring

Further work is needed to build trust in geoenergy experts to improve societal acceptance of innovative geoenergy projects. To create legitimacy, a stakeholder participation process should be open to new information and insights to allow for (re)positioning and enrichment of viewpoints, including minority opinion.

Involving local stakeholders at all stages of the design and implementation of a project, including decisions on what is monitored and the monitoring approach itself, can improve trust in the proposed activities and risk-management strategies.

When implementing a technological design, thinking beyond the technology itself is needed, iteratively including institutions and stakeholder interactions to genuinely embed it in a societal context.

Bringing together international research partnerships

An important part of the legacy of the SECURe project has been to foster enhanced international collaboration between research teams and organisations that share common goals and interests in the fields of environmental monitoring and risk reduction for new uses of the subsurface.

Collaboration with leading groups in Europe, USA, Canada and Australia has been a key part of the project. These are all regions with an interest in decarbonising energy use through the adoption of underground CO₂ storage, or the extraction of hydrocarbons via enhanced oil and gas recovery or exploitation of shale gas and oil.

Through these connections, SECURe initiated the ‘International Platform for Environmental Monitoring’ (IPEM), which is expected to continue in the form of regular, biannual events led by a steering committee, focusing on environmental monitoring and effective community engagement for low-carbon energy projects and other related activities.

Scientists have been testing the extent to which complex statistical models can be used to forecast seismic response during and after unconventional shale gas development — important work that could enable global operators around the world to better understand the processes that lead to induced seismicity.

Joint research by BGS and the University of Bristol has set out to explore the relationship between induced seismicity and operational parameters such as fluid injection rates and injected volumes, which are both key to understanding induced seismic processes in hydraulic fracturing environments.

They were commissioned by the Oil & Gas Authority (OGA) to independently undertake the research using data taken from in 2018 and 2019 at its Preston New Road (PNR) shale gas site near Blackpool, UK. 

Using the PNR data, the team has been able investigate the performance of a well-established statistical model, known as the epidemic-type aftershock sequence (ETAS), to see how well it can help them produce real-time forecasts of variable induced seismic rates and magnitude distributions during and after hydraulic fracturing.

The model treats seismicity in a similar way to a virus spreading during an epidemic, in that each earthquake can trigger offspring events, generally called ‘aftershocks’, that can potentially be even larger in magnitude than the triggering event. It also considers that more earthquakes, called ‘background’ events, can occur independently of others.

According to scientists, the ETAS model is commonly used to describe natural seismicity. Although this popular approach has previously been tested under different fluid-induced seismicity scenarios, it has never been used in hydraulic fracturing scenarios before.

Because ETAS was developed for slow loading rate tectonic activity, in order for the researchers to account for seismicity directly caused by pressurised fluid, they tested a modified ETAS version where the background earthquake rates are proportional to injection rates.

Capturing the Earth complex range of seismic response to subsurface fluid injection is inherently difficult and this is the first time that scientists have been able to test such a model using hydraulic fracturing data. The model has the potential to be applied globally in other environmentally important settings, such as enhanced geothermal energy systems and underground storage.

The relationship between operational parameters and the seismic response to hydraulic fracturing is complicated but one that we need to understand in order to develop robust forecasts of human-induced earthquakes.

The PNR microseismic datasets presented a unique opportunity to develop and evaluate statistical forecasting models of hydraulic fracturing-induced seismicity. We have used them to expand on previous applications of the ETAS model by using a much richer dataset and aiming at forecasting induced earthquake rates from a much broader magnitude range, assessing carefully how the forecast performance changes under different modelling assumptions and parameterisations.

Dr Simone Mancini, BGS postdoctoral researcher based at the Lyell Centre, Edinburgh, led the research.

Mancini explains:

What we initially observed was that, despite a variability in the relationship between earthquake count and injected volume, increased seismicity rates tended to be generally associated with greater volumes.

Motivated by this finding, we modified the classic ETAS model and found that it provides better earthquake rate forecasts than the standard version commonly applied in cases of natural seismicity. In particular, the modified injection-rate driven ETAS model can capture high earthquake rates due to injection periods. This is based on the assumption that the number of background earthquakes and injection rates are correlated.

Mancini adds:

Although this is preliminary research, with further testing we are confident this model could provide valuable information for operators, regulators, residents and other stakeholders in hydraulic fracturing environments, as well as the future development of deep geothermal power plants and energy storage.

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• View the datasets applicable to this research in the National Geoscience Data Centre (NGDC):

New research from the University of Nottingham, supported by the 51ÁÔÆæ (BGS) and published in Nature Communications, has found through new, innovative techniques that resources within the Bowland Shale Formation could be much lower than first thought.

Previously, the BGS was commissioned by the Oil and Gas Authority (OGA) and the former DECC (now BEIS) to produce a number of reports to estimate the shale gas resource in the Bowland Shale Formation in the Weald, Wessex and the Midland Valley. This research was published in 2013.

The estimates in 2013 were calculated using existing data for the areas such as seismic, borehole and outcrop data. The resource estimate for the Bowland Shale Formation was between 822 trillion cubic feet (tcf) and 2281 tcf, with the central figure being 1329 tcf. The resource estimate is for gas in place and is not a reserve estimate, which is the amount of gas that can extracted from the shale.

The BGS has also researched induced seismicity, baseline monitoring (including CH4 in groundwater) and evaluating the spatial relationship between shale deposits and the principal aquifers in the UK.

You can find details of other research carried out here: /shalegas/

A partnership between the BGS organic geochemistry facility and the University of Nottingham used geochemical techniques to better understand the gas resource of the Bowland Shale Formation. In particular a novel technique that replicates petroleum generation and expulsion in certain types of rocks in specific geological contexts.

This study (Shale gas reserve evaluation by laboratory pyrolysis and gas holding capacity consistent with field data) uses an interesting new scientific technique, sequential high-pressure water pyrolysis, to estimate shale gas resources in the Bowland Shale Formation. This technique could help us further understand the shale gas potential of UK onshore basins.

Early indications published today in Nature Communicationssuggest that it is possible there is less shale gas resource present than previously thought, however the study considered only a very small number of rock samples from only two locations.

51ÁÔÆæ has continued to study resource estimation in shales over the past 16 years and further studies are still required to further refine estimates of shale gas resources.

Prof Mike Stephenson, BGS Chief Scientist for Decarbonisation and Resource Management.

This study by Whitelaw et al., which was funded by a BGS PhD fellowship and involves BGS staff working with academic and industrial partners, further enhances our understanding of the shale gas potential of UK onshore basins. These data are of value for companies in helping them optimise their shale gas extraction technology and exploration. It is to be expected that shale gas resource will vary across sedimentary basins depending on rock-composition, organic carbon contents and fracture and faulting patterns.

Prof John Ludden, BGS Chief Executive.