Deep test drilling required to prove viability of UK geothermal power

 An independent study commissioned by the UK Government has concluded that actual test-drilling is required to establish the economic validity of geothermal energy on a commercial basis.

Presently, there are no deep geothermal power plants in the UK, despite government grant awards and eligibility for the Renewables Obligation.

So the Department of Energy and Climate Change (DECC) commissioned Atkins to draw together all the evidence to explore the sector’s potential. The report concludes that:

 At present there is insufficient private sector appetite to de-risk the sector for power generation schemes. Steps to limit the risks, as set out above, would need to be led and funded by Government.
 Deep geothermal energy production in the UK has potential to generate utility level returns for investors but not without significant risk and uncertainty. In order to reduce the risk and uncertainty economically exploitable resources need to be proven to the level at which investor confidence can be achieved.
 Developing confidence in reserve levels would need a programme, led and funded by Government, of test boreholes drilled to the depth required for production and testing of such wells to demonstrate reservoir properties and exploitability.

A spokesman for the Department of Energy and Climate Change’s Energy Innovation Delivery Team told Scottish Energy News; “We have a remit to invest in technologies that will provide significant benefits to the UK in terms of the secure supply of renewable and low carbon energy. In order to prioritise investment, analysis has been undertaken to highlight where investment in certain energy and technology sectors will deliver benefit to the UK.

“With innovations in the use of working fluids with lower boiling points these lower thermal energy resources may prove of increasing interest as a feasible power generating potential reserve.

“Recent reports suggest that in certain regions of the UK the particular granite geology would be less reliant on stimulation techniques as natural fissures and fractures potentially exist in the hot granite rock. These fractures could potentially be used, greatly reducing the risk of not being able to create a sufficiently permeable reservoir. “

Geothermal energy has the potential to provide a significant part of the world’s energy needs in the form of low carbon renewable energy. This is most prominent in active tectonic zones such as Iceland, New Zealand, Italy, Turkey, Japan and parts of the USA, where significant geothermal energy is being generated currently at shallow depths.

Some locations with broadly similar thermal resource conditions and analogous geologies to the UK have an active Deep Geothermal industry. Australia has some very hot geothermal granites with small scale power plants (1MWe) being commissioned from 2013. Germany is a good example of the European context and has been included in the review through the experience of study partners Geowatt and IF Technology. Although generally for heat, small scale geothermal power production is underway in Germany with potential for expansion.

In non-volcanic regions, generating power from deep geothermal resource has typically centred on binary systems at lower temperatures or the development of Enhanced Geothermal System technologies (EGS) at higher temperatures.

EGS may require the use of stimulation such as hydraulic fracturing to produce a subterranean reservoir to enable a sufficient flow of water. Binary systems are already established technologies. However, the technological challenges, risks and uncertainties surrounding deep geothermal EGS technologies mean that there has been only limited development to date. There are no deep geothermal power plants currently in the UK.

The Atkins report adds: “There is currently uncertainty whether there is a viable resource which will not be overcome until deep boreholes are drilled into the potential host rocks to demonstrate both reserve extent and exploitability.

“The lack of certainty of reserves and other factors leads to financial risk and uncertainty of viability. This financial risk is compounded by the uncertainty of the outturn costs and likely returns should the reserve be proven. In order to better quantify such financial uncertainty a series of case study scenarios have been developed.

“The approach taken for selecting the case studies has employed two essential criteria:

  • A temperature of >100 °C.
  • at a depth less than 5km.

Using these criteria, a short list of three areas of the UK has been identified; the radiothermal granites of Cornwall; the radiothermal granites of Weardale in the North East stretching across towards the Lake District; and the sedimentary basin of Cheshire. Other areas may, of course, be suitable for heat only schemes.Three case studies have been developed for illustrative purposes:


* A low permeability granite source in South West England;

* A high permeability granite source in Northern England;

* A deep sedimentary basin low level heat source in Cheshire.


No studies of low permeability granite sources in Scotland were carried out.

The two granite scenarios are interchangeable. Fractured granite has already been found in boreholes in the North West but could also be reasonably inferred as likely to be present in the South West as well. A sensitivity analysis of the costs has been carried out in order to provide context for investors on the potential financial risks.

It has been concluded that economic viability of all schemes is heavily reliant upon heat sales and this becomes a limiting factor, especially in more rural areas where the lower heat demand density makes district heating less economically viable.

Therefore it has been determined that the current potential in South West England is up to approximately 100 MWe. This could increase considerably as the sector matures, uncertainties are removed and costs reduce.

Experts anticipate that between 5 and 10 new jobs could be created per geothermal MW.

If uncertainties can be reduced and resources become proven reserves; capital costs reduce with scale; and experience and/or subsidy levels are altered such that expected rates of return based upon power generation alone become acceptable to investors, then more of the potential resource can be exploited and realised. Given the German context, where approximately 300MWe is planned by 2020 and the sector is more mature, 1 to 1.5 GWe might be a reasonable estimate for the UK in the longer term (2050).

This equates to about 4% of the annual average current UK electricity requirements. Longevity of schemes needs to be considered, with greater certainty needed with respect to total heat outputs and potential for heat degradation of the resource.

To date no wells have been drilled in the UK to sufficient depth to measure or prove the resource for power generation. The cost of trial and exploratory wells is very high relative to the overall capital cost of the project.

In order to limit the risks and make projects more investable, stakeholders consulted during this study suggested the following:

  • Further research studies and investigations of the identified resource areas to improve the characterisation of the potential thermal reserve;
  • Two or three test boreholes drilled in each location;
  • Clear permitting and thermal rights of ownership clarified;
  • Funding or insurance for early stage test boreholes put in place; and
  • Adjustment of subsidy levels would promote investment. However the current large uncertainties surrounding the drilling to characterise the resource make initial investment decisions relatively insensitive to subsidies based upon operational revenues.

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