Renewable energy sources are in the news these days. Although projections by bodies such as the International Energy Agency (IEA) say that hydrocarbons will be around for many decades to come, conventional resources are more elusive and unconventionals like tight gas are costly to develop. Renewables are becoming economic and have the added benefit that they do not produce emissions. But they also have problems. Wind turbines are often intrusive, noisy and may disrupt wildlife. Large scale projects like tidal power stations are accused of potentially huge environmental impact. Solar needs large spaces and is not efficient, particularly in northern latitudes. Crucially, they do not operate continuously – they are not ‘always on’.
Hot dry rocks
Schematic diagram of geothermal circulation system and power plant. Source: ARUPBut what if it were possible to have a reliable and constant energy source that produced no emissions and had a minimal impact on the environment? That is just what a research group based at the Camborne School of Mines in Cornwall at the south-western tip of the UK aimed for in the 1970s and 1980s. Their ‘hot dry rocks’ project, sponsored by the UK Department of Energy (DoE), looked at the possibility of taking advantage of the highest heat flow in the UK, as measured by the British Geological Survey (BGS).
The geology of Cornwall is dominated by igneous rocks, mostly granite. The granite contains radioactive minerals that add to the background geothermal gradient, making the Cornish rocks a UK hot spot. In addition, the history of mining for tin and other minerals over hundreds of years means that there is a lot of geological information about the sub-surface, including knowledge of the strike-slip fracturing systems that the miners called ‘cross-courses’.
The hot dry rocks project succeeded in demonstrating the feasibility of pumping water through these natural fracture systems, but did not reach sufficient depths to access the temperatures that would be needed to generate power. With the data from the project, it was estimated that wells 6,000m deep would have to be drilled, which at that time was uneconomic. A number of technical issues still remained to be addressed, so the DoE decided to focus on the European Commission’s (EC) joint European geothermal project, which has a pilot plant at Soultz near Strasbourg in France.
One of those involved in these early stages, initially on the hot dry rocks project, and then as Geothermal Technical Coordinator for the EC, was Peter Ledingham, now Operations Director with UK consultancy company GeoScience Limited and based at Falmouth in Cornwall. “Everywhere on the planet, it is hot at depth, eventually,” says Peter. “Hot dry rocks have been reinvented as EGS – enhanced or engineered geothermal systems. What we are looking for in Cornwall is something between hydrothermal, where hot water or steam exist naturally underground, and true hot dry rocks where you have to make the reservoir yourself by fracturing it.”
Geothermal Engineering
Peter Ledingham at an abandoned mining engine house near the site of the geothermal project. Photo: Paul Wood
Map of the interpreted fault structures near the proposed geothermal plant. Source: GeoScience LtdWith higher energy prices and the increased importance of low carbon sources, the idea of EGS is more prevalent and people are again prepared to invest in it. Geoscience Ltd was initially formed as a geothermal company in 1985 but has since branched out into the oil and gas business. As well as geothermal engineering, the company offers specialist services such as wellbore stability, sand production and in-situ stress assessments, and also fractured reservoir characterisation and stimulation analyses. A few years ago, Geoscience Ltd was approached by Ryan Law, an Oxford-trained geologist who is now Managing Director of the specialist company Geothermal Engineering Ltd. Ryan had taken the lessons learned from the Camborne project and tried to see where it might be possible to set up an economic geothermal power project.
GeoScience Ltd is now a partner and technical adviser to Geothermal Engineering. They have brought a lot of geology and engineering expertise into the project and especially their knowledge of fractured reservoirs. Peter Ledingham is also a Director of Geothermal Engineering. The joint studies of the two companies have highlighted an area near Redruth, about 10 km north-west of Falmouth, that combines one of the hot spots of heat flow from the Geological Survey map with a fault system that can be seen on the coast and mapped from the mining data. Standing on a currently deserted industrial site within an old mining area, Peter explains how the power plant should work.
“We will drill three boreholes,” he says. “One will be the injector well and there will be two production wells. This will give us an improved fluid flow and the production needed for a plant of 10 megawatts capacity. Our modelling tells us that we need to achieve 150 kg/sec circulation and we expect the circulatory system to be in natural fractures in the faulted structure, though we don’t rule out having to apply some hydraulic fracturing.” Water will be pumped into the injector well and then flow through the fracture system, picking up heat until it is at about 200°C. It will then flow back through the production wells and into a heat exchanger, with surface temperatures at about 175°C. From the heat exchanger, hot fluids feed into a turbine that will produce 10 MW gross power, with around 7 MW expected to be delivered into the electricity grid. Up to 55 MW of thermal energy at around 60-70°C could also be available for industrial or domestic space heating in the area if the infrastructure is put in place.
Uncertainties and challenges
There are several uncertainties in the project, the main one of which is the presence of a good enough fracture system at the depths where the right temperatures are expected. A number of seismic lines were shot both before and during the hot dry rocks project. But mostly the interpretation relies on surface mapping and geological records from the mines, though the deepest of these are only 900m below the surface.
Jon Gutmanis, Chief Geologist at GeoScience Ltd and a specialist in fractured reservoir characterisation, has interpreted a fault zone across Cornwall that is well defined on the north coast and can be seen in outcrop in cliffs near Perranporth. He says “the cross-courses are mainly strike-slip faults – the family of late Variscan structures that cut across South-West England. Cross-course was the miners’ term for these faults because they are orthogonal to the east-north-east to west-south-west trending mineral lodes, and shift them sideways. On the geological map we have indicated the interpreted fault zones near the drilling site. The blue dashed lines show the structural zone that constitutes our target. At the surface, this is the Porthtowan Fault Zone. Our plan is to intersect it at around 4.5 km depth.”
Some hydrothermal projects have in the past encountered problems with dissolved minerals dropping out of solution as the fluid temperature decreases. The project team members do not expect a lot of mineralisation here though, nor do they expect problems with fluids leaking away from the fracture system as it is relatively well confined. A challenge they will have, however, is on the drilling side. The wells will have to be drilled through about 1,000m of low-grade metamorphic rocks (Devonian slates) before encountering the granite and will still then have 4 km or more of that to penetrate. The target is a steeply dipping fault zone and there is some positional uncertainty. More geoscience techniques could be brought into play here as they may conduct downhole seismic surveys to help steer the well to the target. One thing they will do is augment an existing BGS microseismic system to improve it as a network to monitor ‘environmental’ events. They will also install their own ‘engineering’ network to monitor and manage reservoir growth.
Drilling will as far as possible use standard oilfield techniques and hole sizes, the need for an economic fluid circulation volume dictating that the bottom hole section diameter should be 8½ inches. The Camborne project, which reached nearly 3 km drilling depth, has provided some experience, but the remaining uncertainties mean that funding the project has been difficult. Many parties have shown interest but full funding has yet to be obtained, delaying the project start until 2011. Geothermal Engineering Ltd plan to drill the first hole, then evaluate the results and possibly conduct some stimulation tests. Once they have demonstrated the viability of the project, they are confident that funding will not be a problem.
Doubling the capacity
A hurdle that still remains is political. In other countries, including the USA, Germany and Australia, there are incentives that make it attractive to pursue geothermal technologies. World-wide there is around 10 GW of installed geothermal capacity and it is expected this will double in five years. But there are still no geothermal leases in the UK and no legislation. Heat is not a physical commodity, so it is not yet clear how ownership will be determined.
So is this a good business for geoscience students to try to get into? “At present the UK is not running any geothermal student programmes,” says Peter. “But if we can do what we want to do, we will be hiring.” He concludes, “globally, geothermal should and could be much more important than it is. The potential for the south-west of the UK is for 300 MW electricity, enough for half a million homes. The game has changed.”
