Here’s a statistic that will raise an eyebrow: 99.9% of the earth’s mass is at a temperature of more than 100°C. That leaves us perched on the thin shell of a boiling egg of a planet. But it’s also a geological foundation that potentially provides us with an immense resource of on-demand power, heat and cooling.
Indeed, deep geothermal technology, drilling to depths of 3-5km to tap into the hot rock below, is starting to gather real momentum. So far geothermal energy has an installed capacity of around 11GW(e) and 50GW(th) worldwide and many new projects are in the pipeline. Technological development means the cost of installations is coming down and some countries, like Germany, are ensuring that support frameworks are in place to encourage investment. On the face of it, now is an exciting time for a renewable technology that has been slow to deliver on its potential.
“In the past few years we have seen a rapid development of deep geothermal systems across the world,” says Ryan Law, chairman of the Renewable Energy Association’s deep geothermal group and managing director of Geothermal Engineering, one of the UK’s leading companies in the sector. “Technically, drilling to depths of 3-5km is a well established technology.
The oil and gas industry routinely drills to such depths. The challenge for the industry is in other areas – the provision of investment support, the funding of up-front costs, and the need for the introduction of risk insurance mechanisms.”
So how does deep geothermal actually work? In principle the technology is quite simple: two wells, between 5m and 6m apart on the surface, are drilled divergently down to depths of between 3km and 5km, at which point they can be around 2km apart. Cold water is pumped down the injection well, and, as it flows through fractures in the very hot crystalline rock, the water is heated up rapidly and returned to the surface through the production well.
In a steam power plant, the superheated water is expanded into steam very close to the surface, and the steam is used to turn turbines which drive generators to produce electricity. Steam is the only significant emission from these plants. While very small amounts of carbon dioxide, nitric oxide and sulphur are also emitted, these are 50 times less than what is emitted by traditional fossil-fuel power plants.
An alternative approach is to use lower temperature hot water resources in a binary power plant. Here the hot water is passed through a heat exchanger at the same time as a secondary fluid with a lower boiling point. This secondary fluid vaporises, turning turbines which drive generators. The geothermal water is returned to the reservoir for recirculation. These plants produce no gases and zero carbon dioxide emissions.
In deep geothermal installations, the binary power plant is a more common solution because it means the geothermal fluid moves in its own closed circuit and never comes into contact with either the atmosphere or the turbine. That provides an environmental benefit – the geothermal fluid can contain gases such as hydrogen sulphide and carbon dioxide, and the closed loop means these aren’t released to the atmosphere. And if geothermal fluid is used to expand into steam and drive the turbine, it can cause corrosion, which raises maintenance issues.
Increasingly geothermal energy plants can be used to supply heat as well as electricity. And they can also be used for cooling, providing an environmentally friendly solution for large office buildings, which these days often have a greater requirement for cooling than heating.
The technology has been proven at installations across the world. The real challenge with deep geothermal projects, says Law, is gaining an accurate understanding of what’s going on beneath the ground before operation. “The difficult part is working out how the water moves through the rock at depths of up to 5km and how you can engineer that process to work in the way that you want it to,” he says.
Indeed, micro-seismic interpretation is an area of much research at present. When a well is drilled, it can cause thousands of very tiny micro-seismic events that cannot be picked up on the surface. But, through the use of advanced seismic monitoring technologies, underground movements can be monitored to generate a 3D picture of how the rock is performing and where the water is going. Once that picture is gained, the injection and production wells can be drilled with a greater understanding of what is going on at depth. “Producing an accurate 3D picture is a real engineering challenge on geothermal projects. And it is an expensive engineering challenge too,” says Law.
The UK’s first commercial deep geothermal plant, being developed by Geothermal Engineering, was granted planning permission last year. The site, on an industrial estate near Redruth in Cornwall, is expected to be fully operational by 2013, providing up to 55MW of renewable heat for the local area, and 10MW of renewable electricity, which will be fed into the National Grid. Work will begin in October to drill 4.5km into the ground to access rocks at temperatures of approximately 200°C.
“It’s important that we prove these technologies on a commercial scale,” says Law. “The project will cost £12 million for the first well, and I am close to signing an agreement on the funding. I am more hopeful than I ever have been that it will go ahead. If it doesn't, we will see huge delays to the development of the industry in the UK.”
Cornwall is a hotspot of geothermal activity, having particularly suitable geological conditions. Very large granite structures are located relatively close to the surface, making such projects more economically viable than they would be in other parts of the country where drilling would need to go down to depths of up to 8km.
Planning permission has also been given for a geothermal installation at the Eden Project eco attraction in Cornwall. Eden’s co-founder, Tim Smit, is another vocal advocate of deep geothermal technology, calling it a “no-brainer” if the UK is to move towards long-term energy security.
But if geothermal technology is proven, and it offers such potential, why has it been so slow in fulfilling its potential as a renewable energy source? The UK only has one deep geothermal district heating installation plant, in Southampton, but that has not been in full operation for many years. The resistance to the technology is linked primarily to the relatively low cost of oil in recent times, which made geothermal, with its high initial exploration risk and early capital requirements, economically unviable. But times have changed, and the rising oil price, along with the need for greater energy security, is creating renewed interest in the technology across the world.
“Another reason for the renewed interest is that, previously, the UK has never been focused on renewable heat,” says Law. “For a technology just producing electricity, geothermal remains an early-stage solution with high up-front costs. But there is a real demand for heat these days, giving the technology a major selling point and making it economically viable. That’s why interest is rising.”
Another reason behind the slow emergence of the technology has been fears over what effect drilling to such depths will have on the structure of the earth. Some opponents of deep geothermal have questioned the seismic impact of such activity, while others have even suggested that localised cooling of ground conditions could have a wider effect on the planet’s temperature. Law, who worked for many years as a geologist for Arup, says both arguments can be countered.
“The worries about cooling the earth are not valid. It’s a popular misconception. It’s like taking a bucket of water out of the sea. That’s the sort of effect a geothermal energy plant will have on the heat of the earth. Geothermal plants do have a 25-year life expectancy, as they do cool a particular volume of rock by up to 5°C. But, at the end of the lifespan of the plant, the rock recharges itself anyway. It’s not a permanent cooling effect.
“The seismic worries, on the other hand, are completely valid,” he admits. “There have been a couple of projects that have been targeting the wrong geology. If we were to drill into the San Andreas fault and pump it full of water, there would be a very high percentage chance that we would cause serious types of damage. So it depends on the geography you are targeting. We are lucky in the UK in that we have very stable geology. The thing about these plants is that in the worst-case scenario they may cause an event of the magnitude that would occur naturally. The absolute majority will never be felt.”
The other major hindrances to deep geothermal projects are political. While the Department of Energy and Climate Change suggests that deep geothermal could meet approximately 10% of the UK’s baseload electricity supply, the UK is still lagging well behind countries like Germany in terms of investment support and regulatory conditions.
Grant support for UK geothermal, for example, was cut in half in 2010, to a derisory £1 million. This dismays Law, and many others within the Renewable Energy Association’s deep geothermal group. He says: “Quite frankly, £1 million across an entire sector is embarrassing. When I present at European geothermal conferences, the UK’s grant support has become something of a laughing matter. To drill one well costs £10-12 million, so you can see how far £1 million goes. Such an amount sends the wrong messages to investors. It says the government really isn’t that interested in the technology.”
The Renewable Energy Association points to other areas that need to be addressed to ensure that deep geothermal can progress. It wants the Renewable Obligation Certificate (ROC) support raised from two to four ROCs, to bring it in line with the practice in Germany. And it wants to see an increase in the Feed-in Tariff to 10MW and to include a deep geothermal tariff at 23p/kWh(e). There is also a need for exploration licensing legislation under the Energy Security and Green Economy Bill, and for the development of a risk insurance mechanism to encourage up-front investment.
“When all is said and done, deep geothermal is a technology that hasn’t been proved in the UK yet, so you have got to make a compelling case to investors,” says Law. “You can do that in two ways: either you can mitigate the risk of the project and therefore make it more appealing, or you can offer a very high return through sufficient subsidy levels to encourage people to take that risk. In the UK at the moment, I am afraid that we don’t have either.” Germany, on the other hand, tackles both of these. It offers exploration risk insurance to get projects started, and if the well fails the developers get a certain percentage of their money back. And at the same time it gives high levels of Feed-in Tariffs, so that the financial returns to investors are very attractive. The upshot is that investors are much keener to put their money into deep geothermal projects in Germany.
In recent weeks, there have been signs that politicians are keen to promote deep geothermal as a viable renewable technology. A well-attended geothermal conference was held at the Houses of Parliament in January and was addressed by Lord Teverson, the LibDems’ energy and climate change spokesman in the Lords, who expressed his support for efforts to include deep geothermal licensing in the energy bill and for better grant support for the sector.
Law says that people like Teverson will be vital in helping the sector to reach its true potential. But he has his doubts that the Renewable Energy Association’s wish list will come to fruition. “Deep geothermal does seem to be gaining an increasing profile,” says Law. “I have a meeting with the energy minister in February and it will be interesting to hear what he says on geothermal licensing, which is the key to seeing large-scale developments in the UK. But I’ve become increasingly cynical over time over what politicians promise and what is delivered.”
How Cornwall pioneered hot rocks research
A major “hot rocks” deep geothermal research project took place at Rosemanowes Quarry in Cornwall back in the late 1970s, with research input from the Camborne School of Mines, which is part of the University of Exeter. The site was chosen because the granite in the area has the highest heat flow in England (120mW/m2).
The project aimed to see if hot dry rocks could be fractured by water pressure alone, enabling a current of cold water from an inlet borehole to pass easily through the mass and to be collected at an outlet borehole some distance away. The trial proved to be successful, and showed that explosives were not required to fracture this Cornish hot granite at depth.
The project also looked to find out if the rocks were hot enough to make steam for a turbine to generate electricity. This second aim was not achieved at the depths attained. Although the rocks did yield substantial quantities of hot water, to reach a temperature to generate steam hot enough to drive a turbine would have required drilling a further 1km or more into the granite, an option that was too expensive at the time.
“The hot rocks project was cutting-edge stuff,” says Ryan Law, managing director of Geothermal Engineering.
“The project looked at what happened to granite when it was drilled and water was circulated at depth. It came up with really interesting findings – different from what many experts imagined at the time.”
The research project was eventually folded in to a collaborative European project at Soultz-sous-Forêts in France and a number of commercial contracts ensued exploiting hot rock techniques, such as microseismic monitoring in the oil and gas industry.