Krafla geothermal plant in Iceland
Krafla geothermal plant in Iceland: EGS could boost Europe’s geothermal power.
Source: Landsvirkjun

Artificially creating geothermal reservoirs gives Enhanced Geothermal Systems greater siting flexibility than traditional geothermal power plants. This is opening up Europe to the possibility of geothermal energy not only making a significant contribution to the energy mix, but also contributing to system stability, finds David Appleyard

Although Europe is not generally considered to have a particularly rich geothermal resource, an emerging technology commonly referred to as EGS – enhanced or engineered geothermal systems – does offer an opportunity for geothermal power to make a major contribution to the energy mix.

EGS may be considered as a geothermal system with a heat reserve which is artificially created or enhanced. Like conventional geothermal technologies, EGS also relies on the heat contained within the earth’s crust. However, while traditional geothermal systems require an active resource close to the surface capable of delivering high temperatures, EGS makes use of lower temperature resources that are frequently at a considerable depth below the surface. It takes advantage of the naturally occurring phenomenon by which, for every 100 metres depth, the temperature of the surrounding rocks increases by some 3°C.

Similar in some respects to the ‘fracking’ technology used to extract gas and oil from shale deposits, EGS typically uses multiple wells to inject water deep into a borehole, stimulating rock structures at a depth of 3-10 km.

This is because the rocks at these depths are rarely porous due to the compressive mass of material above these strata. EGS development thus begins by increasing the porosity of a geological structure, commonly known as stimulation. Stimulation can also involve the use of acids to dissolve obstructions.

Once the structure has been fractured and becomes sufficiently porous, water or brine can be injected into a well placed near the centre of the reservoir.

Injection water passes through the hot porous zone before it is extracted from the production wells – often multiple – on the edge of the reservoir. While the water from the production wells is still at a relatively low temperature – perhaps 80°C-200°C – when compared with conventional geothermal, another breakthrough technology may be used to apply this heat for use in electricity production.

Indeed, it is the development of so-called binary cycle – such as Organic Rankine Cycle (ORC) or Kalina cycle – machines that has allowed commercial exploitation of the engineered low temperature geological reserves. In binary devices such as ORC turbines the heat is exchanged via a working fluid, for instance refrigerant R134a, which expands through a turbine imparting rotary motion before being condensed into a liquid again to repeat the cycle.

As a result of these relatively recent breakthroughs, EGS is now attracting considerable interest.

Siemens Organic Rankine Cycle
Siemens offers new solution for utilization of waste heat using the Organic Rankine Cycle
Credit: Siemens

Europe’s EGS dream

Although the use of geothermal energy for power generation effectively began in Europe – with the 1913 development of Italy’s Larderello steam field – Europe’s only opportunity to develop geothermal power generation at any significant scale comes from EGS technology, as artificially creating geothermal reservoirs gives greater siting flexibility than traditional geothermal power plants.

Europe already has a number of projects operating, with around half a dozen more currently under development. The first such project is located in eastern France in the Alsace region near Strasbourg, close to the German border. It is a research facility.

The Soultz-sous-Forêts project was initially launched back in 1988 and jointly funded by the EU, France, Germany and private companies. Of the €80 million investment in the project, some €30 million has come from the EU, with €25 million each coming from Germany and France.

This pilot project draws on heat sources of up to 200°C located between 4500 and 5000 metres in depth.

With deep geothermal energy identified by the multi-party roundtable Grenelle de l’Environnement as an important focus for the development of renewable energy in France, as a research project Soultz-sous-Forêts has demonstrated the feasibility of stimulating a reservoir, and four deep boreholes have been drilled to date, three to more than 5000 metres. Some 200,000 m3 of water was also injected to open and clean fractures among the rocks.

With a 1 km separation between the injection well and the two production wells, the fluid in the geothermal loop travels an estimated 11 km.

Power production using Turboden and Cryostar equipment began in the autumn of 2007.

Although the reservoir created was not designed for commercial operations, Soultz-sous-Forêts is used to generate electricity and has a 2.1 MWe gross power generation capacity, of which 1.5 MW is net production to the grid.

After contributing to scientific work on well stimulation with a view to developing the site, in parallel with its operation by the European Economic Interest Group (EEIG) on Heat Mining, BRGM (Bureau de Recherches Géologiques et Minières) – the French geological survey – is now conducting work financed by ADEME on the sustainability of the Soultz operation. The aim is to identify the circulation routes between the wells (by improving tracer tests and circulation modelling) and understand how they evolve during operations.

“The aim of the Soultz project was to demonstrate the feasibility of the underground heat exchanger and show that the site is able to produce electrical power and to supply it continuously to the grid. It has now reached a decisive phase,” explains Sylvie Gentier, project manager and research correspondent with the Geothermal Energy Division.

“Now we need to determine the operational lifetime of this type of installation and identify what problems can occur during operations. As soon as we can show that the site can operate permanently, other operations could be planned in other locations for power generation on a larger scale,” Gentier said.

“In parallel, thanks to improvements in the performance of heat exchangers and thermodynamic cycles, we have found that power can be generated at a temperature of less than 200°C. From the experience gained, we have good reason to expect the development of CHP systems that could also meet local demand for heat, particularly from industries. These more decentralized applications could be considered within the next 5-10 years.

“Finally, understanding the subsurface environment at Soultz, where hot fluids circulate, allows us to work on reducing the geological risks – which are a critical issue in this type of operation – with a view to operating future sites from more closely targeted boreholes, which would also reduce the cost”.

Pre-commercial EGS development

In the wake of this European EGS research plant, work began on two commercial EGS projects in Germany.

The Landau EGS power plant is very similar to the earlier Soultz development but is the world’s first commercially funded EGS plant and is a combined heat and power (CHP) project, rather than power only.

Rated at 3 MW, the project began operations in 2007 following a three-year construction phase. The facility in Landau exploits 155°C strata at a depth of 3000 metres. Water leaves primary cycle at 72°C and is then used for district heating for around 1000 households. At the end of the CHP cycle, 50 °C water is reinjected into the well.

A subsidiary of Pfalzwerke AG and EnergieSudwest AG, Geo X GmBh, owns and operates the plant.

The operators expect the plant to begin to pay off after about 10 years and are apparently already planning the Landau 2 geothermal power station.

In mid-2006 US-based technology firm Ormat Technologies received an order worth some $4.4 million to supply a pre-assembled ORC turbine and generator unit for the Landau development.

The construction was undertaken by a third party under a consortium agreement with Ormat.

The second commercial German project was also developed by a unit of Pfalzwerke on the southern edge of the town of Insheim. Launched in 2007, the project utilizes a 165°C resource located at a depth of 3800 metres. It was connected to the grid in 2012.

The power plant supplies electricity to approximately 8000 households, while the residual heat is used in a district heating network.

With a number of modest-scale EGS plants now operating in Europe, the scene is set for the development of larger projects.

According to Philippe Dumas, Secretary General of the European Geothermal Energy Council (EGEC), there are now several projects in the pipeline at various stages of development.

Two EGS projects are located in the UK, two in Belgium, in France there are between four and six potential projects underway, there is one in Hungary (financed by the EU and expected to be operational by 2018-2019), and in Germany there are a further three to five EGS projects under development.

Among the more advanced projects are installations in Munich, Germany.

Developed on behalf of the local municipal authority Stadtwerke München (SWM) in mid-2010, the municipal authority signed a contract with Italy’s Turboden for the supply of a 5 MWe ORC and generator unit.

Based on a two pressure level cycle and fed with geothermal fluid at 140°C, the plant also provides the existing district heating network with an additional 4 MWth. It uses forced air condensers.

General contractor Karl Lausser GmbH was awarded the public works contract with startup in late 2011.

Paolo Bertuzzi, General Manager of Turboden, comments: “This 5 MWe geothermal plant is going to be an important benchmark for both Turboden and the European geothermal industry. “

Turboden’s other European EGS geothermal projects include a 1 MWe plant in Altheim, Austria.

SWM is also developing a number of additional geothermal projects as part of its campaign to produce all of its electricity requirements for the Munich municipality – some 7.5 TWh annually – from renewables by 2025.

The 10 MWth geothermal system in Riem, a newly built district of Munich, uses 93°C hot water from a depth of some 3000 metres with two boreholes sunk into the Malm karst. Development of the project began in 2002 and the project was commissioned in 2004, supplying district heating. Most recently, the geothermal system at Sauerlach was officially commissioned in January 2014. With a temperature of more than 140°C from a depth of about 4200 metres, the Sauerlach CHP project features three boreholes – two injection and one production – and the plant generates heat and electricity for around 16,000 Sauerlach households.

In total SWM has earmarked a budget of €9 billion for the expansion of green generation out to 2025.

Siemens SST-500 GEO steam turbine geothermal power plants
Siemens develops SST-500 GEO steam turbine for geothermal power plants
Credit: Siemens

EGS: a global phenomenon

While Europe is taking a strong position in EGS development, the advantages of the technology have not been lost on other regions. For example, the US and Australia have both made progress over the last year or so in developing their own EGS projects.

Following the 2008 award of a US Department of Energy (DOE) grant to Ormat, GeothermEx Inc and other stakeholders, in April 2013 Ormat’s Brady facility near Reno, Nevada began supplying 1.7 MW of power to the grid.

Support for the project included $5.4 million in direct DOE funding and $2.6 million in investment from Ormat.

Brady followed a DOE-funded EGS demonstration and development project at Ormat’s 11 MW Desert Peak site about 10 miles (16 km) away from Brady.

Additional US EGS projects by Calpine Corp, Ormat Technologies, and AltaRock Energy all received federal administrative support during 2013.

Aside from US projects, in April 2013 Australia also began generation operations at its first EGS plant, the 1 MW Habanero development near Innamincka in South Australia.

This research installation has been developed by Geodynamics Limited and was supported by the Australian government through the Australian Renewable Energy Agency’s provision of the Renewable Energy Demonstration Program grant funding.

Habanero has achieved a well-head temperature of 200°C from its production well of some 4200 metres depth.

Challenges and opportunities

While there is clear evidence that EGS technology is gaining both investor support and commercial operating experience, some challenges remain to be overcome before it can become a widespread and economically attractive renewable energy resource.

Dumas points out that one of the biggest obstacles is the relative absence of accurate geological data. One of the reasons EGS projects take such a long period to develop – typically five to seven years – is that considerable resources must be expended on geological exploration.

In addition, the required environmental permitting can also be a lengthy process. “In practice, in Germany and France it’s 18 months to two years before you have your permit,” says Dumas.

There is inevitably some geological risk where a well is drilled only to find that the anticipated resources are not realized. Indeed the history of EGS development presents a number of projects which have been abandoned due to adverse geological conditions.

However, Dumas points to the emergence of innovative financial tools, such as risk mitigation insurance schemes, which can address this challenge.

Not only is geological data limited, but exploration is also rather costly. Dumas suggests that an initial investment of €7-10 million is required. Furthermore, given that EGS projects tend to be relatively small, sometimes some months are required to arrange finance for this type of exploration, particularly as these projects are often led by smaller developers.

“It’s quite capital intensive so needs a large amounts of financing and today, in the current economic climate, banks are hesitating in financing projects so you need some new players,” he adds, pointing to the insurance industry, venture capital, pension funds, utilities and the oil and gas sector as potential sources of new finance.

However, while oil and gas majors – with their keen insight into geological risk – may seem an obvious avenue, Dumas suggests they are still hesitating as these projects are typically too small to attract their interest.

The third, and perhaps most significant, obstacle is the cost.

Dumas explains that for EGS to be competitive it must have a total production cost of electricity – LCOE, plus system costs, plus externalities – of around 10 euro cents/kWh.

The main opportunities for cost reduction are increasing the size of the projects, thereby decreasing the relative drilling costs. Drilling costs currently account for around 70 per cent of the total capital development costs, he says, given the requirement to drill more wells for EGS development.

“We expect the [forthcoming] projects to have a capacity of at least 5 MW, but at this stage they are anticipated to have a capacity of not more than 10 MW. Projects above this capacity are the next step,” says Dumas.

Nonetheless, Dumas adds: “We expect to be competitive before 2030, perhaps even 2025.”

He concludes: “EGS is the only way to produce a large quantity of geothermal energy in Europe. We have really a few places with a high enthalpy, so it’s the only possibility for geothermal power to expand.”

“There are plenty of research projects and the sector is really rich in innovation and new technologies. Currently there are new drilling technologies, new simulation processes, new turbines.

“We are quite optimistic for two reasons. Firstly, EGS is a new technology with a recent breakthrough so we need to increase our experience of this technology to show its potential, and secondly, we think that all technologies can be quite instrumental in the future electricity mix in Europe.

“Geothermal can be instrumental because it can be flexible, so it can play a role in stabilizing the grid by, for example, switching production to heating or increasing production of electricity.

“Its flexibility is key to the future stability of the grid.”

David Appleyard is a journalist focusing on energy matters.

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