Feasibility Report of a Deep Geothermal Single Well, Aberdeen Exhibition and Conference Centre

Deep Geothermal Heat in Scotland

As reported by Aecom^[2] in their study on the potential for deep geothermal energy in Scotland (August 2013), 'in Scotland there is little direct evidence at the surface of the vast reservoir of stored heat below and geothermal energy has remained largely untapped'.

The report split the geothermal heat resource beneath Scotland into three main settings:

• abandoned mine workings (low temperature);
• hot sedimentary aquifers (low and possibly relatively high temperature);
• and hot dry rocks / petrothermal sources (relatively high temperature).

The technology to be discussed in this report (the Deep Geothermal Single Well) aims to deliver heat from two of these resources across Scotland: hot sedimentary aquifers and hot dry/ wet rocks.

Reasons for Lack of Deep Geothermal Development to Date

There are a number of well documented reasons why development of deep geothermal projects in Scotland has remained 'largely untapped'. One of the principal problems is the high risk/ low financial reward associated with deep geothermal heat supply coupled to high up front capital expenditure on drilling. These barriers are not necessarily unique to Scotland but are compounded by the lack of knowledge of deep on shore temperatures and an established geothermal industry. Figure 1 shows the typical risk/ expenditure profile of a typical geothermal project and highlights the difficulties project developers face when they reach the stage of raising funding for drilling. This usually results in projects stalling (stall point, Figure 1) prior to drilling a well. This is strongly supported by evidence from the United Kingdom over the past decade of deep geothermal development where a number of projects have been planned but not drilled.

Figure 1: Graphical representation of a typical geothermal project showing risk/ up front capital expenditure (World Bank, 2013)

Compared to other countries within Europe, deep geothermal development in Scotland has been particularly slow, partly due to the relatively low cost of gas throughout the UK from the North Sea. For the geothermal industry (heat and power) to develop in Scotland we believe that the following hurdles will need to be surmounted:

1. Exploration risk

It is common practice to develop deep geothermal heat systems as 'doublet' systems that consist of two wells (one for abstraction and one for re-injection) drilled into a rock that has sufficient permeability to deliver high geothermal fluid flow rates. However, the permeability of the rock (the ability of rock to let water pass through it) and thus the heat or power delivery of the project is not confirmed until at least one or often both of the wells has been drilled. This means that every project has a high degree of 'exploration risk' whilst at the same time requiring significant capital investment (Figure 1). This is particularly true in countries like Scotland where very few wells have been drilled on-shore to any depth. As the economic returns of a deep geothermal heat project are low, this early stage exploration risk will be a major hurdle to investment.

The only deep geothermal well drilled in the United Kingdom over the last decade is a good example of exploration risk and demonstrates that the permeability of the rock is not confirmed until the well has been drilled. The Newcastle Science Central Borehole was drilled in 2011 under the lead of Professor Paul Younger (then of Newcastle University) with the aim of providing deep geothermal heat to the new buildings in the Science Central development. The drilling was grant funded, partly from the Department of Energy and Climate Change. The aim of the project was to target a highly permeable faulted zone in the rock at the target depth of close to 2km. Although the eventual well showed that a good geothermal gradient existed (39C km-1), the measured permeability was two magnitudes smaller than predicted. This meant that the well could not produce anywhere near the required flow rate and the project stopped. This situation exemplifies the risks associated with relying upon the presence of a high permeability aquifer at depth. It also shows that, even if the first well of a doublet system has high permeability, the second well may display very different properties. We do not think that this process should be repeated in Scotland.

2. High capital cost per project and delivery times

Without subsidies or other government incentives such as risk insurance, the economics of deep geothermal heat delivery are always marginal. This is mainly due to the high cost of drilling a minimum of two directional wells per project (one for abstraction, one for re-injection). This is particularly true in the UK, where relatively deep wells need to be drilled to reach suitable temperatures for district heating. Up to 80% of the capital cost of a project is associated with the drilling phase and the funding must be allocated to the project a number of years before the heat plant is constructed and the heat delivered. We believe that the delivery time and the capital cost needs to be significantly reduced before private investment will be forthcoming in Scotland.

3. Geographical reach

Two well or doublet systems always have to be located above a geothermal reservoir (geological environments where sufficient water and permeability is located underground). Either that, or the reservoir needs to be 'manufactured' by hydraulic stimulation or sheering. Locations where these conditions occur are geographically limited and do not often coincide with the location of a heat load. The geographical reach of doublet systems is therefore limited and unlikely to be able to meet a meaningful proportion of the heat demands across Scotland without significant hydraulic stimulation.

4. Induced seismicity

The drilling of a deep two well system within low permeability bedrock such as granites and indeed some sedimentary formations would require hydraulic stimulation or 'fracking' in order to create a permeability pathway for geothermal fluid flow. Normally the deeper the rock, the more difficult it is for water to move through it. A deep geothermal two well system needs to re-inject cooled water back into the rock at relatively high flow rates and under high pressure. Injecting fluids into the ground at depth under pressure has been historically associated with induced seismicity as was recently seen at the Preese Hall shale gas site^[3] near Blackpool. It is our belief that the potential for induced seismicity will limit the geographical locations where doublet systems can be installed (i.e. not in urban areas) and may cause significant concern within the local community wherever they are proposed. This aspect of deep geothermal development has not yet been tested in the UK due to the lack of delivery of deep geothermal doublet projects. However, a community backlash to induced seismicity (however small) could severely limit the integration of such systems with urban heat demands.

5. Heat demand

Two well systems require multiple megawatts of heat demand to be in place above a location that is suitable for drilling. It is our experience that large-scale heat demands and the associated networks prove difficult and time consuming to develop and are rarely above deep geothermal aquifers. In the short term for Scotland, we think it will be easier to start with smaller scale heat demands (often single owner) so that the network can be planned and managed to suit the geothermal heat supply.

How The DGSW Addresses These Problems

Over the past three years, Geothermal Engineering Ltd has been working on the design of a deep geothermal system to address these problems and kick-start the delivery of commercially viable geothermal heat in the UK. The resulting Deep Geothermal Single Well (DGSW) system has now been extensively modelled and field trialled in an existing deep well as part of a previous project (2014) funded by the Department of Energy and Climate Change (DECC). The system addresses each of the hurdles listed above in the following ways:

1. Exploration risk

The DGSW technology is not dependent on abstracting large quantities of water from the sub-surface (such as the Newcastle Well). Instead, the majority of the water is re-circulated within the well. This means that a successful project does not rely on identifying, targeting and hitting a highly permeable rock at a specific depth. The only requirement is that the temperature at depth is within the operational range for the building or plant. This significantly reduces the exploration risk associated with a project, as the temperature at depth is much better understood than the permeability, which can vary by orders of magnitude between different wells.

2. High capital cost per project and delivery times

Drilling narrow diameter single vertical wells substantially reduces the upfront capital expenditure of a deep geothermal heat project. The total capital cost of a commercial DGSW system will be between £1.5m and £2.5m, compared to greater than £14m for a directionally drilled doublet system (£7m per well) that requires directionally drilled wells. Further, as the DGSW only consists of one vertical well and no plant at the surface, the project delivery time can be reduced to between 12 and 24 months. The combination of low risk, short delivery times and reduced capital expenditure means that different funding routes can be pursued for these sorts of projects, such as community Crowdfunding. The simple vertical well design also enables turnkey contracts to be developed that reduce the risk of cost over-runs to the developer.

3. Geographical reach

Because the DGSW system is not dependent on geothermal reservoirs, that are geographically restricted in the UK, it has a much greater geographic reach than traditional systems and can be deployed in almost any geological environment where there is a heat demand at the surface. This is important, as heat demands are often not located above ideal geothermal conditions. The small footprint also means that it is well suited to urban areas and therefore has a more realistic chance of supplying heat to existing end users than larger scale systems.

4. Induced seismicity

The DGSW system does not need to inject fluid into the ground at high pressure and does not need to create a reservoir at depth, which is always required in projects utilising doublet systems. In a hard rock such as a granite, some degree of stimulation or 'fracking' will always be required to engineer a reservoir between two wells. There is therefore no risk of induced seismicity when a DGSW is installed and no risk of community backlash. This is very important when trying to develop a new commercial industry. The recent induced seismicity at a shale gas site in England caused a two year delay to the entire industry whilst the Government investigated the incident.

5. Heat demand

The heat output of the DGSW is suited to sites where small heat networks can be developed quickly or are already in place (such as Universities, schools, sports centres, multiple apartment blocks etc). Larger scale networks with multiple end users are not required. This enables projects to be developed much faster as the number of parties involved in the Heat Purchase Agreement and network operation/ management/ liability is normally one. Given the relatively small number of large-scale heat networks in place in Scotland, the DGSW can be rolled out to many areas that do not have such networks and will, realistically, never have them developed. This is particularly relevant to rural zones that have never even been connected to gas grid networks.