Clive Nattrass, who is on secondment to the NHPower programme from the Carbon and Energy Fund, explains in this article how the programme is using collaboration to manage risks associated with Trusts progressing to Net Zero, while his colleague, the CEF’s Technical director, Stephen Lowndes, focuses on the opportunities for decarbonisation of natural gas at the point of use. Two colleagues from the energy sector, meanwhile, discuss the options for the wider deployment of geothermal energy technology across the NHS.
Part 1
Collaboration to meet NHS 2032 targets
Clive Nattrass, CEF
To meet 2032 targets the NHS needs to green most, if not all, of its top 211 CO2 fossil fuel emitters in under a decade – i.e. the Trusts that use 10 m kWh or more of gas per annum. Since 1996 the NHS has been implementing carbon and energy reduction projects, and now we have exemplar ‘fossil fuel Net Zero’ hospitals emerging at Eastbourne, Bridlington and other locations. However, the challenge of ‘greening’ over 200 hospitals by 2032, in a time of low capital, challenged revenue budgets, and annual Government decarbonisation grants that are soft capped, cannot be overstated. Almost all technologies that would allow an NHS Trust to get to Net Zero involve risk. Even heat pump technology is in its early days, and has yet to prove its resilience at scale in a hospital environment – albeit introducing an additional annual running cost.
NHS Trusts wishing to share risks to reduce failure, costs, and project management overheads are able to collaborate through NHPower. Collaboration shares the risks of failure, so that no Member faces the ‘all or nothing’ risks associated with ‘cutting edge’ technology or unsuitable underground conditions. Collaborating Trusts would benefit from a knowledge-sharing forum with like-minded Members serving a common purpose, and would go forward together to share grant applications, procurement, finance, project management, technical support, site infrastructure upgrade preparation, and ongoing energy management.
Current available routes to Net Zero
The Net Zero routes immediately available are few, and in essence include:
1 Geothermal energy.
2 Hydrogen.
3 Electricity.
4 Decarbonisation of gas at the point of use.
5 District energy
The large NHS emitters are being categorised on the basis of the most suitable available route to Net Zero based on geography. This is because geothermal energy and hydrogen availability are geographical, and based on the geology or socio infrastructure of a particular location
When mapped we can see that some Trusts are in the enviable position of being close to hydrogen and geothermal energy sources purely by their location.
Geothermal energy: All large emitter sites have been run through the British Geological Survey’s database, and about 100 sites have geothermal potential. The piloting wave of five projects is in procurement, and will investigate and install geothermal energy under a flexible procurement route called an Innovation Partnership. This allows careful phasing and management of discoveries and risk.
Hydrogen: So far two main hydrogen areas are worth progressing, and Trusts which have a chance to get hydrogen will be approached to participate in the collaboration during this year in specially set up workshops. While liquid hydrogen will be available this year, we are targeting 2027 for the completion of the first tranche of piped Trust connections. Sites will need conversion to 100% hydrogen and a review of their resilience arrangements. The first workshops to investigate the interest in collaboration will occur this year, with sessions planned at Healthcare Estates in October 2023.
Decarbonisation of gas at the point of use: In the absence of geothermal or hydrogen energy sources, technologies to decarbonise gas on site are being investigated. (See Part 5.) Other low carbon fuels are also being considered.
District heating: The NHS’s 211 main emitters are each surrounded by an ecosystem of mental health and community facilities (over 1600 of them) that all need to get to Net Zero too. While district heating is not in itself necessarily any cleaner than any other heat source, there are a number of systems heated from burning waste or low carbon fuels, or which could use geothermal or hydrogen fuels, and these are being included in the programme.
Risk
The strategy for managing risk is collaboration. Any single project to convert a site to Net Zero involves risks and costs. A standalone project must manage the risks itself, and while NHS Trusts are largely autonomous, the NHS shares big risks, and the NHPower programme is no different. While other collaborations may arise, the only current option for Net Zero collaboration in the NHS is NHPower
Existing technologies and energy reduction methods
This article does not discuss these, as the technologies are available, and every Trust understands the need for energy reduction improvements. There are now many heat pump installations, although they are being closely monitored, as the NHS has little experience of their resilience over time and in all weather
Other benefits of collaboration
It is clear that Net Zero will be very different to the current energy model. Instead of setting up controls once and just relying on boilers, Net Zero installations will require active management, and a programme of reducing temperatures over time. This calls for comprehensive energy management, which currently enjoys certain taxation benefits when carried out for a Trust, and can be included within the collaboration. Every Estates manager appreciates the benefits of a comprehensive and effective BMS system with good building insulation without air leaks. In the Net Zero world this will no longer be optional, to the benefit of all that use the hospital
Part 2
Getting to Net Zero – programme delivery and managing risk
Clive Nattrass, CEF
Most NHS Trusts have an identified roadmap to Net Zero. The most commonly quoted blocker to achieving it, however, is the perceived lack of resource – most notably funding. Experience would suggest that this is not the case, or at least not true in the way that many people interpret the reason. The actual blockers are the risks associated with new technologies, and when managed effectively, the resource follows. The Net Zero routes immediately available are few, and in essence include:
1 Geothermal energy.
2 Hydrogen.
3 Electricity.
4 Burning a low carbon fuel.
5 District energy.
Demand side reduction measures
This list excludes demand side reduction measures and fabric improvements that are usually desirable, and to be encouraged, regardless of primary energy source, in order to promote efficient use. All of these options may be carbon compromised (e.g. electricity is not green now, there is no clean hydrogen, and biomass or waste burning is inherently carbon emitting). However, if we can leave the greening of the grid (electricity and hydrogen) with the related market stakeholders to solve, we can use any of the methods above to get NHS sites to Net Zero. The perceived blocker in funding can reliably use long-term revenue streams to fund the transition, and the remaining risks associated with the technology require focused management.
How do we manage risks and thus solve the funding issue?
The first most common way to solve the funding constraint is to seek some form of governmental funding. That means hoping that the government will fund the conversion – and if it doesn’t work… well that is then considered to be the government’s problem. There are several grants currently available, and many projects running under just that premise. Consider the case of heat pumps; in the NHS there are few heat pumps of size that are not funded by grants. Many projects have not addressed the recurrent costs of running the technology and the impact to the annual revenue budgets. Market indicators suggest that a steady state is a number of years away, and no-one knows what is going to happen to electricity prices. There is a strong risk that most heat pumps will not be used in line with their grant applications.
The second way of managing risks is to pass them to the body best able to manage them. This is common with performance contracts, where it is possible to pass most of the risks associated with performance to a contractor, and most complex energy projects in the NHS are carried out this way. With nearly £1 bn deployed or in deployment across the NHS, huge carbon reductions are being delivered, and in many cases, financial savings too
Technologies currently ‘too risky’
Unfortunately, this route alone will not get the NHS to Net Zero in time to meet its obligations, because most of the current Net Zero technologies are too risky for the established performance contractors to guarantee. In addition, the providers of the new technologies are themselves small, and in no position to take significant risk on their own technologies. In fact, current installations indicate that the task of developing and proving the technology alone is normally all the risk they can manage.
The NHS can learn from other industries that manage the equivalent risk, on a larger scale. Outside the NHS, large risks are managed by insurance, risk sharing, and diversity of risks. The pension industry, insurance, and energy industries, all use these techniques, which – coupled with good engineering design for resilience – offers the NHS a way forward that bypasses the funding issue, and would allow many Trusts to realistically aim for Net Zero.
Benefits of NHPower
While the NHS is considering insurance management for certain risks, it has long managed a risk pooling scheme for larger risks. We are in a time of change, and while the NHS risk pool is not yet being offered for Net Zero projects, there is an affiliated NHS collaboration alternative, called project NHPower, which is available to Trusts wishing to share risks and benefits across member Trusts to avoid the need and expense of project or contractor private finance. NHPower members will have the opportunity to work with grant and centralised funding, and introduce security in the source of energy provision, without carrying an asset on balance sheet, and instead pay a p/kWh for energy, that in many cases is decoupled from the volatility of the open energy market.
The top 211 NHS sites, using more than 10 m kWh each, are all being categorised as to the available and optimal routes to Net Zero, under the categories listed above. Piloting the way forward, five Trusts have commenced a four-year collaborative procurement for geothermal energy. In quarter two of 2023 the second wave of geothermal collaboration will go to market, and it is hoped that where geothermal energy is not a viable option, the first wave of a five-year hydrogen collaboration will start with a workshop of Trusts that have the opportunity to work together. Having the top energy users on the road to Net Zero should meet the NHS 2032 targets. In 2024 the masterplan will widen to include planning for the next 1600 NHS buildings using significant energy, benefiting collective knowledge share and delivery principals from the model programme
NHS Trusts that do not wish to wait until contacted to participate in the NHS collaboration are welcome to contact NHPower at EOI@NHpower.net.
Part 3
Geothermal energy: a potential source for decarbonising the hospital estate
Dr Corinna Abesser, BGS
Geothermal energy occurs across the UK, mostly in deep onshore sedimentary basins. Where groundwater circulation occurs within deeply buried rocks (1 to 3 km), it forms hydrothermal systems or deep geothermal aquifers, also called ‘hot sedimentary aquifers’. Hydrothermal systems arise from a combination of three geological components: fluid, heat, and permeable rocks. Temperatures within the basins are generally 40 to 60 °C, but could reach 100 °C in the deepest parts of some of the basins1 (Busby, 2014); hence these systems are most suited to provide direct-use heating (without use of a heat pump) for district heating, horticulture, or industrial process heat
BGS has undertaken detailed mapping and investigation of this resource since the 1980s, and estimates that the geothermal heat resource contained within these basins is 100-200 times the UK’s domestic heat demand.2 However, as heat cannot currently be transported over long distances because of high distribution losses along the way, opportunities for developing geothermal heat are limited to areas of high heat demand, such as cities. Many major population centres in the UK lie above or adjacent to sedimentary basins.
Drilling of deep wells
Exploitation of these deep geothermal systems requires the drilling of two or more deep wells (typically 1 to 3 km) to reach the higher temperature heat resources. This heat can be used directly to supply heating to users with large heat demands, including hospitals, domestic or commercial space heating, or industrial users. Geothermal technologies are scalable and combinable across the spectrum of drillable depths and temperatures. In some cases, for example, heat pumps are being used in conjunction with moderately deep wells (500 to 1000 m) to boost temperatures, and achieve the required operational temperatures for the heat network. Such hybrid systems benefit from higher temperatures at depth, while avoiding the high capital costs and risks associated with even deeper drilling.
District heating at a city scale
Where a good resource exists, geothermal can supply district heating at the city scale. For example, Paris receives geothermal heating from its deep geothermal aquifer for around 250,000 homes via 50 heat networks, while around 50,000 homes in Munich are supplied with geothermal heating, saving about 75,400 tonnes of carbon dioxide (CO2) per year compared with natural gas.1
Figure 1 shows the sedimentary basins (yellow and blue areas on the map) where deep geothermal prospects exist in England. Also shown on the map are locations of NHS hospitals that have been prioritised for decarbonisation because of their high heat demand. An initial assessment suggests that, out of the 210 sites, 109 overlie potential geothermal aquifers. The estimated drilling depths to reach a temperature of 50 °C range between 1.2 and 3 km. Developing geothermal projects for these sites could save between 1.3 and 22.7 Kt CO2 equivalent emissions per year for individual hospital sites. It is important to note that Figure 1 only shows the extent of the geothermal basins, and that there is great variability in terms of the reservoir properties and temperatures within individual basins. Further analyses, in the form of a more detailed feasibility study followed by site-specific investigations, are required to assess the feasibility of geothermal exploitation at any particular site before any drilling takes place
To find out more about feasibility for using geothermal energy at your site, contact BGS Enquiries (enquiries@bgs. ac.uk). For further information about geothermal energy, see Abesser and Walker (2022).1
Part 4
Deep Geothermal possible ‘with the right skillsets and risk management’
Rik Evans, GT Energy
Deep geothermal technology allows us to extract the heat of the earth from more than 500 m beneath our feet. It offers a potential route for the decarbonisation of traditional heat sources such as gas, which is a source of about 40% of the carbon emissions in the UK. Aside from the people of Roman Britain enjoying the natural thermal springs of Bath (which still flow today), only one purpose-built exploration well has been drilled – in Southampton in the 1980s – and a couple of more recent pilot projects in Cornwall, yet other countries around the world have been successfully harnessing the heat of the earth for many decades.
Our historically heavy reliance on gas in the UK has meant that geothermal heat has largely been ignored. However, with a focus on the need for a rapid decarbonisation of heat as we drive to Net Zero, a flurry of projects at varying stages of maturity from early stage concept, or even on the cusp of construction, are emerging – and it finally looks as though we are set to join the likes of Germany, France, and The Netherlands, in exploiting this exciting renewable technology
A hybrid between natural and renewable
So, how does this technology work? Geothermal resources can be thought of as a hybrid technology. They are reservoirs of hot water at varying depths and temperatures below the earth’s surface. Wells, ranging from a few 100 m to several kms deep (see Figure 2), can be drilled to tap the very hot water and steam, which can then be brought to the surface for use in heating, and even to provide cooling.
The reward for geothermal energy development is high: it’s renewable, has one of the smallest land-use footprints, requires no expensive facilities to retrofit, runs ‘24/7 ‘whatever the weather; is dispatchable, and offers a wide temperature applicability and storage potential. However, as with any development, these projects have an element of risk. At the outset, drilling deep wells is capitally intensive and logistically complex. While we know there is heat, it is critical to optimally place the production well to deliver commercial flow rates, which you cannot validate until you have drilled, emphasising the importance of risk management throughout the project development lifecycle.
Reducing geological risk
These are the risks that engineers – through many years of hydrocarbon drilling experience – have faced in order to explore for and develop a resource. As more and more wells are drilled, and more seismic data are acquired, geological risk is also further reduced. That is not to the say the first projects will be inherently more risky – just that a greater degree of reliance on experience and knowledge is needed to deliver successfully. Once successful projects have been implemented, and a supply chain established, the market will have been ‘de-risked’ to an extent, paving the way for further projects and accelerated investment.
Managing risks in large-scale, complex drilling projects has been undertaken by the oil and gas industry for decades, and a tried and tested approach to standardly identify, categorise, and mitigate risks throughout the project’s evolution is well established. We are now applying this deep expertise to the nascent geothermal industry in the UK.
Part 5
Decarbonisation of natural gas at point of use
Stephen Lowndes, CEF
A perceived advantage of hydrogen as an alternative to natural gas is that it can be combusted in a similar manner using familiar boiler technology, or even used in existing plant that has been retro-adapted. Most importantly, hydrogen contains no carbon, and so no CO2 is released during its combustion. The issue remains though of how we generate hydrogen in the first place. There are currently three main routes to produce hydrogen: electrolysis, steam methane reformation (SMR), and methane pyrolysis.
Methane pyrolysis currently appears to be the technology that may be scalable down to site use level, and is a solution being considered for application at industrial sites, and potentially hospitals too. The process splits the carbon from natural gas through an exothermic reaction derived from a heat source and a controlled pyrolysis process. In the absence of oxygen, this process produces a substance commonly referred to as ‘carbon black’, alongside the required hydrogen fuel output. Carbon black is essentially a dry powder or granular product that can then be removed from site and subsequently used as a raw material as part of the manufacture of other products, such as building materials. Clearly a chain of custody is needed to ensure that the end-product is not then ultimately combusted at the end of its life, and the previously captured carbon released to atmosphere.
H2 at point of use
Currently, small-scale on-site methane ‘pyrolysis’ systems are being developed for market that use either microwave or electric plasma technology to act as a reaction initiator, enabling the process of stripping carbon from methane to occur at comparatively lower temperatures and pressures than might otherwise be needed for traditional pyrolysis.
The key to the success of small-scale methane to hydrogen generation systems will be achieving a realistic capital cost, and the ability to operate efficiently and economically at the same time as not taking up unrealistically large areas of a hospital site. Current small-scale hydrogen production systems are in their initial proving and pilot stages, and it is expected that these technologies will develop rapidly in the coming years.
In all cases electricity input is needed for the energy source driving the microwave or plasma reaction process. This will usually be derived from the national grid, so net carbon sequestered from the natural gas input must also take into account electricity grid emissions incurred.
Initial pilot plants currently being developed for onsite locations take up shipping container-sized modules, and the number of modules required depends upon the throughput of natural gas and hydrogen generation delivered. In addition to the plant space, a suitable area is required for the storage of the carbon black grains, which would need to be regularly collected from site, and so a vehicular access route is also needed.
Business case
To date, comparisons with conventional heat production look promising, both in terms of carbon sequestering and potential running costs. Initial investigations show the potential for on-site hydrogen production to deliver CO2 emissions to air rates that are much lower (around 40%) than current best alternatives using electric heat pumps for equivalent heat delivery.
Work has also started on determining the financial model, which compares smallscale hydrogen production with operating natural gas boilers or electric heat pumps. It is likely that the overall cost of running such systems will need a revenue stream for the carbon black produced in order to achieve parity with the cost of operating natural gas boilers. The potential for achieving this appears promising from work undertaken in conjunction with potential suppliers so far.
Other uses by the NHS
Consideration for generating hydrogen for NHS vehicle fuel application is also being considered, such as ambulance fleets, that may cover many thousands of miles per year, and need to be available 24/7, placing a degree of challenge when considering their wholesale electrification, which needs managing within limitations of charging downtime and range. Early studies to date indicate the potential for significant carbon and fuel cost savings compared with existing diesel and current electric vehicle alternatives. Other areas for investigation include pyrolysis of medical waste, and strategic utilisation in co-generation of heat and power.
Conclusions
The financial and technical business case is still being developed for smallscale point of use hydrogen production. As such, it remains to be seen as to whether the technology has a definite viability and a place within the hospital setting, whether for decarbonising heat, vehicle fleets, or other strategic uses. However, the potential for delivering this technology looks promising, and it may well turn out to be the right answer for some sites and Trusts that find themselves with limited alternative options because of their location, or the limitations of local electricity networks.
Clive Nattrass
Clive Nattrass is the Programme manager of NHPower, appointed by a taskforce of governmental, IHEEM, and NHS representatives to design and implement a programme to get the NHS to Net Zero in fossil fuels. He has a pedigree in this field, having founded the Carbon and Energy Fund, which is the main route to energy infrastructure improvement in the NHS.
Dr Corinna Abesser
Dr Corinna Abesser is the head of Geothermal Energy Research at BGS. She contributes to national and international research, and acts as an expert advisor to the UK Government and Parliament. She has developed several briefing papers on the topic of geothermal energy for policy-makers and parliamentary audiences.
Rik Evans
Rik Evans is the Commercial director for GT Energy. Working initially in the oil and gas service sector, and more recently as head of Integrated Planning and Risk Management for a multinational operator, he has brought the skills and experiences honed from delivering and working on energy projects around the world to bear on the UK geothermal sector. GT Energy has a number of active geothermal developments across the country, including one in Stoke-on-Trent, which will be the UK’s first geothermally powered District Heating Network, and a pipeline of dozens more in gestation.
Stephen Lowndes
Stephen Lowndes BEng (Hons), MSc, CEng, MCIBSE, MEI, has many years’ experience of energy project design, as well as supporting operational management – including carbon and energy management – within the public sector, that started with NHS projects in the 1980s. He leads the Carbon and Energy Fund Technical Delivery team, working on all aspects of project feasibility through to construction and operational delivery.
References
1 Abesser C, Walker A. 2022. Geothermal Energy. Parliamentary Office for Science and Technology Research Briefing, POSTBrief 46, 2022. Available from https://post.parliament.uk/researchbriefings/post-pb-0046/
2 Busby JP. 2014. Geothermal energy in sedimentary basins in the UK. Hydrogeology Journal 2014; 22: 129–141. https://doi.org/10.1007/s10040-013- 1054-4