CARBON AND ENERGY REDUCTION
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
Figure 5: NHS Trusts with unlikely recourse to geothermal energy that may be candidates for decarbonisation of gas at the point of use. (See Part 5.)
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
May 2023 Health Estate Journal 33
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