Proceedings of the Institution of Mechanical Engineers,Part A: Journal of Power and Energy

Subsurface resources include oil, gas, coal, groundwater, saline aquifer minerals, and heat (for geothermal use). Pore space itself should also be considered as a resource as it can be used for injection of waste fluids, produced water, storage of natural gas, compressed air, and supercritical CO₂. Use of subsurface resources can overlap in space, and pressure changes at one site can remotely influence resource use at other sites. Resource use can also vary in time, such as the use of depleted oil or gas fields for natural gas or CO₂ storage. Before allocation of a subsurface resource it is therefore useful to understand the potentially wide range of resources available in an area, how they might be developed successively, and how they could affect each other if used concurrently. While these issues are primarily geological, they have critical significance for legal, environmental, and economic considerations.

The development of tight rock hydrocarbon resources, also known as shales or unconventional reservoirs, has been enabled by the combination of horizontal drilling and hydraulic fracturing. These techniques are described. Shales have required this innovation for the hydrocarbons to be developed: the reason for this is discussed.

The permanent underground storage of large quantities of anthropogenic carbon dioxide from thermal energy and industrial plant is widely recognised as a fundamental tool which can help to avoid the worst impacts of climate change. To achieve this effectiveness, it will require widespread global deployment in a new industry which would rival the current oil and gas industry in its scale and ambition. Many of the technologies for carbon dioxide storage are the adaptations of oil and gas technology, but there are some important differences. These arise from:

 1. the thermodynamic properties of carbon dioxide,

 2. the essential requirement for long-term storage site integrity,

 3. the absence of an established and mature business model for the industry and

 4. the contrasting regulatory environments between carbon capture and storage and oil and gas extraction.

Whilst the underground injection of carbon dioxide can truly be considered a proven technology, there are a range of engineering challenges to achieve this in a safe and cost effective manner. This paper sets out to explore some of these challenges and concludes with a view of what next steps are required to progress carbon dioxide storage effectively within the UK.

 • The challenges of injecting carbon dioxide into offshore subsurface reservoirs:

   ^ Arrival processing (heating before injection)

   ^ Injectivity assessment – how many wells?

   ^ Platform or subsea?

   ^ Well design for long service operations and monitoring

 • The challenges of forecasting reservoir and injection performance within porous and permeable storage reservoirs:

   ^ Issues influencing carbon dioxide storage capacity

   ^ Assuring storage site containment integrity

   ^ Geology and engineering – uncertainty and risk

 • Where has the industry got to and what are the practical next steps?

Many of the largest fixed sources of CO₂ emissions are major power stations located on or very close to major coalfields. Even when local coal reserves are exhausted, coal- and/or biomass-fired power generation often persists at such sites, as they occupy pivotal positions in the national power grids that developed around them. To date, strategies for CO₂ sequestration from such power plants have focused on long-distance transport by pipeline to depleted hydrocarbon reservoirs and similar deep saline aquifers. Yet where abandoned coal mines extend more than about 800 m below ground level, the void space represented by the old mine voids themselves, and roof strata that have been rendered more permeable by void collapse, could represent convenient auxiliary loci for CO₂ sequestration. Furthermore, the geochemical nature of coal and coal-bearing strata may offer mechanisms for entrapment of injected CO₂ in or on the solid phase that are not available in potential storage zones considered to date. Engineering evaluation of this possibility requires consideration of the likely fate of CO₂ in free, adsorbed, dissolved, and mineralized forms, and of the geotechnical integrity of enclosing strata and abandoned mine infrastructure that could serve as seals to trap injected CO₂ in place. A protocol for assessing these factors has been developed, based on critical evaluation of mining records, hydrogeological conditions, and geotechnical data, resulting in a quantitative assessment of the capacity for CO₂ sequestration represented by deep abandoned coal mine workings. Preliminary application of the decision logic is illustrated for the Daning coal mines in China.

Underground coal gasification is a conversion and extraction process, for the production of useful synthetic product gas from an in-situ coal seam, to use in power generation, heat production or as a chemical feedstock. While many variants of the underground coal gasification process have been considered and over 75 trials performed throughout the world, the recent work has tended to focus on the control of the process, its environmental impact on underground and surface conditions and its potential for carbon capture and storage. Academic research has produced a set of mathematical models of underground coal gasification, and the European Union-supported programme has addressed the production of a decarbonised product gas for carbon capture and storage. In recent years, significant progress has been made into the modelling of tar formation, spalling, flows within the cavity and the control of minor gasification components, like BTEX and phenols, from underground coal gasification cavities (BTEX refers to the chemicals benzene, toluene, ethylbenzene and xylene). The paper reviews the most recent underground coal gasification field trial and modelling experience and refers to the pubic concern and caution by regulators that arise when a commercial or pilot-scale project seeks approval. It will propose solutions for the next generation of underground coal gasification projects. These include the need to access deeper coal seams and the use of new techniques for modelling the process.

Effective environmental management of an underground coal gasification pilot has been demonstrated at Kogan in Queensland, Australia. It commenced with selection of a suitable site with a coal seam surrounded by impervious rocks that provided a gas seal for the gasifier and sufficient groundwater pressure to constrain lateral loss of gas and chemicals through coal fractures. Project infrastructure was specified to withstand the temperatures and pressures experienced during gasification and gas processing. During syngas production in the second gasifier, Panel 2, it was shown that all pyrolysis products of environmental concern were retained within the gasifier. This was achieved by maintaining continuous groundwater inflow into the gasifier cavity through control of the relative pressures of the gasifier and surrounding groundwater. In Panel 1, it was shown that when pyrolysis products migrated out of the cavity, they were quickly detected and by modifying relative pressures to increase groundwater inflow the original groundwater conditions were restored. Following production, the cavities were decommissioned and in Panel 2 steam cleaning of the cavity removed 92% of the chemical load from the cavity. As a result, relatively low concentrations of pyrolysis products remained in the cavity. Fate and transport modelling predicted that these products will not migrate into the regional groundwater and will naturally degrade within three decades.

The total worldwide resources of oil sands, heavy oil, oil shale and coal far exceed those of conventional light oil. In situ combustion and gasification are techniques that can potentially recover the energy from these unconventional hydrocarbon resources. In situ combustion can be used to produce oil, especially viscous and immobile crudes, by heating the oil and reducing the viscosity of the hydrocarbon liquids allowing them to flow to production wells. In situ gasification can be used to convert deep carbonaceous materials into synthesis gas which can be used at surface for power generation and petrochemical applications. While both in situ combustion for oil recovery and in situ gasification of coal have been developed and demonstrated over many decades, the commercial applications of these techniques have been limited to date. There are many physical processes occurring during in situ combustion, including multi-phase flow, heat and mass transfer, chemical reactions in porous media and geomechanics. A key tool in analysing and optimising the technologies involves using numerical models to simulate the processes. This paper presents a brief review of mathematical modelling of in situ combustion and gasification with an emphasis on developing a generalised framework and describing some of the key challenges and opportunities.

A combination of thermal fracturing and stress-induced fracturing, i.e. coupled thermal-mechanical fracturing, occurs under the effect of combustion-generated heat and stress in underground coal gasification. Controlling the cracking of roofs and floors and the precise positioning of the combustion zone in underground coal gasification requires full knowledge of the characteristics of the coupled thermal-mechanical fracturing of the surrounding rocks. This study considers the variation in the physical and mechanical parameters of the rock with temperature and rock heterogeneity in order to derive a mathematical model of coupled thermal-mechanical fracturing. Then, a numerical simulation is performed, from which the following conclusions can be reached. First, temperature increases expand fractures, which emerge in the highest temperature area, before extending to lower temperature areas. Second, fracture density is directly related to temperature, with higher temperature corresponding to greater fracture density. Third, the cracking rate increases linearly with time in stages. For m = 1, the growth rate of the cracking rate are 55.76%/h, 26.08%/h correspondingly during the first stage (from 0.8 h to 1.6 h) and the second stage (from 1.6 h to 2 h).While for m = 2, the growth rates are 18.50%/h, 40.99%/h correspondingly during the first stage (from 0.8 h to 1.3 h) and the second stage (from 1.3 h to 2 h). Finally, fracture formation speed is slower in more homogeneous conditions when other conditions are unchanged. A few fractures emerge in the sample after 1.3 h for m = 2; the sample cracking rate is only 14.84%, which is far lower than for m = 1 at the same time (32.31%). Similarly, the cracking rate reaches 29.94% after 1.6 h for m = 2 (still far lower than that for m = 1 at the same time, which is 46.91%). The average growth rate of cracking rate for m = 1 (27.16%/h) is quicker than that of m = 2(21.77%/h).

The advent of new satellite and data processing techniques have meant that routine, operational and reliable surveys of land motion on a regional and national scale are now possible. In this paper, we apply a novel satellite remote sensing technique, the Intermittent Small Baseline Subset method, to data from a new satellite mission, Sentinel-1, and demonstrate that a wide area map of ground deformation can be generated that supports the regulation of a range of energy-related activities. The area for the demonstration is mainland Scotland (∼75,000 km²) and the land motion map required the processing of some 627 images acquired from March 2015 to April 2017. The results show that land motion is encountered almost everywhere across Scotland, dominated by subsidence over peatland areas. However, many other phenomena are also encountered including landslides and deformation associated with mining and civil engineering activities. Considering specifically Petroleum Exploration and Development Licence areas offered under the 14th Onshore Licensing Round in the UK, examples of the types of land motion are shown, including an example related to soil restoration by a wind farm. It is demonstrated that, in Scotland at least, almost all licence areas contain deformation of one form or another and, furthermore, the causes of that subsidence are dynamic and likely to be changing from year-to-year. Therefore, maps like this are likely to be of enormous use in a regulatory framework to scope out pre-existing problems in a licence area and to ensure that the correct monitoring framework is put in place once activities begin. They can also provide evidence of good practice and give assurance against litigation by third parties.

With the transition to renewable energies and, above all, strongly fluctuating electricity from wind and solar energy, there will be a need for energy storage in the future. For central grid-scale storages, underground geological storage, similar to those already used for fossil fuels, is in the first place under review. Compressed Air Energy Storages have already been successfully used to provide minutes to hours reserve. For storage capacities in the day to week range, storage is required on a chemical rather than a mechanical basis, through either the conversion of electricity into pure hydrogen (H₂) or the generation of mixtures of natural gas and synthetic methane. The latter – the so-called power-to-gas option – allows the use of the existing gas infrastructure. A likely first choice for the storage of H₂ or H₂-SNG mixtures are man-made salt caverns. The suitability of porous rock storage (depleted hydrocarbon reservoirs or water-bearing reservoirs – aquifers) is still under investigation. Interest in porous rock storage options arises, inter alia, from the fact that many regions of Europe lack suitable salt deposits. Favorable salt deposits exist in the UK, notably in the Cheshire Basin to the west and in eastern England, with six salt cavern-hosted facilities operated as natural gas storages. In any case, underground gas storages are characterized by high safety and low environmental impact.

In 2015, the primary energy demand in the UK was 202.5 million tonnes of oil equivalent (mtoe = 848 EJ). Of this, about 58 mtoe (2.43 EJ) was used for space heating. Almost all of this heat was from burning fossil fuels either directly (50% of all gas used is for domestic purposes) or indirectly for power generation. Burning fossil fuels for heat released about 160 million tonnes of carbon dioxide in 2015. The UK must decarbonise heating for it to meet its commitments on emissions reduction. UK heat demand can be met from ultra-low-carbon, low enthalpy geothermal energy. Here we review the geothermal potential of the UK, comprising a combination of deep sedimentary basins, ancient warm granites and shallower flooded mines. A conservative calculation of the contained accessible heat in these resources is 200 EJ, about 100 years supply. Presently only one geothermal system is exploited in the UK. It has been supplying about 1.7MW_T (heat) to Southampton by extracting water at a temperature of 76 ℃ from a depth of 1.7 km in the Wessex Basin. Like Southampton, most of the major population centres in the UK lie above or adjacent to major geothermal heat sources. The opportunity for using such heat within district heating schemes is considerable. The consequences of developing a substantial part of the UK’s geothermal resource are profound. The baseload heating that could be supplied from low enthalpy geothermal energy would cause a dramatic fall in the UK’s emissions of greenhouse gases, reduce the need for separate energy storage required by the intermittent renewables (wind and solar) and underpin a significant position of the nation’s energy security for the foreseeable future, so lessening the UK’s dependence on imported oil and gas. Investment in indigenous energy supplies would also mean retention of wealth in the UK.