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Karstified and fractured Lower Carboniferous (Mississippian) limestones of the UK have been evaluated for their geothermal potential. This wholly undeveloped resource is calculated to be in excess of 26 million GWh (95 EJ) for the P90 case and as much as 35 million GWh (129 EJ) for the P50 case for six regions in England and Wales, ranging in scale from Kent at 0.04 million GWh (P50) to Northern England at 15 million GWh (P50). The evaluation used three sources of evidence to assess the distribution, current burial depth, likely temperatures and transmissivity of these limestones. Seismic and outcrop data, well logs and core from drilled wells and water chemistry data from thermal springs were used to demonstrate the presence of deep, water bearing, permeable limestones. Geothermometry calculations using spring-water composition data provided clues about temperatures at which the issuing water equilibrated with its original host rock indicating that water now reaching the surface had acquired its solutes at temperatures significantly in excess of 30 °C and depths much greater than 1km. The UK uses about 2.5 EJ per annum yielding a resource to use ratio of 40-50 years assuming no natural inflow or reinjection of cooled water for reheating.

The energy transition has started. While traditional petroleum exploration and production will become increasingly difficult, the offshore region around the UK, Norway, Denmark and the Netherlands offers many opportunities for companies prepared to embrace low-carbon energy and related activities. We present 19 ideas for new sustainable business. If climate commitments are to be met, the scale of the transformation will be immense. Assuming the economics of floating technologies improve, we envisage the majority of the North Sea (>100,000km2) to be repurposed for renewable power and related activities. In order to fully unlock the future value in wind, solar and ocean energies, as well as in subsurface storage, companies and governments will need to work together to create an integrated energy system.

Large scale storage of heat is critical for the successful decarbonisation of the UK’s energy mix and for grid-balancing. Heat generation currently accounts for 50% of all energy use in the UK and most of this is produced by burning fossil natural gas. Heat is regarded as a single-use commodity, discarded or dissipated when not required in summer yet a lifesaving necessity during the colder winter months. Here we estimate the theoretical potential capacities for the storage of heat in the subsurface using aquifers and flooded mines, with a consideration of seasonal storage of heat in particular. We set this against the theoretical potential volumes of waste heat and solar thermal energy that could be exploited. This contributes to the wider knowledge base of the capacity of different forms of energy storage available through other means and highlights the potential for the UK. Our calculations indicate that the theoretical potential for large-scale underground thermal-energy storage in the UK is substantial, much larger than which might ever be needed and the location of such storage is well matched to the places where people live and work and therefore where the demand for heat occurs.

The Breagh Field is in UK Blocks 42/12a, 42/13a and 42/8a. It is a gas field with multiple reservoir intervals within sandstones of the Early Carboniferous Yoredale Formation (equivalent to the Middle Limestone Formation within the Yoredale Group onshore). It was the first and is presently the only field developed within these sandstones, offshore UK. Breagh was discovered in 1997 by well 42/13-2 and proved by development well 42/13a-A1. Its crest is at 7110 ft TVDSS (true vertical depth subsea), marked by the unconformity between the base Zechstein and the subcropping Yoredale Formation. It has a free water level at 7690 ft TVDSS, a maximum column height of 510 ft and a field extent of 94 km2. Breagh was developed using ten wells from a 12 slot normally unattended platform; five of the wells have been stimulated by hydraulic fractures with proppant injection. The unprocessed gas flows through a 110 km 20-inch diameter pipeline to the Teesside Gas Processing Plant. Production started in 2013, reached a peak rate of 150 MMscfgd in 2014 and, by the end of 2018, had produced 140 bcf. The field is operated by INEOS Oil and Gas UK Ltd (70%) with partner ONE-Dyas B.V. (30%).

Coal‐formed gas generated from the Permo‐Carboniferous coal measures has become one of the most important targets for deep hydrocarbon exploration in the Bohai Bay Basin, offshore eastern China. However, the proven gas reserves from this source rock are remain low to date, and the distribution characteristics and accumulation model for the coal‐formed gas are not clear. Here we review the coal‐formed gas deposits formed from the Permo‐Carboniferous coal measures in the Bohai Bay Basin. The accumulations are scattered, and dominated by middle‐small sized gas fields, of which the proven reserves ranging from 0.002 to 149.4×108m3 with an average of 44.30×108m3 and a mid‐point of 8.16×108m3. The commercially valuable gas fields are mainly found in the central and southern parts of the basin. Vertically, the coal‐formed gas is accumulated at multiple stratigraphic levels from Paleogene to Archaeozoic, among which the Paleogene and Permo‐Carboniferous are the main reservoir strata. According to the transporting pathway, filling mechanism and the relationship between source rocks and reservoir, the coal‐formed gas accumulation model can be defined into three types: “Upward migrated, fault transported gas” accumulation model, “Laterally migrated, sandbody transported gas” accumulation model, and “Downward migrated, sub‐source, fracture transported gas” accumulation model. Source rock distribution, thermal evolution and hydrocarbon generation capacity are the fundamental controlling factors for the macro distribution and enrichment of the coal‐formed gas. The fault activity and the configuration of fault and caprock control the vertical enrichment pattern.

The Permo-Carboniferous sandstones in the Gubei area, Bohai Bay Basin, are reservoirs for large accumulations of natural gas. The natural gas accumulations only occur in the sandstone beds thicker than 1.9 m. Moreover, the maximum porosity of every bed correlates positively with bed thickness up to 2.0 m and for thicker beds porosity is uniform. Porosity transitional zones developed at the top and bottom of each bed, with mean thicknesses of 1.25 m and 0.75 m, respectively. Porosity shows a positive correlation with the distance to the sandstone/mudstone contact in the zones. Interpretations based upon an extensive petrographic and geochemical database indicate that the sandstones experienced a mass fluid input from the adjacent mudstones during the early diagenesis. The infiltration resulted in extensive clay coats and pore-filling cements in sandstones, which were effective for inhibiting dissolution of grains during subsequent diagenesis process. The mass introduction only affected the marginal parts of the sandstones within 1.25 m of the top and 0.75 m of the bottom of every bed, causing thin sandstone beds with thickness of approximately 2 m to be tightly cemented totally. Thus the central parts of each (thicker) beds became preferential sites for the natural gas accumulation. The differential levels of cementation in thin and thick sandstone beds observed here has significant implications for exploration of similar interbedded sandstone and shale sequences elsewhere including shale gas targets.

Cosmic Ray Muon Radiography utilizes highly-penetrating cosmic ray muons to image the density profile of an object of interest. Here we report on the first trial to use a portable field-deployable cosmic ray tracking system in order to image the whole overburden of a UK railway tunnel with short duration scans (c. 30 minutes). A unknown overburden void was identified and, post-trial, confirmed by railway authorities. These experiments demonstrate the identification of hidden construction shafts with high levels of statistical significance as density anomalies within the data.

The abandoned Innes Field was within Block 30/24 on the western margin of the Central Trough in the UK sector of the North Sea. Hamilton Brothers Oil Company operated the licence, and Innes was the third commercially viable oil discovery in the block after Argyll and Duncan. It was discovered in 1983 with well 30/24-24. Three appraisal wells were drilled, one of which was successful. Oil occurs in the Early Permian Rotliegend Group sandstones sealed by Zechstein Group dolomites and Upper Jurassic shale. The discovery well and successful appraisal well were used for production. Export of light, gas-rich crude was via a 15 km pipeline to Argyll. Innes was produced using pressure decline. It was abandoned in 1992 having produced 5.8 MMbbl of oil and possibly 9.8 bcf of gas. Water cut was a few percent. Innes was re-examined between 2001 and 2003 by the Tuscan Energy/Acorn Oil and Gas partnership with a view to tying the field back to the newly redeveloped Argyll (Ardmore) Field but marginal economics and financial constraints for the two start-up companies prevented any further activity. Enquest currently owns the licence and the company has redeveloped Argyll/Ardmore, as Alma. There are no plans to redevelop Innes.

The Endurance, four-way, dip-closed structure in UK Blocks 42/25 and 43/21 occurs over a salt swell diapir and within Triassic and younger strata. The Lower Triassic Bunter Sandstone Formation reservoir within the structure was tested twice for natural gas (in 1970 and 1990) but both wells were dry. The reservoir is both thick and high quality and, as such, an excellent candidate site for subsurface CO2 storage. In 2013 a consortium led by National Grid Carbon drilled an appraisal well on the structure and undertook an injection test ahead of a planned development of Endurance as the first bespoke storage site on the UK Continental Shelf with an expected injection rate of 2.68 × 106 t of dense phase CO2 each year for 20 years. The site was not developed following the UK Government9s removal of financial support for carbon capture and storage (CCS) demonstration projects, but it is hoped with the recent March 2020 Budget that government support for CCS may now be back on track.

There are around 40 new geothermal power projects commissioned in each of the last few years. Growth of the market is around 5% annually and current installed capacity is about 13,300 MW with about the same in development in 24 countries. These figures are impressive, but they do not bear comparison with any of the fossil fuels. However, few will realise that the global oil industry has a cryptic geothermal power potential that is equal to the entire current output of the geothermal industry. The oil industry is ageing. Many areas still produce copious quantities of oil, but the oil comes with an unwanted by-product, water. The volume of water produced is typically is 10–20 times that of the oil; and the water is hot—in some places very hot (>100°C). In a recent study we showed that the power depleted oil production platforms of the North Sea’s North Viking Graben produce sufficient hot water to deliver around 60% of the power requirement for each field. A review of global oil and hence water production has enabled us to calculate that power production alone from waste water from producing oilfields could be at least 15,000 MW.

In 2015, the North Sea petroleum province was 50 years old. The celebrations were short lived because oil prices and gas prices were in free fall. The demand from the UK market had outstripped demand back in 2005 and, 10 years on, falling production and increasing operating expenditure, when coupled with falling prices, had brought the North Sea to crisis point. Many fields became unprofitable and companies began to close down. In an effort to avert the developing crisis, this work examines what options exist for better utilizing the North Sea industry, be that monetizing co-produced fluids or using the pore space once occupied by petroleum for waste products such as carbon dioxide. We briefly examine: the possibility of utilizing heat from the co-produced fluids for power generation; extracting gases and ores from co-produced fluids; and evaluation of the role that carbon dioxide could play in enhanced oil and gas recovery, as well as its ultimate long-term storage in geological deep storage.

Carbon capture and storage is a transition technology from a past and present fuelled by coal, oil and gas and a planned future dominated by renewable energy sources. The technology involves the capture of carbon dioxide emissions from fossil fuel power stations and other point sources, compression of the CO 2 into a fluid, transporting it and injecting it deep beneath the Earth's surface into depleted petroleum reservoirs and other porous formations. Once injected, the CO 2 must be monitored to ensure that it is emplaced and assimilated as planned and that none leaks back to surface. A variety of methods have been deployed to monitor the CO 2 storage site and many such methods have been adapted from oilfield practice. However, such methods are commonly indirect, episodic, require active signal generation and remain expensive throughout the monitoring period that may last for hundreds of years. A modelling framework was developed to concurrently simulate CO 2 geostorage conditions and background cosmic-ray muon tomography, in which the potential was assessed for using variations in muon attenuation, due to changes in CO 2 abundance, as a means of CO 2 detection. From this, we developed a passive, continuous monitoring method for CO 2 storage sites using muon tomography, the tools for which can be deployed during the active drilling phase (development) of the storage site. To do this, it was necessary to develop a muon detector that could be used in the hostile environment (saline, high temperature) of the well bore. A prototype detector has been built and tested at the 1.1 km deep Boulby potash mine on the northeast coast of England, supported by the existing STFC Boulby Underground Laboratory on the site. The detector is now ready to be commercialized. This article is part of the Theo Murphy meeting issue ‘Cosmic-ray muography’.

Rapid growth of hydraulic fracturing for shale gas within the USA and the possibility of shale developments within Europe has created public concern about the risks of spills and leaks associated with the industry. Reports from the Texas Railroad Commission (1999 to 2015) and the Colorado Oil and Gas Commission (2009 to 2015) were used to examine spill rates from oil and gas well pads. Pollution incident records for England and road transport incident data for the UK were examined as an analogue for potential offsite spills associated with transport for a developing shale industry. The Texas and Colorado spill data shows that the spill rate on the well pads has increased over the recorded time period. The most common spill cause was equipment failure. Within Colorado 33% of the spills recorded were found during well pad remediation and random site inspections. Based on data from the Texas Railroad Commission, a UK shale industry developing well pads with 10 lateral wells would likely experience a spill for every 16 well pads developed. The same well pad development scenario is estimated to require at least 2856 tanker movements over two years per well pad. Considering this tanker movement estimate with incident and spill frequency data from UK milk tankers, a UK shale industry would likely experience an incident on the road for every 12 well pads developed and a road spill for every 19 well pads developed. Consequently, should a UK shale industry be developed it is important that appropriate mitigation strategies are in place to minimise the risk of spills associated with well pad activities and fluid transportation movements.

Exploitation of geothermal energy offers a consistent and secure low carbon energy supply. Geothermal energy resources are associated with a variety of geological settings, are available at temperatures ranging from a few tens of degrees to several hundred degrees and may be used for the provision of heat, power or both. Their exploration, assessment and exploitation draw from a wide range of techniques. Improvements in deep drilling and energy conversion technologies mean that many countries could develop geothermal energy systems. There are both economic and technical risks and challenges associated with geothermal energy exploitation; however, the potential for geothermal resources to provide low carbon and continuous power, heat or both means that they have the potential to be an increasingly important part of the energy mix for many areas of the globe.

Traditionally the power demand of offshore oil platforms is delivered by on-platform gas turbines. Natural gas to fuel these turbines is usually separated from the produced oil. However, in ageing fields as oil production declines so does the associated gas. Ultimately gas supply becomes insufficient; in order to continue producing fuel is imported at great expense. This study proposes the power demand of a platform could be met or supplemented by an on-platform ORC (organic Rankine cycle ) fuelled by coproduced hot brines. This could extend the operating life of oil platforms and reduce both cost and emissions. The potential power output of an ORC is modelled for fields in the North Sea's Brent Province. Results show 6 fields have the potential to generate more than 10 MW via an organic Rankine cycle fuelled by hot brines, with a maximum of 31 MW predicted for the Ninian field. Analysis of simulations for the Eider field shows that ORC plants can scale to size constraints. The cost of a 10 MW ORC is compared to cost of continued use of gas turbines. Payback times of between 3.09 and 4.53 years are predicted for an ORC, without accounting for greenhouse gas emissions levies.

Data from around the world (Australia, Austria, Bahrain, Brazil, Canada, the Netherlands, Poland, the UK and the USA) show that more than four million onshore hydrocarbon wells have been drilled globally. Here we assess all the reliable datasets (25) on well barrier and integrity failure in the published literature and online. These datasets include production, injection, idle and abandoned wells, both onshore and offshore, exploiting both conventional and unconventional reservoirs. The datasets vary considerably in terms of the number of wells examined, their age and their designs. Therefore the percentage of wells that have had some form of well barrier or integrity failure is highly variable (1.9%e75%). Of the 8030 wells targeting the Marcellus shale inspected in Pennsylvania between 2005 and 2013, 6.3% of these have been reported to the authorities for infringements related to well barrier or integrity failure. In a separate study of 3533 Pennsylvanian wells monitored between 2008 and 2011, there were 85 examples of cement or casing failures, 4 blowouts and 2 examples of gas venting. In the UK, 2152 hydrocarbon wells were drilled onshore between 1902 and 2013 mainly targeting conventional reservoirs. UK regulations, like those of other jurisdictions, include reclamation of the well site after well abandonment. As such, there is no visible evidence of 65.2% of these well sites on the land surface today and monitoring is not carried out. The ownership of up to 53% of wells in the UK is unclear; we estimate that between 50 and 100 are orphaned. Of 143 active UK wells that were producing at the end of 2000, one has evidence of a well integrity failure.

Effective monitoring and numerical simulations are essential to understanding the implications of long-term geological carbon storage; in particular, the predictions of CO2 plume flow under storage conditions, storage integrity of sites, and the design and operational aspects of the CO2 storage projects could be significantly supplemented. Site monitoring data can assure reliability and accuracy of the numerical simulation while numerical prediction results will provide more detailed information on the storage process. The cross-validation between numerical modelling results and monitoring data can play a major role in the development of carbon capture and storage technology. This paper briefly reviews the monitoring and modelling technologies associated with geological carbon storage. In addition, the spatial and temporal resolutions of the numerical simulations are highlighted, while estimations on the resolutions of some commonly used monitoring technologies are also presented. It is revealed that there are gaps in the correlations and cross-validation between the two technologies, where a possible option to reduce the gaps is to enforce more research efforts on multi-scale modelling and appropriate variable correlations.

We used a sub-salt Rotliegend Group sandstone saline aquifer in the North Sea as a case study site for Monte-Carlo-based CO2 geostorage capacity assessment. In the area of interest, this unit is characterized by sparse, low resolution, subsurface data typical of the margins of global petroleum provinces, favored for CO2 storage. Such data scarcity leads to uncertainty regarding the complex trap geometries and ultimate CO2 storage capacity. The Rotliegend reservoir, estimated to have porosity and permeability ranges of 11–27% and 0.2 mD–125 mD, respectively, is sealed by Zechstein salt. The salt, predominantly halite, is a proven hydrocarbon seal in the central and southern North Sea hosting oil and gas columns of >140 m (>450 ft) and >150 m (>500 ft). Utilizing 2D-seismic data, boreholes and analogues, we estimate the pore volume of a 5-km2 4-way dip-closed structure through Monte-Carlo-based capacity simulations. We estimated storage capacity using published methodologies and compared this against a theoretical total storage calculation analogous to the gas in place equation used in the petroleum industry. We found that different methods yield a capacity range of 109 tonnes CO2 where sensitivity analysis indicates variability in reservoir properties to be the dominant control. Thus static estimates based upon Monte-Carlo calculations present no advantage over theoretical pore volume estimations. This leaves 3D dynamic modeling of storage capacity populated by 3D seismic data and direct down-hole measurement of reservoir properties to improve confidence in capacity estimations as the recommended method.

We estimate the likely physical footprint of well pads if shale gas or oil developments were to go forward in Europe and used these estimates to understand their impact upon existing infrastructure (e.g. roads, buildings), the carrying capacity of the environment, and how the proportion of extractable resources maybe limited. Using visual imagery, we calculate the average conventional well site footprints to be 10,800 m2 in the UK, 44,600 m2 in The Netherlands and 3000 m2 in Poland. The average area per well is 541 m2/well in the UK, 6370 m2/well in The Netherlands, and 2870 m2/well in Poland. Average access road lengths are 230 m in the UK, 310 m in The Netherlands and 250 m in Poland. To assess the carrying capacity of the land surface, well pads of the average footprint, with recommended setbacks, were placed randomly into the licensed blocks covering the Bowland Shale, UK. The extent to which they interacted or disrupted existing infrastructure was then assessed. For the UK, the direct footprint would have a 33% probability of interacting with immovable infrastructure, but this would rise to 73% if a 152 m setback was used, and 91% for a 609 m setback. The minimum setbacks from a currently producing well in the UK were calculated to be 21 m and 46 m from a non-residential and residential property respectively, with mean setbacks of 329 m and 447 m, respectively. When the surface and sub-surface footprints were considered, the carrying capacity within the licensed blocks was between 5 and 42%, with a mean of 26%. Using previously predicted technically recoverable reserves of 8.5 × 1011 m3 for the Bowland Basin and a recovery factor of 26%, the likely maximum accessible gas reserves would be limited by the surface carrying capacity to 2.21 × 1011 m3.

The differential interferometric synthetic aperture radar (DInSAR) remote sensing technique has proven to be invaluable in the remote monitoring of earth surface movements associated with the extraction and geostorage (subsurface injection) of natural resources (water, oil, gas). However, a significant limitation of this technique is the low density and uneven coverage that may be achieved over vegetated rural environments. The Intermittent Small Baseline Subset (ISBAS) method, an amended version of the established SBAS algorithm, has been designed to improve coverage over rural, vegetated, land cover classes by allowing for the intermittent coherence that is predominant in such areas. In this paper we perform a validation of the ISBAS method over an area of gas production and geostorage in North Holland, the Netherlands. Forty-two ERS-2 (SAR) C-band images (1995–2000) and 63 ENVISAT (ASAR) C-band images (2003–2010) were processed using the ISBAS technique and the derived measurements enabled the identification of subsidence patterns in rural and urban areas alike. The dominant feature was an area of subsidence to the west of Alkmaar, attributed to natural gas production from the Bergermeer reservoir, where subsidence rates in the region of 3 mm/year were measured. Displacements derived using linear and non-linear surface deformation models were validated with respect to the first order system of levelling benchmarks which form the Amsterdam Ordnance Datum (NAP). It was established that ISBAS products were accurate to within 1.52 mm/year and 1.12 mm/year for the ERS and ENVISAT data sets respectively. Errors achieved were comparable to results using persistent scatterers interferometry (PSI) during a validation activity carried out in the European Space Agency Terrafirma project. These results confirm the capability of the ISBAS method to provide a more regular sampling of land motion measurements over gas fields that may be critically used in future to infer the properties of buried, fluid-filled, porous rock.

Deep geothermal exploration in the UK in the 1980s resulted in only one operative borehole (in Southampton). In 2004, a 995 m deep borehole was drilled into the Weardale granite in County Durham. This project differed markedly from the earlier ‘hot dry rock’ investigations in the granites of Cornwall, in that it deliberately targeted possible high natural permeability derived from large fault zones. The new approach met with success, discovering what is believed to be the highest natural permeability ever found in granite anywhere in the world. Drilling of a second borehole at Eastgate in 2010 confirmed that high permeability is preferentially associated with major west–east geological faults. Further deep drilling is now targeting similar faults cutting nearby sedimentary sequences. Meanwhile, renewed interest is being shown in Cornish prospects, as well as in previously unexplored resources in Scotland and Northern Ireland. There is also significant interest in the possible geothermal exploitation of hot brines, which are co-produced with hydrocarbons in existing oilfields. Technological advances in directional drilling, reservoir stimulation and power generation using binary-cycle turbine plants are finally making deep geothermal energy a realistic target for full-scale development in the UK.

Analytical solution for Joule–Thomson cooling during CO 2 geo-sequestration in depleted oil and gas reservoirs Simon A. Mathias a *, Jon G. Gluyas a , Curtis M. Oldenburg b , Chin-Fu Tsang b b Department of Earth Sciences, Durham University, Durham, UK Earth Sciences Division, Lawrence Berkeley National Laboratory, Berkeley, CA, USA a ABSTRACT Mathematical tools are needed to screen out sites where Joule Thomson cooling is a prohibitive factor for CO 2 geo- sequestration and to design approaches to mitigate the effect. In this paper, a simple analytical solution is developed by invoking steady-state flow and constant thermophysical properties. The analytical solution allows fast evaluation of spatiotemporal temperature fields, resulting from constant-rate CO 2 injection. The applicability of the analytical solution is demonstrated by comparison with non-isothermal simulation results from the reservoir simulator TOUGH2. Analysis confirms that for an injection rate of 3 kgs−1 (0.1MTyr−1) into moderately warm(>40°C) and permeable formations(>10 −14 m 2 (10 mD)), JTC is unlikely to be a problem for initial reservoir pressures as low as2 MPa (290 psi). Keywords: Joule–Thomson cooling Geologic carbon sequestration Depleted gas reservoirs 1. Introduction Depleted oil and gas reservoirs (DOGRs) represent a significant portion of the global portfolio of target formations currently under consideration for CO 2 geo-sequestration (Benson and Cook, 2005). There are two major advantages associated with DOGRs:(1) they have been extensively characterized during exploration, appraisal and production; (2) they are already proven as potentially long- term traps for buoyant fluids owing to their ability to store oil and gas over tens to hundreds of millions of years(Maloney and Briceno, 2009). However, low pore-pressures, characteristic of depletion- drive reservoirs at cessation of production, will lead to significant Joule–Thomson cooling (JTC) when large pressure gradients are developed due to CO 2 injection. JTC is the name given to the drop in temperature that occurs when a real gas such as CO 2 expands from high pressure to low pressure at constant enthalpy (i.e., adiabatic expansion) (see Oldenburg, 2007b, for further detail). Of particular concern is the severe loss of injectivity that may develop due to freezing of pore fluids (e.g., native brine)and/or the generation of CO 2 or CH 4 hydrates, effectively rendering the injection well dysfunctional (Oldenburg, 2007b). Mathematical tools are needed to identify and evaluate sites where JTC is a prohibitive factor for CO 2 geo-sequestration and to aid in the design of approaches to mitigate the effect. Previously JTC during CO 2 geo-sequestration has been explored using laboratory experiments (Maloney and Briceno, 2009) and numerical simulation (Oldenburg, 2007a; Bielinski et al., 2008; Andre et al., 2010). For wider accessibility and application, analytical solutions are preferable, especially those that can be implemented in simple spreadsheet software (e.g. Oldenburg, 2007b; Mathias et al., 2009a,b). Unfortunately, analytical solution of the full JTC problem is not possible due to the non-linear coupling between the associated fluid flow and thermal transport equations. However, for the low pressures of interest, the Joule–Thomson coefficient for CO 2 remains relatively constant (see Andre et al., 2010, Fig. 1). It is therefore hypothesized that meaningful results can be obtained when thermophysical properties are assumed constant and uniform. In this paper, a simple analytical solution is developed by invoking steady-state flow and constant thermophysical properties. The analytical solution allows fast evaluation of spatiotemporal temperature fields resulting from constant-rate CO 2 injection. The applicability of the analytical solution is demonstrated by comparison with fully coupled and transient non-isothermal simulation results from the reservoir simulator TOUGH2/EOS7C (Oldenburg et al., 2004a). Sensitivity analysis of the analytical solution is explored to provide insight into the importance of JTC for DOGRs. 2. The mathematical model Consider the constant-rate injection of fluid from a fully penetrating injection well into an infinite, homogenous and isotropic, insulated and confined formation. As mentioned previously, for the low pressures of interest, the Joule–Thomson coefficient for CO 2 remains relatively constant. It is therefore hypothesized that meaningful results can be obtained when thermophysical properties are

Injecting CO2 into deep saline formations represents an important component of many greenhouse-gas-reduction strategies for the future. A number of authors have posed concern over the thousands of injection wells likely to be needed. However, a more important criterion than the number of wells is whether the total cost of storing the CO2 is market-bearable. Previous studies have sought to determine the number of injection wells required to achieve a specified storage target. Here an alternative methodology is presented whereby we specify a maximum allowable cost (MAC) per ton of CO2 stored, a priori, and determine the corresponding potential operational storage capacity. The methodology takes advantage of an analytical solution for pressure build-up during CO2 injection into a cylindrical saline formation, accounting for two-phase flow, brine evaporation, and salt precipitation around the injection well. The methodology is applied to 375 saline formations from the U.K. Continental Shelf. Parameter uncertainty is propagated using Monte Carlo simulation with 10 000 realizations for each formation. The results show that MAC affects both the magnitude and spatial distribution of potential operational storage capacity on a national scale. Different storage prospects can appear more or less attractive depending on the MAC scenario considered. It is also shown that, under high well-injection rate scenarios with relatively low cost, there is adequate operational storage capacity for the equivalent of 40 years of U.K. CO2 emissions.

We review the distribution, timing and probable causes of ∼8000 onshore UK seismic events between the years 1970–2012. Of 1769 onshore seismic events with local magnitudes (M L ) ≥ 1.5, we estimate at least ∼21% of these have an anthropogenic origin, at least ∼40% were natural and ∼39% have an undetermined, anthropogenic or natural origin. The majority of the anthropogenic related earthquakes were caused by coal mining and the decline in their numbers from the 1980s to the 2000s was concurrent with a decline in UK coal production. To date, two earthquakes with M L ≥ 1.5 have been caused by hydraulic fracturing. We have a high level of confidence that the mean number of anthropogenic related earthquakes (M L ≥ 1.5) per year onshore in the UK since 1999 is at least three with an annual range of between zero and eight. If we assumed that 50% of the undetermined events had an anthropogenic origin the mean per year increases to twelve. Although there are inherent uncertainties in assigning an anthropogenic versus natural cause for historical earthquakes, these values provide a baseline for the UK, the first of its kind for any nation state, in advance of the presently planned shale gas and oil exploitation.

Capture of carbon dioxide emissions from industry and their subsequent storage deep below the Earth's surface in porous rocks has great potential for reducing the release of greenhouse gases into the atmosphere. Carbon capture and storage (CCS) could provide humankind with a plausible transition to a low carbon economy without having to suddenly stop use of fossil fuels. A prerequisite for geostorage of carbon dioxide is determination of storage capacity, of a potential site, a geological province or indeed for a whole country. The approach to calculation of the resource (available pore space) for carbon dioxide storage shares much in common with the process used to estimate oil, gas, or indeed aquifer water volume. The calculation involves the following stages: measurement of gross rock volume, calculation of net (porous) rock volume, calculation of void space, and finally determination of how much of the void space could be filled with carbon dioxide. The accuracy with which the first three calculations can be made is determined by the quantity and quality of the data available. Typically, gross rock volume is not measured directly but instead combines geographic location data with time domain information from seismic reflection surveys then subject to interpretation of the horizons of interest. Net to gross and porosity tend to be measured very accurately for individual wells or parts of wells but as formation architecture is both heterogeneous and anisotropic, further uncertainties are introduced in the upscaling process from single or multiple wells to field (storage site). However, the most difficult step in the calculation is the final one; what proportion of the void space can be occupied by CO2? Theoretically, the whole of the pore space could be occupied by CO2, but in practice, it will not be possible to remove all of the water or petroleum from a system used for carbon storage. Some of the existing fluids (water or petroleum) will not be displaced. For a regional assessment of storage capacity, here has been a tendency to use an “efficiency factor”—that is a very small number which when applied to the large pore volume calculated gives a plausible storage volume! The calculation may also be subject to numerical simulation in an adaptation of the same approach used by (petroleum) reservoir engineers. Efficiency factors of a small percentage or less are the norm. For an individual, well-characterized site, it is likely to be possible to fill a much greater portion of the pore space. Observations in CO2-enhanced oil recovery (EOR) projects have indicated that it may be possible to displace 40% or more of the pore fluids. Indeed, it is the potential for enhanced oil (and gas) recovery which may drive our understanding of the displacement process. EOR projects are more likely to get funded in the short term because they generate a revenue stream. In addition to storage of CO2 in conventional reservoirs, options exist for storage and/or sequestration in unconventional reservoir systems (shales, coals, and fractured basement rocks). Keywords: CO2; storage; geological; subsurface; permeability; resevoir; carbon; capacity

In New Year 1938, the Edale No. 1 oilwell was drilled in the English Pennines. The target for the well was folded Lower Carboniferous limestone. This target was believed to be analogous both for trap and reservoir, to the giant oil accumulations of Iran (then Persia). The well failed. Poor gas shows were recorded at a depth of 126feet. This gas flowed at a rate of 4000ft3 day−1. There were also minor indications of brown and green oil but no commercial production. Trap and seal were proven. Local seepage also proved the existence of a working source. Reservoirwas however missing. The well was drilled outwith the play fairway. Instead of penetrating massive, porous shelf limestones the well encountered thin shaley limestones, today interpreted as deep water, gravity flow deposits. This paper recounts the geological work done before and during drilling of the well. The data, in the form of a prospect evaluation memorandum, are from the BP Exploration archive.

The number of wells required to dispose of global CO2 emissions by injection into geological formations is of interest as a key indicator of feasible deployment rate, scale and cost. Estimates have largely been driven by forecasts of sustainable injection rate from mathematical modelling of the CO2 injection process. Recorded fluid production rates from oil and gas fields can be considered an observable analogue in this respect. The article presents statistics concerning Cumulative average Bulk fluid Production (CBP) rates per well for 104 oil and gas fields from the UK offshore region. The term bulk fluid production is used here to describe the composite volume of oil, gas and water produced at reservoir conditions. Overall, the following key findings are asserted: (1) CBP statistics for UK offshore oil and gas fields are similar to those observed for CO2 injection projects worldwide. (2) 50% probability of non-exceedance (PNE) for CBP for oil and gas fields without water flood is around 0.35 Mt/yr/well of CO2 equivalent. (3) There is negligible correlation between reservoir transmissivity and CBP. (4) Study of net and gross CBP for water flood fields suggest a 50% PNE that brine co-production during CO2 injection could lead to a 20% reduction in the number of wells required.

The accurate prediction of reservoir quality is, and will continue to be, a key challenge for hydrocarbon exploration and development. Prediction is a logical and critically important extension of the description and interpretation of geological processes. However, in spite of the profusion of publications on sandstone and carbonate diagenesis, relatively few articles illustrate the application of such studies to reservoir quality prediction. This Memoir represents the first attempt to compile worldwide case studies covering some predictive aspects of both siliciclastic and carbonate reservoir characteristics. We have attempted here to focus on the variability due to diagenetic effects in sandstones and carbonates, rather than on sedimentological effects, i.e., the presence or absence of a given reservoir. The chapters cover the spectrum of stages in the explorationexploitation cycle (Table 1). The importance of reservoir quality in pay evaluation has been illustrated by Rose (1987), who analyzed an unnamed company's exploration results over a 1-year period. Of 87 wildcat wells drilled, 27 were discoveries (31 % success rate); incorrect predictions of the presence of adequate reservoir rocks were made in 40% of the dry holes. Importantly, the geologists believed that reservoir quality was the primary uncertainty in 79% of the unsuccessful wells. Similarly, a comparison of predrill predictions with postdrill results by Shell (Sluijk and Parker, 1984) indicated that reservoir quality was seriously overestimated, whereas hydrocarbon charge and retention predictions were more accurate. Although these statistics do not clearly separate drilling failure due to lack of potential reservoir from the lack of adequate reservoir quality, it seems that although explorers are aware of the significance of reservoir quality prediction, generation of predictive models continues to be a formidable task.