Geoenergy - Volume 2, Issue 1, 2024

The Lower Triassic Bunter Sandstone Formation is a major prospective reservoir for carbon capture, utilization and storage in the UK Southern North Sea, and is likely to play a pivotal role in the UK reaching mid-century Net Zero targets. A knowledge gap in reservoir quality exists between previous detailed, but highly focused front-end engineering and development projects, and large-scale regional analysis. This study integrates a regional approach with locally derived reservoir characterization, offering a holistic analysis of the prospectivity of the Bunter Sandstone Formation for subsurface CO2 storage. Petrophysical analysis of ninety-six wells across the UK Southern North Sea is coupled with seismic interpretation to understand spatial variations of reservoir thickness, facies and quality that underpin theoretical CO2 storage capacity models. Electrofacies classification is employed to identify and correlate baffles and barriers to permeability over areas currently licensed for geological carbon storage. Our findings point to variable, but broadly favourable reservoir conditions, though identification and correlation of laterally extensive intraformational mudstones and halite-cemented horizons will likely present challenges to CO2 injection. Within carbon storage license blocks CS001, CS006 and CS007, the Bunter Sandstone Formation has the potential to store 5700 MCO2t, the equivalent of seventy-nine years of the UK's 2022 business and industrial CO2 emissions. A further 434 MCO2t is offered by Triassic closures within license CS005, with many neighbouring moderate (100–1000 MCO2t) and small (<100 MCO2t) closures forming part of newly awarded carbon storage licenses that will likely form part of the UK SNS CCUS portfolio in the future.

Supplementary material: well-correlation panels and tabulated velocity and storage capacity modelling parameters are available at https://doi.org/10.6084/m9.figshare.c.7027450

With the global drive for net-zero emissions, it has never been more important to find clean energy sources. There are thousands of abandoned oilfields worldwide with the potential to be reactivated to produce clean energy with air injection and subsequent waste fluid sequestration. Air injection, and the development of a fire-front, may be used with enhanced geothermal systems by taking advantage of the inherent increase in heat and pressure. Conventionally used as an enhanced oil recovery technique, air injection has gained the reputation of being a high-risk intervention due to the many failures in its history. Knowledge of how petrophysical rock properties and oil physical and chemical properties control the consequences of air injection is key to optimzing the selection of late-life, or even abandoned oilfields for use in such systems. Here we use one-dimensional modelling to test the effect of varying porosity, permeability, oil viscosity and API gravity on the success of air injection. Modelling shows that the most important factor controlling temperature is the porosity of the reservoir, followed by the API gravity and then the viscosity of the oil. The most important factors controlling velocity of the fire-front are API gravity followed by oil viscosity. We show that reservoirs with high porosity and low permeability with high viscosity and low API gravity oil reach the highest fire-front temperatures. The significance of this work is that it provides several geoscience-related criteria to rank possible candidate reservoirs for reactivation and clean energy generation via air injection: the best candidates will have the highest total porosity, relatively low permeability, highest oil viscosity and lowest API gravity, such fields can then move on to bespoke and more complex simulations.

Assessments of fault geometries and fault-risk parameters are crucial when evaluating the integrity of a structurally controlled CO2 storage site. To perform these assessments, seismic data, recorded in time, must be converted to depth. The velocity models used for this time to depth conversion influence the final depth image and, consequently, the geometry of the interpreted faults. Against this background, we created four velocity models for depth conversion, assessed the impact on fault throw, dip and thickness of the primary seal, and, subsequently, a fault-risk assessment of the Vette Fault Zone in the Smeaheia CO2 storage site. We found that depth conversion had a larger influence on fault throw and thickness of the primary seal than on fault dip. In contrast, the overall assessment of the presence of a membrane seal and geomechanical integrity showed less sensitivity to the depth conversion process. Consequently, we suggest that a relatively robust fault-risk assessment can be made with a variety of velocity model designs and data input. Nevertheless, we found a mean difference of 2% in the shale gouge ratio, 4% in the slip tendency and 9% in the dilation tendency for the Vette Fault Zone, emphasizing the importance of accounting for the influence of depth conversion in optimizing structural assessments in potential CO2 storage sites.

In the present study, different geocellular models of meander-belt stratigraphic architectures were produced that are representative of the sedimentary products of sand-bed meandering rivers and their petrophysical heterogeneity. The static models were created by combining a rule-based stratigraphic modelling approach with geostatistical modelling, and were applied in groundwater-flow and heat-transport simulations using MODFLOW-2005 and MT3D-USGS software. Overall, histories of injected cold-water plume propagation were examined considering: (i) three architectural frameworks as representative of different river morphodynamics; (ii) four scenarios of facies architecture; and (iii) alternative well layouts. The presence, size and spatial distribution of sedimentary heterogeneities related to river hydrodynamics, channel-form abandonment or modes of meander-transformation are seen to control the shape of the thermal plume, thereby affecting well-doublet performance. The considered scenarios of facies make-up for point-bar deposits have a modest influence on the temperature decline near the abstraction well. The presence of sandstone beds in the lower heterolithic parts of abandoned-channel fill does not facilitate significant thermal-plume expansion beyond the mud-plug. The effect of basal lags made of open-framework conglomerates on heat advection depends on their geometry but is effectively negligible when it makes up less than 1% of the deposits. Relatively thin mud drapes lying on point-bar accretion surfaces are seen to act as baffles to flow but their impact is minimal in view of their small number. The study provides useful and novel insights into the potential impact of sedimentary heterogeneity in fluvial reservoirs, which can be applied to the design of well doublets and to highlight areas that deserve further investigations.

Energy from Earth resources (geoenergy) in the form of coal, oil and gas has fuelled the global society since the Industrial Revolution began. Amongst the consequences of fuelling society and associated population growth, is climate change, driven by the emission of greenhouse gases liberated through unabated combustion of fossil fuels.

There is much more to Earth energy systems, however, than just coal oil and gas. The Earth contains, in human terms, an unlimited supply of accessible heat and pressure (differences), as well as copious quantities of storage space, non-hydrocarbon gases and valuable solutes. These resources can be targeted to provide sustainable energy sources with low to zero carbon footprints.

This report does not contain any new radical technologies that will deliver energy free from all environmental impacts but it does show that, when considering geoenergy, society needs to look at the whole system, which combines chemical, thermal, potential, kinetic, gravitational and other energy forms that could be used from individual developments to minimize waste, maximize efficiency and reduce unwanted impacts.

We demonstrate that geoenergy will continue to play a key role in decarbonized energy systems for centuries to come.

In the context of Carbon Capture and Storage (CCS), monitoring the behaviour of CO2 within subsurface reservoirs is pivotal for efficient and safe storage operations. This study proposes a new approach to enhance the accuracy of predicting CO2 saturation maps directly from shot gathers, using a combination of deep learning (DL) and feature extraction methods. We employ a U-Net model, specifically tailored to solve regression tasks, and two-dimensional continuous wavelet transform (2D-CWT) to analyse shot gathers at different scales. We introduce a novel approach using multi-channel input data for the DL model, combining shot gathers and CWT images. The DL model was trained and tested using both single channel and multichannel input. The single channel datasets included shot gathers and CWT images at the first scale, while the multi-channel datasets integrated shot gathers with either two or four scales of CWT. We conducted a sensitivity analysis on the number of training epochs to compare the performance of the model with multichannel and single channel input. Additionally, a Transfer Learning approach was implemented to improve performance in noisy conditions by leveraging knowledge from a pre-trained model on noise-free images. Monte Carlo dropout was used to predict pixel-scale variability and provided a prediction variability with a standard deviation ranging from 0.019 to 0.194, enhancing the robustness of CO2 saturation estimates. Our results suggest that combining feature extraction using 2D-CWT with the U-Net architecture improves the prediction performance of CO2 saturation in a synthetic CCS model. Additionally, using multi-channel input instead of single channel is more efficient as it requires less training and prediction time to achieve comparable results. This confirms the effectiveness of 2D-CWT as a pre-processing technique, contributing valuable insights and advances in the field of data-driven geophysical inversion problems.

The temporal and spatial scale of interest of CO2 storage studies lies in between reservoir and basin models. While reservoir modelling software is best fitted to address some of the multiphysics issues related to the behaviour of CO2 once injected into the subsurface (adsorption, dissolution, near injection wellbore mechanics and temperature, and, in some cases, fluid rock interaction) within a human timescale, basin modelling tools handle better the full basin volume and time-scale heterogeneities that impact the storage potential and risk associated with CO2 injection. This study takes a basin modelling approach to provide an assessment of the influence of geological evolution on CO2 storage capacity, both at the reservoir level, by helping to estimate the amount of CO2 that can be stored in its connected porosity, and at the cap-rock level, by assessing the seal integrity. Our basin model also captures the evolution of the pressure plume induced by the CO2 injection, taking into account the pressure and temperature fields, aquifer connectivity and permeability, and seal integrity, on a much shorter timescale than is usually considered by such a model. The results show the impact of basin evolution on aquifer properties and consequently on the dissipation of the induced pressure plume. They also highlight the large-scale influence of the CO2 on the pressure field both vertically along the stratigraphic column, when the pressure plume reaches shallower aquifers through unconformities, and horizontally, when good aquifer injectivity and connectivity allows the pressure plume to dissipate widely.

Carbon capture and storage (CCS) requires the safe, long-term storage of CO2 in the subsurface. This challenges subsurface practitioners to build on and adapt many of the techniques and processes developed for hydrocarbon exploration and production to create innovative approaches to assessing CO2 storage risk and uncertainty. A wide-ranging and integrated understanding of the processes controlling CO2 behaviour in the subsurface is required to facilitate effective risk identification and characterization.

In this paper we explore the different physical processes acting within storage formations and their evolution throughout the injection project life cycle to illustrate key controls on CO2 plume behaviour and frame risk identification and characterization. An approach applying wide-reaching premortem risk identification coupled with evidence-led uncertainty characterization is described to frame inputs for detailed risk characterization and management activity during early screening of prospects for CO2 storage.

The Endurance saline aquifer CO2 store in the UK North Sea is the planned storage site for CO2 emissions that will be captured from the East Coast Cluster. The site has been characterized to assess its suitability for injectivity, containment and capacity. The injection target is the Early Triassic Bunter Sandstone Formation, consisting of fine-grained sandstones deposited in fluvial, lacustrine and playa lake environments that were subject to repeated aeolian and fluvial reworking. The sandstones have excellent reservoir quality and are likely to be well connected due to the lack of preserved heterolithic layers. The trap is a large, four-way dip-closed anticline, sealed by mudstones and evaporites of the Middle Triassic Dowsing Formation. The top seal sediments are laterally extensive and geomechanically strong, and faulting observed in the overburden does not appear to connect to the reservoir, providing confidence that CO2 containment will be secure. The risk of leakage through existing legacy wells is assessed as low. The maximum effective CO2 storage capacity is c. 450 Mt: Phase 1 development of 100 Mt is equivalent to a storage efficiency factor of 3%, which is achievable without the need for brine production. First injection is planned from 2027.

The Northern Lights full-scale commercial CO2 transport and storage project is open to multi-industry capture plants, in a business still under development. The geological sequestration concept of a sloping saline aquifer raised several subsurface challenges related to timeline, data availability and development constrains, which all affected the decision process. The subsurface focus on storage security required the different disciplines to perform adjustments to the established workflows available from the hydrocarbon industry. A risk management-focused approach, front-end loading and early emphasis on containment were paramount. Here we share the experience from the Northern Lights subsurface maturation process and highlight the crucial contribution from the different disciplines in a challenging new industry.

A key aspect of transferrable oil and gas expertise to subsurface CO2 storage (SCS) relates to risk assessment. While initial subsurface risk and volume assessments for SCS projects are similar to oil and gas prospect evaluations, full life-cycle risk assessment requires evaluation of the current knowledge of the storage complex and future potential events that may have impacts over long time frames. It is important to learn from past water, gas, and CO2 injection and storage projects, examples of which are reviewed here. The concepts of aleatory and epistemic risk and uncertainty are discussed, and the use of standard risk matrices for evaluation of long-term, low-frequency but potentially high-impact events is challenged. Drawing on the large volume of previous work, this paper highlights key elements for development of a robust risking framework, including thorough project framing and implementation of a staged approach to project execution. The paper assesses methods for ensuring all potential hazards are captured and addresses the challenges of defining a quantitative risking scale suitable for long-term SCS projects. Example quantitative risk profiles can be used to calculate the timing and duration of ‘Peak Risk’, augment monitoring and mitigation planning for management of risk and capital exposure, and help to ensure successful project outcomes.

Thematic collection: This article is part of the Geoscience workflows for CO2 storage collection available at: https://www.lyellcollection.org/topic/collections/geoscience-workflows-for-CO2-storage

In August 2022, the world's longest running offshore industrial CO2 injection project celebrated its 26-year anniversary. During these years, the Sleipner CO2 injection project has been invaluable in demonstrating that offshore CO2 storage is feasible, safe, and efficient. We will here show how time-lapse seismic monitoring of the CO2 plume development has revealed depositional architecture in the Utsira Formation, and how thin mudstone layers have contributed to distributing the CO2 in a larger rock volume, promoting trapping by dissolution. The relatively shallow depth (800–1000 m) of Utsira Formation in the Sleipner area also makes the Sleipner CO2 injection site a good proxy for understanding the effects of overburden stratigraphy for deeper injection sites, giving important knowledge of detectability of thin, shallow CO2 accumulations. Finally, we will show how the experience from Sleipner CO2 injection has built confidence when planning monitoring programmes for future CO2 injection sites.

Hydrogen is an energy carrier that can balance the divergent variations in seasonal energy demand and energy supply from renewables. Underground hydrogen storage in porous formations, such as depleted gas sandstone reservoirs or saline aquifers, provides the capacities needed for large-scale, long-duration energy balancing. This paper reports on the fundamental behaviour of hydrogen in a model reservoir setup, involving a two-phase (H2, water) system and a two well (injector, producer) setup placed at different depths in the reservoir. We specifically focus on the impact of natural heterogeneities, and associated permeability contrasts, on flow and efficacy of hydrogen injection and production. We found that positioning the wells, both injector and producer, at the top of the reservoir facilitates the highest hydrogen production. We also found that permeability contrasts of three to four orders of magnitude significantly affect hydrogen flow; however, factors affecting the pressure gradient also need to be considered. These factors include compartmentalization, the behaviour of co-existing fluids and the localized pressure gradient created by the hydrogen plume. Our research underlines the need to understand the architecture of the whole reservoir, from seismic to sub-seismic scales, not just the zones surrounding the wells and pathways in-between, as this controls capacity, pressure fluctuations and informs operational management decisions.

Thematic collection: This article is part of the Hydrogen as a future energy source collection available at: https://www.lyellcollection.org/topic/collections/hydrogen

Several sources of natural hydrogen are known or postulated but the process of serpentinization, the action of water on ultramafic rocks, is shown to be the most effective. Studies indicate that the rates and volumes generated by high-temperature serpentinization, (i.e. in the temperature range of 200–320°C), could feed a focused hydrogen system potentially capable of sealing and trapping gas-phase hydrogen in commercially-sized accumulations.

Natural hydrogen is generated by serpentinization wherever ultramafic rocks can be penetrated by aqueous fluids. This includes diverse geotectonic settings ranging from divergent and convergent plate margins to intra-plate orogenic belts and Precambrian cratons.

The ‘hydrogen system’ describes the generation, migration and sealing/trapping of hydrogen. There are two parts to the ‘generic hydrogen system’: the ‘source-generation sub-system’ requires an ultramafic protolith, usually in basement, and a supply of water penetrating basement rocks. In the ‘migration-retention sub-system’ migration, sealing and entrapment of gas-phase hydrogen behaves the same as for hydrocarbon gases.

The hydrogen system by serpentinization is used to develop play models to guide exploration in the accessible and exploitable geotectonic settings of continental cratons, ophiolites and convergent margins.

Thematic collection: This article is part of the Hydrogen as a future energy source collection available at: https://www.lyellcollection.org/topic/collections/hydrogen