Accurate monitoring of injected CO₂ plumes is an important tool for ensuring the success and safety of carbon capture and storage (CCS) operations. While seismic monitoring and flow forecasting are established tools for managing storage sites, field-based studies come with limitations in terms of costs, uncertainties and logistical constraints. Laboratory experiments provide a valuable complementary approach by enabling precise experimental controls and real-world physics with a high degree of customization. Here, we present a new laboratory facility designed for lab-scale seismic monitoring of CO₂ storage. The setup includes a downscaled (1:2000) replica of the Utsira Formation caprock in the Sleipner CO₂ storage site, monitored with an ultrasonic system of 128 transducers, functioning as both sources and receivers. Using air as a proxy for CO₂, “4D seismic” data were acquired and processed using conventional reflection seismic techniques. The results demonstrate successful detection of the gas plume evolution and topographic imaging of the aquifer top-layer. Furthermore, the facility enables direct testing of novel seismic techniques and plume monitoring strategies under highly controlled and flexible conditions, offering a scalable and adaptable platform for future CCS research.

Injection of dense-phase CO2 in a saline sandstone aquifer involves several processes which ideally work together to ensure effective long-term storage. The main processes are flow of free-phase CO2 (controlled by viscous and gravity forces), residual trapping at the pore scale, structural trapping at the scale of geological heterogeneities and dissolution in the aqueous phase. Assessment of possible lateral and vertical migration along high-permeability layers or faults and fractures will also require stress-sensitive flow models which consider the phase behaviour of CO2, and the associated coupled thermal-hydraulic-mechanical-chemical processes.Many insights into these complex processes can be obtained by analysis of the time-lapse seismic data at Sleipner CO2 storage project in Norway, in conjunction with findings derived from the quantitative and qualitative uncertainty analysis of the medium-scale flow experiments at the Mont Terri Rock Laboratory (Switzerland), involving periodic injections over long-term (CO2LPIE). The insights at Sleipner include the effects of internal shale layers and shale breaks in controlling the actual multi-layer CO2 distributions, the likely contribution of different of trapping mechanisms and the effectiveness of the overlying caprock. Another set of insights gained from these data are estimates of the effective use of the pore space at different length scales. The seismic imaging datasets can be used to show that at the scale of whole storage unit the overall storage efficiency is in the range of 2-5%, with the result depending very much on how the storage volume is defined. When the effects of areal and vertical sweep efficiency are considered, the fraction of the pore space occupied by CO2 rises to around 40-50%.We illustrate these multi-scale processes using seismic data, analytical analysis, example flow models and 3D/4D visualization. Use of Invasion Percolation (IP) flow models is contrasted with multiphase (finite difference) flow simulators. With this approach CO2 migration problems will be addressed, as well as various open-source research codes will be used to develop enhancements for handling fluid mixing between hydrocarbon and CO2 phases in brine-saturated media. Moreover, coupled thermal modelling is found to be important at this site due to significant temperature changes as the CO2 plume expands and rises within the formation. Next to classic PC screen display, we empower the visualization by using the extended reality (XR) platform for geoscience, BaselineZ. This allows for true 3D (holographic) display in virtual reality (VR) as well as remote and interactive collaboration around the Sleipner dataset and thus leads to new insights.

Capillary heterogeneity has been identified over the last decade as a key control on subsurface CO2 flow behavior during geological CO2 sequestration. These heterogeneities can be formed in all sedimentary rocks, ranging from slight variations in the sand grain sizes to extensive sequences of interbedded sands, shales, and limestones. Capillary heterogeneity has been largely, although not entirely, overlooked in subsurface flow modeling because it is assumed to only directly influence fluid redistribution over scales of centimeters to meters. However, even small-scale fluid movements can result in dramatic impacts on the mobility and trapping of CO2 over kilometers. Therefore, neglecting capillary heterogeneity at multiple scales could potentially lead to errors in modeling and predicting field-scale plume migration. In this review paper, we aim to provide a consistent overview to (1) establish that capillary heterogeneity can have a major impact on CO2 plume migration, (2) establish the respective length scales at which capillary heterogeneity matters, and (3) provide guidance for numerical modeling.This review covers pertinent literature and extracts key observations from core to field scales. Experimental studies have shown that millimeter-decimeter scale capillary heterogeneity can cause the so-called capillary heterogeneity trapping in addition to pore-scale residual trapping. Even at such a small scale, capillary heterogeneity can already lead to complex upscaled constitutive relationships, such as flow-rate dependent and anisotropic relative permeability, which affects field-scale CO2 migration even when field-scale heterogeneities are present. Under gravity-dominated flow regimes, centimeter-meter scale capillary heterogeneity can entrap a significant amount of CO2 at the field scale, not only after imbibition but also during drainage. In certain cases, the presence of capillary heterogeneity can even completely stop the vertical movement of the CO2 plume, hence greatly reducing leakage risks. At the meter-kilometer scale, the influence of capillary heterogeneity is more pronounced and can hinder or redirect CO2 migration in both lateral and vertical directions.The impact of capillary heterogeneity across multiple spatial scales poses a great challenge in modeling CO2 migration at the field scale, because it is practically impossible to build a field-scale earth model with grid blocks at the millimeter scale. We recommend a hierarchical modeling approach to address this challenge. At the field scale, earth models are built to capture geological features and heterogeneities in high but still practical grid resolutions. For each facies or rock type in the field-scale model, high-resolution meter-scale “conceptual” models are built using millimeter-scale grid blocks to capture representative fine-scale bedding geometries and heterogeneities in various depositional environments, thereby bridging the gap between the subcore scale and the size of a field-scale simulation grid block. Upscaling is then used to preserve the smaller-scale flow dynamics of various rock types in field-scale simulations. Future work is needed to (1) refine, improve, and validate the hierarchical modeling approach; (2) build libraries of fine-scale bedding models for facies in various environments of deposition; (3) quantify multiscale capillary heterogeneity effects under subsurface uncertainties; (4) gain learning from different storage formations; and (5) establish best practices that balance accuracy and computational speed.

Summary Seismic monitoring plays a key role in carbon capture and storage projects, offering evidence into the distribution of the injected CO2 and verifying its containment within the aquifer. Owing to the subsurface permeability variations and the complex fluid dynamics of CO2, injected CO2 may adopt complex multi-tiered configurations, posing challenges for its accurate imaging when relying only on the reflected wavefield. Leveraging the complete seismic wavefield, comprising reflections and transmissions, provides an alternative for improving the monitoring of these complex CO2 systems. In this study, we use vintage pre-stack seismic data acquired in 2010 over the Sleipner CO2 Storage site in the North Sea, to demonstrate the potential of full-waveform inversion (FWI) as a tool for monitoring CO₂ sequestration. Despite the limitations of this legacy dataset, comprising a maximum offset of 6 km, our study demonstrates the value of FWI in capturing the significant slow-down within the CO2 layers, and revealing CO2 migration pathways. These aspects are important for effective sequestration monitoring and the forecasting of CO2 migration over time. Furthermore, FWI holds the promise of improving conformance monitoring and estimation of CO2 mass within the aquifer, thus becoming a valuable asset in carbon capture and storage monitoring programs.

Summary Detecting thin layers of CO₂ and their detection on a multi-layer setting are key objectives in carbon sequestration monitoring projects. Diving-wave time-lapse analyses offer a complementary tool to reflection time-lapse analyses and have the potential for improving CO₂ detection for multi-layer plume geometries. We present an analytical approximation to the diving-wave time-lapse delay due to a thin layer of CO₂ encased in a sedimentary medium where the velocity increases linearly with depth. The approximation can be used to gain insight on CO₂ detection limits using diving waves and can aid the design of seismic acquisition systems for CO₂ storage monitoring. The diving-wave delay can be exploited by advanced monitoring methods such as Full-waveform inversion (FWI) to improve CO₂ migration monitoring. We compare the benefits of using different parts of the wave-field via acoustic FWI for CO₂ thin-layer detection on a multi-layer setting. The inversion using diving waves and reflections is able to reconstruct the low-frequency trend for the thin CO₂ layers, enabling detection and recovery of the true depth for all layers in the plume. The low-frequency reconstruction is not possible with reflection data only, resulting in poorer detection for deep complex regions within the plume, and yielding a depth increasing error in the depth of the CO₂ layers.

Summary Based on the invasion-percolation concept, we present a stochastic model to simulate the height of the CO2 column and hence the pore pressure in continuous time in each layer of a multi-layer stratigraphic system. Assuming the capillary threshold pressure of the sealing layer as the limiting factor, we extract the time of CO2 migration from a layer to the layer above. By modelling the heights in different layers explicitly, we facilitate the linkage to monitoring, assuming that seismic data can be used to estimate the heights of the CO2 columns that build up in various layers over time. We conduct value of information (VOI) analysis to understand when it is optimal to gather seismic data about the CO2 plume in the stratigraphic layer model.

Summary In order to support offshore developments in carbon capture and storage, a novel, low-cost Ocean Bottom Node (OBN) seismic survey have been designed. The survey is to be acquired over a proposed test site across the Øygarden Fault in the Horda platform region offshore Norway. The aim is to improve the imaging of the fault and the resolution of the juxtaposed sedimentary units required to re-evaluate the risk of storing CO2 over a segment of the Beta Structural high. All, while using a limited set of 50 nodes. Evaluation of the acquisition configuration showed that receiver arrays allowing for high-resolution imaging and advance velocity inversion have divergent technical specifications. Meeting both objectives, while crucial for addressing de-risking and CO2 storage monitoring challenges, is not straightforward at low cost. Targeted imaging using hybrid OBN configurations may represent a cost-effective alternative to resolve this challenge, while sparse OBN acquisition, for velocity inversion and re-migration of legacy data, may comprise a low-cost solution for de-risking CO2 storage over uncertain or highly complex structures.

The SHARP project was launched in late 2021 as a collaboration between 16 research institutions and commercial companies in Norway, UK, the Netherlands, Denmark, and India under the ACT3 Programme. The project is interdisciplinary with a strong focus on understanding and reducing the uncertainties related to subsurface CO2 storage containment risk focusing on the geomechanical aspects of CO2 storage. The geomechanical response to CO2 injection is one of the key uncertainties in assessing proposed storage sites. The main aim of the SHARP project is to mature the technology for quantification of subsurface deformation by the development and integration of models for subsurface stress, rock mechanical failure and seismicity. Key activities for the project include: developing basin-scale geomechanical models that incorporate tectonic and deglaciation effects and use newly developed constitutive models of rock/sediment deformation (WP1); improving knowledge of the present-day stress field in the North Sea from integrated earthquake catalogues and developing a database of earthquake focal mechanisms (WP2); quantifying rock strain and identifying failure attributes suitable for monitoring and risk assessment using experimental data (WP3); developing more intelligent methods for in situ monitoring of rock strain and failure as part of the overall monitoring programmes (WP4); quantifying containment risks using geomechanical models and observations from the field and laboratory (WP5); and communicating technology development on containment risk to industry and regulators (WP6). The SHARP project is expected to accelerate the maturation of six sites from the North Sea region and India. The case study sites range from very mature projects such as the Northern Lights CO2 storage project in the Horda area (N) to emerging storage prospects such as the Endurance site (UK) and the Hanstholm structure (DK). Furthermore, application of the methods to well-characterised offshore depleted oil and gas fields as Nini (DK) and Aramis (NL) will accelerate their transformation into viable and safe CO2 storage sites. India has high focus on emission reduction including development of CCUS and an onshore case study for CO2 injection will be matured using lessons learned from the European projects in order to kick-start CO2 injection and storage projects in India. Involvement of international CO2 storage operators in the consortium ensures that the SHARP project has a high impact on CCS development in Europe and India, as well as globally. New technologies for quantification of subsurface deformation and strategies for monitoring deformation and fluid flow will provide cost-efficient tools for CO2 subsurface risk management. The results of the project will be communicated to storage site operators and regulators to increase confidence in storage safety and seismicity risk assessment.

Summary Pressure management is a key issue for efficient utilization of CO2 storage within sedimentary basins of the world. We develop analytical approaches to pressure management for the case of multiple CO2 injection sites in a basin model with multiple fault compartments, using the case of the Smeaheia prospects offshore Norway. The analysis helps identify when and where key limiting factors are reached. Preliminary results show that the rock compressibility limits are only of concern in very small fault blocks, while pressure rise towards the geomechanical limits occurs across a range of fault block sizes. In very large fault blocks it is mainly the injectivity which controls final stored volumes. The study indicates that large scale CO2 storage in the Smeaheia prospects appears to be credible, with good potential for finding multiple injection sites with >50Mt storage per fault block. The methodology developed in this study should also be valuable for efficient early-stage screening of storage sites around the globe.

Summary Equinor in collaboration with Shell and Total is working on maturing the carbon storage project to store industrially produced CO2 into geological subsurface offshore Norway. However, the selected candidates for CO2 storage are part of a region with moderate natural seismicity. In order to assure a safe storage, the background seismicity should be monitored to understand both the nature of natural seismicity and to detect possible events induced by the imposed pressure changes due to CO2 injection. Current existing seismic network onshore is rather sparse and due to the limitation of recording mostly from the Norwegian side, event location uncertainty is rather high which complicates associating individual earthquakes to specific faults. Integration of onshore network with selected offshore PRM stations improved detectability. However, a more local monitoring system is required to improve the detectability and reduce the location uncertainty. We here present a proposal for a seismic monitoring array design for the offshore setting around the Smeaheia and Aurora sites that includes an upgrade of the onshore monitoring network as well as some ocean bottom nodes. We argue that such a network will provide an adequate baseline dataset, which is crucial for understanding the site prior to injection.

Summary Equinor in partnership with Shell and Total is working on a concept selection for a CO2 storage site offshore Norway. This storage site is planned to be monitored by passive seismic, prior and in the life time span of injection to make sure CO2 injection will not impose any seismic risk. We analyzed the recorded data on a limited set of offshore 3C-geophones on Grane Permanent Reservoir Monitoring (PRM) system, from December 2018 to May 2019, to evaluate the potential of conventional geophones for background seismicity monitoring. During these six months, 278 events with a local magnitude ranging from -0.7 to 2.0, could be located. Our study shows that good azimuthal coverage of stations can have large impact on accuracy of location and magnitude of event. In addition, improved velocity model can reduce the location uncertainties. A seismic network consisting of pre-existing offshore geophones on Grane/Snorre PRM and Oseberg Seismic Waste Injection Monitoring (SWIM), combined with a limited number of broadband seismometers from the Norwegian National Seismic Network, could optimize a cost-effective setting for passive monitoring. An ongoing study is evaluating the benefits of dedicated or enhanced seismometer deployments (offshore/onshore) to give further improvements to detection and location accuracy.

Summary Over the coming decades our society has a significant challenge in achieving globally significant reductions in greenhouse gas emissions. Numerous studies show that large-scale geologic disposal of CO2 from industrial emissions will be essential to achieve this objective. There are currently 21 large-scale CCS facilities in operation. Of these large-scale CCS projects, five use geologic storage in saline formations (Sleipner, Snehvit, Quest, IBDP & Gorgon) and together inject nearly 6 million tonnes CO2 per annum (Mtpa). The remaining large-scale projects mainly use CO2EOR as the storage vehicle. Enhanced oil recovery using carbon dioxide (CO2EOR) can have a dual purpose: (a) To recover additional oil, thereby supplying energy and additional revenues; and (b) to mitigate climate change by reducing anthropogenic CO2 emissions. Historically, CO2EOR projects have tended to maximize oil production as a function of the CO2 injected. There are various options proposed to enhance the climate mitigation effect of CO2EOR projects by maximizing the ratio of the CO2 injected to the oil produced, or by transiting projects from CO2EOR in the initial stages to pure storage projects in the later stages. However, to achieve net zero-emissions, CO2EOR projects need to include a significant fraction of non-EOR CO2 storage. CO2EOR projects also play an important role in building the infrastructure needed for large-scale carbon capture, utilisation, and storage. We illustrate these potential pathways using examples of large CCUS/CCS projects, both from offshore Norway and onshore Canada.

This study assumes that the target mass of CO2 can be captured and delivered to injection wells at acceptable costs, largely ignoring the primary economic factors needed to ensure successful full-scale capture deployment. The analysis presented uses the historical development of hydrocarbon extraction wells drilled in various regions as a basis for the expected rate of future well deployment for CO2 injection (Fig. 1). The most aggressive of these is the Bakken unconventional development in the central U.S., and the smallest scale is represented by the offshore hydrocarbon development offshore Texas. The Norwegian North Sea and the entire Gulf of Mexico represent other potential scenarios. This future hypothetical CO2 well development assumes that experience and technology will allow a similar exponential growth in deployment as was observed for hydrocarbon extraction, as well as for other technologies (Kramer and Haigh, 2009). By making some further assumptions based on industry experience about the likely life of each injection well (25 years) and the average annual rate of CO2 injection (0.7 Mtpa; Ringrose and Meckel, 2019), the future incremental and cumulative volume (Fig. 2) of injected CO2 can be estimated. Such estimates are useful for understanding the scale of regional and global deployment needed, as well as for providing a basis with which to evaluate incremental progress and maintain targets.

Summary The decarbonisation of power production, industry, transport and heating to meet climate change targets is a major challenge and one that intrinsically involves the subsurface and geoscience. Here we report a summary of the 2019 Bryan Lovell conference, where thirty expert speakers examined decarbonisation from the point of view of what the subsurface can offer, and came to the conclusion that there are a number of technologies that will make a real difference to our ability to decarbonise

Summary CO2 has been injected and stored at the Sleipner injection site since 1996 and the CO2 distribution has been monitored through a total of nine repeat time-lapse surveys. The time-lapse response when CO2 replaces brine is very strong and has enabled us to quantify at least nine strong seismic reflections which are interpreted as CO2 being trapped beneath thin shale layers within the otherwise very homogenous storage formation. The CO2 accumulation beneath each shale layer can be described and modelled by capillary seal theory and Invasion Percolation modelling; however, some unexpected behaviour is observed which is best explained by CO2 migrating through a main feeder chimney of dim amplitudes observed near the location of the injection point. There are also examples of layers growing at leakage points offset from the main chimney, without any obvious feeder chimney attached to them. In this paper we discuss the detection of these ‘invisible seismic response’ features and the consequences for reservoir understanding and simulation. The Sleipner CO2 plume observations can also serve as a proxy for and give understanding of migration and leakage detection using seismic time-lapse data.

Equinor’s ambition is to be a leading company in CO2-efficient oil and gas production, and to offer new business opportunities within renewable energy (Figure 1). CO2 handling consequently provides both a challenge and an opportunity. Equinor has long experience with CO2 capture, transport, and storage as operator of TCM (Test Centre Mongstad), Sleipner and Snøhvit fields and also as partner in the In Salah field in Algeria. The Norwegian State is presently leading a new full-scale CCS project, aimed at capturing CO2 from industrial sources and storing it beneath the North Sea. Equinor, together with partners Shell and Total in the Northern Lights partnership, is responsible for FEED (Front-End Engineering Design) of the transport and storage part of this project.

Summary Acoustic log data are important and have been widely used in the petroleum industry to detect fractures in the formation, the fluids and to check the quality of the cementation process in the wellbore. In present study, we used the acoustic log data to detect the overpressured Cretaceous shale units, by contrasting P- and S-waves, under mechanical and chemical compactions.