Does numerical modelling of the onset of dissolution-convection reliably reproduce this key stabilization process in CO2 storage?

Dissolution of carbon dioxide into water is a key medium-term CO2 plume stabilization process. It proceeds much more quickly when aided by convection than when driven by diffusion alone. The onset of the convection process is not well understood, so laboratory experiments using a Hele-Shaw cell containing a porous medium were used to reproduce the process of CO2 dissolution and convection in water. High resolution numerical flow models were then used to replicate the laboratory results. They show a remarkably good match in terms of convective plume temporal and spatial development. This suggests that numerical models of dissolution-convection at much larger reservoir scales can reliably predict the onset of dissolution-convection

Using pressure recovery at a depleted gas field to understand saline aquifer connectivity

A key uncertainty facing Carbon dioxide Capture and Storage (CCS) in saline aquifers is long term injectivity, which is primarily a function of the connected aquifer pore-volume within which formation brine can be displaced as the CO2 is injected. Protracted injection testing to interrogate and prove the far-field connected pore-volume would increase the lead-in times for commissioning of storage sites and would significantly increase appraisal costs. Here we use natural gas production and subsequent reservoir recharge legacy data from the Esmond gas field in the UK sector of the southern North Sea to gain an understanding of the dynamic behaviour of the Bunter Sandstone, a major saline aquifer. Results suggest that Esmond has a connected pore volume of 1.83x1010 m3, suitable for injecting CO2 at a rate of up to 2 million tonnes per year for at least 55 years. 3D seismic data suggest that Esmond reservoir properties are likely to be replicated across the wider Bunter Sandstone aquifer, notably around the Endurance structure which was, until recently, proposed for a full-chain CCS project

The impact of energy systems demands on pressure limited CO2 storage in the Bunter Sandstone of the UK Southern North Sea

National techno-economic pathways to reduce carbon emissions are required for the United Kingdom to meet its decarbonisation obligations as mandated by the Paris Agreement. Analysis using energy systems models indicate that carbon capture and storage is a key technology for the UK to achieve its mitigation targets at lowest cost. There is potential to significantly improve upon the representation of the CO2 storage systems used in these models, but sensitivities of a given reservoir system to future development pathways must be evaluated. To investigate this we generate a range of numerical simulations of CO2 injection into the Bunter Sandstone of the UK Southern North Sea, considered to be one of the most important regional aquifers for CO2 storage. The scenarios investigate the sensitivity of CO2 storage to characteristics of regional development including number of injection sites and target rates of CO2 injection. This enables an evaluation of the impact of a range of deployment possibilities reflecting the range of scenarios that may be explored in an energy system analysis. The results show that limitations in achieving target injection rates are encountered at rates greater than 2 MtCO2/year-site due to local pressure buildup. The areal location of injection sites has minimal impact on the results because the Bunter Sandstone model has good regional connectivity. Rather, the depth of the site is the most important factor controlling limits on CO2 injection due to the relationship between the limiting pressure and the lithostatic pressure gradient. The potential for model simplification is explored by comparison of reservoir simulation with analytical models of average reservoir pressure and near-site pressure. The numerical simulations match average pressure buildup estimated with the “closed-box” analytical model of Zhou et al. (2008) over a 50 year injection period. The pressure buildup at individual sites is estimated using the Mathias et al. (2011) formulation and compared to the simulation response. Discrepancies in the match are mostly due to the interaction of signals from multiple injection sites and heterogeneous permeability in the numerical simulations. These issues should be the focus of further development of simplified models for CO2 storage in an energy systems analysis framework

Understanding the impact of regional structures on pressure communication within the Bunter Sandstone Formation, UK Southern North Sea

The Lower Triassic Bunter Sandstone Formation is one of the UK’s principal targets for carbon capture and storage. Located in the Southern North Sea, the formation contains several periclinal closures which provide potential carbon storage opportunities for industrial clusters in eastern England. Numerical simulation studies, investigating the dynamic behaviour of industrial scale CO2 injection, have highlighted that CO2 storage can result in widespread pressurisation of the aquifer. Understanding the potential for pressure communication in the Bunter Sandstone is therefore important in the context of pore pressure management, as injection activities at one site could potentially impact negatively on operations elsewhere. The Bunter Sandstone Formation is regionally divided by recognised fault systems and salt walls, such as the Dowsing Graben System, North Dogger Fault Zone, Audrey Salt Wall and Outer Silverpit Salt Wall. The Bunter Sandstone Formation is underlain by the Permian Zechstein Salt. Extension and transtension during the Mid-Late Triassic, Jurassic and Early Cretaceous, associated with the breakup of Pangea, and inversion during the Alpine Orogeny in the Late Cretaceous and into the Palaeogene, has resulted in mobilisation of the Zechstein Salt and the deformation of the Bunter Sandstone and its overburden. Recently, localised studies have been completed which map zones of separation of the Lower Triassic strata within the Dowsing Graben System (Grant et al 2019; Grant et al 2020) and regionally the distribution and evolution of salt walls (Gaitan & Adam, 2023). However, there is little investigation into the characteristics of these boundaries as a whole and their likely impact on the migration pathways of fluids within the aquifer, and therefore pressure, during large-scale CO2 injection. This study uses a large seismic database to evaluate these bounding structures at Bunter level. Each boundary has been investigated and the structural variation described. A new structural map has been created for the Top Bunter Sandstone Formation and a classification scheme has been developed to map the variation in the structural character and therefore the likelihood of pressure communication across each boundary. The structural boundaries predominantly provided distinct separation of the Bunter Sandstone Formation. Areas of uncertainty remain where: the structures are highly complex, there is little well control, and the seismic imaging is of lower resolution. Legacy well data has been sourced from the NSTA’s National Data Repository to investigate formation pressures within the Bunter Sandstone Formation. These data indicate that different structural regions in the UKSNS are subject to distinct pressure gradients supporting the lack of aquifer connectivity inferred from the seismic interpretation. Current national development plans (NSTA, 2023) envisage multiple storage sites within the wider connected aquifers. Strategic management and pressure control may become a key factor in the development and operation of these storage sites. To investigate the impact of the boundary classification on regional pressure, numerical flow modelling was used with the ELCIPSE300 simulator and the CO2STORE option. Regionally appropriate parameter values were used, primarily sourced from the CO2Stored database and other publicly available data. A realistic but ambitious CO2 injection strategy has been used with staggered injection into multiple closures, including the Endurance structure. For boundaries with uncertain connectivity, cases of closed, semi-closed and open boundaries were run and the flow of pore fluids through permeable boundaries quantified. The flow simulations provide an insight into the potential implications for pressure management for effective utilisation of storage capacity, and could be used to inform development of monitoring strategies

Effect of sedimentary heterogeneities in the sealing formation on predictive analysis of geological CO₂ storage

Numerical models of geologic carbon sequestration (GCS) in saline aquifers use multiphase fluid flow-characteristic curves (relative permeability and capillary pressure) to represent the interactions of the non-wetting CO2 and the wetting brine. Relative permeability data for many sedimentary formations is very scarce, resulting in the utilisation of mathematical correlations to generate the fluid flow characteristics in these formations. The flow models are essential for the prediction of CO2 storage capacity and trapping mechanisms in the geological media. The observation of pressure dissipation across the storage and sealing formations is relevant for storage capacity and geomechanical analysis during CO2 injection. This paper evaluates the relevance of representing relative permeability variations in the sealing formation when modelling geological CO2 sequestration processes. Here we concentrate on gradational changes in the lower part of the caprock, particularly how they affect pressure evolution within the entire sealing formation when duly represented by relative permeability functions. The results demonstrate the importance of accounting for pore size variations in the mathematical model adopted to generate the characteristic curves for GCS analysis. Gradational changes at the base of the caprock influence the magnitude of pressure that propagates vertically into the caprock from the aquifer, especially at the critical zone (i.e. the region overlying the CO2 plume accumulating at the reservoir-seal interface). A higher degree of overpressure and CO2 storage capacity was observed at the base of caprocks that showed gradation. These results illustrate the need to obtain reliable relative permeability functions for GCS, beyond just permeability and porosity data. The study provides a formative principle for geomechanical simulations that study the possibility of pressure-induced caprock failure during CO2 sequestration

An integrated geophysical study for the assessment and monitoring of CO2 sequestration in Gandhar Oilfield, Cambay Basin, India

Introduction Gandhar oilfield, Cambay Basin, Gujarat is one of the Oil and Natural Gas Corporation Limited's (ONGC) major brownfields and a pilot candidate for India’s first large-scale CO2 sequestration project. The field which has been produced from multilayered sand bodies of Hazad Member, Ankleshwar formation has undergone various phases of production, and currently, it has reached a highly matured stage of its production life. ONGC has planned to implement the CO2 EOR technique in this field to recover an extra 15% of residual oil based on recent studies of source-sink matching, petrophysical properties analysis, current reservoir pressure, minimum miscibility pressure (MMP), and other laboratory experiments. The field is being studied for the assessment of CO2 storage potential and the feasibility of seismic techniques to monitor injected CO2 in Hazad sands (reservoir) and overlying brine saturated Ardol sands of Ankleshwar formation. For such a study, an integrated geophysical approach is performed with seismic, petrophysical, and geophysical well-log data provided by the National Data Repository-DGH (Govt. of India) and ONGC. Prediction of unrecorded P-sonic logs using Gradient Boosting Regressor algorithm in Gandhar oilfield A total of 15 wireline geophysical well log data from a 50 sq. km. block of the Gandhar oilfield for this study were provided but only 12 out of the 15 wells had P)-sonic logs. The sonic log (DT) is one of the essential logs required to perform petrophysical analysis, to aid in missing check-shot profiling, fluid substitution modeling, and seismic modeling & inversion studies. Therefore, the prediction of unrecorded P-sonic logs was required to reduce the uncertainty in reservoir characterization at the field scale by reducing the scarcity of sonic log data over an area. To overcome this problem, we implemented the Ensemble machine learning technique named Gradient Boosting Regressor (GBR) (J.H. Friedman, 2001, 2002) algorithm to predict the unrecorded P-sonic logs in the Gandhar oilfield. The GBR has unique functionality to reduce bias and variance problems by converting weak learners to strong ones. Also, GBR can optimize different loss functions and provides several hyperparameter tuning options that make the prediction function fit very flexibly. The predicted P-sonic log correlates very well with the original P-sonic log. The predicted sonic logs are then used in the geomodel building process and fluid substitution modeling for CO2 sequestration. Gandhar Oilfield Geomodel Building We interpreted the 3D seismic data of the Gandhar oilfield with the help of the geophysical well logs including the predicted one and prepared a structural and stratigraphic geomodel of the Gandhar oilfield. The geomodel consists of 12 sand layer units (multi-stratigraphic pay sands) with thin intercalated shales in between them. The shales are as thin as 1.5 m and incorporating them in the geomodel was a hectic task that required several updates (well-tie tomography) in the building process to reduce mistie to avoid the crosscut between layers. We first displayed the prepared geomodel on 3D seismic data and it is observed that it honors the seismic data very well. The geomodel was flooded with facies interpreted from the geophysical well logs, effective porosity, and water saturation for the purpose of CO2 storage capacity assessment. Synthetic seismogram generation for monitoring CO2 sequestration in Gandhar oilfield The feasibility of seismic data to monitor CO2 sequestration in the overburden of the reservoir, which is brine saturated Ardol sands of the Ankleshwar Formation, is demonstrated through convolutional synthetic seismic modeling and seismograms. The evolution of an expanding CO2 plume in Ardol sands was calculated through the analytical approximation of axisymmetric gravity currents in a brine-CO2-saturated medium by using an injection rate of ∼0.5 Mt/year for a period of 6 years. CO2-saturated rock properties were determined using Gassmann fluid substitution and monitoring of CO2 plume was imaged by a time-lapse convolutional synthetic seismogram. Random noises were added to the synthetic seismogram and then NRMS and repeatability metrics were performed which established the detection threshold of 30 days since CO2 injection. The results are shown in Figure 1. Now, we don’t have the geomodel ready for the full-wavefield seismic modeling as it is in the development process. The Poroviscoelastic wave equation was solved numerically and was tested on the Sleipner field geomodel for monitoring the CO2 sequestration. Full-wavefield synthetic seismograms were generated for the pre-and post-CO2 injection cases. The poroviscoelastic theory models realistic amplitude attenuated due to squirt-flow (viscoelasticity) and Biot-flow (poroelasticity) related to matrix fluid coupling relaxation mechanisms. The prediction of more realistic amplitudes subject to CO2 sequestration signifies the success of the poroviscoelastic theory in monitoring CO2 sequestration in geological formations. Conclusions Gradient Boosting (ML) can be used for the prediction of logs, and it clearly demarcates the lithological boundary changes in Gandhar by preserving the amplitude. Fine scale geomodel of Gandhar oilfield (Hazad sands, Ankleshwar Formation) will give more accurate estimation of CO2 storage capacity. We anticipate that monitoring of CO2 sequestration on synthetic seismogram by poroviscoelastic theory will be more enhanced due to realistic amplitude attenuation attributed to interplay of squirt-flow and Biot-flow relaxation mechanisms. In addition to Hazad Sands (reservoir), brine saturated Ardol Sands is studied for the possibility of CO2 sequestration. The detection threshold is obtained for 30 days since CO2 injection in Ardol sands

A feasibility study to assess seismic detectability of CO2 sequestration in Gandhar Oilfield, Cambay basin: India’s first CO2 Project

The Gandhar oilfield is one of the major hydrocarbon fields of the Cambay Basin and a pilot candidate for India’s first large-scale CO2 injection project. The feasibility of seismic data to monitor CO2 sequestration in the Ardol Member of the Ankleshwar Formation is demonstrated through synthetic seismic modeling. The evolution of an expanding CO2 plume was calculated through the analytical approximation of axisymmetric gravity currents in a brine-CO2-saturated medium. CO2-saturated rock properties were determined using Gassmann fluid substitution. Seismic modeling was carried out for both pre-CO2 and post-CO2 injection models to determine the potential value of time-lapse seismic monitoring. It was observed that the CO2-saturated layers were readily detected, and seismic data would provide a suitable monitoring tool for a future CO2 storage complex. We anticipate that monitoring of CO2 sequestration on synthetic seismogram by poroviscoelastic theory will be more enhanced due to realistic amplitude attenuation attributed to interplay of squirt-flow (viscoelasticity) and Biot-flow (poroelasticity) mechanisms associated with matrix-fluid coupling relaxation. In addition to Hazad Sands (reservoir), brine-saturated Ardol Sands is studied for the possibility of CO2 sequestration. The enhanced impedance contrast between CO2 saturated Ardol Sand sand layers below it brightens the amplitude of the underburden. If the injection point is on the top of Ardol Sands, we see that it is easier to detect the CO2 saturated layer. Detection threshold is obtained for 30 days since CO2 injection in Ardol sands

Does the United Kingdom have sufficient geological storage capacity to support a hydrogen economy? Estimating the salt cavern storage potential of bedded halite formations

Hydrogen can be used to enable decarbonisation of challenging applications such as provision of heat, and as a fuel for heavy transport. The UK has set out a strategy for developing a new low carbon hydrogen sector by 2030. Underground storage will be a key component of any regional or national hydrogen network because of the variability of both supply and demand across different end-use applications. For storage of pure hydrogen, salt caverns currently remain the only commercially proven subsurface storage technology implemented at scale. A new network of hydrogen storage caverns will therefore be required to service a low carbon hydrogen network. To facilitate planning for such systems, this study presents a modelling approach used to evaluate the UK's theoretical hydrogen storage capacity in new salt caverns in bedded rock salt. The findings suggest an upper bound potential for hydrogen storage exceeding 64 million tonnes, providing 2150 TWh of storage capacity, distributed in three discrete salt basins in the UK. The modelled cavern capacity has been interrogated to identify the practical inter-seasonal storage capacity suitable for integration in a hydrogen transmission system. Depending on cavern spacing, a peak load deliverability of between 957 and 1876 GW is technically possible with over 70% of the potential found in the East Yorkshire and Humber region. The range of geologic uncertainty affecting the estimates is approximately ±36%. In principle, the peak domestic heating demand of approximately 170 GW across the UK can be met using the hydrogen withdrawn from caverns alone, albeit in practice the storage potential is unevenly distributed. The analysis indicates that the availability of salt cavern storage potential does not present a limiting constraint for the development of a low-carbon hydrogen network in the UK. The general framework presented in this paper can be applied to other regions to estimate region-specific hydrogen storage potential in salt caverns