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Three different outcrops are selected in this study, each representing a shallow-marine system with varying heterogeneity provided by siliciclastic–carbonate mixing that may form a small or large stratigraphic trap. The impact of these styles of mixed facies on CO2 storage is relatively poorly known. This study demonstrates the significance of these systems for safe CO2 geological storage, as stratigraphic traps are likely to be a significant feature of many future storage sites. The three 3D models are based on: (1) the Grayburg Formation (USA), which displays spatial permeability linked to variations in the mixture of siliciclastic–carbonate sediments; (2) the Lorca Basin outcrop (Spain), which demonstrates the interfingering of clastic and carbonate facies; and (3) the Bridport Sand Formation outcrop (UK), which is an example of a layered reservoir and has thin carbonate-cemented horizons. This study demonstrates that facies interplay and associated sediment heterogeneity have a varying effect on fluid flow, storage capacity and security. In the Grayburg Formation, storage security and capacity are not controlled by heterogeneity alone but are influenced mainly by the permeability of each facies (i.e. permeability contrast), the degree of heterogeneity and the relative permeability characteristic of the system. In the case of the Lorca Basin, heterogeneity through interfingering of the carbonate and clastic facies improved the storage security regardless of their permeability. For the Bridport Sand Formation, the existence of extended sheets of cemented carbonate contributed to storage security but not storage capacity, which depends on the continuity of the sheets. These mixed systems especially minimize the large buoyancy forces that act on the top seal and reduce the reliance of the storage security on the overlying cap rock. They also increase the contact area between the injected CO2 and brine, thereby promoting the CO2 dissolution processes. Overall, reservoir systems with mixed carbonate–siliciclastic facies contribute to improving the safe and effective storage of CO2. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Small-scale deformation bands in Penrith Sandstone are used to assess the extent to which these features can act as effective mini-traps and contribute to secure CO2 geological storage. A comprehensive set of simulation scenarios is applied to one conjugate set of deformation bands and also to clusters of deformation bands, to evaluate the effects of i) deformation band density; ii) the contrast in host rock/deformation band permeability; and iii) deformation band geometry, orientation and distribution on fluid movement and its significance for CO2 storage capacity and security. The findings of this study show that one conjugate set of deformation bands can improve CO2 storage security, depending upon the plunge angle of the hinge. It has also been demonstrated that a high contrast in permeability (at least three orders of magnitude) is necessary for the CO2 to be effectively trapped by the deformation bands. It is shown that the highest number of bands observed and modelled for Penrith Sandstone outcrop, with three orders of magnitude permeability contrast, is a configuration that can contribute to the secure storage of CO2 without causing an injectivity issue. This study shows that storage security is not only controlled by the contrast in permeability, but also by the permeability of the host rock. Furthermore, some geometries may contribute to storage security, while others may compromise it. To improve storage capacity and security for the type of reservoir studied herein, the results demonstrate the importance of accounting for the optimum injection rate and well placement.

Summary The work presented here investigates mixed carbonate and siliciclastic sediments, which are present in many stratigraphic successions for CO2 flow simulation. Such a mixed sedimentary system can exhibit extensive lateral and vertical facies heterogeneity. We have conducted a range of 3D numerical simulations to study the impact of such systems on CO2 storage. The results indicate that the shape of the injected CO2 in the heterogeneous models is asymmetrical. The flow paths are dispersed which result in irregular plume shape. Although the amount of CO2 dissolved in the brine is higher in the homogenous model and models with lower proportion of carbonate, we believe that the storage security cannot be guaranteed. This is because CO2 laterally migrated longer distance under the caprock and leakage points may allow free CO2 to escape from the reservoir.

Exhumed bleached palaeoreservoirs provide a means of understanding fluid flow processes in geological media because the former movement of fluids is preserved as visible geochemical changes (grey bleaching of continental red-beds). The bleached palaeoreservoirs of the Jurassic Entrada Sandstone occur in a region (Utah) where there are high fluxes of naturally-occurring CO2 and form outcrop analogues for processes related to geological storage of CO2. In this paper a bleached palaeoreservoir now exposed at outcrop is used to test the importance of geological heterogeneity on fluid flow. The bleached palaeoreservoir is developed in ‘wet aeolian’ lithofacies composed of alternating layers of sandstone and cemented muddy sandstone that range across three or more orders of magnitude in permeability. Despite these permeability contrasts the bleaching shows a remarkably uniform distribution within the palaeoreservoir that crosses lithofacies boundaries. Evidence from bleaching therefore suggests that geological heterogeneity within the range 1–103 millidarcies should not greatly impede the relatively uniform distribution of low-viscosity CO2 charged fluids throughout a reservoir: a conclusion that has been substantiated here by flow modelling. Residence time is an important factor and where flows are transient the distribution of bleaching and modelling shows that flows are confined to high-permeability lithofacies.

CO2 has lower density than brine and is a buoyant fluid. Therefore, after injecting CO2 into saline aquifers, CO2 will move upward under buoyancy to reach a barrier. Afterward CO2 will spread underneath and moves laterally which depends on the caprock and aquifer interface. One type of interface is unconformity surface. In this work, the effect of this interface on CO2 dissolution was investigated by conducting 2D numerical simulations and it is concluded that in low injection scenarios, distance travelled by CO2 plays a significant role to increase CO2 dissolution. In addition, existence of high permeable layer at unconformity surface which was formed due to erosion or deposition of large grain sediments increases CO2 dissolution by providing additional pathways to other storage formations. In higher injection rates however, both pressure build up and distance traveled by CO2 play role. In absence of the high permeable layer, pressure in the formation increases and this triggers more CO2 dissolution. Overall, precisely choosing well or perforation location and injection rates will increase the CO2 dissolution as a long term trapping mechanism and will reduce the potential for leakage. In addition, sensitivity of CO2 dissolution to temperature and salinity gradients was examined.