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• Classification and analysis of geological heterogeneous factors for accurate simulations. • Quantification assessment of CO 2 storage parameters using two sensitivity methods. • Various heterogeneous factors exert distinct influences on CO 2 plume and BHP in different layers and time. • A method to enhance CO 2 storage modeling precision with limited data. The intensifying global climate change has prompted the imperative implementation of CO 2 capture and storage (CCS) projects as a mitigation strategy. Ensuring the safety and reliability of these projects requires meticulous validation, including the establishment of geological models and conducting numerical simulations. In CO 2 geological storage initiatives, the limitation of well data during the initial stages leads to data deficiency. This scarcity compromises the precision of geological and numerical models, hindering their ability to accurately depict actual subsurface conditions. Meanwhile, parameters related to heterogeneity significantly also impact storage effectiveness and safety. This study addresses these challenges by utilizing the Shenhua CCS demonstration project as a case study. Various heterogeneous parameters are selected, and local and global sensitivity analysis methods are subsequently introduced to determine the ranges and sequences of these parameters in numerical simulations. The simulation results can aid in assessing the influence of various heterogeneous parameters on the CO 2 plume and bottom hole pressure. The study establishes the importance ranking of various heterogeneous parameters under different temporal and spatial conditions through sensitivity analysis. The findings reveal the following key points: 1. During the small-scale injection period, the CO 2 plume is particularly sensitive to variations in net-to-gross and vertical permeable properties. 2. During and after larger-scale injections, the net-to-gross significantly impacts plume evolution, while bottom hole pressure is predominantly influenced by variations in vertical permeable properties. 3. Both the CO 2 plume and well bottom pressure are primarily affected by changes in sand body morphologies, especially at low net-to-gross scenarios. These conclusions assist in prioritizing the collection of critical parameter data in CCS projects, facilitating the establishment of more precise and reliable geological and numerical simulation models. The heightened accuracy and reliability of these models contribute to improving their predictive capabilities, ultimately guiding engineering practices. [ABSTRACT FROM AUTHOR]

• A suite of 3D models with faulting and variable reservoir dip were built based on the Shenhua CCS demonstration site. • Plume migration and volumetric storage were found to be a function of reservoir dip and high transmissibility fault zone. • The results will help to inform site selection for future CCS projects in the Ordos Basin and other potential storage sites. Carbon dioxide (CO 2) storage security is a key issue in CO 2 geological storage (CGS). A three-dimensional (3D) conceptual reservoir model of the Shenhua CO 2 geological storage site in the Ordos Basin has been used to investigate the impact of reservoir formation dip and the influence of enhanced permeability fault zones on CO 2 storage and migration security. A total of 8 simulations were carried out using the TOUGH2 integral finite difference modelling code with the ECO2N fluid property module. The simulation results showed that the dip of the reservoir formation and fault had a significant impact on CO 2 migration and storage security. Increasing the dip of the reservoir increased CO 2 migration distance, decreased the total volume of CO 2 safely stored in the formation and resulted in increased maximum gas saturation and liquid mass fraction of dissolved CO 2. The presence of fault provided a channel for CO 2 leakage and caused an irregular distribution of formation pressure. The onset time of leakage through the fault proved to be a function of formation dip, occurring at 465, 230, and 160 years following commencement of CO 2 injection for dips of 5°, 10°, and 15° respectively. The lateral extent of both the high saturation CO 2 plume and the plume of dissolved CO 2 was greater in the steeply dipping faulted reservoir model, suggesting that gently dipping un-faulted reservoir formations should be selected for future CGS projects in the Ordos Basin. [ABSTRACT FROM AUTHOR]

Storing CO 2 for geological timescales is crucial to delivering decarbonisation of industrial economies aligned with global climate change mitigation objectives. This requires CO 2 injection into a large subsurface pore space overlain by a high capillary entry pressure seal rock to prevent CO 2 escape. Such formations occur abundantly in productive hydrocarbon basins such as the North Sea. However, these geological conditions for CO 2 storage are unavailable close to some large CO 2 emitting economic areas in China. We identify this problem and innovate a solution for the example of the Pearl River Mouth Basin (China). This offshore basin has an estimated effective storage capacity of hundreds of Gt CO 2 based on reservoir pore volumes. Production and geological data of three oil fields of the Huizhou hydrocarbon cluster are analysed as analogues for large-scale aquifer storage of CO 2 . Results suggest the injection and storage of CO 2 in individual trap structures will perform poorly, due to thin reservoir layers, small structural traps, and indications that the cap rocks may have only limited sealing capability. To address this a novel alternative CO 2 sequestration strategy, based on multi reservoir layer injection and dispersion trapping, is recommended to exploit the vast available pore space for CO 2 storage. [ABSTRACT FROM AUTHOR]

• Composite confining systems are multi-layer systems of discontinuous barriers. • They work by drastically lowering effective Kv/Kh, creating long flow paths for CO 2. • Migration-assisted trapping effectively immobilizes CO 2 with little vertical migration. • Risks are familiar—legacy wells, permeable faults and high-relief structures. • Composite confining systems are ideally suited to the goal of permanent sequestration. Permanent containment is paramount for geologic carbon sequestration. Petroleum experience proves the possibility but also creates bias—to date, carbon storage projects have used seals similar to those of producing petroleum accumulations—thick, laterally extensive, effectively impermeable layers. These work for CO 2 , but may not be present where needed, nor optimal for sequestration. We introduce the concept of composite confining systems, defined here as multi-layer stratigraphic systems of discontinuous barriers with no a priori requirements for continuity or minimum capillary entry pressure. We explore the concept through physical analog modeling, geologic characterization and full-scale numerical modeling. We find that barriers need only offer enough capillary entry pressure contrast to divert the flow of CO 2 and that barrier frequency and barrier area are the key variables in retarding vertical migration. Data from Southern Louisiana Miocene deltaic deposits shows ∼5–15 mudstone barriers/100 m of section, with average mudstone lengths of over 1 km and aspect ratios ∼2:1, giving effective ratios of vertical to horizontal permeability (k v /k h) of ∼0.0005. Full-scale reservoir models show that these systems can completely arrest vertical migration of industrial-scale volumes of CO 2 (10's of megatons) within a few 10's of meters of stratigraphic section. Unlike more conventional petroleum seals and traps, which retain CO 2 in a concentrated, mobile state, composite confining systems disperse and immobilize it via migration-assisted trapping. The greatest risks to performance of composite confining systems are the same as for conventional seals–the potential shortcuts across stratigraphic barriers, e.g., legacy wells, fluid escape pipes and permeable faults that focus flow. [ABSTRACT FROM AUTHOR]

Long-term security is critical to the success and public acceptance of geologic carbon storage. Much of the security risk associated with geologic carbon storage stems from CO 2 buoyancy. Gaseous and supercritical CO 2 are less dense than formation waters providing a driving force for it to escape back to the surface via fractures, or abandoned wells. This buoyancy can be eradicated by the dissolution of CO 2 into water prior to, or during its injection into the subsurface. Here we demonstrate the dissolution of CO 2 into water during its injection into basalts leading directly to its geologic solubility storage. This process was verified via the successful injection of over 175 t of CO 2 dissolved in 5000 t of water into porous rocks located 400–800 m below the surface at the Hellisheidi, Iceland CarbFix injection site. Although larger volumes are required for CO 2 storage via this method, because the dissolved CO 2 is no longer buoyant, the storage formation does not have to be as deep as for supercritical CO 2 and the cap rock integrity is less important. This increases the potential storage resource substantially compared to the current estimated storage potential of supercritical CO 2 . [ABSTRACT FROM AUTHOR]

• CO 2 dissolution is a dynamic process due to the heterogeneity of the porous medium. • Increasing the injection rate promoted the CO 2 dissolution rate. • Wettability is a factor controlling CO 2 dissolution into the brine. • Maximum dissolution was observed under the water-wet and high flow rate conditions. We report a quantitative study on the dynamics of dissolution trapping occurring during the injection of supercritical CO 2 (scCO 2) into a brine-filled heterogeneous porous medium, implying an application for the geological storage of CO 2 in saline aquifers. We present volume-of-fluid (VOF)-based simulations of integrated two-phase flow and species mass transport at the pore-scale to capture transient dissolution of scCO 2 in brine. It becomes evident that CO 2 dissolution is not an instantaneous process, as the structural heterogeneity of the porous medium induces incomplete mixing leading to non-equilibrium dissolution. According to our observations, dissolution of scCO 2 into brine occurs at an increasing rate at the early stage of the injection period, reaches a peak value, and follows by a declining trend at late stages. The observed trend in the dissolution rate is attributed to the evolution of interfacial area between percolated fingers of CO 2 plume and brine. When the system reaches the steady-state, a stabilized interface between scCO 2 and brine forms, undermining the scCO 2 dissolution and dissolved CO 2 mass transfer in brine. The pore-level analysis implies that injection rate and surface wettability are key factors influencing the evolution of the scCO 2 -brine interfacial area and consequently the mass transfer occurring at the interface during the dissolution trapping of scCO 2. According to the results, scCO 2 dissolution becomes more pronounced when the injection rate becomes higher and the medium is more wetting to the brine. [ABSTRACT FROM AUTHOR]

• Application of the downhole cooler tools at the depth of 1500 m. • Application of the downhole cooler tools at shallow (1000 m) and deep (2700 m) reservoirs. • Application of downhole cooler tools in a real field. Different injection methods have been already proposed by different researchers to improve the solubility of CO 2 in formation brine. In this study a novel injection technique is presented, its aim being to cool down (liquefy) the supercritical CO 2 injected in a wellbore through the use of downhole cooler equipment. Higher temperature CO 2 entering the cooling equipment therefore exits with a lower temperature further downstream. If the temperature of the downhole, where CO 2 is in contact with the formation brine, decreases to the lowest possible safe operational temperature, the consequence is an increase in the solubility of CO 2 to the highest possible value for that pressure. The colder (liquid) CO 2 has a higher solubility in brine, higher density and viscosity, which increases the security of the CO 2 storage. Using this method to cool the supercritical CO 2 down to a liquid phase increases its solubility at the wellbore, thereby eliminating the risk of a phase change or pressure and rate fluctuation in the liquid CO 2 injection from the surface. Additionally the formation will have a lower pressure build-up because CO 2 and brine are well mixed, and so less CO 2 remains in the free phase. [ABSTRACT FROM AUTHOR]