Evaluation of CO2 hydrate storage potential in the Qiongdongnan Basin via combining the phase equilibrium mechanism and the volumetric method

Carbon dioxide (CO₂) dissolution is the secondary trapping mechanism enhancing the long-term security of CO₂ in confined geological formations. CO₂ injected into a randomly multilayered formation will preferentially migrate along high permeability layers, increasing CO₂ dissolution efficiency. In this study, sequential Gaussian simulation is adopted to construct the stratified saline formations, and two-phase flow based on MRST is established to illustrate the spatial mobility and distribution of CO₂ migration. The results show that gravity index $G$ and permeability heterogeneity ${\sigma }_Y^2$ are the two predominant factors controlling the spatial mobility and distribution of CO₂ transports. The CO₂ migration shows a totally different spatial mobility under different gravity index and heterogeneity. When the permeability discrepancy is relatively larger, CO₂ preferentially migrates along the horizontal layer without accompanying the vertical migration. For the formation controlled by gravity index, CO₂ migration is governed by supercritical gaseous characteristics. For the medium gravity index, the upward and lateral flow characteristics of the CO₂ plume is determined by gravity index and heterogeneity. When the gravity index is smaller, permeability heterogeneity is the key factor influencing CO₂ plume characteristics. Permeability heterogeneity is the decisive factor in determining final CO₂ dissolution efficiency. This investigation of CO₂ mobility in randomly multilayered reservoirs provides an effective reference for CO₂ storage.

A pressure-controlled jet crushing tool (PJCT) for the exploitation of deep-sea natural gas hydrate (NGH) was invented to achieve sediment crushing and cavity creation. The opening and closing of tool is controlled by changing the internal flow rate remotely. It can realize the controllable continuous switching of the working state between horizontal well drilling and cavity creation. A dynamic simulation model of the sliding core was established based on the innovative design scheme of the PJCT and the motion law of its slide core was analyzed under the influence of spring stiffness, friction coefficient, and flow rate loading scheme. Moreover, an engineering prototype of the PJCT was manufactured so that a sliding core motion experiment of the prototype was carried out. When the drilling fluid flow rate reaches 455 L/min, the PJCT can stably complete the self-locking and unlocking functions. Its sliding core needs more time to stabilize with an increase in spring stiffness. Meanwhile, the PJCT could achieve continuous fast switching between the mechanical drilling state and the jet crushing state within a cycle of continuous flow changes. Finally, the kinematic and dynamic working mechanism of the PJCT is verified by the combination of the numerical simulation and the experimental analysis above.

The pressure-controlled injection tool (PCIT) is the key equipment in the process of high-pressure water jet fragmentation in the solid fluidization exploitation of deep-sea natural gas hydrate (NGH). The internal flow field erosion wear numerical simulation model of PCIT is established through computational fluid dynamics software to study the influence law and main factors of the drilling fluid erosion wear of PCIT. The influence laws of different drilling fluid physical parameters and different structural parameters on PCIT erosion wear were analyzed based on the Euler–Lagrangian algorithm bidirectional coupled discrete phase model (DPM) and the solid–liquid two-phase flow model. The results show that the easily eroded areas are the cone of the sliding core, the plug transition section, the plug surface, and the axial flow passage. The sliding core inlet angle and solid particle size are the main factors affecting the PCIT erosion rate. When the inlet angle of the sliding core is 30°, the diameter of solid-phase particles in drilling fluid is less than 0.3 mm, and the erosion degree of the PCIT could be effectively reduced. The research results can provide guidance for the design and application of the PCIT and advance the early realization of the commercial exploitation of hydrate.

The increasing global focus on carbon capture and storage (CCS) has highlighted the potential for offshore CO₂ sequestration, particularly following recent successes in onshore projects. This research investigates the qualitative analysis of carbon trapping efficiency in offshore basins, employing a GEM simulator to incorporate factors such as aqueous solubility and geochemistry. The findings reveal that anticlines represent ideal geological structures for carbon storage, effectively trapping a significant portion of injected CO₂. For effective mineralization, it is crucial to dissolve CO₂ into saline aquifers to generate H⁺, which facilitates the release of Ca²⁺ and Al³⁺ from anorthite. This process leads to the dissolution of anorthite and the precipitation of kaolinite, while calcite transitions from a dissolved state to a precipitated state over time. The analysis indicates that structural trapping provides the highest storage contribution during the injection phase, whereas residual gas trapping becomes dominant by the end of the simulation. Notably, it is observed that the storage contribution of structural trapping decreases from 28.39% to 19.05%, and the percentage increase in storage contributions of residual gas, solubility, ionic, and mineral trapping are 4.12%, 3.25%, 1.69%, and 0.28% for CO₂ plus water injection, thereby improving the long-term security of CO₂ storage in offshore basins. It is most beneficial to optimize the layout and design of the injection well to ensure a uniform distribution of carbon dioxide and to increase the injection rate.

Despite extensive pore-scale studies on oil–water displacement, quantitative understanding of the dynamic evolution of residual oil morphology and waterflooding efficiency in geologically heterogeneous sandstones remains limited, particularly under large water-injection multiples. To better understand pore-scale oil–water distribution and its influence on enhanced oil recovery, this study utilized Micro-CT combined with SEM-EDS to examine the 3D pore structure and oil–water phase evolution in a heterogeneous sandstone sample from the Xiayang Formation, Wushi Sag, Zhanjiang. Mineralogical analyses reveal that dolomite cementation and vermicular kaolinite infilling introduce strong pore-scale heterogeneity by selectively reducing pore connectivity and permeability, posing challenges for uniform fluid displacement. A 30% KI solution was used to enhance X-ray attenuation of the aqueous phase, enabling clear discrimination between oil and water. Micro-CT reconstructions reveal a relatively uniform pore network dominated by medium-to-large intergranular pores. As the water-injection multiple increases, water progressively invades larger pores, while residual oil is immobilized by capillary forces within micro-throats, forming isolated clusters. The oil-droplet size distribution broadens from a narrow range (50–100 µm) to a wider one (200–300 µm), indicating interfacial destabilization and droplet coalescence. Quantitative analysis indicates that oil saturation decreases from approximately 90% to 36%, while waterflooding efficiency increases rapidly to ~45% at 1 PV and gradually approaches a plateau of ~60% beyond 500–1000 PV. This waterflooding plateau is attributed to capillary trapping and pore-scale connectivity limitations imposed by mineral-induced heterogeneity, which prevent further mobilization of residual oil despite continued water injection. This study advances pore-scale waterflooding research by combining mineralogical heterogeneity with long-term micro-CT imaging, revealing the pore-scale mechanisms controlling residual oil evolution and ultimate waterflooding limits in realistic sandstone.