Carbon dioxide Enhanced Oil Recovery (CO₂-EOR) technology guarantees substantial underground CO₂ sequestration while simultaneously boosting the production capacity of subsurface hydrocarbons (oil and gas). However, unreasonable CO₂-EOR strategies, encompassing well placement and well control parameters, will lead to premature gas channeling in production wells, resulting in large amounts of CO₂ escape without any beneficial effect. Due to the lack of prediction and optimization tools that integrate complex geological and engineering information for the widely used CO₂-EOR technology in promising industries, it is imperative to conduct thorough process simulations and optimization evaluations of CO₂-EOR technology. In this paper, a novel optimization workflow that couples the AST-GraphTrans-based proxy model (Attention-based Spatio-temporal Graph Transformer) and multi-objective optimization algorithm MOPSO (Multi-objective Particle Swarm Optimization) is established to optimize CO₂-EOR strategies. The workflow consists of two outstanding components. The AST-GraphTrans-based proxy model is utilized to forecast the dynamics of CO₂ flooding and sequestration, which includes cumulative oil production, CO₂ sequestration volume, and CO₂ plume front. And the MOPSO algorithm is employed for achieving maximum oil production and maximum sequestration volume by coordinating well placement and well control parameters with the containment of gas channeling. By the collaborative coordination of the two aforementioned components, the AST-GraphTrans proxy-assisted optimization workflow overcomes the limitations of rapid optimization in CO₂-EOR technology, which cannot consider high-dimensional spatio-temporal information. The effectiveness of the proposed workflow is validated on a 2D synthetic model and a 3D field-scale reservoir model. The proposed workflow yields optimizations that lead to a significant increase in cumulative oil production by 87% and 49%, and CO₂ sequestration volume enhancement by 78% and 50% across various reservoirs. These findings underscore the superior stability and generalization capabilities of the AST-GraphTrans proxy-assisted framework. The contribution of this study is to provide a more efficient prediction and optimization tool that maximizes CO₂ sequestration and oil recovery while mitigating CO₂ gas channeling, thereby ensuring cleaner oil production.

Injection–production coupling (IPC) technology holds substantial potential for boosting oil recovery and enhancing economic efficiency. Despite this potential, discussion on gas injection coupling, especially in relation to microscopic mechanisms, remains relatively sparse. This study utilizes microscopic visualization experiments to investigate the mechanisms of residual oil mobilization under various IPC scenarios, complemented by mechanical analysis at different stages. The research quantitatively assesses the degree of microscopic oil recovery and the distribution of residual oil across different injection–production methods. Findings reveal that during the initial phase of continuous gas injection (CGI), the process closely mimics miscible displacement, gradually transitioning to immiscible displacement as CO₂ extraction progresses. Compared to CGI, the asynchronous injection–production (AIP) method improved the microscopic oil recovery rate by 6.58%. This enhancement is mainly attributed to significant variations in the pressure field in the AIP method, which facilitate the mobilization of columnar and porous residual oil. Furthermore, the synchronous cycle injection (SCI) method increased microscopic oil recovery by 13.77% and 7.19% compared to CGI and AIP, respectively. In the SCI method, membrane oil displays filamentary and Kármán vortex street flow patterns. The dissolved and expanded crude oil tends to accumulate and grow at the oil–solid interface due to adhesive forces, thereby reducing migration resistance. The study findings provide a theoretical foundation for improving oil recovery in low-permeability reservoirs.

Subsequent CO₂ injection can enhance oil recovery and achieve carbon sequestration in shale reservoirs, which is crucial for energy sustainability and environmental protection. However, for continental sedimentary shale oil, the development process must consider the multiscale matrix-fracture structure and the impact of heterogeneous wettability on fluid-solid interactions. Moreover, the mechanisms of CO₂ miscibility and interfacial behavior in post-fracturing reservoirs remain unclear. In this study, a laminated shale micro-model with fracture based on scanning electron microscopy observations was designed, and the process of fracturing fluid flowback and subsequent CO₂ huff-n-puff were simulated. Results showed that forced imbibition primarily affects limestone layers, while spontaneous imbibition affects mudstone layers, contributing 89.3% and 10.7% to the affected area, respectively. The oil recovery mechanism of CO₂ is mainly influenced by pressure, transfer from displacement-carry at low pressure to dissolution-extraction, and eventually to diffusion-extraction in the miscible state. Additionally, before reaching miscibility, Taylor dispersion, Kelvin-Helmholtz instability, Rayleigh-Taylor instability, and Marangoni effects occur at the oil-CO₂ interface, leading to interfacial turbulent instability. Lastly, water huff-n-puff produces membrane and isolated droplet residual oil, while immiscible CO₂ breaks cluster residual oil into columnar residual oil. Miscible CO₂ enhances the recovery of various residual oils, improving oil recovery and facilitating CO₂ storage. This study provides insights for post-fracturing CO₂ huff-n-puff development of continental sedimentary shale oil and CO₂ sequestration, promoting energy utilization and environmental improvement.

In shale reservoirs, spontaneous imbibition is an important mechanism of fracturing fluid loss, which has an important impact on enhanced oil recovery and water resource demand. However, spontaneous imbibition behaviors are more complicated to characterize and clarify due to the nanoscale effects of the boundary slip, oil-water interfacial slip, and heterogeneous fluid properties caused by intermolecular interactions. A nanoscale multi-relaxation-time multicomponent and multiphase lattice Boltzmann method was applied to investigate the water imbibition into oil-saturated nanoscale space. The effects of pore size, fluid-surface slip, water film, oil-water interfacial slip, water bridge, and pore structures on the imbibition behaviors in a single nanopore were investigated. Then, the spontaneous imbibition behaviors in nanoporous media based on the pore scale microsimulation parameters obtained from the molecular simulation velocity results were simulated, and the effects of water saturations on imbibition behaviors were discussed. The results show that as the water saturation increases from 0 to 0.1, the imbibition mass in nanoporous media increases because of the oil-water interfacial slip and a completely hydrophilic wall. As water saturation continues to increase, the imbibition mass decreases gradually because the existence of water bridges impedes the water imbibition.

The microscale liquid flow in nanoscale systems considering slip boundary has been widely studied in recent years, however, they are limited to single-phase flow. As in nature, multicomponent and multiphase flows can also exist with non-zero slip velocities, such as oil/water slip flow in nanoporous shale. In this paper, a novel multicomponent-multiphase multiple-relaxation-time lattice Boltzmann method with a combinational slip boundary condition is developed to study the two-phase slip flow behaviors. The proposed combined slip boundary condition is derived from adjustments to the conventional diffusive Maxwell’s reflection and half-way bounce-back scheme boundary parameters, incorporating a compelled conservation requirement. With the analysis of simulations for the layer, slug, and droplet types of two-phase flow in single pores, and two-phase flow in porous media with complex wall geometry, it can be concluded that the proposed schemes of two-phase slip boundary conditions are particularly suitable for multicomponent and multiphase flow with a non-zero slip velocity. The proposed model can be used to determine relative permeability and simulate spontaneous imbibition in particular in shale reservoirs where those flow properties are hard-to-determine.

In this study, the multiphase multicomponent Shan-Chen lattice Boltzmann method is employed to analyze the impact of capillary force on oil-CO₂-water fluid flow and enhanced oil recovery. Various sizes of the single throat are designed to simulate the interaction between displacing and displaced phases as well as their mechanical equilibrium. Several sensitivities are taken into account, such as wettability, miscibility, interfacial tension, and pore aperture. Based on the objective reservoir conditions, supercritical CO₂ as an injection fluid is adopted to study the influence of different displacement patterns on the mechanical equilibrium in both homogenous and heterogeneous porous media, in which enhanced oil recovery is also quantitatively estimated. The results show that the water-alternating-gas injection pattern reduces the moving speed of the leading edge by increasing the swept area of the residual oil, and inhibits the breakthrough effect of the gas, making it the optimal displacement method in terms of the degree of oil production. Compared with the results of different displacement patterns, the enhanced oil recovery of water-alternating-gas injection is the highest, followed by supercritical CO₂ flooding after water flooding, and lastly, continuous supercritical CO₂ flooding.

Shale gas resources are widely distributed and abundant in China, which is an important field for strategic replacement and development of oil and gas resources. Shale gas reservoirs has adsorption gas, free gas. The structure of different scale media, such as organic pores, are difficult to describe. Therefore, flow behavior cannot be simulated by conventional method. In this paper, the micro-scale fluid migration in shale gas reservoirs was established in a single pore, which coupled surface diffusion, slip flow, and viscous flow. On this basis, the fractal scale relationship was applied to describe the distribution of pore radius, tortuosity, and surface roughness. Based on the comprehensive characterization of static structure characteristics of porous media, such as pore size distribution, pore shapes, tortuosity and surface roughness, and the dynamic pore size influenced by various stresses, the apparent porosity/permeability model of organic matter considering singlephase multi-migration mechanism was established. The gas migration in organic porous media was analyzed with the apparent porosity/permeability model. The results show that the small pores in organic matter are the main storage space of gas (more than 95% of the gas is stored in pores less than 10 nm), and the large pores are gas flow channel. At the same time, the apparent porosity/permeability model combined with conventional Darcy equation can be used to describe the single-phase gas flow in shale gas reservoirs.

Reorientation of fractures and high production improvement are observed and illustrated by fields and theoretical researches. During the refracturing treatments, it is important to get familiar with the enhanced oil recovery mechanics of fracture reorientation and distribution of residual oil. Mechanisms of fracture reorientation are discussed in order to design the parameters of reoriented fractures in numerical simulation. To furtherly evaluate the oil recovery of different angles of reoriented fractures, geological and numerical models are simulated using data of the actual reservoir with rhombus inverted nine spot well pattern, different angles of reoriented fracture are designed for both corner and edge wells to obtain the enhanced oil recovery. Results show that potential of production increase is highly impacted by the well pattern and angles of fractures and meanwhile impacted by distribution of residual oil and formation properties. Oil enhancement potential is significantly different with fracture reorientation angles in refracturing treatment: cumulative produced oil for corner wells is symmetrical around the angle of 0° and reaches the highest at the angles of positive and negative 23°; for the edge wells, it is also symmetrical around the angle of 0° while reaches the highest cumulative oil at the angles of positive and negative 90°. The difference shows that optimal angles exist for reoriented fractures during refracturing design and with proper induced reoriented fractures, more oil will be recovered for field restimulation treatments.