Han Wang

Summary: Understanding how acid-rock reactions alter pore systems and rock physics is essential for interpreting stimulation-induced property changes in tight carbonate reservoirs. In this study, we investigate the multiscale effects of acid-rock reaction on pore structure and elastic properties of tight carbonate rocks. X-ray diffraction is used to analyze mineral composition changes before and after acid treatment, while acoustic velocity measurements track the evolution of rock elastic properties. Scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), and fractal theory are employed to characterize pore structure modifications. The results show that acid treatment dissolves calcite and dolomite, increasing porosity while weakening the rock framework. This reduces acoustic velocity and dynamic elastic modulus in dry samples. The expanded pore space enhances fluid storage, amplifying wave velocity increases upon saturation. Physical property alterations initially intensify and then diminish with acid concentration. Microstructurally, acidization generates secondary pores and microfractures across all size ranges, with rising fractal dimension confirming structural complexity. In core tests, porosity enhancement peaks at an intermediate acid concentration under static conditions, whereas powder experiments show continuous improvement in pore volume (PV) and other pore structure parameters with concentration, because the larger reaction interface eliminates penetration limitations. Finally, based on the influence of acid concentration on the physical properties of tight carbonate rocks, we construct a modified Gassmann model that accounts for the acid concentration/porosity relationship. The model provides accurate predictions for the bulk modulus of reacted rocks across varying saturation conditions, offering a rock-physics basis for interpreting time-lapse seismic responses and optimizing matrix acidizing strategies in tight carbonate reservoirs.

Shale reservoirs are characterized by ultralow permeability and nanoscale confinement and exhibit significant challenges for efficient oil recovery and carbon storage. CO₂-displaced enhanced oil recovery offers multiple benefits for CO₂ sequestration and enhanced oil recovery due to its strong miscibility and adsorption affinity. However, the coupled mechanisms of diffusion and competitive adsorption remain inadequately understood under realistic pore-structure conditions. In this study, a pore-scale lattice Boltzmann model incorporating competitive adsorption, miscible diffusion, inlet/outlet boundary conditions, and microfractures is developed and validated against molecular simulations and diffusion theory. Then, the effects of injected pore volume, CO₂ adsorption capacity, Péclet number, and microfracture structures on CO₂ displacement behaviors are investigated. Results reveal two primary oil recovery mechanisms: surface adsorption-diffusion and bulk displacement-diffusion, whose dominance depends on flow and adsorption conditions. Strong adsorption capacity enhances recovery in enclosed pores via surface adsorption-diffusion but slows overall breakthrough. Low Péclet numbers yield uniform fronts, while high values result in preferential channelized flow and residual oil. Microfractures accelerate early-stage recovery via preferential channelized flow but reduce long-term efficiency due to cross-flow within the preferential channel. This study provides new mechanistic insights for optimizing CO₂ injection strategies in shale reservoirs to simultaneously enhance oil recovery and CO₂ storage.

CO₂ flooding has become a key technology for enhancing oil recovery in tight reservoirs, with great application potential. However, certain microscopic mechanisms of this technology still need to be further clarified. In this work, a multi-component and multi-phase lattice Boltzmann model based on the pseudopotential scheme is constructed considering different CO₂ flooding behaviors and verified for both immiscible and miscible phases, showing good agreement. On this basis, the effects of capillary numbers, extreme wetting at different velocities, Péclet numbers and injection patterns under fractured conditions on the CO₂ flooding process are systematically investigated. The results show that a larger capillary number enhances the displacement effect, whereas an excessively large value tends to cause viscous fingering, leading to accelerated CO₂ breakthrough. High-velocity extreme wetting conditions result in a higher displacement effect than low-velocity conditions. Moreover, an increase in displacement velocity weakens the wetting effect dominated by capillary force, thereby reducing the difference in oil recovery observed under high-velocity extreme wetting conditions. Different Péclet numbers dominate different fluid transport mechanisms. When the Péclet number is around the unity, the synergistic effects of molecular diffusion and viscous flow are balanced, jointly dominating fluid transport. The pore-fracture combined injection mode integrates the advantages of pore and fracture injections and effectively delays CO₂ breakthrough in the fracture system, resulting in an optimal displacement effect. This model can be extended to research on multiphase flow in tight and shale reservoirs as well as CO₂ geological sequestration. Document Type: Original article Cited as: Liu, J., Xiao, D., Li, J., Cheng, L., Wang, H., Cai, J. Enhanced oil recovery via CO₂ flooding in tight reservoirs: A pore-scale analysis. Advances in Geo-Energy Research, 2025, 17(2): 162-175. https://doi.org/10.46690/ager.2025.08.07

Shale reservoirs are characterized by tightness, extremely low permeability, and poorly developed natural fractures, typically requiring hydraulic fracturing technology to enhance oil recovery. Understanding displacement mechanisms and their influencing factors in fracture-matrix coupled media holds significant importance for optimizing hydrocarbon recovery. This study employed the lattice Boltzmann method with a fracture-matrix coupling model to simulate forced imbibition under varying wettability conditions and capillary numbers, systematically investigating the influence mechanisms of these parameters on recovery efficiency. The results demonstrated that enhanced water-wet characteristics in the matrix pore structure correlate with improved ultimate hydrocarbon recovery. During initial forced imbibition stages, similar oil recovery rates across different wettability conditions were observed due to water phase channeling through large pores. However, distinct recovery differentials gradually emerged with prolonged imbibition. In fracture-coupled models, the pronounced water channeling effect through fractures minimized wettability-induced differences in oil recovery. Furthermore, capillary number exhibited more substantial control over water phase flow paths and oil displacement efficiency compared to wettability, particularly in governing the preferential infiltration patterns during forced imbibition processes.

Shale formations serve as primary reservoirs for natural gas and emerging candidates for hydrogen storage, where the wetting behaviors of organic matter (i.e., kerogen) play a critical role in fluid retention and transport. This study employed molecular dynamics simulations to investigate the pressure-dependent wettability of kerogen surfaces in H2 and CH4 environments under geological conditions (333 K, 10-100 MPa). Results reveal distinct gas-specific mechanisms governing wettability evolution. For CH4-H2O systems, increasing pressure induces a wettability transition from weakly water-wet to gas-wet due to the strong interaction between CH4 and the kerogen surfaces, which results in a smaller gas-solid interfacial tension compared with liquid-solid interfacial tension . Meanwhile, both the reduced gas-liquid and gas-solid interfacial tension contributes to a linear rise in contact angles (88° to 119°). In contrast, H2 exhibits weaker interactions with the kerogen surfaces and experiences a minimal decrease in gas-liquid interfacial tension, thus presenting persistently water-wet characteristics (53° to 69.5°) even at 100 MPa. Crucially, the Young-Laplace equation remains valid at the nanoscale, as evidenced by direct capillary pressure measurements aligning with theoretical predictions, confirming classical interfacial thermodynamics govern nanoconfined fluid behavior. These mechanistic insights elucidate how gas-specific molecular interactions dictate shale wettability, providing a physicochemical basis for optimizing CH4 recovery through pressure-managed wettability alteration and ensuring H2 storage security in hydrophobic kerogen network. Document Type: Original article Cited as: Zhang, M., Huang, J., Wang, H., Niu, W. Wetting behaviors of water on kerogen surfaces from molecular level: Implication for gas extraction and hydrogen storage in shale. Capillarity, 2025, 14(3): 72-81. https://doi.org/10.46690/capi.2025.03.02

Acid fracturing has become a crucial technology for developing carbonate reservoirs, playing a particularly significant role in enhancing oil and gas recovery. However, the retention and flowback behaviors of residual acid in fractured-vuggy carbonate reservoirs after acid fracturing remain poorly understood, and this uncertainty significantly hinders the efficient development of such reservoirs. In this study, the micro-computed tomography images of carbonate rocks were used to extract actual fracture–vug structures. A microscopic flow model for fractured-vuggy carbonate reservoirs was then designed and fabricated using wet etching techniques. Microfluidic experiments were performed to investigate the invasion and flowback behavior of residual acid within these reservoirs. This study introduces a novel approach by integrating actual fracture-vuggy structures from micro-CT images into a microfluidic model, providing a more realistic representation of fractured-vuggy carbonate reservoirs compared to previous studies that relied on simplified or idealized geometries. Additionally, the invasion coefficient (the ratio of acid invaded area to total pore area) and flowback rate (the proportion of residual acid expelled during flowback) were introduced to quantitatively assess the efficiency of acid invasion and flowback under varying flow rates, viscosities, and the presence or absence of surfactants. The results demonstrate that the invasion coefficient of residual acid increases with the injection rate, while the flowback rate decreases as the injection rate is reduced. A higher viscosity of the oil phase hinders acid invasion and results in slower flowback due to increased flow resistance in the micro model. However, the final flowback rate is higher with a higher viscosity oil phase compared to a lower viscosity phase. The addition of surfactants enhances the efficiency of acid invasion and flowback, increasing the invasion coefficient by up to 5% and the flowback rate by up to 3%.

The imbibition process plays a crucial role in the development of shale reservoirs, particularly during the volume fracturing and water injection development phases. This process significantly influences the production capacity of shale and also serves as a essential parameter for assessing reservoir performance. Clay minerals contribute to the formation of numerous micro-pores and micro-fractures, exhibit strong plasticity and are prone to swelling. The unique structures and properties of clay minerals have a profound impact on shale imbibition. This review analyzes the effects of clay minerals on imbibition from different perspectives, finding that the effect is closely related to the total amount of clay minerals, as well as to specific mineral types and content. Clay minerals exhibit a dual impact on imbibition, which can either facilitate imbibition by promoting micro-fractures formation or hinder it by reducing pore throats and migrating to block flow paths due to swelling. While capillary action is usually considered the main mechanism for fluid displacement during the imbibition, the osmotic pressure formed by clay minerals can also serve as a driving force for imbibition, positively contributing to shale oil and gas recovery. This review aims to provide a comprehensive understanding of the role of clay minerals on the imbibition, providing a theoretical foundation and practical guidance for future research and efficient development of shale reservoirs. Document Type: Invited review Cited as: Wang, L., Wang, H., Xia, X., Zhao, F., Masoodi, R., Xia, Y. The effects of clay minerals on imbibition in shale reservoirs: A review. Capillarity, 2025, 14(1): 13-22. https://doi.org/10.46690/capi.2025.01.02

Due to the existence of fracturing fluid and formation water in shale gas reservoirs, the coexistence of gas and water in nanopores is prevalent. The pore water in the reservoir, on the one hand, affects gas flow behavior and permeability. On the other hand, it blocks pore throats and occupies adsorption sites on the pore surface, consequently reducing the gas adsorption capacity. The occurrence of pore water in shale reservoirs holds significant importance for shale gas resources exploration and development. In this paper, the shale from the Longmaxi Formation, Sichuan Basin was selected as the research target. The content and micro-distribution behavior of pore water were evaluated through centrifugation-nuclear magnetic resonance experiment and theoretical model. The results demonstrated that the content of free water would be underestimated by the experiment, with 2.55%-6.80% lower than that calculated by theoretical model. 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Gas adsorption behavior in shale reservoirs: Insights from molecular scale

Micro- and nanoscale flow mechanisms in porous rocks based on pore-scale modeling