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.

Adsorbed gas confined in nanopores is a significant component of shale gas, and understanding the mechanisms of gas adsorption in shale nanopores is crucial for enhancing shale gas recovery and carbon dioxide geological sequestration. Due to the nanoscale pore sizes, complex pore structures, and diverse mineral types, adsorption experiments have a limited capacity to elucidate the microscopic mechanisms of gas adsorption. Compared to expensive adsorption experiments, molecular simulation methods can not only simulate reservoir in-situ conditions but also reveal the adsorption mechanisms from the molecular scale perspective. This work provides a brief review for the characteristics of methane adsorption in shale inorganic minerals and organic matter. Additionally, the competitive adsorption behavior of methane and carbon dioxide in shale is introduced to clarify the potential of shale reservoirs for carbon dioxide geological storage. Finally, the challenges faced by molecular simulation methods in gas adsorption research are discussed.

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. Moreover, due to the limitations of nuclear magnetic resonance experiment, the adsorbed water in mesopores and macropores might be mistakenly identified as that in smaller pores. As a result, the theoretical model is more applicable for characterizing the micro-distribution behavior of pore water than the origin nuclear magnetic resonance data.

Fluids flow within microporous and nanoporous rocks involves several industrial processes such as enhanced oil recovery, geological CO₂ sequestration, and hydraulic fracturing. However, the pore structure of subsurface rocks is complex, and fluid flow is influenced by strong fluid-fluid and fluid-solid interactions, including wettability, interfacial tension, and slip effects. Characterizing this flow processes is costly and challenging through experimental techniques. At meanwhile, pore-scale simulations have been widely employed to investigate complex flow behaviors within microporous and nanoporous media. This work investigates the applications of pore-scale simulation methods for characterizing flow processes in porous rocks considering microscale and nanoscale effects. Two mainstream simulation methods, pore network modeling and direct numerical simulation, are introduced. Their application scenarios encompass immiscible flow, as well as miscible and near-miscible flow involving CO₂ enhanced recovery. Additionally, some explorations of single-phase and multiphase flow processes within nanoporous media are described. Finally, future development of pore-scale simulations is discussed, with a focus on complex transport phenomena involving diffusion, reactions, and dissolution.

This paper explores significant advancements in the numerical simulation of multiphase, multi-physics flows within underground reservoirs, driven by the necessity to understand and manage complex geological and engineered systems. It delves into the latest research in numerical simulation techniques at both the pore and Darcy scales, emphasizing the integration of traditional methods with emerging machine learning technologies. Key simulation methods reviewed at the pore scale include the lattice Boltzmann method, level set method, phase field method, and volume of fluid method, each offering unique advantages and facing limitations related to computational efficiency and stability. Special attention is given to spontaneous imbibition, where capillary action facilitates the movement of wetting fluids into porous media. Discussions at the Darcy scale focus on macroscopic simulation methods that simplify microscale interactions but face challenges in accurately modeling the multiscale and heterogeneous nature of fractured media. Furthermore, an overview of the basic principles, limitations, and potential of integrating machine learning algorithms with traditional numerical methods emphasizes their role in enhancing simulation efficiency and stability. Future research will aim to address existing challenges and maximize the use of advanced computational technologies to refine the accuracy, efficiency, and practical applicability of multiphase and multifield flow simulations in underground reservoirs.

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.

As common physical phenomena in porous media,capillarity behaviors exist in many engineering applications and natural science fields. The experimental,theoretical and numerical research on capillarity in porous media has lasted for more than a century,and the research results have been widely used in various fields,such as the development of conventional and unconventional resources. However,although the research has made great progress,the complex imbibition mechanism poses new challenges to us. The 1st National Conference on Imbibition Theory and Application in Porous Media was held in Beijing from April 22 to 24,2023, to gather researchers who are interested in imbibition research,exchange the latest progress and achievements in the field of imbibition in porous media,and discuss research hotspots and difficulties.