Jiangtao Zheng

The immiscible displacement behavior in porous media is crucial for oil recovery and subsurface remediation, yet how wettability influences this process across different pore structures remains unclear. Using a color-gradient lattice Boltzmann model, this study investigates immiscible displacement dynamics in porous media. Heterogeneous porous structures with various degrees of permeability were reconstructed using the quarter structure generation set algorithm, and wettability effects were analyzed with the contact angle set in the range of 30◦to 150◦. The numerical results showed that porous heterogeneity greatly affects the displacement efficiency via permeability-dependent flow pathway optimization. Enhanced efficiency was observed in high-permeability media through low-tortuosity channels, whereas low-permeability systems exhibited reduced efficiency due to capillary trapping in pores with lower flow capacity. Wettability alters displacement patterns via capillary forces – under hydrophilic condition, the displacing fluid preferentially enters smaller pores. Fractal dimension and Euler number were used to quantify flow heterogeneity, revealing that increased permeability reduces flow complexity and improves connectivity. Moreover, permeability heterogeneity and wettability interact to disrupt classical linear flow responses, leading to non-monotonic efficiency trends in lowpermeability systems. These findings highlight the importance of pore-scale multiphase flow in heterogeneous media and offer new insights for predicting wettability effects in subsurface flows. Document Type: Original article Cited as: Gong, W., Liu, Y., Dai, C., Zheng, J., Chen, Z., Zhao, W., Li, J. Non-monotonic effect of permeability and wettability on immiscible displacement dynamics in porous media. Capillarity, 2025, 17(2): 54-67. https://doi.org/10.46690/capi.2025.11.02

The pore‐scale interfacial dynamics including main‐meniscus flow and corner flow usually occurs in heterogeneous porous media and significantly affects the macroscopic multiphase flow process. Numerical research on the competition between main‐meniscus flow and corner flow remains challenging due to the ambiguity in pore‐scale interfacial dynamics and the complexity of upscaling these processes to porous media, given the substantial spatial and temporal scale differences. In this study, we proposed a critical capillary number () by considering the interplay of local capillary and viscous forces, which predicts transition from main‐meniscus flow‐dominated processes into corner flow‐dominated processes during the strong imbibition. The criterion was integrated into a dynamic network model to translate pore‐scale interfacial dynamics into multiphase flow patterns in porous media. The forced imbibition in heterogenous porous media under different Ca were simulated and compared to microfluidic experimental data. The comparison indicates that the dynamic competition between main‐meniscus flow and corner flow has a vital impact on displacement behaviors predicted by pore‐scale modeling, and our dynamic network model accurately captures the interfacial dynamics observed in microfluidic experiments. Moreover, the impact of interfacial dynamics on macroscopic multiphase flow pattern and displacement efficiency in heterogeneous porous media were addressed during strong imbibition under various viscosity ratios and capillary numbers. The phase diagram manifests a monotonic effect of viscosity ratio on displacement efficiency at high Ca due to the dominance of viscous fingering. A non‐monotonic effect of viscosity ratio is revealed at low Ca, which is ascribed into competition between corner flow and main‐meniscus flow. This study highlights the gap in the existing models of interfacial dynamics at pore scale, and provide an effective upscaling approach to investigate the multiphase flow in porous media.

Spontaneous imbibition (SI) of water driven by capillary forces within underground reservoir is recognized as a key mechanism influencing the oil and gas recovery. A comprehensive investigation at both the pore and core scales is essential for a deeper understanding of the SI behavior. This study employs continuous weighing measurement and in situ computed tomography (CT) scanning to quantitatively characterize the SI of de-ionized water into a dry synthetic rock sample with a permeability of 124 mD. At the core scale, the co-current SI weighing data showed two-stage imbibition behavior. Detailed analysis indicated that the imbibition rate slowed after the imbibition front advanced to the top of the sample. Pore-scale observations using in situ CT imaging confirmed that the imbibed masses at the end of the two stages were consistent with the weighing data. At the end of the first stage, the imbibed de-ionized water was distributed throughout the pore space. Subsequent imbibition in the second stage was attributed to increased saturation within the pores. Notably, the central region of the sample imbibed less de-ionized water than its peripheral counterpart of equivalent volume in the first stage, which was caused by the heterogeneous distribution of pores and rock matrix in the central region. The integration of core-scale measurements and pore-scale imaging provided insights into the mechanisms governing SI in porous rocks.

Understanding preferential flow in porous media holds substantial theoretical significance on the design and optimization of hydrocarbon exploitation in shale reservoir. Previous researches discussed the competition of imbibition front in layered porous media while the underlining mechanism for interfacial dynamics and induced displacement efficiency of multiphase flow remains ambiguous. In this paper, we investigate the spontaneous imbibition in dual permeable media and analyze the flux exchange between the neighboring porous zones with permeability contrast using dynamic pore network model. The impact of fluid viscosity ratio and permeability contrast on the spontaneous imbibition preference have been addressed, and finally a phase diagram for displacement efficiency has been obtained. The results reveal that the dual permeable structure enhances the invasion rate of wetting fluid in the low‐permeable zone and induces unstable displacement patterns, leading to reduction of the long‐term displacement efficiency. The interfacial pattern transition from stable displacement to unstable pattern in dual permeable media could be ascribed into the flux exchange between dual permeable zones, which shows a contrary impact on the fluid flow within the low‐permeable zone under favorable and unfavorable viscosity ratios. The permeability contrast in dual permeable media intensifies this impact during spontaneous imbibition. These results help us to understand the occurrence and mutual interaction of multiphase flow in layered porous media, and provide a theoretical guidance for the hydrocarbon exploitation in shale reservoir.

As a critical technological approach, multistage fracturing is frequently used to boost gas recovery in compact hydrocarbon reservoirs. Determining an ideal cluster distance that effectively integrates pre-existing natural fractures in the deposit creates a fracture network conducive to gas movement. Fracturing fluid leak-off also impacts water resources. In our study, we use a versatile finite element–discrete element method that improves the auto-refinement of the grid and the detection of multiple fracture movements to model staged fracturing in naturally fractured reservoirs. This computational model illustrates the interaction between hydraulic fractures and pre-existing fractures and employs the nonlinear Carter leak-off criterion to portray fluid leakage and the impacts of hydromechanical coupling during multistage fracturing. Numerical results show that sequential fracturing exhibits the maximum length in unfractured and naturally fractured models, and the leak-off volume of parallel fracturing is the smallest. Our study proposes an innovative technique for identifying and optimizing the spacing of fracturing clusters in unconventional reservoirs.