Zhilin Cheng

Spontaneous imbibition is an important process in many subsurface multiphase-flow applications, yet the pore-scale mechanisms of co-current spontaneous imbibition remain incompletely understood. We employ a quasi three-dimensional (3D) color-gradient multiple-relaxation-time lattice Boltzmann method to simulate co-current spontaneous imbibition in regular and complex porous media over a range of viscosity ratios M defined as μnw/μw (nonwetting/wetting). Interfacial tension and contact angle are varied in combinations that maintain a constant σ cos θ. Results show that the final recovery factor varies nonmonotonically with the σ–θ combination, and the ranking of the three cases changes with viscosity ratio and pore structure. Mirzaei time scaling collapses the recovery trajectories onto a common kinetic trend during the main front-propagation stage, and the kinetic similarity does not imply equivalent final states. As the viscosity ratio increases, the displacement front shifts from relatively continuous lateral sweep to selective channel advance. Pore structure further controls branch competition, bypassing, and the distribution of residual nonwetting phase. A Saffman–Taylor-based linear stability interpretation indicates that higher interfacial tension suppresses short-wavelength perturbations, although the resulting displacement pattern remains jointly controlled by wettability and pore accessibility. Analyses of capillary pressure and fluid–fluid interfacial area further show that the in-plane curvature response and interfacial topology remain nonunique even at identical σ cos θ. These findings define the applicability limits of equivalent macroscopic capillary driving and provide a mechanistic basis for structure-specific selection of interfacial parameters and improved continuum-scale closure models.

Metaheuristic algorithms can fail to balance global exploration and local exploitation, occasionally becoming trapped in suboptimal regions on highly multimodal problems. The Groupers and Moray Eels (GME) algorithm, inspired by the associative hunting strategies of marine predators, provides a cooperative optimization framework. However, the sequential interaction phases of GME can fail to maintain diverse topological coverage across heavily constrained landscapes. To address these limitations, we propose an enhanced variant, GPS-CC-GME. The approach improves the initial agent distribution by deploying a number-theoretic Good Point Set (GPS) generation protocol to establish a uniformly dispersed starting space. In addition, algorithmic stagnation is addressed through a dual-crossover search architecture. A horizontal crossover stage enforces information sharing among randomized agents to sustain global diversity, and a vertical crossover phase isolates specific dimensional vectors within individual agents for localized fine-tuning. We evaluated the proposed model on the CEC2017 benchmark suite, where it secured the highest overall ranking compared to the baseline GME and several standard metaheuristics. GPS-CC-GME was then applied to a high-dimensional optimization scenario for petroleum reservoir production. The algorithm yielded higher Net Present Value (NPV) metrics than the canonical framework. The results indicate that embedding deterministic initialization and bidirectional mutation operators into multipredator models can improve search outcomes in non-linear engineering tasks.

Summary: To enable the quantitative evaluation of oil recovery and mobilization across different pore types using the nuclear magnetic resonance (NMR) transverse relaxation time (T2) technique, high-concentration manganese(II) chloride (MnCl2) brines are frequently used to suppress the hydrogen signal from water. However, the potential effects of MnCl2 on the interfacial properties of the crude oil/brine/rock system remain largely uncharacterized. In this study, we combine contact angle measurements with molecular dynamics (MD) simulations to investigate the impact of high-concentration MnCl2 on wettability at both macroscopic and molecular scales. Our findings demonstrate that the influence of high-concentration MnCl2 is minimal, as indicated by the contact angle change obtained from both the contact angle measurements and molecular simulations. High-concentration MnCl2 reduces the density of water molecules near the quartz surface while simultaneously increasing the local concentration of crude oil, particularly its acidic components, which results in a slight increase in the contact angle across different brine compositions, suggesting a trend toward reduced water affinity. However, this change is insufficient to induce a wettability alteration. Compared with the systems without MnCl2, manganese(II) (Mn2+) ions exhibit a negligible impact on the ionic distribution near mineral surfaces. Moreover, the strong hydration energy of Mn2+ disrupts hydrogen bonding, both among water molecules and between water molecules and surface hydroxyl groups on quartz, thereby contributing to the observed slight increase in contact angle. Overall, the findings suggest that high-concentration MnCl2 exerts only a minor effect on wettability and is unlikely to significantly influence imbibition-driven oil recovery.

The characterization of oil and water displacement in porous media often relies on the capillary number (Ca = μv/σ cos θ). However, limited investigations have been conducted to explore the relative significance of interfacial tension and wettability in determining oil recovery, particularly under the imbibition mode. To address this research gap, the modified color gradient lattice Boltzmann method has been employed. This study aims to systematically investigate the transient imbibition characteristics, pore-scale events, and morphological features of the two-phase distribution in the matrix, all under the same capillarity but varying capillary numbers. The obtained results indicate that, for a given capillary number, a more water–wet condition generally leads to a higher imbibition recovery. Conversely, the influence of capillary number on oil recovery is complex and contingent upon the capillarity value, i.e., the interfacial tension between oil and water. Additionally, the oil recovery data from all cases have been effectively fitted using the Minkowski functionals, demonstrating a linear correlation. Moreover, an attempt has been made to elucidate the mechanism behind the varying oil recovery observed in different capillarity combinations. This analysis considers factors such as energy conversion, the transient change of the ratio of viscous force over capillarity, and the capillary valve effect. The findings of this study contribute to our understanding of the use of chemical agents to enhance oil recovery and provide valuable insights for determining key two-phase parameters in reservoir simulations.

Currently, research on enhancing imbibition oil recovery in tight oil reservoirs through the ion-tuning technique remains limited. Two critical parameters for capillary imbibition are the wettability and interfacial tension between oil and water. In this investigation, we manipulate the properties of two types of formation water for both aged and unaged samples by diluting brine and altering ion composition. Subsequently, we employ captive and pendant-drop methods to assess rock wettability and interfacial tension under varied brine conditions. Additionally, we elucidate the primary mechanisms underlying changes in rock wettability and interfacial tension. Meanwhile, we analyze capillarity characteristics and assess the relative significance of wettability and interfacial tension. Results indicate that there is a critical interfacial tension with progressive dilution of two types of formation water. However, modifying ion composition leads to a complex trend in interfacial tension, which can be explained qualitatively through the Gibbs adsorption isotherm. For unaged samples, the contact angle demonstrates a pronounced water-wet characteristic, showing a nonmonotonic trend with respect to dilution times. Remarkably, the rock surface exhibits the strongest water-wet, particularly evident in the case of FW-10, largely influenced by variations in interfacial tension. Conversely, aged samples demonstrate strong oil-wet, with a critical salinity resulting in the lowest contact angle, while altering brine ion types can alter rock wettability from strongly oil-wet to intermediate-wet, which is not sufficient to result in the wettability alteration. The removal of multivalent cations is proposed as the most effective method for wettability modification. Furthermore, capillarity variations among different brine cases are primarily contingent upon contact angle changes, and interfacial tension does not have a significant change when regulating the brine properties. Consequently, we emphasize the significance of wettability in the adoption of ion-tuned brine techniques for tight oil reservoirs. Overall, our study underscores the potential of reasonably regulating brine properties to enhance capillarity and, thereby, improve imbibition oil recovery.

The microscopic pore structure of tight sandstone reservoirs significantly influences the characteristics of CO₂ flooding after water flooding. This research was conducted using various techniques such as casting thin sections, high-pressure mercury injection, scanning electron microscopy, nuclear magnetic resonance (NMR) testing, and a self-designed high-temperature and high-pressure microscopic visualization displacement system. Three types of cores with different pore structures were selected for the flooding experiments and the microscopic visualization displacement experiments, including CO₂ immiscible flooding, near-miscible flooding, and miscible flooding after conventional water flooding. The characteristics of CO₂ flooding and the residual oil distribution after water flooding were quantitatively analyzed and evaluated. The results show the following: (1) During the water flooding process, the oil produced from type I and type III samples mainly comes from large and some medium pores. Oil utilization of all pores is significant for type II samples. The physical properties and pore types have a greater impact on water flooding. Type I and II samples are more suitable for near-miscible flooding after water flooding. Type III samples are more suitable for miscible flooding after water flooding. (2) In CO₂ flooding, oil recovery increases gradually with increasing pressure for all three types of samples. Type II core samples have the highest recovery. Before miscibility, the oil recovered from type I and type II samples is primarily from large pores; however, oil recovery mainly comes from medium pores when reaching miscibility. As for the type III samples, the oil produced in the immiscible state mainly comes from large and medium pores, and the enhanced oil recovery mainly comes from medium and small pores after reaching the near-miscible phase. (3) It can be seen from the microscopic residual oil distribution that oil recovery will increase as the petrophysical properties of the rock model improve. The oil recovery rate of near-miscible flooding after water flooding using the type II model is up to 68.11%. The oil recovery of miscible flooding after water flooding with the type III model is the highest at 74.57%. With increasing pressure, the proportion of flake residual oil gradually decreases, while the proportion of droplet-like and film-like residual oil gradually increases. Type II samples have a relatively large percentage of reticulated residual oil in the near-miscible stage.

The microscopic pore structure of tight sandstone reservoir significantly influences the characteris-tics of CO2 flooding after water flooding. The research was conducted using various techniques such as casting thin sections, high pressure mercury injection, scanning electron microscopy, Nu-clear magnetic resonance (NMR) testing, and a self-designed high-temperatures and high-pressures microscopic visualization displacement system. Three type cores with different pore structures were selected for the flooding experiments and the microscopic visualization displace-ment experiments, including CO2 immiscible flooding, near-miscible flooding, and miscible flood-ing after the conventional water flooding. The characteristics of CO2 flooding and the residual oil distribution after water flooding were quantitatively analyzed and evaluated. The results show that: (1) During the water flooding process, the oil produced from type I and type III samples mainly comes from large and some medium pores. Oil utilization of all pores is significant for type II samples. The physical properties and pore types have a greater impact on water flooding. Type I and II samples are more suitable for near-miscible flooding after water flooding. Type III samples are more suitable for miscible flooding after water flooding. (2) In the CO2 flooding, oil recovery increases gradually with increasing pressure for all three types of samples. Type II core samples have the highest recovery. Before miscibility, the oil recovered from type I and type II samples was primarily from large pores, however, the oil recovery mainly comes from medium pores when reaching miscibility. As for the type III samples, the oil produced in the immiscible state mainly comes from large and medium pores, and the enhanced oil recovery mainly comes from medium and small pores after reaching the near-miscible phase. (3) It can be seen from the microscopic re-sidual oil distribution that oil recovery will increase as the petrophysical properties of the rock model improve. The oil recovery of near-miscible flooding after water flooding regarding the type II model is up to 68.11%. The oil recovery of miscible flooding after water flooding about type III model is the highest at 74.57%. With increasing pressure, the proportion of flake residual oil grad-ually decreases, while the proportion of droplet-like and film-like residual oil gradually increases. Type II samples have a relatively large percentage of reticulated residual oil in the near-miscible stage.

Hydraulic fracturing technology significantly enhances the productivity of shale oil and gas reservoirs. Nonetheless, the infiltration of fracturing fluid into shale formations can detrimentally affect the microscopic pore structure, thereby impairing the efficacy of hydraulic stimulation. In this study, nuclear magnetic resonance (NMR) technology was utilized to conduct high-pressure soaking tests on shale specimens treated with EM30⁺ + guar gum mixed water and CNI nano variable-viscosity slickwater, where various concentrations of a drag reducer were utilized. Additionally, the differences in porosity, permeability, mineral composition, and iron ion concentration before and after the measurements were compared, which were used to analyze the influence on the shale’s microscopic pore structure. It features a reduction in the total pore volume after the interaction with the fracturing fluid, with the pore-throat damage degree, porosity damage degree, and permeability damage degree ranging from 0.63% to 5.62%, 1.51% to 6.84%, and 4.17% to 19.61%, respectively. Notably, EM30⁺ + guar gum mixed water exhibits heightened adsorption retention, alkaline dissolution, and precipitation compared to CNI nano variable-viscosity slickwater, rendering it more deleterious to shale. Moreover, higher concentrations of drag reducers, such as EM30⁺ or CNI-B, predominantly result in damage to the shale’s micropores. Shale compositions characterized by lower content of quartz and elevated proportions of clay minerals and iron-bearing minerals showcase augmented mineral dissolution and precipitation, consequently intensifying the shale damage. The hydration expansion of mixed-layer illite/smectite profoundly diminishes the core permeability. Consequently, the mechanisms underpinning the damage inflicted on shale’s microscopic pore structure primarily involve fracturing fluid adsorption and retention, mineral dissolution, and precipitation, such as clay minerals and iron-containing minerals.