In this article, a new method is proposed to quantificationally evaluate the effect of pore heterogeneity on the adsorption behavior of fluids in nanopores. First, the assumptions of furrowed, sinusoidal, and ravine pore surfaces are proposed to represent the heterogeneous nanopores in shale. Under the assumptions, a multicomponent potential theory of adsorption (MPTA) is coupled with Peng–Robinson equation of state (PR EOS) to model the adsorption behavior of hydrocarbons in nanopores. And, the geometrical and chemical heterogeneities in shale nanopores are, respectively, simulated by a spatial alteration and an amplitude deformation on potential energy. The fluid–fluid interaction is modeled by PR EOS, and the fluid‐pore wall surface interaction is simulated by a Steel 10‐4‐3 model for slit‐like nanopores and by a modified Lennard–Jones (LJ) 12‐6 model for cylindrical ones. Thereafter, the results of our theory are compared against the experimental data of shale rocks to validate its accuracy.

Nanoscale pores are widely developed in tight oil, and the scale effect significantly affects the dynamic behavior of crude oil molecules at different positions in the nanopores. The molecular dynamics simulation method was used to study the mechanism of threshold pressure of tight oil molecules at different positions in quartz and calcite nanopores and the influence of pore radius on threshold pressure. The results show that the mobilizing of crude oil molecules at different positions in nanopores is mainly affected by liquid−solid interactions and intermolecular friction. The interactions between naphthenic acids and pore walls are the main contributing factor to the threshold pressure of boundary crude oil molecules. Van der Waals interaction and weak hydrogen bonds mainly contribute to the bonding of naphthenic acids with quartz walls, and strong electrostatic interaction and strong hydrogen mainly contribute to that with calcite walls. Except for the boundary layer, the threshold pressure of other layers relates to the interactions between saturated hydrocarbon, aromatic hydrocarbon, and adjacent layers as well as the molecular friction, among which friction between the saturated hydrocarbon and the adjacent molecules is dominant. It is challenging for crude oil to mobilize in quartz pores smaller than 3 nm. However, when the quartz pore width exceeds 7 nm, the mobilizing law of crude oil is scarcely affected by the pore width. The mobilizing laws of crude oil differ in calcite pores smaller than 11 nm, while that stays nearly the same in pores larger than 11 nm. Finally, a prediction model for the threshold pressure of tight oil molecules at different positions in quartz and calcite nanopores is proposed, which provides theoretical guidance for precise control of working fluid properties to improve tight oil recovery.

Formation water (FW) and fracturing fluid (FF) significantly affect the adsorption rules of CH4 on a shale surface. To clarify the impact rules and micromechanisms of FW and FF on CH4 adsorption, isothermal adsorption experiments of CH4 on different shale minerals with different equilibrium water were conducted. Then, the corresponding adsorption models were constructed by Grand Canonical Monte Carlo (GCMC) simulation to perform adsorption simulation after matching experiments. Finally, molecular dynamic (MD) simulation was carried out to study the micromechanisms of FW and FF affecting CH4 adsorption on different shale minerals. The results show that the adsorption capacity of organic matter to CH4 is much stronger than that of other minerals. Compared to dry conditions, the adsorption capacity of organic matter, smectite, illite, and total shale with FW (S w ≈ 15%) decreases to 65, 45, 70, and 55%, respectively. The impact of FF on CH4 adsorption capacity is more significant than FW. The adsorption capacity decreases to 45, 30, 50, and 45% for organic matter, smectite, illite, and total shale with FF (S w ≈ 15%), respectively. FW molecules inhibit CH4 adsorption by occupying adsorption sites on mineral surfaces. However, the HPAM in FF completely covers the mineral surface to compress adsorption space and hinder CH4 adsorption. Although water molecules in both FW and FF occupy part of the adsorption sites on organic matter, the left sites can still absorb large amounts of CH4. It provides theoretical guidance for the efficient development of shale gas.

The breakage and deep plugging law of deformable gel particle (DGP) in porous media are not clear. In this study, the flow experiments of DGP were carried out, the changes of residual resistance coefficient (RRC), DGP size and concentration along the way were measured, and the breakage and plugging law of DGP was quantitatively characterized. The results show that the passage after breakage is the main migration behaviors of DGP, and DGP are reduced by half in front of the porous media. Breakage is an important reason for the continuous decrease of concentration, particle size and RRC. However, the DGP can plug in deep of the porous media after breaking. The higher the injection rate or the larger the DGP size, the faster the breakage along the injection direction, and the worse the deep plugging ability. The empirical model can be used to optimize the DGP parameters in oil field.

The presence of strongly sealed faults can divide a reservoir into complex fault blocks, while partially sealed faults can be created by farewell faults within each block, leading to more intricate fluid migration and residual oil distribution. However, oilfields often overlook these partially sealed faults, focusing instead on the entire fault block, which can impact the efficiency of the production system. In addition, the current technology struggles to quantitatively describe the evolution of the dominant flow channel (DFC) during the water-flooding process, especially in reservoirs with partially sealed faults. This limits the ability to formulate effective enhanced oil recovery measures during the high water cut stage. To address these challenges, a large-scale sand model of a reservoir with a partially sealed fault was designed, and water flooding experiments were conducted. Based on the results of these experiments, a numerical inversion model was established. By combining percolation theory and the physical concept of DFC, a new method was proposed to quantitatively characterize DFC using a standardized flow quantity parameter. The evolution law of DFC was then studied, considering the variations of volume and oil saturation of DFC, and the water control effect of different measures was evaluated. The results revealed that, during the early stage of water flooding, a vertical uniform dominant seepage zone formed near the injector. As the water was injected, DFCs from the top of the injector to the bottom of the producers gradually formed in the unoccluded area. However, DFC was only formed at the bottom in the occluded area. During water flooding, the volume of DFC in each area gradually increased and then tended to stabilize. The development of the DFC in the occluded area lagged behind due to gravity and fault occlusion, leading to the formation of an unswept area near the fault in the unoccluded area. The volume of the DFC in the occluded area was the slowest, and the volume was the smallest after stabilization. Although the volume of the DFC near the fault in the unoccluded area grew the fastest, the volume was only higher than that in the occluded area after stabilization. During the high water cut period, the remaining oil was mainly distributed in the upper part of the occluded area, the area near the unoccluded fault, and the top of the reservoir in other areas. The plugging of the lower part of the producers can increase the volume of DFC in the occluded area, and the DFC moves up throughout the entire reservoir. This improves the utilization degree of the remaining oil at the top of the entire reservoir, but the remaining oil near the fault in the unoccluded area remains inaccessible. The combination of producer conversion, drilling infill wells, and producer plugging can alter the injection−production relationship and weaken the occlusion effect of the fault. The occluded area forms a new DFC, leading to a significant increase in the recovery degree. The deployment of infill wells near the fau...