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 fault in the unoccluded area can effectively control the area and improve the utilization of the remaining oil.

Pan-connected interlayers are widely present in oil reservoirs, forming flow channels at different positions. However, conventional profile control agents struggle to plug deep interlayer channels in reservoirs, limiting the swept volume of injected water. Additionally, a clear methodology for physically simulating pan-connected reservoirs with interlayer channels and calculating interchannel flow rates remains lacking. In this study, a physical model of pan-connected interlayer reservoirs was constructed to carry out deformable gel particles (DGPs) plugging experiments on interlayer channels. A mass conservation-based flow rate calculation method for interlayer channels with iterative solution was proposed, revealing the variation law of interlayer channel flow rates during DGP injection and subsequent water flooding. Finally, oil displacement and DGP profile control experiments in pan-connected interlayer reservoirs were conducted. The study shows that during DGP injection, injected water enters the potential layer through interlayer channels in the middle and front of the water-channeling layer and bypasses back to the water-channeling layer through channels near the production well. With the increase in DGP injection volume, the flow rate of each channel increases. During subsequent water flooding, DGP breakage leads to a rapid decline in its along-path plugging capability, so water bypasses back to the water-channeling layer from the potential layer through all interlayer channels. As the DGP injection volume increases, the flow rate of each channel decreases. Large-volume DGPs can regulate interlayer channeling reservoirs in the high water cut stage. Its effectiveness mechanism involves particle migration increasing the interlayer pressure difference, which drives injected water to sweep from the water-channeling layer to the potential layer through interlayer channels, improving oil recovery by 19.74%. The flow characteristics of interlayer channels during DGP injection play a positive role in oil displacement, so the oil recovery degree in this process is greater than that in the subsequent water flooding stage under each injection volume condition. The core objective of this study is to investigate the plugging mechanism of DGPs in pan-connected interlayer channels of high-water-cut reservoirs, establish a method to quantify interlayer flow rates, and reveal how DGPs regulate flow redistribution to enhance oil recovery.

Due to the growing problem of depletion of non-renewable resources such as natural gas and coal in the traditional power generation model, new energy sources such as wind and solar are being used more and more in the grid. However, the emergence of distributed power sources also brings many instability factors to the grid: temperature, humidity, light intensity and other external environmental conditions can cause disturbance to the grid. Therefore, new energy microgrids with energy storage elements that can regulate the internal energy flow of the system have emerged. This paper establishes a simulation model for the islanding operation of the scenery storage microgrid. A hybrid energy storage method is proposed to stabilize the voltage at the DC bus of the system by separating the voltage signal through a low-pass filter to control the power generated by the scenic power system to ensure a stable supply of energy to the load side during islanding operation. Through the simulation, it is verified that the model can meet the needs of the load side and supply energy stably in islanding mode.

To solve the problems of high injection pressure and low water injection in an ultra-low-permeability reservoir, nanoemulsion was injected to reduce the surface interfacial tension, change the wettability, and achieve the purpose of depressurization. In this paper, the surface and interfacial tension, wettability properties, and particle size distribution characterization of nanoemulsion were determined, and the performance of nanoemulsion was evaluated by laboratory experiments such as core displacement. At the same time, the depressurize and augmented injection mechanism of the nanoemulsion was studied through a scanning electron microscope. The experiment shows that the nanoemulsion system has good compatibility with brine. With the increase in temperature, the surface and interfacial tension does not change, and there is no precipitation. And the system can reduce the oil–water interfacial tension to about 1 mN·m⁻¹ under the best conditions. By measuring the wettability angle of nanoemulsion at the concentration of 0.1% to 0.5%, which can adjust the wettability of the rock surface, the hydrophilicity is weakened. The depressurization performance of nanoemulsion under different injection rates, concentrations, and slug sizes was also compared through core displacement experiments, to provide reasonable experimental support for field operations. In the most reasonable case, the depressurization rate after using nanoemulsion can reach 16.78%.