Fractured horizontal wells have been widely used to develop unconventional oil and gas reservoirs. In previous studies, most studies on the transient pressure behavior of multistage horizontal wells were based on the assumption of single porosity medium, in which the coupling relationship of natural fractures and artificial fractures was not taken into account or artificial fractures were assumed to be infinitely conductive. In this paper, the fracture is finite conductive, which means that there is flow resistance in the fracture. Based on point-source method and superposition principle, a transient model for multistage fractured horizontal wells, which considers the couple of fracture flow and reservoir seepage, is built and solved with the Laplace transformation. The transient pressure behavior in multistage fractured horizontal wells is discussed, and effects of influence factors are analyzed. The result of this article can be used to identify the response characteristic of fracture conductivity to pressure and pressure differential and provide theoretical basis for effective development of tight oil reservoirs. The findings of this study can help for better understanding of transient pressure behavior of multistage fractured horizontal wells with finite conductivity in tight oil reservoirs.

With the continuous development of the petroleum resources, unconventional oil reservoirs such as shale oil and tight oil have gradually become a main development direction of oil reservoirs in various countries. The reserves of shale oil in China are huge, reaching 1.42 × 1011 t; therefore, China has a great development potential and prospects for exploitation. However, in the process of developing shale oil reservoirs, we encountered many problems, such as un-replenishment of formation pressure and low flowback rate. At this stage, the development technology of shale oil reservoirs cannot effectively solve these problems. The proposition of shut-in technology can effectively improve these problems in theory, but the current shut-in technology of shale reservoirs after fracturing in China is still in its infancy. There is no in-depth understanding of the mechanism of shut-in wells. In addition, the factors affecting the change of oil-water distribution during shut-in after fracturing are complex, mainly including reservoir permeability, capillary force, fracture stress sensitivity, and reservoir damage. This paper investigates the mechanism of shut-in in shale reservoirs after fracturing and summarizes the mechanism of the shut-in process. Then, a single well shut-in numerical simulation model is established for the three complex characteristics of spontaneous imbibition, fracture stress sensitivity, and reservoir damage, and the oil-water distribution and change laws of shut-in shale reservoirs after fracturing are analyzed. Finally, the numerical model is used to study the influence of reservoir permeability, capillary force, fracture stress sensitivity, and reservoir damage on oil-water replacement, pressure increase, and daily fluid production during shut-in. The research results show that the influence of reservoir permeability and capillary force is more obvious, and the influence of fracture stress sensitivity and reservoir damage is relatively small.

Compared with conventional reservoirs, shale reservoirs are more difficult to develop due to their characteristics of self-generation and self-storage and tightness. Based on the experience accumulated in production practice, the technical method of improving shale oil development through shut-in is put forward. The literature research on shale reservoirs shows that there is a lack of microscopic study on imbibition, the essence of oil–water exchange is not clear enough, and there is a lack of the systematic summary and induction of theoretical knowledge. This article starts from the background of shut-in stimulation of Gulong shale oil, conducts literature research on the related knowledge of shut-in of shale oil from three aspects: characterization of fracture network, shut-in mechanism, and oil and water distribution state, and summarizes the law of shut-in of shale oil in a microscopic aspect. On this basis, a dual-porosity numerical simulation model is established according to the geological and fluid characteristics of the Gulong shale oil reservoir. Through the simulation of a numerical simulation model, the water saturation and pressure maps of the matrix and lamellation-fracture system in the process of shut-in were obtained. It was found that the matrix system basically did not participate in the oil–water exchange in the process of shut-in, so in the subsequent characteristic curve analysis, only the lamellation-fracture system was mapped and analyzed. The water saturation and pressure curves of different distances of the main fracture at different times were made, and it was found that the water saturation and pressure in the main fracture and near fracture areas were higher, and the change was more obvious than that in the far. Thus, the pressure drop curves of the near fracture were used to analyze the flow stage of the fluid. The single variable method is used to analyze the influencing factors from two aspects: the fracture density and permeability of the stimulated zone. The results will give a better understanding of the oil and water distribution during shut-in and guide the duration of shut-in in shale oil reservoirs.

After multistage hydraulic fracturing of shale gas reservoir, a complex fracture network is formed near the horizontal wellbore. In postfracturing flowback and early-time production period, gas and water two-phase flow usually occurs in the hydraulic fracture due to the retention of a large amount of fracturing fluid in the fracture. In order to accurately interpret the key parameters of hydraulic fracture network, it is necessary to establish a production decline analysis method considering fracturing fluid flowback in shale gas reservoirs. On this basis, an uncertain fracture network model was established by integrating geological, fracturing treatment, flowback, and early-time production data. By identifying typical flow-regimes and correcting the fracture network model with history matching, a set of production decline analysis and fracture network interpretation method with consideration of fracturing fluid flowback in shale gas reservoir was formed. Derived from the case analysis of a typical fractured horizontal well in shale gas reservoirs, the interpretation results show that the total length of hydraulic fractures is 4887.6 m, the average half-length of hydraulic fracture in each stage is 93.4 m, the average fracture conductivity is 69.7 mD·m, the stimulated reservoir volume (SRV) is 418 × 10 4   m 3 , and the permeability of SRV is 5.2 × 10 − 4   mD . Compared with the interpretation results from microseismic monitoring data, the effective hydraulic fracture length obtained by integrated fracture network interpretation method proposed in this paper is 59% of that obtained from the microseismic monitoring data, and the effective SRV is 83% of that from the microseismic monitoring data. The results show that the fracture length is smaller and the fracture conductivity is larger without considering the influence of fracturing fluid.

Carbonate reservoirs are rich in oil and gas reserves; thus, they have great exploitation potential. Therefore research on the microscopic mechanisms of carbonate reservoirs is of great significance. Based on the thin section images of core castings of typical Well 555 and its pore and fracture features in actual reservoirs, this study designed three kinds of images representing the pore and throat structure of real rocks by applying image stitching and binarization processing methods. A microscopic pore model of carbonate rocks was then established using COMSOL numerical simulation software. The microscopic water flooding characteristics and residual oil distributions of different schemes were observed by designing different fracture development forms. The fractures that developed in parallel main lines showed a more obvious influence on water flooding characteristics compared to fractures that developed in vertical main lines. The cluster residual oil was the main residual oil type in the early stage of water flooding in the pure matrix model. With the progress of water flooding, the continuous cluster residual oil gradually turned into mainly discontinuous porous and columnar residual oils. Vertical mainline fractures reduced the amount of residual oil in clusters and replaced it with columnar residual oil. In contrast, parallel main line fractures expanded the unswept area, with the residual oil appearing in contiguous clusters. This study microscopically analyzed the law and characteristics of water flooding in carbonate reservoirs to provide key theoretical support for enhancing oil recovery.