The volume fracturing technology along with horizontal well is the main technology to obtain commercial oil flow in shale reservoirs because of the low porosity and low permeability. Whether the fracturing fluid has the potential of shale matrix imbibition oil recovery after a large amount of slickwater injected into the reservoir is a research hotspot at present. Therefore, it is of great significance to study the law of imbibition and replacement during the shut-in time. Aiming at the Jimsar area, there are several steps in this study in order to explore the new law of fracturing fluid imbibition and oil recovery in shale reservoirs. Primarily, the distribution of pressure and saturation during fracturing time and shut-in time is accurately described by the numerical simulation method. Furthermore, the sensitivity analysis is carried out from two aspects of geological and fracture factors. Eventually, the evaluation of optimal shut-in time is taken by imbibition replacement balance. According to the numerical simulation results, the pressure diffuses rapidly among the matrix during the shut-in time in the hydrophilic reservoir. After 65 days of well shut-in, the whole reservoir tends to be at the same pressure and reaches the equilibrium of imbibition replacement. Contrarily, the pressure of the lipophilic reservoir diffuses slowly and only propagates in the secondary fracture or the matrix near the fractures. The fracture system remains a “high-pressure area” for a long time during shut-in. Additionally, the optimal shut-in time chart of different geological parameters and fracture parameters is drawn to optimize the shut-in time. This research work has a certain reference value for the optimization of shut-in time after fracturing in Jimsar and similar shale oil wells.

Currently, volume fracturing of horizontal wells is the main technology for shale oil development. A large amount of fracturing fluid is injected into the formation, but the flowback efficiency is very low. Besides, the impact of fluid retention on productivity is not fully clear. There is still a debate about fast-back or slow-back after fracturing, and the formulation of a reasonable cleanup scheme is lacking a theoretical basis. To illustrate the injected-fluid recovery and production performance of shale oil wells, an integrated workflow involving a complex fracture model and oil-water production simulation was presented, enabling a confident history match of flowback data. Then, the impacts of pumping rate, slick water ratio, cluster spacing, stage spacing and flowback rate were quantitatively analyzed. The results show that the pumping rate is negatively correlated with injected-fluid recovery, but positively correlated with oil production. A high ratio of slick water would induce a quite complex fracture configuration, resulting in a rather low flowback efficiency. Meanwhile, the overall conductivity of the fracture networks would also be reduced, as well as the productivity, which indicates that there is an optimal ratio for hybrid fracturing fluid. Due to the fracture interference, the design of stage or cluster spacing is not the smaller the better, and needs to be combined with the actual reservoir conditions. In addition, the short-term flowback efficiency and oil production increase with the flowback rate. However, considering the damage of pressure sensitivity to long-term production, a slow-back mode should be adopted for shale oil wells. The study results may provide support for the design of a fracturing scheme and the optimization of the flowback schedule for shale oil reservoirs.

With the deep development of tight reservoir in Mahu Sag, the trend of rising water cut during flowback concerns engineers, and its control mechanism is not yet clear. For this purpose, the integrated numerical model of horizontal well pattern from fracturing to production was established, and its applicability has been demonstrated. Then the flowback performance from child wells to parent wells and single well to well pattern was simulated, and the optimization method of reasonable flowback strategy was discussed. The results show that the formation pressure coefficient decreases as well patterns were put into production year by year, so that the seepage driving force of the matrix is weakened. The pressure-sensitive reservoir is also accompanied by the decrease of permeability, resulting in the increase of seepage resistance, which is the key factor causing the prolongation of flowback period. With the synchronous fracturing mode of well patterns, the stimulated reservoir volume (SRV) is greatly increased compared with that of single well, which improves the reservoir recovery. However, when the well spacing is less than 200 m, well interference is easy to occur, resulting in the rapid entry and outflow of fracturing fluid, and the increased water cut during flowback. Additionally, the well patterns in target reservoir should adopt a drawdown management after fracturing, with an aggressive flowback in the early stage and a slow flowback in the middle and late stage. With pressure depletion in different development stages, the pressure drop rate should be further slowed down to ensure stable liquid supply from matrix. This research can provide a theoretical guidance for optimizing the flowback strategy of tight oil wells in Mahu sag.