Search Results (4)

After hydraulic fracturing, hydraulic fractures and opened beddings are intertwined, which results in a complex fracture network in shale oil reservoirs. In addition, the migration of multi-phase fluids during fracturing and shut-in processes leads to complex flowback performance and brings difficulty to flowback strategies optimization. In this paper, taking the Daqing Gulong shale reservoir as an example, a numerical model, which considers oil–water–gas three-phase flow and the orthogonal fracture network, has been established for flowback period. The characteristics and influencing factors of flowback performance have been deeply studied, and the flowback modes of shale oil are reasonably optimized. Geological factors such as PTPG (pseudo-threshold pressure gradient), matrix permeability, and engineering factors such as opened bedding stress sensitivity, opened bedding permeability, and fracturing fluid distribution have obvious effects on the flowback performance, resulting in significant variations in production peaks, high production periods, and decline rates. Furthermore, three flowback modes distinguished by the BHP (bottom hole pressure) correspond to the three types of choke mode that have been optimized. This study reveals the main factors affecting the flowback performance. Meanwhile, the optimization method can be applied to optimize flowback strategies in Gulong and other similar shale reservoirs to obtain higher shale oil production. Full article

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. Full article

The presence of a reasonable flowback system after fracturing is a necessary condition for the high production of shale gas wells. At present, the optimization of the flowback system lacks a relevant theoretical basis. Due to this lack, this study established a new method for evaluating the conductivity of artificial fractures in shale, which can quantitatively characterize the backflow, embedment, and fragmentation of proppant during the flowback process. Then, the mechanism of the stress sensitivity of artificial fractures on fracture conductivity during the flowback stage of the shale gas well was revealed by performing the artificial fracture conductivity evaluation experiment. The results show that a large amount of proppant migrates, and the fracture conductivity decreases rapidly in the early stage of flowback, and then the decline gradually slows down. When the effective stress is low, the proppant is mainly plastically deformed, and the degree of fragmentation and embedment is low. When the effective stress exceeds 15.0 MPa, the fragmentation and embedment of the proppant will increase, and the fracture conductivity will be greatly reduced. The broken proppant ratio and embedded proppant ratio are the same under the two choke-management strategies. In the mode of increasing choke size step by step, the backflow proppant ratio is lower, and the broken proppant is mainly retained in fractures, so the damage ratio of fracture conductivity is lower. In the mode of decreasing choke size step by step, most of the proppant flows back from fractures, so the damage to fracture conductivity is greater. The research results have important theoretical guiding significance for optimizing the flowback system of shale gas wells. Full article

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. Full article