The Keshen gas field in the Kuqa Depression, the Tarim Basin, China, contains multiple ultra-deep fractured tight sandstone gas reservoirs with edge/bottom water, which are remarkably complex in geologic structure, with fracture systems at different scales. There is still a lack of a method for effectively describing the flow behaviors of such reservoirs. In this paper, the fracture system was characterized by classes using the actual static and dynamic data of the gas reservoirs, and the mathematical models of gas (single-phase) and gas-water two-phase flows in “pore–fracture–fault” multi-porosity discrete systems. A fracture network system was generated randomly by the Monte-Carlo method and then discretized by unstructured grid. The flow models were solved by the hybrid-unit finite element method. Taking Keshen-2/8 reservoirs as examples, four types of dynamic formation modes were built up. Performances of reservoir of the same category were systematically analyzed, which revealed the coupling of gas supply and water invasion mechanisms in different fracture systems. The gas single-phase flow was found with the characteristic of “fault–fracture gas produced successively and matric-fracture system coupling overlaid”, while the gas-water two-phase flow showed the characteristic of “rapid water dash in fault, drained successive in fractures and matric block divided separately”. This study reveals the development features of this unique reservoir effectively, and designs development strategies of full life cycle water control for enhancing the gas recovery. It can be expected that the recovery factor of newly commissioning reservoirs would be increased by more than 10% as compared with the Keshen-2 gas reservoir. These findings will play an important role in guiding high and stable production of Keshen gas field development in the long term.

In order to improve the shale oil production rate and save fracturing costs, based on dynamic production data, a production-oriented optimization method for fracture spacing of multi-stage fractured horizontal wells is proposed in this study. First, M. Brown et al.’s trilinear seepage flow models and their pressure and flow rate solutions are applied. Second, deconvolution theory is introduced to normalize the production data. The data of variable pressure and variable flow rate are, respectively, transformed into the pressure data under unit flow rate and the flow rate data under unit production pressure drop; and the influence of data error is eliminated. Two kinds of typical curve of the normalized data are analyzed using the pressure and flow rate solutions of M. Brown et al.’s models. The two fitting methods constrain each other. Thus, reservoir and fracture parameters are interpretated. A practical model has been established to more accurately describe the seepage flow behavior in shale oil reservoirs. Third, using Duhamel’s principle and the rate solution, the daily and cumulative production rate under any variable production pressure can be obtained. The productivity can be more accurately predicted. Finally, the analysis method is applied to analyze the actual dynamic production data. The fracture spacing of a shale oil producing well in an actual block is optimized from the aspects of production life, cumulative production, economic benefits and other influencing factors, and some significant conclusions are obtained. The research results show that with the goal of maximum cumulative production, the optimal fracture spacing is 5.5 m for 5 years and 11.4 m for 10 years. All in all, the fracture spacing optimization and design theory of multi-stage fractured horizontal wells is enriched.

There is high uncertainty in reserve estimation during the early development of deep ultrahigh pressure gas reservoirs, largely because it remains challenging in accurately determining the formation compressibility. To overcome this, starting from the definition of compressibility, a novel gas production of cumulative unit pressure drop analysis method was established, of which the effectiveness was proven by applications in calculating the reserves of three gas reservoirs. It has been found that, in the limiting case, i.e., when the formation pressure dropped to the normal atmospheric pressure, the dimensionless gas production of the cumulative unit pressure drop was the reciprocal of the initial formation pressure. Besides, the relationship curve of the dimensionless gas production of the cumulative unit pressure drop and pressure drop was a straight line in the medium term, extending the straight line and intersecting the vertical line passing through the original formation pressure point, and the reserves can be determined according to the intersection point and the initial formation pressure. However, due to the influence of natural gas properties, the value needs further correction, and the correction coefficient depends on the pseudocritical temperature of natural gas. Specifically, when the pseudocritical temperature is given, the correction coefficient would be close to the minimum value of the natural gas deviation factor. When the pseudocritical temperature is more than 1.9 and less than 3.0, the minimum deviation factor would be between 0.90 and 1.0, and the higher the pseudocritical temperature, the closer the ratio is to 1.0.