The Dina 2 gas field in the Kuqa Depression of the Tarim Basin is one of China’s most critical oil and gas exploration areas. Natural fractures have played an important role in the low-permeability reservoirs in the Tarim area. Tectonic fractures are dominant in such reservoirs. In fact, the factors influencing tectonic fracture development have always been the source of important issues in tight reservoirs. Cores, thin sections, and borehole image logs were used to analyze the types, basic characteristics, and factors influencing tectonic fractures in the tight sandstone reservoirs of the Dina 2 gas field in the Tarim Basin. The results showed that the tectonic fractures are dominated by high-angle and upright shearing fractures, and they mainly show ENE–WSW strikes. The thin sections suggest that 60% of the fractures are fully filled with minerals, 20% are unfilled, and 20% are partially filled. The analysis also shows that lithology, faults, and in situ stress are the main factors controlling the development of the tectonic structures. Furthermore, the correlation between the unimpeded flow from a single well and the apertures of the tectonic fractures indicates that tectonic fractures play an important role in the production of hydrocarbons.

During the development of multi-layer tight sandstone gas reservoirs in Ordos Basin, China, it has not been easy to calculate accurately the production of each individual layer in gas wells. However, production allocation provides a vital basis for evaluating dynamic reserves and drainage areas of gas wells and remaining gas distributions of gas layers. To improve the accuracy and reliability of production allocation of gas wells, a new model was constructed based on the seepage equation, material balance equation, and pipe string pressure equation. In particular, this new model introduced the seepage equation with an elliptical boundary to accurately capture the fluid flow characteristics within a lenticular tight gas reservoir. The new model can accurately calculate the production and reservoir pressure of each individual layer in gas wells. In addition, the new model was validated and applied in the Sulige gas field, Ordos Basin. The following conclusions were drawn: First, The gas production contribution rates of pay zones based on the new model are fairly close to the measurements of the production profile logging, with errors less than 10%. Second, The overall drainage area of a gas well lies among those of each pay zone, and the total dynamic reserves of the well are close to the sum of the dynamic reserves of pay zones. Third, Higher permeability may lead to higher initial gas production of the pay zone, but the ultimate gas production contributions of pay zones are affected jointly by permeability and dynamic reserves. Finally, The new model has been successfully applied to the SZ block of the Sulige gas field, in which the fine evaluation of dynamic reserves, drainage areas, gas production, recovery factors, and remaining gas distributions of different layers was delivered, and the application results provide technical support for the future well placement and enhanced gas recovery of the block.

Shale gas development in China is dominated by high-pressure gas reservoirs occurring in deep horizons in Sichuan Basin and its peripheral areas. With the progress of exploration and development technologies, medium-shallow normal-pressure shale gas represented by Anchang Syncline in Guizhou has also realized commercial operation. To address the problems of overall low production and high gas breakthrough flowback ratio of medium-shallow normal-pressure shale gas, this paper systematically analyzes its development performance laws based on the complex tectonic setting and the reservoir characteristics of “four lows and one high” of the Anchang Syncline. A series of key technologies were developed, including the static–dynamic iterative identification technology for faults and micro-amplitude structures in complex tectonic areas, the coupled iterative fine modeling technology of geology-development dual chain, the iterative optimization technology of fractures and simulation parameters, as well as low-cost drilling-completion and drainage-production process technology. The application of the above technical suite achieved commercial development of normal-pressure shale gas. By the end of 2024, 66 wells had produced 6.5 × 10⁸ m³ cumulatively, and the well Estimated Ultimate Recovery (EUR) is 2000–4000 × 10⁴ m³. It was clarified that geological conditions constitute the intrinsic basis of gas well production capacity, and engineering factors such as horizontal section length, well type selection, fracturing matching degree, and drainage-production timing are the key to production enhancement. The established development technical system and practical experience for normal-pressure shale gas provide an important reference for the efficient development of analogous gas reservoirs.