During hydraulic fracturing, the aperture of hydraulic fractures will shrink by the in-situ stress, but will not fully close because of the existence of proppant inside the fracture. In previous studies, few people noticed the existence of proppant, which has resulted in the inaccuracy of simulation results. In this study, based on the boundary element method, a numerical simulation model for sequential fracturing was established, which respectively considered the influence of proppant in staged fracturing and zipper fracturing. In addition, the influence mechanism of proppant on fracture morphology is then revealed. Simulation results show that the residual aperture of the previous hydraulic fracture, which was produced by proppant, may increase with the increase of proppant stiffness and fracture spacing and may also be shrunk by the dynamic propagation of subsequent hydraulic fracture. However, the residual aperture will rebound after hydraulic fracturing construction is finished. The shrinkage and rebound values of residual aperture of hydraulic fracture are usually less than 1 mm. In addition, at the same time, the residual aperture of previous hydraulic fracture may also influence the propagation of subsequent hydraulic fracture. These influences are represented by the bend of fractures in multistage fracturing and the intersection in zipper fracturing. With the increase of well spacing, the influence degree of residual aperture on subsequent fracture propagation is reduced. The previous hydraulic fracture cannot have a significant effect on the deflection of subsequent hydraulic fracture when fracture spacing is between 10 and 30 m. The above research has important guiding significance for controlling fracture morphology in hydraulic fracturing.

Tight sandstone gas reservoirs are rich in reserves and are an important part of unconventional oil and gas resources. However, natural fractures’ impact on hydraulic fracture propagation behavior and network formation mechanisms remain unclear. Exploring how to optimize fracturing parameters to maximize post-fracturing productivity requires further investigation. Therefore, this study focused on the characteristics of tight sandstone gas reservoirs and established a three-dimensional numerical simulation model for hydraulic fracture propagation and post-fracturing productivity using production history matching to validate the reliability of the model. Based on this model, this study investigated the influence mechanisms of natural fracture angles, density, and lengths on hydraulic fracture propagation behavior and network formation. The spatial distribution of hydraulic fracture widths in three dimensions is also explored. When natural fracture angles are lower, a greater number of natural fractures are activated, leading to more developed secondary hydraulic fractures and the formation of complex fracture networks. Hydraulic fractures tend to penetrate directly through high-angle natural fractures. Single-well cumulative gas production increases initially with increasing natural fracture angles, then decreases, but increases with higher natural fracture density and length. Optimal fracturing in areas with longer natural fractures, lower angles, and higher density distribution enhances single-well productivity effectively.

As an important replacement resource for conventional oil and gas, tight oil and gas are quite abundant. Long horizontal wells and multi-stage fracturing have become key technologies for developing tight oil and gas, and reasonable shut-in measures can improve the utilization efficiency of fracturing fluid. Therefore, it is especially critical to master the pressure transfer law during the shut-in process in tight reservoirs to further improve the energy efficiency of fracturing fluid. However, many studies have mostly focused on the separate design of fracturing, shut-in and production, and have not yet revealed the pressure transfer law during shutting in well based on the integration of fracturing, shut-in and production, which makes it difficult to realize the efficient development of tight oil and gas. Taking the tight oil reservoir in Block M as an example, the geological model of the target block was established using an integrated fracturing development software platform, on which the simulation of fracture extension, well shut-in and production was carried out. The changes in the reservoir pressure field during shutting in well were analyzed, and the influence law of fracturing fluid volume, shut-in time, reservoir original formation pressure and fracture network complexity on the effect of well shut-in were studied to optimize the shut-in system. It was found that the retained fluid increases, the pore pressure of the near-fracture matrix increases, and the diffusion distance of fracturing fluid to the distant matrix increases. The tight oil production increased after shutting in well, and the optimal retained fluid volume of 9600 m³ was actually preferred based on the model. The pore pressure of the near-fracture matrix decreases as the shut-in time increases, the diffusion distance of fracturing fluid to the distant matrix increases, and the pore pressure decreases with an increase in diffusion distance. The tight oil production increased after shutting in well, and the optimal shut-in time was actually preferred to be 90 days based on the model. The increase in formation pressure on abnormal low pressure formation is larger, and the production can be significantly improved after shutting in well. The more complex the fracture network is, the more obvious the non-uniform variation in matrix pore pressure during shutting in well. The research is of great significance for the optimal design of a shut-in system for tight reservoirs and the sustainable development of oil and gas resources in China.

As a transitional energy source, natural gas plays a crucial role in the energy transition. In the efficient development of shale gas, the drainage and production process, as an important link between hydraulic fracturing and production, determines the recovery rate of individual wells. To clarify the main controlling factors of shale gas drainage and production, provide strategies for classification, and improve the recovery rates of individual wells, a numerical simulation method was proposed to analyze the factors affecting drainage and production, and the VIKOR method was used for quantitative evaluation of the drainage and production effects. The research results showed that: (1) The study identified nine main controlling factors affecting drainage and production performance, including gas saturation, permeability, stress difference, burial depth, formation pressure, cumulative fracture volume, final fracture loss rate, average final diversion ability, and wellbore liquid loading. (2) A workflow for quantitatively evaluating the drainage and production effectiveness of shallow shale gas wells and selecting wells with potential for optimized drainage and production was proposed. The correlation between the evaluation results and EUR fitting had an R² value of 0.71, indicating a good level of credibility. (3) The evaluation results for the target gas field indicated that out of the 16 representative wells, 12 wells have optimization potential, with 5 wells showing significant optimization potential. Studying the rules of shale gas drainage and production and evaluating the drainage and production effects can help us to propose refined drainage and production strategies, which are essential for improving the estimated ultimate recovery (EUR).

Frequent wellbore loss incidents in the Mesozoic reservoirs of the Zhengning oilfield in the Ordos Basin, China, have severely impacted the development of tight oil and gas reservoirs in the basin. This study analyzed the mineral composition, microstructure, natural fracture distribution, and hydration–dispersion characteristics of rocks in the loss-prone intervals of the Mesozoic reservoirs using a laboratory experimental system. The effects of natural fractures and drilling fluid immersion on the mechanical properties and failure behavior of the rocks were investigated, and the wellbore loss mechanisms in the Mesozoic reservoirs of the Zhengning oilfield were comprehensively analyzed. Experimental results show that the reservoir rocks in the loss-prone intervals are widely distributed, with natural fractures having a width of 0.2–0.3 mm, and the clay mineral content is generally above 40%. When the relative content of illite/smectite interstratification exceeds 80%, the rock exhibits strong hydration–dispersion behavior, with a thermal recovery rate of less than 85%. Drilling fluid immersion causes the rock mass to become unstable. The presence of natural fractures and the hydration–dispersion effect significantly weaken the strength of the surrounding rock mass, leading to enhanced rock plasticity. During drilling, the expansion and interconnection of natural fractures, combined with the hydration–dispersion effect, are the main causes of wellbore loss incidents. Our study clarifies the mechanisms underlying wellbore loss incidents in the Zhengning oilfield and provides reliable experimental evidence for preventing such incidents in this area.

During the hydraulic-fracturing process, stress interference occurs among multiple wells and fractures, potentially affecting the trajectory of hydraulic fracture propagation. Previous studies have largely overlooked the influence of proppant support stresses on the trajectories of fracture propagation. This paper establishes a mathematical model, grounded in the boundary element method, designed to compute the propagation of multiple fractures, considering both proppant support on the fracture surface and dynamic perturbations within the local stress field. The findings of this research reveal that the stress field induced by hydraulic fracturing exhibits dynamic evolution characteristics, necessitating a comprehensive study of the fracture initiation and extension across the entire fracturing time domain. The effect of the residual fracture width under proppant action on the in situ stress field cannot be ignored. During simultaneous fracturing, hydraulic fractures are inclined to propagate in the direction of the maximum horizontal principal stress, particularly as the in situ differential stress escalates. Staggered fracturing between wells has been proven to be more effective than head-to-head fracturing. Simply increasing the well spacing cannot solve the problem of inter-well fracture interference. In zipper fracturing, adjusting the fracturing sequence can inhibit the fracture intersections between wells, thereby controlling the trajectory of fracture propagation. The aforementioned research has considerable significance in guiding the control of fracture morphology during hydraulic-fracturing processes.