Fracturing fluids are widely applied in the hydraulic fracturing of shale gas reservoirs, but the fracturing fluid flowback efficiency is typically less than 50%, severely limiting the shale gas recovery. Additionally, the mechanism and main influencing factors of fracturing fluid flowback are unclear. In this study, microscopic experiments are conducted to simulate the fracturing fluid flowback progress in shale gas reservoirs. The mechanism and factors affecting fracturing fluid flowback/retention in the fracture zone were analyzed and clarified. Results show that the ultimate flowback efficiency of fracturing fluid is positively correlated with the fracturing fluid concentration and the gas driving pressure difference. There are four kinds of mechanisms responsible for fracturing fluid retention in the pore network: viscous resistance, the Jamin effect, the gas blockage effect and the dead end of the pore. Additionally, the ultimate flowback efficiency of the fracturing fluid increases linearly with increasing capillary number. These insights will advance the fundamental understanding of fracturing fluid flowback in shale gas reservoirs and provide useful guidance for shale gas reservoirs development.

Understanding the mechanical properties of rock is of great significance for the development of unconventional reservoirs. However, a large number of bedding makes the mechanical laws of rock unclear. To investigate the effect of bedding properties on the uniaxial mechanical properties of rock, the coal model containing bedding is developed based on the continuousdiscontinuous method, and the effect of bedding angle, bedding strength, bedding number, and loading rate on the uniaxial mechanical properties of rock is investigated. The failure morphology, stressstrain evolution, peak stress, and fracture degrees are analyzed and discussed in detail. The reliability of the numerical model in this paper has been verified by comparison with the indoor experiments. The results show that when the bedding angle is 0, the peak stress of the rock is maximum, 8.16MPa, and when the bedding angle is 90, the fracture degree of the rock is maximum, 3.74. For the different bedding strengths, the peak stress first decreases linearly with the decrease of the bedding strength. The peak stress barely varies when the bedding strength is less than 0.5MPa. The fracture degree of the rock shows a nonlinear increase with the increase in bedding strength. For different bedding numbers, the activation of the bedding is not related to the bedding number. The loading speed also has a great influence on the mechanical properties of rock. With the increase in loading rate, the difficulty of bedding activation gradually increases, and the complexity of fractures gradually increases. This study aims to further improve the understanding of the effect of bedding properties on the uniaxial mechanical properties of rock.

In the process of fracturing, proppant flowback is unavoidable, and excessive proppant flowback will cause sand plugging in the wellbore, change the morphology of proppant fractures, reduce the effective flow‐conducting capacity of fractures, weaken the effect of fracturing to increase production, and affect the extraction of hydrocarbons in the later stage of the fracturing process. At present, the research on proppant flowback during fracturing and re‐discharge process mainly focuses on the force of proppant and its critical flowback rate at the time of startup, and there are fewer studies on the factors affecting proppant flowback, and there is not yet a theoretical model to specifically analyze the flowback characteristics of proppant in a rough fracture. Combining the above reasons, this paper constructs a three‐dimensional numerical simulation model of proppant flowback in rough fracture by using the coupled computational fluid dynamics‐discrete element method to study the factors affecting proppant flowback in rough fracture, and it is found that the rough fracture can reduce the flowback of proppant by comparing the flowback of proppant in the smooth fracture and the rough fracture. Meanwhile, it is clearly understood that the flow rate of return fluid and proppant particle size are the main influencing factors affecting proppant flowback. This study can provide theoretical references for the program design and field construction of the actual fracturing return phase.

The development of unconventional hydrocarbon resources has positioned hydraulic fracturing as a pivotal technology in shale oil extraction, where understanding fracture propagation mechanisms is critical for reservoir stimulation optimization. This study employs gelatin‐based visualized experiments to systematically investigate the effects of perforation modes, flow rates, fluid volumes, and bedding conditions. Experimental results reveal that reducing the number of perforations increases fracture initiation pressure (12%), and adjusting perforation density within clusters modifies initiation locations without fully resolving propagation heterogeneity. Elevated flow rates significantly reduce initiation pressure (40%) and systematically shift fracture origins from the wellbore heel to the toe. Nonlinear correlations between fluid volume and fracture propagation area suggest the mutual influence between injection pressure and boundary constraints. In layered heterogeneous models, higher flow rates enhance interfacial crossing capabilities, and a complex fracture behavior often corresponds to more intricate pressure curves. These findings provide experimental validation for perforation strategy optimization and fracture geometry control in unconventional reservoir stimulation.