Proppant transport in complex fracture networks strongly influences the effectiveness of volumetric hydraulic fracturing in deep shale reservoirs; however, experimental investigations remain limited by the scale and structural complexity of existing laboratory models. In this study, large-scale physical experiments were conducted using a self-designed fracture system consisting of a main fracture and multi-level tertiary branch fractures to investigate proppant transport and placement behavior under different operational conditions. Twelve experimental cases were performed by varying injection rate, fracturing fluid viscosity, proppant concentration, proppant type, and particle-size pumping sequence. The results show that increasing the injection rate and fluid viscosity improves the proppant transport capacity and promotes proppant migration into tertiary branch fractures, increasing the proppant distribution ratio by 6.58%, while the placement proportion in the main fracture decreases by 15.92%. Increasing the proppant concentration enhances proppant placement in all fracture levels, with the placement ratio of quartz sand increasing by 10–15%, but excessive concentration causes accumulation and bridging near the fracture entrance. Under identical conditions, ceramic proppant exhibits better overall placement performance than quartz sand, with a 22.81% higher placement ratio in the main fracture. In addition, the pumping sequence significantly affects proppant distribution; the large–small–large particle-size sequence achieves the highest placement ratio of 74.52%. These results provide quantitative experimental evidence for optimizing proppant injection strategies and fracturing parameters in deep shale reservoirs.
Bai et al. (Sat,) studied this question.
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