The conductivity of propped fractures following hydraulic fracturing is crucial in determining the success of the fracturing process. Understanding the primary factors affecting fracture conductivity and uncovering their impact patterns are essential for guiding the selection of fracturing engineering parameters. We conducted experiments to test fracture conductivity and analyzed the effects of proppant particle size, closure pressure, and fracture surface properties on conductivity. Using the orthogonal experimental method, we clarified the primary and secondary relationships of the influencing factors on conductivity. The results indicate that proppant particle size, formation closure pressure, and fracture surface properties significantly affect fracture conductivity, with the order of influence being closure pressure > fracture surface properties > proppant particle size. Using large-particle-size proppants effectively increases interparticle porosity and enhances fracture conductivity. However, large-particle-size proppants reduce the number of contact points between particles, increasing the pressure on individual particles and making them more prone to crushing, which decreases fracture conductivity. Proppants become compacted under closure pressure, leading to a reduction in fracture conductivity. Proppant particles can embed into the fracture surface under closure pressure, further impacting fracture conductivity. Compared to non-laminated fracture surfaces, proppant particles are more likely to embed into laminated fracture surfaces under closure pressure, resulting in a greater embedding depth and reduced conductivity.

The placement of proppant within fractures is critical to the effectiveness of hydraulic fracturing. To elucidate the migration and placement patterns of proppant within multi-branched fractures during hydraulic fracturing, we conducted simulation experiments under both single-fracture and multi-branched-fracture conditions, varying injection rates and proppant sizes. The results of the research indicate that increasing the injection rate effectively increases the magnitude of vortex formation at the leading edge of sandbars and the drag forces acting on the proppant particles, resulting in increased particle migration distances. However, effective proppant packing near the wellbore entrance is not achieved at higher injection rates, leaving the fractures susceptible to closure under in situ stress, thereby reducing overall fracture conductivity. In addition, increasing the proppant size results in higher settling velocities and weakens the vortex’s ability to entrain the proppant particles. This results in shorter proppant placement distances, and the proppant cannot effectively reach the distant branched fractures. In addition, the diversionary effect of the branched fractures gradually reduces the flow rate in the distant branches, resulting in poorer proppant placement efficiency. Based on these findings, we recommend an approach that initially increases injection rates while reducing proppant size to ensure proppant placement in distant wellbore fractures and branched fracture networks. Subsequently, larger proppants can be used to effectively fill fractures close to the wellbore.