Summary Tight sandstone reservoirs are commonly stimulated by large-scale volume fracturing. Slickwater has become the dominant fracturing fluid; however, its low viscosity causes rapid proppant settling within the fracture, creating heterogeneous placement with a sandbank at the bottom and an open fluid channel above. Existing studies largely assume uniform proppant placement and homogeneous conductivity within the fracture, deviating from the actual transport behavior of slickwater and providing an inadequate understanding of the overall fracture closure shape and intrafracture fluid flow mechanism under nonuniform proppant distribution. Therefore, this study established an equilibrium height prediction model incorporating the stable dune angle of the proppant to reveal the proppant placement morphology in field-scale hydraulic fractures. Subsequently, the finite element method was used to simulate the fracture closure process and clarify the overall fracture closure geometry. A productivity model integrating the closure morphology of tight gas fractured wells was then constructed to analyze the intrafracture fluid flow mechanism. This forms a systematic research framework that links “proppant placement morphology” to “overall fracture closure shape” and finally to “well productivity.” The results show that during slickwater fracturing, proppants form a sandbank along the fracture bottom, which is divided into frontal, equilibrium height, and trailing edge areas. After closure, the fracture segments into propped, arch, and unpropped areas from bottom to top. The arch area exhibits high conductivity and lower fluid pressure, attracting fluid from the propped and unpropped areas to converge before flowing toward the fracture entrance. While occupying only 0.85% of the fracture volume, the arch area contributes 37% of the total gas flux, and the propped area contributes 52%, forming dominant flow pathways. The high conductivity of the arch area expands pressure drainage area and enhances well productivity, particularly in lower-permeability reservoirs. Based on these findings, this study proposes a novel “multiarch areas for productivity enhancement” concept, shifting from pursuing uniform proppant placement toward actively optimizing heterogeneous placement. The simulation results also show that cumulative gas production increases with arch numbers, although gains diminish gradually, suggesting that an optimal arch count exists for maximizing well production. This study provides a theoretical basis for optimizing fracture design in tight gas reservoirs and offers a new perspective for improving unconventional reservoir recovery.
LU et al. (Thu,) studied this question.