Numerical Simulation of Fracture Propagation during Temporary Plugging Staged Fracturing in Tight-Oil Horizontal Wells.

Abstract

Fracture propagation with temporary plugging hydraulic fracturing in tight-oil reservoirs is simulated in this study. The research considers dynamic fluid redistribution, with stress differences among multiple fractures. The fracture morphology during temporary plugging staged fracturing (TPSF) is investigated by using a user-defined perforation element combined with a pore-pressure finite-element model. The precision of the integrated model is verified by using the standard finite-element approach. Then, case studies are presented to investigate the influence of cluster spacing, horizontal stress difference coefficients (SDC), injection rates, and barrier tensile strengths. The simulation results show that central cluster fractures are hampered by side-cluster fractures, while TPSF can alleviate the effect and lead to a more uniform propagation of all fractures. Stress interference weakens as cluster spacing increases, and propagation patterns are minimally influenced once spacing reaches 40 m. Higher injection rates can improve the injection pressure, enlarging fracture width, and potentially increasing the risk of fracture penetration. Barrier tensile strength and horizontal SDC can modify fracture geometries and determine the penetration behavior of multiple fractures.