High injection rate stimulation for improving the fracture complexity in tight-oil sandstone reservoirs

Successfully creating a large field fracture network is crucial for achieving economic production of tight-oil sandstone reservoirs. In this paper, the variations of in situ stress as well as the fracture network are studied based on a fully coupled flow and mechanics model. A high injection rate stimulation technique is extensively investigated as an effective method for improving the fracture complexity in single or multiple stages of horizontal well. Sensitivity studies are conducted for this stimulation method in improving the fracture complexity. The high injection rate stimulation cannot efficiently promote the fracture network area for ductile rocks. Initial in situ stress contrast plays an important role in the creation of fracture network. The fracture aperture as well as stress perturbation is controlled by the minimum in situ stress. The stress perturbation is accentuated in low permeability reservoirs, which is helpful to achieve a large field of fracture network. The area of new created fracture network in sequential fracturing is increasing with the fractures due to the arising of mechanical interaction between fractures. The results presented in this paper can be used in hydraulic fracturing design in tight-oil sandstone reservoirs to promote productivity.