Characterization of Hydraulic Fracture–Natural Fracture Coupling and Stimulation Effects in a Tight Oil Reservoir Using Core CT

Direct core-scale evidence remains insufficient for evaluating hydraulic fracture–natural fracture coupling and stimulation effectiveness in tight sandstone oil reservoirs. In this study, post-fracturing full-diameter cores from the Chang 81 tight oil reservoir in the Xi 119 well block, Xifeng Oilfield, Ordos Basin, were investigated using core observation, computed tomography (CT) scanning, fracture-source evidence and three-dimensional fracture-network reconstruction. A total of 87.56 m of core from 11 core runs was scanned at a voxel size of 50.62 μm. Natural fractures, hydraulic fractures and engineering-induced fractures were identified and distinguished based on fracture-surface features, CT expression, spatial continuity, proppant/tracer evidence and their relationship with bedding and lithological boundaries. The results show that lithological structure exerts a first-order control on hydraulic-fracture surface morphology. Massive sandstone tends to generate straight and continuous high-conductivity main fractures, argillaceous laminated sandstone promotes bedding-controlled discontinuous fractures with limited connectivity, and cross-bedded sandstone favors fracture diversion, branching and natural-fracture activation. Based on fracture assemblage, spatial connectivity and seepage behavior, three hydraulic fracture–natural fracture coupling types were classified: single hydraulic-fracture type, single main fracture–diverted fracture–natural fracture type, and dual main fractures–diverted fractures–natural fractures type. Their equivalent permeability increases stepwise from 155 mD to 345 mD and 586 mD, respectively, indicating a positive relationship between fracture-network complexity and seepage capacity. A CT-derived stimulation-effect evaluation framework was further established by integrating pore–fracture structural modification, fracture volume increase, aperture improvement and seepage-capacity enhancement. The dual main fractures–diverted fractures–natural fractures type shows the strongest stimulation response, with the largest reduction in small-aperture pore/fracture proportion, the greatest lamina-fracture aperture enlargement and the most significant permeability improvement. These results provide direct core-scale evidence for understanding fracture-network formation in continental tight sandstone reservoirs and support more targeted hydraulic-fracturing design and stimulation-effect evaluation.