Geomechanical Characteristics and Development Significance of Natural Fractures in Carbonate Reservoirs of F_Ⅰ17 Strike-Slip Fault Zone, Fuman Oilfield

Geomechanical research in the ultra-deep carbonate rock domain of the Tarim basin has achieved a series of results, offering effective support to the exploration, development, and engineering practices of ultra-deep oil and gas resources. To facilitate further exploitation of the fracture-fragmented reservoir in the F_Ⅰ17 fault zone of the Fuman oilfield, in this paper it integrates rock mechanics tests, single-well in-situ stress interpretation, and three-dimensional in-situ stress field simulations to clarify the geomechanical characteristics of the fault-controlled reservoirs in the F_Ⅰ17 fault zone, on the basis of which the geomechanical responses of natural fractures associated with the F_Ⅰ17 fault zone are analyzed. It is found that : ① The reservoir's Young's modulus ranges from 32-47 GPa, and Poisson's ratio ranges from 0.23-0.26. Elastic parameters exhibit vertical heterogeneity and planar differences between faults and surrounding rocks. Near fault development areas, a decrease in Young's modulus (approximately 20%) and an increase in Poisson's ratio (approximately 10%) are observed. ② The current minimum horizontal principal stress of the reservoir ranges from 110-170 MPa, and the maximum horizontal principal stress ranges from 145-205 MPa. The orientation of the maximum horizontal principal stress intersects the fault strike at a small angle, with significant stress drops (exceeding 15% locally) observed in the fault zone compared to the surrounding rocks. ③ The effective normal stress on large-scale natural fracture surfaces ranges from 30-105 MPa, and shear stress ranges from 5-35 MPa, influenced by in-situ stress, fracture orientation, and formation pore pressure. ④ Through stress calculations, the ratio of shear stress to effective normal stress of natural fractures primarily ranges from 0.1-0.55, the critical injection pressure ranges from 92-204 MPa, and the fracture geomechanical activity index (FGAI) ranges from 0.2-0.8, with an average of 0.48. High-angle fractures exhibit higher activity and are activated first after fluid injection. ⑤ When the formation pressure reaches the fracture closure pressure, the fractures will alter the connectivity state between fracture-cavity reservoir bodies. To avoid stress sensitivity damage after fracture closure, cyclic injection and production can be implemented.