Reservoir fracturing stimulation is the key to the successful development of tight oil and gas fields. To effectively improve the performance of fracturing stimulation, it is urgent to clarify the propagation laws of hydraulic fractures under the tectonically heterogeneous in-situ stress field of different structural types. A series of large-scale north-dipping faults and fold structures have developed in the Bozhi-Dabei area of the Kuqa Depression under the north-to-south thrust nappe action. The complex structural characteristics have caused significant disturbance to the in-situ stress field, which further restricts the propagation and extension of the fracture network formed by fracturing stimulation. In this paper, the typical structural characteristics of the study area were extracted, and geological models of fault structure, fold structure, and fault-fold composite structure were established respectively. Heterogeneous rock mechanical parameters were assigned to the models, followed by stress loading, to clarify the distribution characteristics of the in-situ stress field corresponding to different structures. On this basis, the three-dimensional hydraulic fracturing process in the heterogeneous in-situ stress field was simulated, and the differences in fracturing effects among different structural types were analyzed. The results show that the in-situ stress near the fault zone decreases significantly, and the closer to the fault zone, the lower the in-situ stress. For the fold structure, the in-situ stress is reduced in the core and crest of the anticline due to the tensile stress derived from tectonic deformation, while it is increased in the anticline bottom affected by the compressive stress derived from tectonic deformation. The in-situ stress field characteristics of the fault-fold composite structure present a superposition of those of the individual fault and fold structures. Fracture propagation is dominated by the heterogeneous in-situ stress field. Overall, the lower the in-situ stress, the easier the fracture opening. Within the same duration, the fracture propagation length is the largest in the fault-fold composite structure model and the smallest in the fold structure model. With the in-situ stress release near the fault zone, the growth rate of fracture opening area in the fault model and fault-fold composite structure model accelerates as the fracture propagates closer to the fault over time. For the fold model, the in-situ stress along the Z-axis remains unchanged; the fracture opens rapidly near the fluid injection point with sufficient energy, while the opening rate slows down as the fracture propagates outward. Within the same fracturing time, compared with the single fault and fold structures, the fault-fold composite structure features a larger fracture opening area and lower fluid pressure, thus being the most favorable for fracture propagation. It is recommended that well placement in the study area should be prioritized in the fault-fold composite structural belt. The optimal well location is on the hanging wall of the fault close to the fault plane, and the preferred drilling depth is above the neutral surface of the fold.

With the rising global energy demand, shale gas and oil emerge as pivotal resources. Recent innovations utilizing CO₂ as an injectant can effectively enhance shale oil and gas recovery and facilitate CO₂ storage within shale reservoirs. However, low-temperature CO₂ injection may result in the coexistence of three hydrocarbon phases, while the abundant nanopores in shale formations also notably influence the phase behavior of reservoir fluids. To optimize shale oil recovery and CO₂ sequestration in shale formations, it is a prerequisite for precisely capturing the effect of confinement on the phase behavior of reservoir fluids within nanopores during CO₂ injection. In this work, we introduce a novel three-phase vapor-liquid-liquid equilibrium calculation algorithm, which is designed to handle the unique phase behavior challenges presented by CO₂ utilization and storage in shale reservoirs. To improve the robustness and efficiency, the proposed algorithm integrates a trust region-based stability test with a hybrid flash calculation algorithm that combines the Newton-Raphson and trust-region methods. Our thermodynamic model incorporates the capillarity effect and shifts in the critical points due to molecule-wall interactions, which are essential for accurate phase behavior simulation under confinement. Initial validations against experimental bulk phase data show promising results, and further investigations indicate that confinement alters three-phase vapor-liquid-liquid equilibria by suppressing two-phase and three-phase regions and shifting boundaries in the phase diagrams. The proposed algorithm not only advances our understanding of multiphase equilibrium in nanoporous media but also enhances the practicality of CO₂ sequestration and improved oil recovery strategies in shale formations.