With the introduction of China’s “dual carbon” goals, CO₂ is increasingly valued as a resource and is being utilized in unconventional oil and gas development. Its application in fracturing operations shows promising prospects, enabling efficient extraction of oil and gas while facilitating carbon sequestration. The process of reservoir stimulation using CO₂ fracturing is complex, involving coupled phenomena such as temperature variations, fluid behavior, and rock mechanics. Currently, numerous scholars have conducted fracturing experiments to explore the mechanisms of supercritical CO₂ (SC-CO₂)-induced fractures in relatively deep formations. However, there is relatively limited numerical simulation research on the coupling processes involved in CO₂ fracturing. Some simulation studies have simplified reservoir and operational parameters, indicating a need for further exploration into the multi-field coupling mechanisms of CO₂ fracturing. In this study, a coupled thermo-hydro-mechanical fracturing model considering the CO₂ properties and heat transfer characteristics was developed using the phase field method. The multi-field coupling characteristics of hydraulic fracturing with water and SC-CO₂ are compared, and the effects of different geological parameters (such as in situ stress) and engineering parameters (such as the injection rate) on fracturing performance in tight reservoirs were investigated. The simulation results validate the conclusion that CO₂, especially in its supercritical state, effectively reduces reservoir breakdown pressures and induces relatively complex fractures compared with water fracturing. During CO₂ injection, heat transfer between the fluid and rock creates a thermal transition zone near the wellbore, beyond which the reservoir temperature remains relatively unchanged. Larger temperature differentials between the injected CO₂ fluid and the formation result in more complicated fracture patterns due to thermal stress effects. With a CO₂ injection, the displacement field of the formation deviated asymmetrically and changed abruptly when the fracture formed. As the in situ stress difference increased, the morphology of the SC-CO₂-induced fractures tended to become simpler, and conversely, the fracture presented a complicated distribution. Furthermore, with an increasing injection rate of CO₂, the fractures exhibited a greater width and extended over longer distances, which are more conducive to reservoir volumetric enhancement. The findings of this study validate the authenticity of previous experimental results, and it analyzed fracture evolution through the multi-field coupling process of CO₂ fracturing, thereby enhancing theoretical understanding and laying a foundational basis for the application of this technology.

Acid–shale interaction can substantially alter shale microstructure and time-dependent mechanical behavior, yet the link between mineral-scale reactions, pore–fracture reconstruction, and damage-dependent creep remains insufficiently quantified. Shale specimens were exposed to acidic solutions with initial pH values of 5, 3, and 1, followed by solution chemistry analysis, X-ray diffraction (XRD), nuclear magnetic resonance (NMR) T₂ relaxation analysis, scanning electron microscopy coupled with energy-dispersive X-ray spectroscopy (SEM–EDS), micro-computed tomography (micro-CT), and stepwise triaxial creep testing. A comprehensive damage variable D_c integrating mass loss, P-wave velocity degradation, and porosity increase was introduced to describe the post-reaction damage state independently of the mechanical parameters subsequently used in constitutive modeling. Preferential dissolution of calcite and dolomite weakened carbonate-bearing cement and promoted pore–fracture reconstruction. The total NMR porosity increased from 3.82% to 8.62%, while the long-T₂ (>100 ms) signal fraction increased from 5.5% to 18.0%. Correspondingly, the final cumulative axial strain increased from 0.687% to 2.480%, and the steady-state creep rate at 30 MPa increased from 1.55 × 10⁻⁴ to 10.40 × 10⁻⁴ h⁻¹. The estimated long-term strength threshold exceeded 30 MPa for the control shale but decreased to approximately 22 MPa after strong acid exposure. Incorporating D_c into a history-dependent viscoelastic–viscoplastic formulation enabled the progressive degradation of elastic stiffness, viscous resistance, and the nonlinear creep threshold to be described within a unified framework. Specimen-level cross-validation showed improved predictive performance relative to conventional Burgers and Nishihara models. The results therefore provide a quantitative state-to-response framework linking independently characterized acid-induced physicochemical damage to subsequent creep evolution.