This research presents a two-dimensional transient thermo-hydraulic model designed to study how temperature and pressure change within a wellbore during CO₂ tubing fracturing. The model integrates one-dimensional axial compressible flow with radial heat transfer across the tubing, annulus, casing, cement sheath, and surrounding geological formation. Using the predicted temperature and pressure distributions, the phase behavior of the fracturing fluid along the wellbore is assessed. To enhance the accuracy of phase predictions, a visualization experiment is performed on a CO₂-based fracturing fluid containing 5 wt% of the thickener HPG. The critical transition conditions obtained experimentally are used to adjust the model accordingly. The study systematically examines the influence of key operational parameters such as injection rate, wellhead pressure, injection temperature, and the geothermal gradient of the formation. Findings reveal that injection conditions mainly govern the temperature and velocity fields, while heat transfer from the formation has a lesser impact during short-term injections. Pressure steadily decreases along the wellbore due to friction and fluid compressibility. A method based on density gradients is introduced to determine the depth at which phase transitions occur. Overall, this work offers a practical approach for predicting thermo-hydraulic behavior and phase changes during CO₂ fracturing processes.

During the CO₂ fracturing of unconventional oil and gas resources, the structural and operational parameters significantly influence the fracturing effectiveness. To quantitatively reveal the influence mechanisms of key parameters on the CO₂ jet flow field through perforations, this study employed computational fluid dynamics (CFD) via Ansys Fluent to simulate and compare the effects of the nozzle contraction angle, injection rate, confining pressure, and fluid temperature. The results indicate that the contraction angles and injection rates have a more significant influence on the jet temperature, pressure, and velocity than the confining pressures and fluid temperatures. As the contraction angle increases, the average velocity of the jet core region increases by 5.0% (with the most significant growth at 35°), and the length of the potential core increases correspondingly. The flow through the perforations is characterized by an instantaneous drop of 2.5 °C in temperature and 2.7 MPa in pressure, then transitions to a regime of temperature recovery and dynamical pressure decay along the fracture. Increasing the fracturing displacement raises the maximum jet velocity to 104.7 m/s (an average increase of 15.5%), extends the potential core length, and amplifies the temperature and pressure drops across the perforation from 1.1 °C and 1.2 MPa to 4.2 °C and 4.8 MPa, respectively. Conversely, higher confining pressure reduces the average jet velocity by 4.3%, shortens the potential core, and diminishes the perforation temperature and pressure drops from 5 °C and 3 MPa to 2 °C and 2.5 MPa. In contrast, elevating the fluid temperature increases the jet velocity by an average of 6.3% but exerts minimal influence on the potential core length; the temperature drop at the perforation remains at approximately 2 °C, while the pressure drop rises from 2.2 MPa to 2.9 MPa. Collectively, both the confining pressure and fluid temperature significantly affect the density and velocity characteristics of the jet. An increase in confining pressure enhances the density of the CO₂ jet fluid, which may potentially improve the fracturing impact in actual engineering applications. Quantitatively, the influence of each parameter on the temperature, pressure, and velocity of the CO₂ jet is ranked from the most significant to the least as follows: nozzle contraction angle > fracturing injection displacement > formation confining pressure > fluid temperature. The findings of this research have direct implications for practical application, informing the optimization of the fracturing design to achieve greater efficiency and lower risk in CO₂ fracturing operations.