Fluid compressibility and the pressure-transmission mechanism of CO2 injection based on a conserved-variable wellbore flow model

The initiation and propagation of fractures and the overall effectiveness of CO 2 fracturing are strongly controlled by wellbore temperature, pressure, and flow conditions, which are typically predicted using wellbore flow models. Previous studies have focused mainly on coupled wellbore temperature-pressure calculations, while the role of fluid compressibility in pressure transmission remains insufficiently understood, potentially reducing injection efficiency and increasing energy consumption. In this study, a wellbore flow model for CO 2 injection was developed using the conserved variable method, and a wellbore compressibility response coefficient was introduced to quantify the effect of CO 2 compressibility on pressure transmission. The results show that CO 2 transitions from liquid to supercritical state at low pump rates and short injection times but remains entirely liquid at high pump rates. Wellbore pressure is strongly affected by flow friction, with frictional losses increasing markedly at higher pump rates. Wellbore temperature is governed primarily by the Joule-Thomson effect and frictional heating; the former may either heat or cool the fluid depending on operating conditions, whereas the latter consistently increases temperature. Both effects become more pronounced as pump rate increases. Continued CO 2 injection lowers bottomhole temperature and raises pressure, suppressing the transition to the supercritical state, while the duration of the all-liquid state decreases rapidly with increasing pump rate. Pump rate was identified as the dominant factor controlling wellbore pressurization. Pressurization can be enhanced by increasing pump rate within an appropriate range, lowering injection temperature, or increasing injection pressure. These results provide a theoretical basis for optimizing CO 2 fracturing design.