Modeling and Prediction of Sustained Casing Pressure of High-Pressure and High-Temperature Gas Wells during Production Operations

Summary To accurately predict the sustained casing pressure resulting from tubing leakage in high-pressure and high-temperature (HPHT) gas wells during production operations, we developed a predictive model that incorporates the effects of tubing leakages, wellbore temperature changes, and multiannulus interactions. First, we determined the thermodynamic parameters of the annular liquid through a combination of experimental and computational methods. Next, we formulated a transient model to predict wellbore temperature and pressure. Then, we analyzed the coupling relationship between tubing leakages, wellbore temperature changes, and multiannulus interactions, and proposed an equation to calculate the sustained casing pressure. Finally, to illustrate the significance of coupled effects of multiple factors, we conducted a comparative case study using both the new model, which incorporates these effects, and the existing model, which considers only the tubing leakage. The characteristics of the sustained casing pressure were analyzed, and a sensitivity analysis was performed. The results show that, compared with measured data, the average error of the new model was 9.2%, which was much lower than the existing model’s 21.6%. The increase rate and maximum value of the annular pressure obtained by the new model were higher than those of the existing model. When the equivalent diameter of the leakage point was less than 0.65 mm, the coupled effects of multiple factors had a more pronounced impact on the sustained casing pressure. Optimizing the annular liquid density proved to be a more economical and effective method for mitigating the sustained casing pressure. This model offers valuable technological support for the prediction and analysis of the sustained casing pressure during production operations.