A Model for Predicting Wellbore Pressure during the Managed Pressure Cementing Injection Stage

Managed pressure cementing (MPC) technology has significant advantages in dealing with cementing challenges in formations with narrow density windows, but there are fewer studies on the prediction model of wellbore pressure during the injection stage. The cement slurry injection stage, based on the process of MPC, is divided into four substages. Based on rheological theory, wellbore heat transfer theory and pressure field theory, a model coupling temperature, pressure and fluid property is established taking into account the differences in the rheology of multiple fluids during the injection stage. The model is solved using four-loop iterative method. Using the parameters from the MPC operation of well X, the model was solved, and the prediction errors are small. Analyses of the temperature field, pressure field and ECD in the annulus during MPC show that the effects of the temperature field on the backpressure at wellhead are different in different time periods; when the fluid column in the annulus is a multi-liquid column, the effects of temperature on the backpressure at wellhead are relatively small. The change of the wellbore pressure is greatly affected by the distribution of fluid position. When other conditions remain constant, increasing injection rate will increase the operating density window, while the maximum ECD in the annulus remains basically unchanged. Corresponding improvement ideas are proposed based on the results for better design of the pressure control parameters..