Oil and gas operators must measure or calculate the shut-in wellhead pressure for well integrity applications. Some operators adopt a method that gives satisfactory results for dry gas and lean gas condensate. They are using the steady-state simulator to calculate the wellhead pressure at a very low gas rate. The friction losses become negligible, and the only losses are due to hydrostatic head simulating (to some extent) the shut-in condition. This method again can work well with oil producers with low GOR/Bubble point pressure as the production string will be nearly a single phase. The problem is that this method is inaccurate for high GOR/CGR wells because of phase redistribution and the error can be significantly high. Phase redistribution occurs After shut-in, liquid droplets will accumulate at the bottom of the well. The interface liquid/gas will move up with sometimes liquid cushion is being re-injected back in the reservoir due to gravity or gas expansion in the tubing while the gas/liquid interface will move down a little. Many factors affect the behavior, including the well deviation, fluid properties, and the productivity and the injectivity of the formation. Thus, simulating this behavior requires a dynamic multiphase simulation. As some of the fluids might return to the formation, as a result of compressibility, coupling with a numerical reservoir simulation to model the near wellbore is also necessary. In this paper, we applied a dynamic multiphase model to predict the shut-in wellhead pressure. We used an uncertainty analysis approach to investigate the effect of many parameters on the accuracy of the results. We presented all recommended calculation procedures with a guide to minimizing the uncertainty associated. We presented our approach to three actual wells with different configurations and fluid properties with a deviation of +-10% of the real measurements.