Most of the deep condensate gas fields under development in China are characterized by high temperature，high pressure，and complex phase behaviors. Due to the constraints of testing cost and safety，direct measurement of downhole pressure is not feasible，and therefore，multiphase pipe flow models suited to high pressure and high temperature （HPHT） condensate gas wells are required to predict bottomhole pressure according to wellhead data. To clarify the applicability differences of multiphase wellbore flow models for pressure prediction in HPHT condensate gas wells and establish a rational basis for model selection，this study analyzes the phase behavior evolution across the dew point and the flow pattern transitions under high pressure conditions，compares the applicability of black-oil and compositional models，and evaluates four mechanistic models and five empirical models through case studies. The results indicate that for the seven case wells，the average error of mechanistic models is only 1.76% in deep wells，lower than that of empirical models；in conventional wells，the average errors of both model types exceed 10%. The multi-fluid mechanistic model corrected by high pressure flow experiments and field test data，combined with compositional models accounting for the effect of polar water，can better capture condensate dropout，liquid holdup variation，and are thus more suitable for HPHT condensate gas well pressure prediction. This study provides important references for improving and applying prediction methods of wellbore pressure profiles and bottomhole pressure in HPHT condensate gas wells.