The exploration and development of global oil and gas resources are extending into deep strata reaching depths of 10,000 m, where wellbore temperatures during drilling processes can exceed 220 ℃. It is imperative to implement temperature control measures for circulating fluids in the wellbore to prevent failure or damage to the drilling equipment due to excessively high operational temperatures. To achieve this temperature control, numerical simulations are necessary to assess the temperature distribution and heat exchange within the wellbore and tubing systems of these ultra-deep wells, thereby guiding the proper management of wellbore fluid temperatures. Unlike conventional wellbore temperature models, ultra-deep wells with extended depths and complex tubing structures are highly sensitive to minor errors, which can significantly impact the thermodynamic parameters of the wellbore. This paper establishes a “thermal-fluid-solid” multi-medium coupled wellbore thermodynamic model, taking into account factors such as varying geothermal gradients, multiple heat sources within the wellbore, and complex tubing dimensions. The model is solved using a successive over-relaxation iterative method after dividing the wellbore into dynamically complex, non-uniform grids, providing a detailed analysis of the temperature distribution and heat flux under various influencing factors. The results indicate that while the size and structure of the drill string have minor effects on temperature distribution, the geothermal gradient, thermal properties of the drilling fluid, and the thermal conductivity of the drill string system significantly influence the wellbore temperature distribution. Notably, the geothermal gradient largely determines the trend in temperature distribution changes, while the thermal properties of the drilling fluid play a crucial role in the numerical values of wellbore temperatures.