The formation pressure system of deep and ultra-deep carbonate reservoirs is complex, with widespread fracture development and a narrow safety pressure window. The use of conventional cyclic well control methods often leads to overpressure and leakage alternation. The bullheading well control method is a commonly used technique to address blowouts in such oil and gas reservoirs. However, during the bullheading method, gas–liquid counter-current two-phase flow is frequently encountered, yet it remains inadequately studied. This gap in scientific understanding may result in potential hazards. This study carried out experiments to investigate gas–liquid counter-current two-phase flow at various inclination angles and viscosities. The research revealed the transition behaviors of the flow and developed a set of criteria to identify shifts in the flow patterns. A model for two-phase flow in bullheading well control within the wellbore was developed. The discrepancy between the predicted and observed casing pressures during the well control phase was found to be within 15%. In addition, the study explored the effects of flow rate, density, and viscosity of the well control fluid on wellbore pressure and the distribution of gas holdup. The results indicate that a higher fluid flow rate leads to a shorter well control duration but causes an increase in casing pressure at the wellhead. On the other hand, an increase in fluid density accelerates the reduction in casing pressure, ultimately lowering the pressure at the wellhead. Increasing the viscosity of the well control fluid slows down the casing pressure decline, leading to a higher wellhead casing pressure, while the required backflow time decreases. The research suggests that appropriately increasing the density and viscosity of the well control fluid can improve the efficiency of bullheading operations for well control.