Effects of Gas–Liquid Two-Phase Flow on Tubing Axial Force and Buckling in Deepwater High-Temperature and High-Pressure Gas Wells

During production of high-temperature and high-pressure (HTHP) gas wells, condensate and formation water may generate gas–liquid two-phase flow, altering wellbore temperature and pressure and consequently affecting the axial loading and buckling risk of packer-constrained production tubing. This study establishes a sequentially coupled thermal–hydraulic and tubing-mechanics framework that transfers distributed two-phase temperature–pressure profiles to thermal, piston and ballooning load calculations. The governing conservation equations are solved iteratively along the well trajectory, and potential sinusoidal- and helical-buckling intervals are identified using critical-load criteria. Validation against field data from four offshore HTHP gas wells in China yielded relative errors of 5.48–8.52% for wellhead temperature and 4.16–7.57% for wellhead pressure. At the same bottomhole pressure, the predicted wellhead pressure was 22 MPa for two-phase flow and 38 MPa for single-phase gas, indicating that neglecting the liquid phase substantially underestimates wellbore pressure loss. Increasing the bottomhole inlet liquid volume fraction from 10% to 25% raised the wellhead temperature from 45.6 to 51.6 °C, reduced the wellhead pressure from 35.6 to 25.7 MPa, and decreased the wellhead axial force from 406.9 to 384.4 kN. Higher gas production shifted critical-load crossings towards shallower depths, while their absolute locations depended on the adopted buckling criterion. The model provides a comparative assessment of thermal–hydraulic loading and criterion sensitivity in HTHP gas wells under steady homogeneous flow and quasi-static tubing mechanics.