Abstract: As the development cycle of gas wells extends, wellbore liquid loading intensifies, leading to reduced field production and recovery. To address this issue, based on the minimum pressure drop theory, critical liquid-carrying flow rate calculation models with wellhead tubing pressure and water-gas ratio as variables were established for vertical wells with depths of 2 400-4 000 m, using two types of tubing strings: Φ50.8 mm coiled tubing and Φ60.3 mm tubing. The study shows that Φ50.8 mm coiled tubing has stronger autonomous liquid-carrying capacity, less severe liquid loading, lower bottom-hole flowing pressure, and higher daily gas production; the critical liquid-carrying flow rate increases with water-gas ratio, wellhead tubing pressure, and well depth, among which the influence of water-gas ratio and wellhead tubing pressure on the critical flow rate is significantly higher than that of well depth; when the wellbore flow pattern transitions to slug flow, the gas flow rate for Φ50.8 mm coiled tubing (7 000 m³/d) is lower than that for Φ60.3 mm tubing (16 000 m³/d), and the production time of the latter is reduced by more than 70% compared to the former. Field tests show that compared to Φ60.3 mm tubing, Φ50.8 mm coiled tubing brings higher completion efficiency, extending the natural continuous production period by 1.5 years, further verifying the accuracy of the model. This research provides a theoretical basis for analyzing gas well liquid-carrying laws and optimizing liquid drainage gas production measures, and offers important guiding significance for improving the development efficiency of low-productivity gas wells.

Key words: production tubing, minimum pressure drop theory, critical liquid-carrying, gas-liquid two-phase flow, wellbore flow pattern