Abstract: To address the liquid accumulation issue in deep shale gas wells caused by reduced casing fluid-carrying capacity, a solution is proposed that optimizes the timing of tubing deployment and key parameters to improve wellbore liquid-carrying efficiency and enhance production. This study is based on wellbore multiphase flow theory and the critical liquid-carrying model. It uses field data-modified pressure and critical liquid-carrying models for calculation. Taking into account key parameters such as daily gas production, gas-liquid ratio, pipe diameter, well inclination angle, and fluid velocity, a three-dimensional decision-making chart was established to determine the optimal timing, size, and depth for lowering the tubing, based on the criteria of minimizing the total pressure drop in the wellbore while ensuring that the actual gas velocity exceeds the critical liquid carryover velocity.The results show that tubing deployment timing is related to pipe diameter. The critical conversion points for Ø76 mm, Ø62 mm, Ø50.4 mm, and Ø40 mm tubing correspond to daily gas production values of 4.2×10⁴ m³, 3.9×10⁴ m³, 3.5×10⁴ m³, and 3.3×10⁴ m³, respectively. The optimal deployment depth is related to the production stage. When the daily gas production is greater than or equal to 5×10⁴ m³, the casing production pressure drop is minimized, and no tubing deployment is needed. When the daily gas production is below this value, tubing should be deployed to the A target depth to minimize wellbore pressure drop. This method was applied in the field to 10 wells, with an average absolute error of 4.83% in daily gas production predictions. For example, in well X1, the optimized plan (daily gas production of 3×10⁴ m³, deploying Ø76 mm tubing to 5 000 m) increased daily gas production by 66.7%. This collaborative optimization method provides effective guidance for water drainage and gas production in deep shale gas wells.