During the production of deep shale gas wells in Western Chongqing, variations in production regimes and water-gas ratios in water-bearing gas wells lead to significant differences in bottom-hole flowing pressure calculations, affecting the accuracy of early Estimated Ultimate Recovery (EUR) predictions. Therefore, this study evaluates and optimizes the calculation results of eight commonly used gas-liquid two-phase flow pressure calculation methods, based on measured flowing pressure data from deep shale gas wells in Western Chongqing, considering both flow regimes and water-gas ratios. The research found that the production tubing in Western Chongqing deep shale gas wells forms four flow regime combinations: “slug flow + transition flow + stratified flow,” “bubble flow + transition flow + stratified flow,” “mist flow + intermittent flow + stratified flow,” and “slug flow + intermittent flow + stratified flow.“ The Gray model performs best for calculating flowing pressure in the first three combinations, while the Ansari model is optimal for the fourth combination. To facilitate on-site operation, the model was optimized in terms of the water-gas ratio. The water-gas ratio was divided into five intervals: < 7 m3/104 m3, 7–10 m3/104 m3, 10–20 m3/104 m3, 20–30 m3/104 m3, and > 30 m3/104 m3. The overall error of converting the gas well flow pressure in each interval to the Gray model was small and the effect was good. The research results provide technical support for the calculation of flow pressure in on-site management of deep shale gas in areas such as western Chongqing.