As large-scale fracturing in the development of deep shale gas results in rapid production decline, the accurate understanding of gas-liquid flow patterns is considered essential for stabilizing gas well production. Gas well models with two different wellbore trajectory structures were established, and OLGA software was applied to conduct transient calculations on models with varying tubing depths. The results indicate that in deep shale gas well A₁, slug flow only occurs in the build-up section and above, while in well B₁, slug flow appears in the horizontal section and near the build-up section. Considering cumulative gas production and liquid loading, the optimal tubing depth for deep shale gas wells A₁ and B₁ is at the heel of the horizontal section, while for conventional shale gas wells A and B, the optimal tubing depths are at the heel of the horizontal section and one-third of the horizontal section. Deep shale gas wells are more favorable for drainage and production compared to conventional shale gas wells. The optimal tubing setting depths for conventional shale gas wells with two deep formation wellbore configurations are at the horizontal section heel and the one - third point of the lateral, respectively. It is determined that deep shale gas wells are more advantageous for drainage and production compared to conventional shale gas wells. As the tubing size decreases, both the gas production and the corresponding critical gas flow rate for liquid carryover are reduced. It is also found that the greater the light hydrocarbon content in the shale gas composition, the higher the gas production. This study is intended to provide a reference for determining the rational tubing placement in the drainage and gas production processes of deep shale gas wells.