## 4 Results and Discussion  
As the formation gas is continuously extracted, the formation pressure gradually decreases. When the formation pressure drops to a certain critical value, the formation pressure will not be able to maintain the gas well self-blowout production if the formation pressure is further reduced, and this paper refers to this critical value as the critical formation pressure. According to the simulation results (Figure 5), when the formation pressure is 8 MPa, the fluctuation of gas production is more stable, and there is no obvious downward trend; when the formation pressure drops to 7.8 MPa, the gas production shows a slight downward trend in the late simulation, and the amount of liquid production decreases; when the formation pressure drops to 7.7 MPa, the fluctuation of gas production is frequent in the late stage of production and the downward trend is obvious, the liquids start to accumulate at the bottom of the gas well, and eventually the gas well accumulates liquid and stops production (the final gas well accumulates liquid). Eventually, the gas well accumulated liquid and stopped production (Figure 6). Due to the accumulation of liquid in the casing, gas passes through the liquid accumulation section during the production of the gas well, thus causing fluctuations in gas production. Moreover, as the formation pressure decreases, it can be seen from Figure 4 that the trend in gas production decline does not have a clear boundary and it is difficult to determine the critical formation pressure at this time. In order to determine the critical formation pressure, a straight fit is made to the gas production curve, and the decreasing trend is judged based on the slope (Figure 6), thereby determining the reasonable critical formation pressure. Therefore, the critical formation pressure is 8 MPa when the tubing is lowered to the inclination point and according to the gas components (Table 4), analyzing the gas compression factor under different formation pressures, and determining the geological reserve of 8.24 \(\times\) 10\({}^{7}\) m\({}^{3}\) based on the production data of the gas wells, the cumulative gas production of the wells at this time is calculated to be 55.26 \(\times\) 10\({}^{6}\) m\({}^{3}\) by using the equation of the balance of substances. Change the position of the tubing depth to simulate the production dynamics of gas wells at different tubing depths and determine the corresponding critical formation pressure at this time. Set the tubing depth at 2400 m and simulate the production trend of gas wells under different formation pressure conditions (Figures 7 and 8). The results are similar to those of the simulation when the tubing is lowered to the inclination point, when the formation pressure is 7.8 MPa, the gas production shows a slight downward trend, and the liquid production decreases. When the formation pressure drops to 7.7 MPa, the gas production fluctuates frequently in the late stage of production and the downward trend is obvious, the liquids begin to pile up in the bottom of the well, and the well eventually stops production due to the accumulation of liquids, so it is judged that the corresponding  
Figure 5: Gas well production dynamics (tubing down to the skew point). which is approximately 2.1 \(\times\) 10\({}^{5}\) m\({}^{3}\) higher than that at a tubing depth of 2200 m. The gas production increase is approximately 1.7 \(\times\) 10\({}^{5}\) m\({}^{3}\) compared to a depth of 2400 m below the oil pipe, about 2 \(\times\) 10\({}^{5}\) m\({}^{3}\) compared to a depth of 2800 m below the oil pipe, about 2.8 \(\times\) 10\({}^{5}\) m\({}^{3}\) compared to a depth of 3000 m below the oil pipe, and about 2.4 \(\times\) 10\({}^{5}\) m\({}^{3}\) compared to a depth of 3200 m below the oil pipe. Due to the small vertical depth difference of this well, the cumulative gas production of the gas well changes little when the tubing is lowered to different depths.