Despite converting large, laterally unbounded, highly connected low-permeability lithologic gas reservoirs—without faults or fixed lithological boundaries—into underground gas storage, the evolution of transition zone pressures and the mechanisms of gas escape under multiple injection–production cycles remain poorly understood. This knowledge gap critically hinders the safe and efficient operation of such facilities. A core–transition zone injection–withdrawal model for the S4 underground gas storage was developed using the numerical well test module of Saphir software v4.20. The model quantifies transition zone pressure dynamics over ten injection–withdrawal cycles and elucidates how the interplay of formation permeability and operating conditions governs gas leakage. During multi-cycle injection–withdrawal operations, formation pressure in the transition zone steadily accumulates under the combined influence of core zone gas crossflow and local gas advection equilibrium within the non-utilizable region. Assessed by the transition zone boundary formation pressure, suppressing gas leakage depends primarily on total injection and withdrawal volume, followed by the injection schedule and, lastly, the location of the boundary injection well. To achieve cost-effective containment, we therefore recommend prioritizing a shorter injection duration, moderately reducing total injection and withdrawal volume, and increasing the distance between the boundary injection wells and the transition zone. Under the geological conditions of the S4 UGS, by sequentially adjusting the injection duration, reducing the total injected–withdrawal gas volume to 6000 × 10⁴ m³, and increasing the distance between boundary injection wells and the transition zone to 900 m, the transition zone boundary pressure rise over ten cycles was controlled to below 1 MPa, thereby effectively preventing gas leakage.

Natural gas loss directly threatens the safety and economic viability of underground gas storage (UGS) facilities. The short-term, high-rate cyclic injection and withdrawal processes may cause fault reactivation, resulting in gas loss. Current assessment techniques are mostly concerned with overall storage performance, with few studies focusing on fault-related leakage. This study looks at a UGS facility developed from a difficult fault-block sandstone dry gas resource in China. Focusing on one of its border faults, we develop geological and numerical models to systematically examine the impacts of well-to-fault distance, gas injection rate, and gas withdrawal rate on fault leakage. The results show that numerical simulations can accurately estimate this gas loss. The well-to-fault distance, injection rate, and withdrawal rate are highlighted as critical regulating variables. There is an ideal range for the well-to-fault distance, and altering the injection/withdrawal rates of wells within this range is an effective loss mitigation approach. The crucial distance between injection–production wells and the fault in the X1 gas storage facility is 900 m. Notably, improving the gas withdrawal rate of wells close to the fault considerably minimizes leakage. Reducing the gas injection rate from 11 × 10⁴ m³/d to 7 × 10⁴ m³/d reduces natural gas loss by 353 × 10⁴ m³. Increasing the gas production rate from 9 × 10⁴ m³/d to 29 × 10⁴ m³/d reduces natural gas loss by 975 × 10⁴ m³. The findings provide a scientific basis for assessing and managing natural gas loss at boundary faults in similar UGS plants.