Underground gas storage reservoirs (UGSRs) are used to keep the natural gas supply smooth. Native natural gas is commonly used as cushion gas to maintain the reservoir pressure and cannot be extracted in the depleted gas reservoir transformed UGSR, which leads to wasting huge amounts of this natural energy resource. CO₂ is an alternative gas to avoid this particular issue. However, the mixing of CO₂ and CH₄ in the UGSR challenges the application of CO₂ as cushion gas. In this work, the Donghae gas reservoir is used to investigate the suitability of using CO₂ as cushion gas in depleted gas reservoir transformed UGSR. The impact of the geological and engineering parameters, including the CO₂ fraction for cushion gas, reservoir temperature, reservoir permeability, residual water and production rate, on the reservoir pressure, gas mixing behavior, and CO₂ production are analyzed detailly based on the 15 years cyclic gas injection and production. The results showed that the maximum accepted CO₂ concentration for cushion gas is 9% under the condition of production and injection for 120 d and 180 d in a production cycle at a rate of 4.05 kg/s and 2.7 kg/s, respectively. The typical curve of the mixing zone thickness can be divided into four stages, which include the increasing stage, the smooth stage, the suddenly increasing stage, and the periodic change stage. In the periodic change stage, the mixed zone increases with the increasing of CO₂ fraction, temperature, production rate, and the decreasing of permeability and water saturation. The CO₂ fraction in cushion gas, reservoir permeability, and production rate have a significant effect on the breakthrough of CO₂ in the production well, while the effect of water saturation and temperature is limited.

The regulation of the seasonal energy supply for natural gas and the storage of fossil energy are important to society. To achieve it, storing a large amount of natural gas in porous underground media is one of the government’s choices. Due to the successful lesson learned from the oil and gas industry, natural gas storage in underground porous media has been regarded as the most potential long−term energy storage method. In this paper, we developed a new workflow to evaluate the performance of gas reservoir−type underground natural gas storage (UGS). The theoretical background of this workflow includes the correction of the average formation pressure (AFP) and gas deviation factor by error theory and the analytical mathematical model of UGS wells. The Laplace transform, line source function, and Stehfest numerical inversion methods were used to obtain pressure solutions for typical vertical and horizontal wells in UGS. The pressure superposition principle and weighting method of the gas injection−withdrawal rate were used to obtain the AFP. Through the correction of the AFP and gas deviation factor in the material balance equation, the parameters for inventory, effective inventory (the movable gas volume at standard condition), working gas volume (the movable gas volume is operated from the upper limit pressure to the lower limit pressure), and effective gas storage volume (the available gas storage volume at reservoir condition) were determined. Numerical data from the numerical simulator was used to verify the proposed model pressure solution. Actual data from China’s largest Hutubi UGS was used to illustrate the reliability of the proposed workflow in UGS performance evaluation. The results show that large−scale gas injection and withdrawal rates lead to composite heterogeneity in gas storage wells. The nine injection and production cycles’ pressure and effective inventory changes from Hutubi UGS can be divided into a period of rapid pressure rise and a period of slow pressure increase. The final AFP is 32.8 MPa. The final inventory of the Hutubi UGS is 100.1 × 10⁸ m³, with a capacity filling rate (the ratio of effective inventory to designed gas storage capacity) of 93.6%. The effective inventory is 95.3 × 10⁸ m³, and the inventory utilization ratio (the ratio of effective inventory to inventory) is 95.2%. The working gas volume is 40.3 × 10⁸ m³. This study provides a new method for inventory evaluation of the gas reservoir−type UGS.

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.