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.
During their life cycle, high-pressure gas wells experience circulating working fluid, acid fracturing, blow off, and other development and production conditions. This may lead to the failure of the cement sheath integrity and result in sustained casing pressure (SCP). Therefore, we explored the failure types and mechanisms of the cement sheath using different wellbore operating procedures. In this study, we used the downhole packer as the demarcation point; the integrity of the cement sheath at the upper and lower parts of the packer was tested through a self-developed wellbore simulation device, which is based on the equivalent theory of cement sheath interface differential pressure. Results showed that the lower part of the single-layer cement sheath underwent compressive strength failure due to the pressure drop in the wellbore before perforation. Plastic deformation of the cement sheath occurred during acid fracturing.In addition, the cooling effect caused by the acid fracturing led to the bonding failure at the cement sheath's second interface. The double-layer cement sheath's inner-layer cement sheath was subjected to tensile failure -attributed to highpressure -and the outer-layer cement sheath maintained its integrity under the pressure changes. Considering the risk factors associated with integrity failure, we propose an engineering optimization plan in the study. The retest results showed that reducing the internal casing pressure and temperature and controlling the annular pressure in the production stage was beneficial in ensuring the integrity of the cement sheath at the lower and upper parts of the packer, respectively. The research results provided an important reference for ensuring the integrity of the cement sheath of high-pressure gas wells.
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