CO₂, N₂, and CO₂/N₂ mixed gas injection for enhanced shale gas recovery and CO₂ geological storage

Abstract

In this work, using fractured shale cores, isothermal adsorption experiments and core flooding tests were conducted to investigate the performance of injecting different gases to enhance shale gas recovery and CO₂ geological storage efficiency under real reservoir conditions. The adsorption process of shale to different gases was in agreement with the extended-Langmuir model, and the adsorption capacity of CO₂ was the largest, followed by CH_4, and that of N₂ was the smallest of the three pure gases. In addition, when the CO₂ concentration in the mixed gas exceeded 50%, the adsorption capacity of the mixed gas was greater than that of CH₄, and had a strong competitive adsorption effect. For the core flooding tests, pure gas injection showed that the breakthrough time of CO₂ was longer than that of N₂, and the CH₄ recovery factor at the breakthrough time () was also higher than that of N₂. The of CO₂ gas injection was approximately 44.09%, while the of N₂ was only 31.63%. For CO₂/N₂ mixed gas injection, with the increase of CO₂ concentration, the increased, and the for mixed gas CO₂/N₂ = 8:2 was close to that of pure CO₂, about 40.24%. Moreover, the breakthrough time of N₂ in mixed gas was not much different from that when pure N₂ was injected, while the breakthrough time of CO₂ was prolonged, which indicated that with the increase of N₂ concentration in the mixed gas, the breakthrough time of CO₂ could be extended. Furthermore, an abnormal surge of N₂ concentration in the produced gas was observed after N₂ breakthrough. In regards to CO₂ storage efficiency (), as the CO₂ concentration increased, also increased. The of the pure CO₂ gas injection was about 35.96%, while for mixed gas CO₂/N₂ = 8:2, was about 32.28%.

Key words： shale gas; gas injection; competitive adsorption; enhanced shale gas recovery; CO₂ geological storage

Acknowledgment

The authors would like to thank the China National Petroleum Corporation South-west Oil and Gas Field Branch Shale Gas Research Institute (Grant No. JS-2020-42) for providing research funding.

Electronic Supplementary Material

Supplementary material is available in the online version of this article at https://doi.org/10.1007/s11708-023-0865-9 and is accessible for authorized users.

Competing interests

The authors declare that they have no competing interests.

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