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Although significant progress has been made in the geological theory and exploration and development of shale gas in China, the research on the geological particularity and enrichment regularity associated with shale gas accumulation remains weak. With this in mind, we analyzed the shale gas accumulation patterns in China. The findings show that: (1) A variety of organic-rich shales were deposited in the continental margin-type marine and transitional environments during the Pre-Mesozoic period and the basin-type terrestrial environment during the Mesozoic and Cenozoic eras. (2) The basins dominated by Mesozoic and Cenozoic terrestrial sediments superimpose on the Pre-Mesozoic continental margin-type marine–or transitional-facies sediments. The former developed the terrestrial shales with large thickness, high organic matter abundance, new age, and low thermal maturity; meanwhile, the deep parts of the basins are favorable for shale gas enrichment. However, the latter preserves the shale with old age, high thermal maturity, and undergoing multiphase tectonic movements; and the tectonically stable regions are favorable for shale gas enrichment. (3) The aulacogens mainly formed in the Meso-Neoproterozoic, Sinian-Ordovician, and Devon-Triassic periods are favorable for marine organic-rich shale deposition; moreover, this type of shale and other types including transitional facies shales with favorable reservoir-forming assemblages, coal-measure shales in small and medium-sized basins, and low-medium mature shales affected by magma intrusion, have jointly constituted the various shale gas accumulation patterns in China. (4) Based on the drilling discoveries in China, shale gas accumulation patterns can be categorized into two types: tectonic-controlled and stratigraphic-controlled. The former is mainly related to structural features, whereas the latter is mainly related to the variation of lithology and strata. (5) Shale development and gas content are mainly affected and controlled by geological factors including sedimentation, diagenesis, and later tectonic movements. Favorable sedimentary environments, appropriate thermal maturity, good sealing capacity of caprock, and excellent structural preservation are the necessary conditions for shale gas enrichment.

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Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

CO2-EGR, i.e. enhanced gas recovery by injecting CO2, is to displace natural gas by injecting CO2 in the supercritical phase. It can both enhance the recovery of gas reservoirs and realize CO2 storage. Currently, this technique is still at its exploring stage. The effect of CO2-EGR is not clarified, the geologic conditions for CO2-EGR are not definite, and the rational working system for CO2-EGR is not available. In this paper, the long-core experiment was conducted to determine whether and how much the recovery of low-permeability reservoirs can be enhanced by injecting CO2. According to the experimental results, the recovery can be enhanced by 12% when CO2 content in produced gas is more than 10%. Moreover, the multi-component seepage mathematical model was built for displacing natural gas by injecting supercritical CO2, and the model accuracy was verified using laboratory data. With this mathematical model, the influence factors for displacing natural gas by injecting supercritical CO2 were analyzed in order to define the conditions for selecting favorable zones. The Well DK13 area in the Daniudi gas field, Ordos Basin, was selected for potential evaluation of CO2-EGR. As indicated by the numerical simulation results, when CO2 content of producing wells in the Well DK13 area is 10% (with a lower cost for corrosion prevention), the ratio of CO2-EGR is 8.0–9.5%, and 31.1% HCPV(hydrocarbon pores volume) of CO2 storage can be realized. It is thus concluded that the CO2-EGR technique can enhance the recovery of gas reservoirs and also store CO2 underground, contributing to the increase of both social and economic benefits.