Differential accumulation mechanism of shale gas in superimposed basins: Insights from dynamic evolution of shale gas content and occurrence state

By investigating the evolution of shale gas generation, storage, adjustment and accumulation under different structural settings in superimposed basins, this study elucidates the differential accumulation mechanisms of shale gas. An improved evaluation method of shale gas content evolution in superimposed basins is proposed. This method incorporates the coupling effect of key geological factors such as temperature, pressure, organic matter abundance, maturity, and pore characteristics on the content and occurrence state of shale gas, as well as the configuration relationship between shale gas generation and storage throughout geological history. Using this approach, the gas evolution histories of the Longmaxi Formation shales in wells N201 and PY1 are reconstructed under varying geological conditions. The Longmaxi Formation shales in these wells are dominated by type Ⅰ kerogen, with original total organic carbon (TOC_o) contents of 6.20 wt% and 4.92 wt%, respectively, indicating differences in the initial material basis for gas generation. At the maximum burial depth of approximately 5000 m, the Longmaxi Formation shale in well N201 exhibits a formation pressure coefficient of 2.05, an organic matter maturity of 2.2%, and organic pores accounting for 68% of the total porosity. The gas generation quantity (Q_g) reaches 19.24 m³/t, while the gas storage capacity (Q_s) is 4.30 m³/t. The actual total gas content (Q_a), constrained by Q_s, is 4.30 m³/t, with free gas comprising 94%. Following relatively moderate tectonic uplift, the Q_a in well N201 decreases to 4.03 m³/t, with free gas accounting for 63%. In contrast, the Longmaxi Formation shale in well PY1 reached a maximum burial depth of 6300 m, associated with a formation pressure coefficient of 1.62, organic matter maturity of 2.5%, and organic pore proportion of 67%. Here, Q_g is 16.87 m³/t, and both Q_s and Q_a are 3.65 m³/t, with free gas accounting for 98%. After intense tectonic uplift, Q_a declines to 2.72 m³/t, and the proportion of free gas drops to 51%. Finally, a four-stage differential accumulation model of shale gas is established: Slow gas generation and only adsorbed gas occur in stage Ⅰ, which is primarily controlled by TOC content; both adsorbed gas and free gas present in stage Ⅱ, with free gas becoming dominant; rapid gas generation and free gas predominance are controlled by temperature and porosity in stage Ⅲ; and gas adjustment and accumulation are primarily controlled by temperature and pressure in stage Ⅳ.