Differential fluid migration behaviour and tectonic movement in Lower Silurian and Lower Cambrian shale gas systems in China using isotope geochemistry

Isotope geochemistry has been introduced as a means to trace origin of the hydrocarbon and characterize highly productive shale gas systems recently. To assess the impact of tectonic movement and the sealing of shale gas systems, isotope geochemistry, pressure coefficients and the distribution of bitumens are analysed. Many samples yield isotope geochemical data with typical carbon isotopic reversals (δ13C1 > δ13C2) and hydrogen isotopic reversals (δ13DC2H6 > δ13DCH4) in the Lower Silurian shale gas. Isotopically reversed gases are considered to originate in sealed, self-contained petroleum systems. Besides, isotope “reversals order” degree of shale gas has positive correlation with gas production. Isotopically normal gases from the Lower Cambrian indicate that this formation was a continued relatively open petroleum system when oil and gas generated. The pressure coefficients of the Lower Silurian shale gas reservoir range from 1.45 to 2.03, indicating that the reservoir is overpressurized, whereas the Lower Cambrian shale gas reservoir possesses a normal pressure system. Overpressurization of the Lower Silurian shale gas reservoir also indicates that it is a well-sealed system. The distribution and isotope geochemistry of bitumens in the Sinian dolomite and Cambrian shale suggests that the source rock of the Sinian hydrocarbon is the Cambrian shale. An unconformity induced from tectonic movement during the Tongwan period is interpreted to be the fluid migration tunnel and the cause of the differential shale gas content and production. Finally, the isotopic reversals associated with maturity, pressure coefficients and tectonic evolution can both assess the preservation conditions of the reservoir and explain the differential fluid migration behaviour.