Carbon isotopic composition of fluid inclusions in fracture-fill mineralization: a tool for tracing origin of gases and maturity of their parent source rocks
The presence of fractures in shale may have a high impact on the capacity of gas storage. In highly fractured settings shale gas may have escaped from the source rocks into overlying reservoir rocks or even to the surface. On the other hand, fractures in shale may form pressure compartments which can enhance the storage capacity for gas significantly. Fracture formation often causes flow of fluids and may lead to the formation of fracture-fill mineralization. Detailed studies of the isotopic composition of fracture-fill calcite or fluid inclusions trapped in differently oriented fracture-fill mineralization provide direct information regarding the composition and temperature of the migrating fluids in fracturing history.
Several studies using carbon isotope ratios of natural gas hydrocarbons have shown that gases that are produced by thermal cracking of oil and/or kerogen show increasing carbon isotopic composition with progressive catagenesis. Thermogenic gas typically shows δ13C(CH4) values between -50 and -20‰. However, irrespective of the original type of kerogen (type I-IV) in a source rock, there is often a well-expressed correlation between the δ13C(CH4) values of the gas and the maturity of the organic matter in the parent source. This relationship is commonly plotted in δ13C (CH4) versus maturity diagrams where the maturity of the source rocks is indicated by vitrinite reflectance (Fig. 1). In cases where gases are assumed to be unaffected by contamination during migration or mixing increasing δ13C(CH4) values with increased maturity have been generally observed. In this study we use fluid inclusion carbon isotopic composition as a tool to trace the origin of gases and to estimate the maturity of source rocks at the time the gases were sourced.
Participants Volker Lüders
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