Abstract

A critical component of petroleum exploration risk assessment involves quantifying the risks associated with the presence of a viable hydrocarbon system. This requires an accurate estimate of thermal maturity and thermal history. However, in some sedimentary basins, traditional organic-based maturity tools such as vitrinite reflectance cannot be used because of various geologic and sampling limitations. This article establishes fluid inclusion microthermometry as a new inorganic thermal maturity tool that can be used to help fill the void in these situations. This tool uses an empirical calibration of fluid inclusion data and vitrinite reflectance data to estimate thermal maturity.

Our empirical approach uses rigorous sample selection criteria that improve the statistical chance of analyzing aqueous fluid inclusions that have been thermally reequilibrated (stretched). This empirical calibration is based on a worldwide set of data that yield a logarithmic correlation having r2 = 0.96 for an ideal sample set and r2 = 0.81 for a nonideal sample set. The amount of data scatter (absolute deviation of measured vitrinite reflectance in % Ro) from the logarithmic correlation line is minimal (±0.12% Ro for the ideal data set). This new calibration, along with the sample selection and data analysis procedures described in this study, forms the basis for a new thermal maturity technique.

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