On the determination of oil charge history and the practical application of molecular maturity markers

Abstract

Determining the thermal maturity and the charge history of crude oil to any reservoir, has key implications for understanding petroleum generation, accumulation history and hence identification of exploration potential. In this paper we combine studies of several source rock sequences and associated crude oils using quantitative component concentration data in addition to traditional molecular marker ratio parameter approaches. The case history studies include examination of organic-rich sapropelic marine source rocks from the Second White Speckled Shale Formation (2 WS Fm.), in the Western Canada Sedimentary Basin and the upper Jurassic Draupne Fm. in the North Sea and their related oils. Each molecular component in the petroleum has a unique concentration evolution curve during source rock maturation, in which n-alkanes, light aromatic hydrocarbons and diamondoid hydrocarbons increase in concentration with increasing maturity, while biomarkers decrease in concentration with maturity. This maturity dependent concentration variation plus the ubiquitous mixing of multiple oils in the reservoir is a key process that complicates the direct application of qualitative molecular marker ratio approaches to analysis of petroleum systems. We suggest an alternative maturity assessment approach using maturation calibrated curves of absolute concentrations of biomarkers and other alkanes in petroleum, coupled with selected aromatic hydrocarbon ratios to track the maturity/petroleum mass fraction relationships for a reservoired oil mixture in a more complex but realistic manner. Isoprenoid alkanes show less variation in concentration with maturity than other components and may be used as an internal reference point for mass fraction maturity and charge history assessment. Using component concentration data normalized to the concentration of the isoprenoid alkanes and calibrated using source rock analyses at different maturity levels from a single petroleum system (2WS), a simple mass balance model was constructed that allowed aggregate concentration data to be calculated for any mixture of oils produced in a prescribed oil charge history. In principle any charge history can be simulated using this approach and comparing the modelled and actual quantitative compositional profiles of crude oils allows differentiation of the more plausible and implausible oil charge histories for that particular reservoir. Clearly considerable refinement of this approach is needed but it appears that such a procedure has the potential, if developed further, to be a useful addition to the arsenal of petroleum geochemists and basin modelers. Knowing what a typical complete charge mass fraction maturity profile would look like for a given source rock type, enables the estimation of missing charge in the basin, allows the detection of complex multi-history charge scenarios, and provides a much more robust and complete data set for calibration of basin model charge history assessments. It also, with further development may be integrated into stochastic basin modelling approaches to study petroleum systems.