Revisiting the Determination of Oil Thermal Maturity in Sedimentary Basins
The search for reliable thermal maturity indicators to determine the maturity of reservoired crude oil is an important objective in petroleum geochemistry. While section maturity (relating to the maximum temperature experienced by a source rock or other stratigraphic units), is defined and petroleum generation maturity is a well discussed concept, current usage of the term “maturity” for migrated fluids, is limiting and indeed often misleading! We review the concept of crude oil maturity and suggest a new approach is needed, to define what we mean by the maturity of a migrated crude oil. Oil reservoirs integrate an evolving petroleum composition over millions, to tens of millions of years and no single value of a “maturity”, can describe the complete history of such complicated mixtures. Complications in assessing oil maturity are introduced by migration fractionation, multiple charges and mixing, and secondary alteration processes. We suggest an alternative approach is needed which tracks the maturity/ petroleum mass fraction relationships for a reservoired oil (mass fraction maturity), in a more complex but realistic manner and allows the more effective bracketing of source kitchen maturity. The natural evolution curves of concentrations of acyclic alkanes and biomarkers and also some aromatic hydrocarbons in maturing source rock systems forms the base of maturity related calibration charts from defined source rock types. Comparison of biomarker concentrations and aromatic hydrocarbon ratios in a given oil, with profiles of these components retained in source rock extracts, permits a first pass at deriving how much oil was sourced from source rocks through a given maturation interval. The range of fraction‐specific maturities of an oil would effectively bracket the source kitchen maturity range for a reservoired oil. Three “end member”, mass fraction maturity scaled models have been proposed based on data sets of oil and source rock samples using molecular marker concentrations and distributions, from the Western Canada Sedimentary Basin (WCSB), North Sea Basin and China’s Tarim Basin. This study has shown that none of the commonly used maturity parameter systems function as commonly described and component concentration comparisons between source rocks and migrated fluids provide an added level of system understanding. A cumulative “instantaneous oil charge” system represented by the Second White Speckled Formation derived oils in the WCSB, is characterized by consistent maturity parameters from different hydrocarbon components. The continuous charge represented by the Draupne Formation derived oils in the North Sea Basin, show low apparent biomarker maturity but high aromatic component assessed maturity, suggesting oils were generated over a wide maturity range with source rock fractionations. An interrupted charge model can be illustrated by the Tarim Basin case history where the early oil charge has been biodegraded and partially lost but a late high maturity charge mixes, in variable intensity, with an early charged residual petroleum charge. The distinct features for interrupted charge model oils are a non‐linear correlation of most molecular concentrations and maturity parameters and a very wide range of component‐specific maturity levels indicated. Such mass fraction maturities would allow much greater resolution of charge histories as they would provide a vehiclefor distinguishing, in a quantitative way, the impact of many geological scenarios for a reservoir or prospect suite such as early petroleum charge loss, or the addition of late charges of high maturity petroleum, from idealized scenarios where a complete source basin charge is captured.
AAPG Datapages/Search and Discovery Article #90349 © 2019 AAPG Hedberg Conference, The Evolution of Petroleum Systems Analysis: Changing of the Guard from Late Mature Experts to Peak Generating Staff, Houston, Texas, March 4-6, 2019