Mass Fraction Maturity — Next Generation Geochemical Constraint of Basin Models

Abstract

Thermal maturity measurement on oil accumulations are crucial for resource assessment. However, the current concept of an oil maturity is flawed and simplistic, as all oils are mixtures with different components charged from source rocks at different temperatures. With typical geological heating rates of 1-10 °C/Ma at any location within a petroleum system, this means that source rocks are charging traps for timescales on the order of a few million years, to a few tens of millions of years. During this period of time, the expelled and trapped petroleum shows a progressive evolution of both bulk and molecular compositions. The concentrations of various components in oil vary greatly for a single facies source rock of differing maturities nonetheless for the different facies. However, petroleum geochemists have continued to use relative abundances of, in particular, saturated hydrocarbon and other biomarkers to a large degree in oil-source rock and oil-oil correlations and maturity and facies assessment of reservoired oils, leading to many confusing and inconsistent approaches to characterizing maturity. We have suggested an alternative approach is needed which tracks the maturity/ petroleum mass fraction relationships for a reservoired oil, in a more complex but realistic manner and allows the more effective bracketing of source kitchen maturity. The maturity distribution of oil would then represent the mass fraction versus source temperature at expulsion profile, for all the components in that reservoired fluid. This concept, called Mass Fraction Maturity (MFM), aims to develop the tools, protocols and calibration data sets to enable the assessment of the reservoired oil mass fraction and source charge temperature interval relationship. Having this relationship, and knowing what a typical complete charge mass fraction maturity profile would look like for a given source rock type, would enable estimation of any missing charge in the basin (validating additional exploration activity), detection of complex multi-history charge scenarios, and also a much more robust and complete data set for calibration of basin model charge history assessments. We will demonstrate the importance of MFM for understanding the properties of reservoir fluids, post-burial uplift and petroleum mass loss, instantaneous versus cumulative charge events and exploration potential by using case studies from Western Canada and elsewhere.

AAPG Datapages/Search and Discovery Article #90259 ©2016 AAPG Annual Convention and Exhibition, Calgary, Alberta, Canada, June 19-22, 2016