--> Weighing Atoms: Isotopic Characterization of Kerogens, Oils and Condensates

AAPG Hedberg Conference, The Evolution of Petroleum Systems Analysis

Datapages, Inc.Print this page

Weighing Atoms: Isotopic Characterization of Kerogens, Oils and Condensates


An important aspect in calibration of petroleum system models is to correctly predict known oil accumulations and shows. This requires us to tie these occurrences to specific source rocks via oil to source correlation techniques (“forensic geochemistry”). Biological marker compounds are an important aspect of this but that approach suffers from a number of limitations, most notably that the absolute concentration of most of these compounds decrease with increasing maturity making them very vulnerable to mixing with small amounts of lower maturity oil. This can be partly overcome with the use of stable carbon isotope ratios, particularly of carbon (δ13C) which characterizes all of the carbon in an oil rather than only a few percent as do biomarkers. Following the first discovery that sedimentary organic carbon is depleted in 13C relative to carbonates by 20 to 30‰ (Nier & Gulbransen, 1939) subsequent research by Silverman (1967) was able to demonstrate conclusively that oil is derived from the lipids of organisms by comparing δ13C of oil and bulk kerogens with the isotopic difference between lipids and bulk organic matter. However, most research at this time concentrated on recent organic matter and demonstrated that recent marine organic matter was enriched in δ13C compared with land plants, best illustrated by the work of Sackett & Thompson (1963) who were able to show that recent sediments from the eastern Gulf of Mexico ranged from about -21‰ for pure aquatic input to - 26 to -28‰ for terrigenous organic matter. Sadly however, the present is not the key to the past in this case and the reverse is true for most of geologic history despite many analytical service companies still using δ13C of kerogen as a palaeoenvironmental indicator based on this work. The most significant advance in terms of oil-source correlation during this time was the introduction of isotope type curves by Stahl (1978) in which δ13C of the major oil fractions was plotted in order of increasing polarity to give greater refinement to the comparison between oils. There then followed a period in which numerous case studies appeared without any significant increase in fundamental understanding. This changed with the contribution of Sofer (1984) who demonstrated that plotting of δ13C of the aromatic fraction of an oil against δ13C of the saturated fraction can differentiate a waxy (=terrigenous) from a non-waxy (marine) source. This paper was also the first to debunk the theory that all ancient terrigenous sources produced oil which was isotopically lighter than that from marine sources and also showed that the isotope ratios of the oil fractions increased significantly with maturity. The maturity effect was further investigated by Clayton (1991) who differentiated a maturity effect of about 1‰ during the generation process from a further increase of up to ~3‰ during oil to gas cracking and that this technique could also be applied to condensate liquids. The hydrogen isotope ratio, δD, of kerogen is initially controlled by δD of the waters in which the organic matter grew but numerous studies have shown that δD of oil fractions are substantially altered by isotopic exchange with formation waters during the generation process itself. This phenomenon undoubtedly has important implications for understanding the generation process itself and more research could be useful in that respect. Sulphur isotope ratios in kerogen crudely follow that in marine sulphates, although isotopically much lighter, but nothing significant has been published on the effects of maturity in δ34S of oils. Similarly, δ15N ratios of oils have hardly been investigated although these potentially offer great potential as correlation tools.