Abstract: Diamondoid Hydrocarbons as Indicators of Thermal Maturity and Oil Cracking

Dahl, Jeremy and J. Michael Moldowan - Geochemical Solutions; Ken E. Peters - Mobil Corp.; and Marcio R. Mello - Petrobras/Cenpes

We have developed a methodology based on both biomarkers and diamondoid hydrocarbons which allows for: (1) reliable determination of thermal maturity for any sample including highly-mature condensates, (2) estimation of the amount of oil cracking (conversion of liquids to gas and pyrobitumen) which a sample has undergone either in the source or reservoir, (3) recognition of oils derived from both a highly-mature and less-mature sources, (4) determination of the "oil-deadline" in a basin: i.e., the depth below which commercial amounts of liquids will not be found due to cracking, and (5) calibration of cracking and expulsion efficiency models. This methodology, combined with other information, allows for a better understanding of gas/oil ratios (GOR's), and can lead to the discovery of unrecognized generative petroleum systems operative in a basin. An understanding of GOR is crucial to economic evaluation of exploration and production projects and the recognition of new petroleum systems can lead to new play types in previously well-explored basins.

Although there are a variety of biomarker ratios, e.g., 5a,14a,170a(H)-24- ethylcholestane 20S/(20S+20R), which are routinely used to determine the thermal maturity of an oil (which generally reflects the thermal maturity of the source rock at the time of expulsion), thermal maturity determinations made on highly mature oils and condensates are problematic. Several of the main factors resulting in equivocal results include: (1) Highly mature samples have very low biomarker concentrations which are often below GC-MS detection limits. (2) Due to the low biomarker concentration, contamination from small amounts of biomarkers present in carder beds and reservoir rocks picked up during migration, can lead to erroneous results. (3) At very high maturities there is evidence that many of the ratios used to determine thermal maturity undergo "reversals". (4) In oils derived from more than one source (which we believe is a much more common scenario than is generally recognized), 90% of the oil or condensate may be from a highly mature source containing almost no biomarkers, and 10% from a low maturity source containing abundant biomarkers, and the biomarker signature will reflect only the low maturity source. As a result, the geochemist may not recognize the most significant source contribution, and thus misunderstand the operative generative petroleum system in the basin. Such a misunderstanding can result in missed exploration opportunities. Our method allows for recognition of the high-maturity source.

Oil cracking can occur in the reservoir, however, based on our work, it is more common in the source. The expulsion efficiency of many lean source rocks is too low to allow for liquid-phase migration out of the source. Consequently liquids are trapped until the source is buried sufficiently deeply that cracking can occur. The generated gas, can then migrate out of the source and carry with it dissolved and entrained liquids. Such a scenario is probably quite common in regions of marginal source rocks Bolivia, Peru, Argentina, the Burgos Basin of Mexico, the Northwest Shelf of Australia, the Tertiary of the U.S. Gulf Coast, and much of the Tertiary of Venezuela and Colombia. Mapping our diamondoid cracking parameter in these basins provides a regional understanding of expulsion efficiency thus GOR.

AAPG Search and Discovery Article #90933©1998 ABGP/AAPG International Conference and Exhibition, Rio de Janeiro, Brazil