Petroleum Geochemistry
This project is collaborative with Herbert Volk and colleagues at CSIRO Petroleum.
For nearly 15 years I worked as a petroleum geochemist at CSIRO. I have continuing interests in this area, especially in the accumulation and fate of oil in reservoirs.
Use of oil inclusions to define early oil generations
The abundance, distribution and composition of oil inclusions can be used to provide clearer data on the extent of palaeo-oil columns, and the composition of that palaeo-oil.
Case study: Bayu-1, Northern Bonaparte Basin, Timor Sea
The distribution of oil-bearing fluid inclusions (FI) in currently gas-bearing Jurassic reservoir sandstones from Bayu-1 (Northern Bonaparte Basin, Timor Sea) is consistent with the Bayu gas-condensate field originally containing a palaeo-oil column beneath a thick palaeo-gas cap. In order to assess the origin of the oil trapped in the FIs and its relationship, if any, to the gas condensate, a detailed molecular geochemical study was carried out on a FI oil extract and a condensate sample recovered from a similar interval by Modular Formation Dynamics Tester (MDT).
Compared to the condensate, the FI oil was generated from a more marine-influenced, less clay-rich source rock or source facies, which was deposited in a less oxic environment with greater eukaryotic input. The source rock of the condensate was more terrigenous and had greater microbial input. The Bayu FI oil contains a greater amount of C28 and C29 tricyclic terpanes than the Bayu condensate, and particularly compared to the Elang/Plover sourced oils from further to the northwest (e.g. Corallina and Laminaria), which are more terrestrially-dominated.
The Bayu condensate has previously been attributed to either the marine Cretaceous Echuca Shoals Formation, or mixed sourcing from the less terrestrially-influenced facies of the Jurassic Elang and Plover formations, together with the marine Flamingo Group. Analysis of the FI oil confirms a more marine-influenced source facies of the palaeo-oil, with the Echuca Shoals Formation being the most likely source based on oil-oil and oil-source correlations. The FI oil appears to represent a marine source end-member and it is likely that mixing of this oil (sourced from the Echuca Shoals Formation) with hydrocarbons sourced from the more terrestrially dominated Plover/Elang source facies could account for the intermediate composition of the currently reservoired condensate. A discrete "Flamingo Group" is not required and this oil family may not be present in the Bayu area. The differences are nevertheless subtle and a contribution from the Flamingo Group cannot be completely discounted.
The FI oil has a mid-oil window maturity (~0.75% vitrinite reflectance equivalent, VRE), whereas the currently reservoired condensate has a higher maturity (~0.9% VRE). These maturity data are consistent with early expulsion from the more labile, marine-derived organic matter in the Echuca Shoals Formation, followed by expulsion of large amounts of condensate from the more terrestrially-dominated Elang and Plover formations. Three possible transition mechanisms from gas over oil to condensate are consistent with the FI petrographical and geochemical data. The first charge may have (1) been lost by breaching of the seal, (2) been displaced by the condensate, or (3) been partly dissolved in the later condensate charge. A combination of factors 2 and 3 is considered most likely, but further investigation is required to assess these options. The FI oil at Bayu-1 predominantly represents a different hydrocarbon charge compared to the condensate liquid, and so by analogy the large residual oil columns that are observed elsewhere in the Northern Bonaparte Basin are unlikely to be due to water-washing of a pre-existing gas-condensate column similar to Bayu-Undan.
George, S. C., Lisk, M., and Eadington, P. J. (2004) Fluid inclusion evidence for an early, marine-sourced oil charge prior to gas-condensate migration, Bayu-1, Timor Sea, Australia. Marine and Petroleum Geology21, 1107-1128.
Use of oil inclusions to define oil migration
Champagny-1: gamma ray and GOI
Dry well within closure, 2.5 km distant, 90 m below crest of structure
During secondary migration, there is an opportunity for oil to be trapped as fluid inclusions within framework grains such as quartz and within diagenetic cements that have a crystalline structure. Oil saturation on migration pathways remains relatively low, so typically less oil inclusions get trapped compared with samples from an oil column. Geochemical analysis of the much smaller amounts of inclusion oil present in samples from interpreted oil migration pathways has been attempted for two samples from the Champagny-1 and Delamere-1 wells in the Vulcan Sub-Basin, northern offshore Australia. A combination of petrographic analysis, bulk geochemical inclusion analysis and log evaluation confirmed that both samples were from oil migration pathways. Despite the small number of oil inclusions, reliable geochemical data were acquired from both samples that were significantly above the levels detected for the system and outside-rinse blanks. The fluid inclusion (FI) oil trapped on the interpreted oil migration pathway in Champagny-1 was generated from clay-rich marine source rock with little terrigenous organic matter input. It was generated at peak oil window maturity and correlates best with oils derived from the Late Jurassic Lower Vulcan Formation. In contrast, the Delamere-1 FI oil contains evidence of greater input of terrigenous organic matter, and was generated at early oil window maturity. This FI oil also contains a signature of a biodegraded component, which could have been generated either from the Middle Jurassic Plover Formation, or from an older source rock. These data indicate that it is feasible to geochemically map migration pathways across prospects or basins, and to analyse palaeo-oil compositions in oil zones where few inclusions get trapped. This also suggests that the few oil inclusions that sometimes occur in Proterozoic or Archaean rocks may be analysable in the future, which will provide relatively pristine and robust data on the composition and diversity of Earth's early biosphere.
George, S. C., Ahmed, M., Liu, K. and Volk, H. (2004) The analysis of oil trapped during secondary migration. Organic Geochemistry35, 1489-1511.
Controls on biodegradation
There are three main controls on the susceptibility to biodegradation of cyclic, branched and aromatic low molecular weight hydrocarbons: carbon skeleton, degree of alkylation, and position of alkylation. Firstly, ring preference ratios at C6 and C7 show that isoalkanes are retained preferentially relative to alkylcyclohexanes, and to some extent alkylcyclopentanes. Dimethylpentanes are substantially more resistant to biodegradation than most dimethylcyclopentanes, but methylhexanes are depleted faster than methylpentanes and dimethylcyclopentanes. For C8 and C9 hydrocarbons, alkylcyclohexanes are more resistant to biodegradation than linear alkanes. Secondly, there is a trend of lower susceptibility to biodegradation with greater alkyl substitution for isoalkanes, alkylcyclohexanes, alkylcyclopentanes and alkylbenzenes. Thirdly, the position of alkylation has a strong control , with adjacent methyl groups reducing the susceptibility of an isomer to biodegradation. 1,2,3-Trimethylbenzene is the most resistant of the C3 alkylbenzene isomers during moderate biodegradation. 2-Methylalkanes are the most susceptible branched alkanes to biodegradation, 3-methylalkanes are the most resistant and 4-methylalkanes have intermediate resistance. Therefore, terminal methyl groups are more prone to bacterial attack compared to mid-chain isomers, and C3 carbon chains are more readily utilised than C2 carbon chains. 1,1-Dimethylcyclopentane and 1,1-dimethylcyclohexane are the most resistant of the alkylcyclohexanes and alkylcyclopentanes to biodegradation.
Position of alkylation: C8 alkanes
George, S. C., Boreham, C. J., Minifie, S. A. and Teerman, S. C. (2002) The effect of minor to moderate biodegradation on C5 to C9 hydrocarbons in crude oils. Organic Geochemistry 33, 1293-1317.