No abstract

Biomarker geochemistry, maturation modelling and migration pathway analysis have been used in a new, integrated analysis of the Gippsland Basin. The analysis has resulted in the development of a predictive model for hydrocarbon charge and oil versus gas split. The study was carried out in 4 parts: analytical geochemistry, source distribution mapping, maturation modelling and migration pathway analysis.New geochemical biomarker studies confirm a non-marine source for the oils, but place peak oil generation in the upper part of the traditional oil window. Gas in the basin is mainly derived from overmature source rocks. Coals were recognised to contribute significantly to oil generation.The source rock thickness and distribution for the entire basin were mapped using analytical techniques plus wireline log analysis, coupled with seismic structural mapping and facies analysis. Prime oil-prone source rocks were found to be located in the lower coastal plain depositional environment. Extrapolations were necessary for older rocks, using stratigraphic models.Maturation modelling modelling of selected wells and synclines was carried out and an overall basin model constructed. Post-structuring yields of oil and gas were also derived. A key result was the lack of post-structuring overmature gas generation in the oil prone southeastern part of the basin, owing to high palaeo-temperatures associated with earlier rifting.Analysis of present day and palaeo-migration pathways gave an excellent match between predicted oil versus gas ratios and discoveries, both geographically and stratigraphically. The tool is now being used in a predictive mode to highgrade basin prospectivity.

Although the concentration of long-chain aliphatic constituents is a primary determinant of the oil generation potential of coals, the factors which govern their occurrence in different coals are poorly understood. In this study, Permian coals from the Cooper Basin, Australia, and the Eocene coals from the Taranaki Basin, New Zealand, were compared to determine these factors.The Taranaki Basin coals were deposited in temperate, fluvial-deltaic environments. HI values range from 236-365. Extracts have high pristane/phytane ratios and variable abundances of oleanane and other non-hopanoid terpanes. The extracts and pyrolysates contain high relative concentrations of aliphatic groups > n-C20. These data imply that much of this aliphatic carbon is derived directly from higher plant material.The Cooper Basin coals were deposited in high latitude bogs and contain 40-70% inertinite. The coals have been severel~¢ degraded. Pristane/phytane ratios are low (2.15-6), but His are moderate (up to 243 mg g-OC). The extracts and pyrolysates both contain high relative concentrations of aliphatic groups; however, the distributions are different from higher plant-derived material. These data imply the bulk of the aliphatic carbon in these coals is derived from microbial biomass (both bacterial and fungal degradation products and algal input).These results show that long-chain aliphatic groups in coals can be derived directly from the higher plant material, from microbial activity in the depositional environment, or from a combination of the two.

The Gippsland oils, though derived from a common terrestrial source, show considerable variation in their chemical compositions. They range from being very waxy and paraffinic to light, almost condensate-like, oils. Much of this variation can be explained as a function of increasing maturity at the time of generation, with the earliest generated oil being characterised by dominant n-alkanes in the C22-23 is range, remnant odd-over-even preference above C25 and general lack of lower molecular weight gasoline and kerosene range hydrocarbons. At peak generation, the oils show a trimodal distribution as increased thermal cracking generates lighter hydrocarbons with a maximum around n-C7-8 and lesser maxima at n-C14 and n-C23. The most mature oils show the destruction of nearly all of the high molecular weight hydrocarbons and exhibit a unimodal composition maximising at n-C9 or less. These light oils are nearly always associated with gas caps, suggesting a link between the two. Secondary alteration by biodegradation and water-washing is common but its severity and the composition of the resulting oil is varied. Reservoir temperature is one of the key controls on biodegradation with no degraded oils observed at temperatures above 75-80°C. This, combined with the known limits of fresh water influx, makes it possible to predict the probable biodegradation effects on reservoired oil prior to drilling.

The technique of determining the level of maturity of a gas by using the isotopic separation between its hydrocarbon components has been applied to gases flashed from undersaturated Gippsland Basin oils. The results suggest that the Gippsland Basin oils have been generated at an LOM of 11-12. Fluviatile shales of Late Cretaceous age at depths of around 3900 m are interpreted as being the source for much of the paraffinic oil discovered to date.