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.

Jurassic and Cretaceous clastics of the Western Papuan Basin provide reservoir and source potential for hydrocarbon accumulation. Early Jurassic coarse clastics from sources in the south and west cover a wide stable platform area, while finer grained equivalents were deposited in a deepening trough along the east and northeast margins. A Middle Jurassic transgression deposited a thick shale unit over most of the basin, followed by a return to sand and silt deposition in the Late Jurassic-Early Cretaceous. Eocene/Miocene structuring in the north formed the Omati Trough which filled with deep water Miocene carbonates. This was followed by shallow water carbonates which cover the Western Papuan Basin. Mountain ranges to the north and northeast were the source for thousands of feet of poorly sorted Plio- Pleistocene sediments which were dumped in the rapidly subsiding Aure Trough and spread as a veneer over the remainder of the Papuan Basin.Geochemical studies indicate that adequate source rocks exist within the Mesozoic shales and these reach maturity at a depth of about 2700m. The Mesozoic shales correlate more closely with the various oil and condensate seeps than do the Miocene carbonates which are generally too immature over much of the basin to be considered as a significant oil source.The stable platform, except for the Omati Trough, has undergone very little tectonic movement since the Triassic and this has severely restricted the formation of structural traps suitable for hydrocarbon entrapment. Better structuring exists to the east of a Mesozoic hinge-line running approximately north- south just offshore from the present-day coastline, but lack of good Mesozoic reservoir sands in this area limits the hydrocarbon prospects. The most prospective area is the structured margin of the Omati Trough, where tilted fault blocks provide traps for hydrocarbons generated from the underlying shales of the Cretaceous and Jurassic, but difficult terrain and high exploration costs make for high risk exploration.

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.

No abstract

The Fortescue-1 well drilled in the Gippsland Basin in June 1978 was a dry hole. However, results of detailed stratigraphic analysis together with seismic data provided sufficient information to predict the possible occurrence of a stratigraphic trap on the flank of the giant Halibut structure.Three months later the West Halibut-1 well encountered oil in the Latrobe Group 16 m below that depth carried as the original oil-water contact for the Halibut field. Following wireline testing in both the water and oil-bearing sandstone units, two separate pressure systems were recognised in the well. Three additional wells, Fortescue-2, 3 and 4, were drilled to define further the limits of the field, the complex stratigraphy and the hydrocarbon contacts.Integration of detailed well log correlations, stratigraphic interpretations and seismic data indicated that the Fortescue reservoirs were a discrete set of units stratigraphically younger and separated from those of Halibut and Cobia Fields. Analysis of pressures confirmed the presence of two separate pressure systems, proving none of the Fortescue reservoirs were being produced from the Halibut platform. Geochemical analysis of oils from both accumulations supported the above results, with indications that no mixing of oils had occurred.Because the Fortescue Field is interpreted as a hydrocarbon accumulation which is completely separated from both Halibut and Cobia Fields, and was not discovered prior to September 17, 1975, it qualified as "new oil" under the Federal Government's existing crude oil pricing policy. In late 1979, the Federal Government notified Esso/BHP that oil produced from the Fortescue Field would be classified as “new oil”.