This product is a Microsoft Access database which contains the raw data, calculated biomarker ratios and reporting output forms. This product includes 120 oils from the first Oils of Western Australia study (WOZ1) and 150 oils from the second Oils of Western Australia study (WOZ2). This database is one component of "The Oils of Western Australia II" product which comprises two other components: an interpretative report documenting the petroleum geochemistry of the oils in the study and assignment of each sample to an oil family, and an ArcView GIS CD containing coverages of North West Shelf regional geology and petroleum exploration themes, and oil family maps linked to graphs of specific chemical parameters which define the families. The Oils of Western Australia II report summarises the findings of a collaborative research program between Geoscience Australia and GeoMark Research undertaken on the petroleum geochemistry of crude oils and condensates discovered within the basins of western Australia and the Papuan Basin, Papua New Guinea prior to March 2000. The interpretations documented herein build on research that Geoscience Australia and GeoMark Research undertook previously in The Oils of Western Australia (AGSO and GeoMark, 1996) and The Oils of Eastern Australia (Geoscience Australia and GeoMark, 2002) studies. To make informed decisions regarding Australia's petroleum resources, it is important to understand the relationship between the liquid hydrocarbons within and between basins. This Study has geochemically characterised the liquid hydrocarbon accumulations of western Australian basins and the Papuan Basin into genetically related families. From a total of 316 samples, 33 oil/condensate families were identified in the western Australian basins; Bonaparte (10), Browse (2), Canning (4), Carnarvon (11) and Perth (6), as well as some vagrant and contaminated samples. Three oil/condensate families were recognised in the Papuan Basin. The geographic distribution of each oil/condensate family is mapped within each basin/sub-basin. Using the geochemical characteristics of each family, the nature of their source facies, thermal maturity level and degree of preservation has been determined. This Study used a set of standardised geochemical protocols that include bulk geochemical (API gravity, elemental analysis of nickel, vanadium and sulphur), molecular (gas chromatography of the whole-oil and gas chromatography-mass spectrometry of the saturated and aromatic hydrocarbons) and bulk stable carbon isotopic analyses. n-Alkane-specific 13C isotopic analyses were carried out on only a selected set of oils and condensates. Statistical analyses were performed on these data using the software Pirouette' provided by Infometrix. In addition to this report, the geochemical data acquired for the crude oils and condensates in this Study are provided in the accompanying Microsoft Access2000 database. These data may be viewed spatially and plotted on x-y cross-plots in the charting application included in the ESRI Australia GIS ArcView3.2 georeferencing package that also accompanies this report.

The Ceduna Sub-basin of the Bight Basin is a frontier region containing only one exploration well. Therefore, our assessment of the distribution of potential source rocks in the area is based on an understanding of the regional sequence stratigraphic framework and the potential petroleum systems present, along with the regionsal palaeogeography, and geochemical data from onshore and the adjacent Duntroon Basin. Studies carried out by AGSO over the past three years suggest that the thick Cretaceous succession in the Ceduna Sub-basin contains a range of fluvio-lacustrine, deltaic and marine source rocks that have the potential to generate liquid hydrocarbons.

Harold Raggatt Award for Distinguished Lecturer Series: "Offshore Australian oil families and petroleum systems" by Dr Dianne Edwards presented as a powerepoint presentation on 1 August 2001.

During ODP Leg 189, the JOIDES Resolution recovered about 4200 m of continuous core from four sites in sedimentary basins on continental crust off Tasmania. These sites, one off west Tasmania, two on the South Tasman Rise (STR), and one on the East Tasman Plateau (ETP) are 760-968 m deep and in water 2100-2700 m deep. No hydrocarbon accumulations were expected at these sites. The pre-Oligocene section is largely shallow-marine organic-rich mudstone, which seismic profiles indicate is the top of a Cretaceous-Eocene largely deltaic sequence thousands of metres thick. This siliciclastic sequence formed as Tasmania rifted from the surrounding parts of Gondwana. Sedimentation rates were relatively high until the late Eocene, when a condensed siltstone sequence formed as the Antarctic Circumpolar Current first swept the shelves of the separating land masses. From the earliest Oligocene, when Australia finally cleared Antarctica, deposition of several hundred metres of carbonate pelagic ooze and chalk predominated. Sedimentation no longer kept up with subsidence, and at most sites unconformities have removed much of the Oligocene. The cores, in conjunction with seismic profiles, provide information on tectonic and sedimentary history and petroleum potential. New data include evidence of high present-day thermal gradients; marginally mature organic matter less than 1000 m below sea bed, biogenic and probably thermogenic gas, and bitumen generation; and overall source rock potential. Tectonic histories vary, but all basins have sufficient sediment and thermal gradient to generate hydrocarbons. However, of the thick sequences interpreted as deltaic, only the upper shelf mudstones were drilled. TOC content decreased with time as the gulfs around Tasmania widened, and also eastward from the more restricted Australo-Antarctic Gulf into the less restricted early Tasman Sea. Although the thermal gradient is highest in the three western sites, the holes do not reach the petroleum window. Methane is biogenic in the younger sediments, but higher hydrocarbon gases at depth suggest a thermogenic component. In addition, Rock-Eval analyses of the oldest sediments suggest bitumen (S2 peak) and organic matter approaching maturity. Little stratigraphic section is missing, so past overburden was unlikely to exceed present. Whether there are reservoir rocks and suitable hydrocarbon traps remains unknown. On the existing evidence, west Tasmania and STR appear to be reasonably prospective for petroleum, and more prospective than ETP, and we present a speculative play concept for them.

The technique of Reaction Gas Chromatography-Mass Spectrometry (R-GCMS) has been applied to the analysis of the polar extracts from a Heartbreak Ridge lignite (Bremer Basin, Western Australia; Eocene age) and a Monterey Formation shale (Naples Beach, USA; Miocene age). A catalyst, palladium black, is packed into glass liners for split vaporising injection. The liners are then placed into the injection port to catalyse the gas phase reaction of volatile polar mixtures. Hydrogen gas is used both as the reactant for hydrogenation/hydrogenolysis, and as the carrier gas for the subsequent separation. The reaction products are mostly hydrocarbons, and are swept on to the column where they are chromatographically resolved by the non-polar stationary phase. The products are then identified by mass spectrometry. The fully active catalyst is effective in hydrogenating and isomerising alkenes as well as partially hydrogenating aromatic moieties. Desulphurisation of thiols, sulphides, and thiophenes readily occurs also. Oxygenated compounds such as primary alcohols, acids, esters and ethers undergo a decarbonylation/decarboxylation, while secondary alcohols are reduced to the parent hydrocarbon. Polar fractions react to produce compound distributions that are characteristic of the organic matter source, namely angiosperm-derived triterpenoids and bacterially-derived hopanoids. The reaction of the polar fraction from the Monterey Formation shale results in the formation of high relative amounts of pristane and phytane. A suite of steroids and triterpenoids, typical of marine organic matter, is also observed. R-GCMS provides less detailed information on the exact nature of the functionalised lipids partitioned within the polar fraction compared to more conventional wet chemical analyses. However, this technique requires only a GCMS instrument fitted with a vaporising injector, which acts as a chemical reactor at the inlet of the column. The main advantages of R-GCMS are its speed, low sample requirement, and production of easily resolved and identified products.

Compelling evidence is presented for the process of lipid sulfurisation in humic coal-forming environments. The production of reduced inorganic sulfides by sulfate-reducing bacteria during early diagenetic marine transgression enabled the selective sequestration of functionalised lipids in the polar and asphaltene fractions from the Eocene, marine-influenced Heartbreak Ridge lignite deposit, southeast Western Australia. Nickel boride desulfurisation experiments conducted on these fractions released small, but significant, quantities of sulfur-bound hydrocarbons. These comprised mostly higher plant triterpanes, C29 steranes and extended 17?(H),21?(H)-hopanes, linked by one sulfur atom at, or close to, sites of oxygenation in the original natural product precursors. These sulfurised lipids mostly derive from the same carbon sources as the free hydrocarbon lipids, the exception being the sulfurised extended hopanoids, which may be partially derived from a different bacterial source compared to the free hopanoids. These results indicate that the selectivity and nature of steroid and hopanoid vulcanisation in coal-forming mires is akin to that observed in other sedimentary environments. However, the diversity of sulfurised higher plant triterpanes is greater than that typically reported in immature coals. This selective preservation mechanism explains the formation of the structurally-related biomarkers in more mature sulfur-rich humic coals.

This Record presents a new stratigraphic interpretation of Cretaceous sedimentary rocks encountered in petroleum exploration wells, stratigraphic holes and water bores along the southern Australian coast in Western Australia and South Australia. The Cretaceous succession in these wells is interpreted within the Bight Basin sequence stratigraphic framework, and is correlated with the thicker section farther basinward. The correlation is based on existing and recently commissioned biostratigraphic data, and the interpretation of seismic data on the continental shelf. The onshore wells contain a sedimentary section ranging in age from Valanginian to Campanian, and attributable to the Bronze Whaler, Blue Whale-White Pointer, Tiger and Hammerhead supersequences. The succession reaches a maximum thickness of more than 357 m in the Madura 1 well. The section preserved in these wells records the evolution of depositional environments near the northern margin of the Bight Basin, from areally restricted non-marine deposition in the Early Cretaceous, through increasingly marine, although shallow and anoxic, conditions, to the local development of a small deltaic complex in the Late Cretaceous. Organic-rich non-marine shales of Early Cretaceous age, and Late Cretaceous organic-rich facies of marine affinity have been identified in wells in the study area., providing new information about the nature and extent of potential source rocks in the Bight Basin.

Legacy product - no abstract available

To date, compositional information and compound specific isotope analysis (CSIA) of stable carbon isotopes for individual C1 to C5 gaseous hydrocarbons has been the primary data for the interpretation on Australian natural gases (Boreham et al., 2001). Here we report for the first time the stable hydrogen isotopic composition (D/H ratio) of the C1 to C5 gaseous hydrocarbons in Australian natural gases. The influence of source, maturity and in-reservoir alteration (biodegradation) is documented, and in combination with complementary carbon isotope data, this provides a powerful tool for the study of the origin and correlation of the natural gas. Source influences in Australian natural gases from Australian sedimentary basins show a wide range in hydrogen isotopes with ?D ca. 160 ? for both methane (?D -290 to -135 ?) and iso-butane (?D -255 to -94 ?). On the other hand, the isotopic range for carbon isotopes is an order of magnitude less, ?13C of 17 ? and 13 ? for methane (?13C -48.5 to 31.5 ?) and iso-butane (?13C -35.4 to -22.5 ?), respectively (Boreham et al., 2001). The source rock ages of the natural gases cover most of the Phanerozoic, from Ordovician in the Amadeus Basin to Early Eocene in the Bass Basin. Gases generated from older marine source rocks are most depleted in deuterium whereas gases sourced from the younger terrestrial coals are amongst the most enriched in D; carbon isotopes also show a similar response to age and source organic facies. Biodegradation of natural gas from the Carnarvon Basin produces a drier gas, due to the addition of biogenic methane and selective removal of wet gas components in the order propane > n-butane ? n?pentane > i-pentane > ethane ? i-butane. The addition of isotopically light biogenic methane leads to an overall isotopic shift of ?13C = ?11.5 ? compared to the non-biodegraded thermogenic gas, whereas the hydrogen isotopes remain unchanged. This, coupled with the enrichment in 13C of the associated CO2 suggests a role for anaerobic methanogenic bacteria. For the wet gas components maximum isotopic enrichments of ?13C = 18.2 ? (Boreham et al., 2001) and in ?D of 225 ? occur for those components that have been almost completely biodegraded. The strong positive correlation between carbon and hydrogen isotopes for the individual wet gas components implies a kinetic control on the isotopic composition, consistent with a biological-mediated process. The response of ?D to maturity is less attenuated compared to source and biodegradation effects. A maturation sequence from mature oil-associated wet gas to highly overmature dry gas from the Cooper Basin shows a ?13C enrichment of 15 ? for methane, with less isotopic enrichment in the wet gas components (Boreham et al., 2001). Such a maturity range in carbon isotopes for methane relates to a vitrinite reflectance range between 0.9 to 7.0% (Schoell, 1983), which is consistent with measured source rock maturities in the Cooper Basin (Boreham and Hill, 1998). On the other hand, ?D varies by ca. 50 ? for methane (?D -162 to -116 ?), with a lower isotopic enrichment observed for the wet gas components. The strong correlation shown between hydrogen and carbon isotopes in natural gas components suggests that isotopic exchange with external hydrogen sources (eg. water) is not a significant process. This contrasts with liquid hydrocarbon components where it appears that scrambling of the hydrogen isotopes occurs during oil generation (Schimmelman et al., in press). Furthermore, the relative insensitivity in ?D to maturity effects enhances the potential of CSIA for D/H ratios becoming an important isotopic tool in gas-gas (and gas-oil) correlation where the influence of source is of primary interest.

Australia's National Oil-on-the-Sea Identification Database (NOSID) contains organic geochemical data on a reference set of 30 oils that is used to characterised (or fingerprint) an oil. The data on these oils have been produced from a variety of analytical methods including isotope, UVF, GC and GC-MS (biomarker) analyses. The NOSID database and the Oil Identification Reference Kit are the products of collaboration between the Geoscience Australia (GA), the Australian Government Analytical Laboratories (AGAL) and the Australian Maritime Safety Authority (AMSA).