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.

No abstract available

This product contains basic data drawn from Geoscience Australia's in-house databases. The data relates to the Bass and Durroon Basins, and provides information on bathymetry, gravity, magnetics, biostratigraphy, porosity and permeability, geochemistry, velocity and hydrocarbon shows.

The regional assessment of hydrocarbon seepage is built around a combination of Radarsat and ERS Synthetic Aperture Radar (SAR) data, acquired during 1998 and 1999, as part of a collaborative project between AGSO - Geoscience Australia, Nigel Press & Associates, Radarsat International and AUSLIG (specifically the Australian Centre for Remote Sensing). In total, 55 Radarsat Wide 1 Beam Mode scenes and 1 ERS scene from the Great Australian Bight (GAB) region were analysed. The data were integrated with regional geological information, and other hydrocarbon migration/seepage indicators such as reprocessed and reinterpreted legacy Airborne Laser Fluorosensor (ALF) data, to provide an assessment of the possible charge characteristics of the region. The results of the study suggest that active, though areally restricted, liquid hydrocarbon seepage is occurring within the Bight Basin. The majority of seepage slicks occur along the outer margin of the major depocentre, the Ceduna Sub-basin, in areas where significant Late Tertiary to Recent faulting extends to the seafloor. Very little evidence of seepage was observed on the SAR data above the main depocentre, which is an area of minimal Late Tertiary to Recent faulting. Reprocessed ALF data reveal three main areas with relatively dense fluors. Although they are not directly coincident with locations of seepage interpreted from SAR data, their distribution support the pattern of preferred leakage along the basin margins. Integration of regional geological models with the results of this study suggests that structural features related to active tectonism have focused laterally migrating hydrocarbons to produce active seepage at specific locations in the basin. Where these features are absent, seepage may be passive and/or be governed by long distance migration to points of seal failure. Together with oil and gas shows in exploration wells, observations from this study provide further evidence that liquid hydrocarbons have been generated in the Great Australian Bight.

The Capel and Faust basins, located on the Lord Howe Rise in water depths between 1,300 m and 2,500 m, were the focus of a series of marine surveys by Geoscience Australia in 2006 and 2007. Their interpretation of high-fold 2D seismic reflection, gravity and magnetic, multi-beam bathymetry, sonobuoy refraction, heat flow and geological sample data suggested the basins have petroleum potential. Analysis of petroleum generation and migration, based on structural maps, lithological and other data supplied by Geoscience Australia, is the focus of this study. Basin models predict that most of the deeper depocentres in the Capel and Faust basins, mapped as containing Jurassic-aged pre-rift and Cretaceous-aged syn-rift source rocks, have the potential to expel oil and gas, and charge nearby syn-rift and post-rift reservoir formations from Cretaceous time to the present day. Multi-1D thermal and petroleum generation models predict: - Pre-rift (215 - 165 Ma) and Syn-rift 1 (130 - 100 Ma) megasequences within the deeper depocentres are within the oil or gas generation window; - Based on the expected presence of petroleum-generative coaly source rocks, total oil and gas expulsion from the major depocentres exceeds 5 MMbbl/km2 and 25 Bcf/km2 respectively from the Pre-rift source rocks, and 20 MMbbl/km2, and 300 Bcf/km2 respectively from the Syn-rift 1 source rocks. In terms of timing, 80% of total hydrocarbon expulsion is predicted by the end of the Eocene, with maximum expulsion taking place between the Late Cretaceous and the Late Eocene (c. 68-36 Ma); - A significant increase in paleo-water depth in late Cenozoic time has supressed further heating related to post-Eocene burial. However, modelling predicts post-Eocene expulsion of oil and gas may have been partly enhanced by post-rift magmatism. In this study total expelled oil and gas volumes are 'migrated across' mapped horizons to assess charge of and fill-spill relationships between structural traps. This map-based charge modelling assumes certain reservoir properties with no migration losses and predicts that: - Accumulations within potential reservoir facies, such as deltaic, shoreline and turbidite sandstones of the lower Post-rift unit (70 - 68 Ma) are dominantly gas with volumes generally about 5 to 9 Tcf at burial depths of 400 - 700 m; - Accumulations within similar sandstones of the upper Syn-rift 2 unit are mixed oil and gas (about 2 to 3 billion bbl oil and 10 Tcf gas) at burial depths of 400 - 800 m; - Similar accumulations are present in the lower Syn-rift 2 and Syn-rift 1 fluvial sands; - Most of the mapped structural traps are buried to relatively shallow depths and seal effectiveness for containment must therefore be a significant risk. Deeper structures and stratigraphic plays may further contribute to the petroleum potential in the basins. The model presented here illustrates the potential for petroleum charge of structural traps in the Capel and Faust basins and highlights the risks associated with source rock distribution and type, reservoir distribution and quality, and seal effectiveness. Volumetric and charge assessments could be further refined using higher density seismic data and appropriate rock property data for reservoir and seal rocks in combination with 3D modelling.

No abstract available

Small Angle Neutron Scattering analyses were carried out on 165 organic-rich Lower Cretaceous-Upper Jurassic claystone samples from 9 wells in the Browse Basin (Adele-1, Argus-1, Brecknock South-1, Brewster-1A, Carbine-1, Crux-1, Dinichthys-1, Gorgonichthys-1 and Titanichthys-1). Samples from Brewster-1A and Dinichthys-1 were also analysed using the Ultra Small Angle Neutron Scattering technique. Although geochemical data indicate the existence of a potential gas and oil effective source rock in the Lower cretaceous section (Echuca Shoals and Jamieson Formations), the SANS/USANS data indicate significant generation but little or no expulsion. This source limitation may explain poor exploration success for oil in the area. The SANS/USANS data provide evidence of intra- and inter-formational hydrocarbon migration or kerogen kinetics barriers. Some gas charge to the Berriasian 'Brewster' sandstone in Brewster-1A is possible.

Conference volume and CD are available through the Petroleum Exploration Society of Australia

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.