Evolution of the Lord Howe Rise basin systems and underlying basement terrances were influenced by multiple periods of tectonism and volcanic activity spanning the Palaeozoic to Tertiary. The prospects for hydrocarbon accumulations are moderate to high in several basins of the LHR, with evidence such as amplitude anamalies, bottom-simulating reflectors and low-level seeps observed on seismic and remotedly sensed data. The economic viability of exploration and production in this rremote region has not been assessed.

1. Blevin et al.:Hydrocarbon prospectivity of the Bight Basin - petroleum systems analysis in a frontier basin 2. Boreham et al : Geochemical Comparisons Between Asphaltites on the Southern Australian Margin and Cretaceous Source Rock Analogues 3. Brown et al: Anomalous Tectonic Subsidence of the Southern Australian Passive Margin: Response to Cretaceous Dynamic Topography or Differential Lithospheric Stretching? 4. Krassay and Totterdell : Seismic stratigraphy of a large, Cretaceous shelf-margin delta complex, offshore southern Australia 5. Ruble et al : Geochemistry and Charge History of a Palaeo-Oil Column: Jerboa-1, Eyre Sub-Basin, Great Australian Bight 6. Struckmeyer et al : Character, Maturity and Distribution of Potential Cretaceous Oil Source Rocks in the Ceduna Sub-Basin, Bight Basin, Great Australian Bight 7. Struckmeyer et al: The role of shale deformation and growth faulting in the Late Cretaceous evolution of the Bight Basin, offshore southern Australia 8. Totterdell et al : A new sequence framework for the Great Australian Bight: starting with a clean slate 9. Totterdell and Bradshaw : The structural framework and tectonic evolution of the Bight Basin 10. Totterdell and Krassay : The role of shale deformation and growth faulting in the Late Cretaceous evolution of the Bight Basin, offshore southern Australia

This "Petrel on WebBury" package presents interactive geohistory models of the regional burial, thermal and hydrocarbon maturation and expulsion history of the Petrel Sub-basin, Bonaparte Basin, NW Australia. These models are based on a comprehensive geohistory analysis undertaken by Geoscience Australia and Burytech Pty Ltd. The geohistory models are generated by the WinBuryTM 1D burial and thermal geohistory modelling software. The thermal history models are constrained by conventional vitrinite reflectance (VR), thermal alteration index (TAI), spore colour index (SCI), conodont colour alteration index (CAI) and limited fluorescence data (FAMM), together with limited apatite fission track analysis (AFTATM). The burial and thermal models are applied to potential Carboniferous-Cretaceous two source units within each well, and to three basin-wide source rock units - Lower Carboniferous Milligans Formation, Lower Permian Keyling Formation and Late Permian Hyland Bay Formation - to constrain the timing and relative volumes of expelled liquid/gaseous hydrocarbons. New kerogen kinetic data for these source facies are utilised in the expulsion models. The modelling package is divided into 5 sections: Wells: Geohistory models for 24 wells & 11 depocentre sites. X-sections: Cross-section geohistory models. Multi-well: Multiple-well geohistory curves and basin-wide maps for three source unit. Seismic: Interpreted seismic lines showing structural setting of the wells. Petroleum Systems: Schematic summary of the active petroleum systems. Multiple views within each section can be interactively selected by the user (eg. temperature, heatflow, subsidence, maturity and expulsion time-plots/contoured maps) by way of point and click buttons and drop-down windows. The user can make temporary modifications to existing, or add new, data in the well models, and view corresponding maturity, generation and expulsion models based on these changes. These revised models can be printed directly from the screen views but will not be saved on exit from the well. Current users of WinBuryTM modelling software can copy well data files from this package to their WinBury working directories. The package is run on a PC and requires 30MB hard disc space, Windows 95/98 or NT operating systems, and utilises a standard Web browser (Internet Explorer or Netscape Navigator).

The spectral signature of an about 1 micrometer thick oil slick has been identified from airborne hyperspectral data (HyMap sensor) acquired over a floating oil production facility located on the North West Shelf of Australia. The paper describes spectral characteristrics of the signature and identifies conditions in which it can be observed.

Using numerous illustrations this comprehensive black and white resource describes the formation, trapping and uses of natural gas as a non-renewable energy source. The exploration and recovery methods of gas are described, as are Australia's natural gas potential and environmental issues such as greenhouse gases. This 110 page booklet includes student activities with suggested answers. Suitable for secondary Years 9-12.

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.

A medium term forecast of undiscovered hydrocarbon resources for the Mesozoic and Palaeozoic petroleum systems of the Bonaparte Basin has been generated by Geoscience Australia. It concludes that there is a mean expectation that 56 gigalitres (350 million barrels) of oil, 82 billion cubic metres (2.9 trillion cubic feet) of gas, and 18 gigalitres (115 million barrels) of condensate are likely to be discovered in the next ten to fifteen years. This assessment is highly sensitive to the modelled number of wildcat wells to be drilled and is based on historical drilling success rates. The assessment process only assesses existing play types and cannot account for new or unconceived plays. This assessment is significantly smaller than the US Geological Survey assessment released in 2000, and the difference is mainly attributable to the timeframe being addressed by the two different assessment processes and the level to which reserves growth is modelled. The Geoscience Australia forecast is for the medium term with no reserves growth modelled whereas the USGS forecast approximates an ultimate discovery assessment with reserves growth incorporated. An appropriate assessment methodology is critical when attempting to undertake an assessment and should be selected to answer specific questions. The Geoscience Australia methodology is a discovery-process (or creaming curve) model and the assessment results are primarily used for input into production forecasts. The assessment process has been revised with this new assessment being a petroleum system approach which is more suitable than the migration fairway approach used in the previous resource estimations. Reserves growth has been identified by the US Geological Survey as a critical element in estimating future hydrocarbon supply. Research is being directed within Geoscience Australia to determine its effect on its resource assessments.

A study of the Strahan Sub-basin in particular, and the wider Sorell Basin in general, has revealed the likely presence of an active hydrocarbon generation, migration, leakage and seepage system along the West Tasmanian Margin (WTM). 2D basin modelling of seismic data has demonstrated that a previously identified, high-quality Maastrichtian source interval is unlikely to contribute significantly to hydrocarbon inventories in the region. However. an interpreted deeper Cretaceous source rock has been sufficiently mature to expel hydrocarbons over much of the sub-basin since the Early Tertiary. Combining the seismic mapping and modelling of this deeper source facies with the mapping of hydrocarbon leakage indicators such as gas chimneys and carbonate build-ups has shown that active, present day hydrocarbon leakage and seepage is restricted to fault arrays immediately to the north-west of, and up-dip from, a thermally mature, Cretaceous source system. These observations demonstrate that a deeper source system is working but do not reveal whether the source system is oil-, condensate- or gas-prone. In one area, strong seismic evidence for present day seepage at the seafloor was observed, with the likely formation of methane-derived authigenic carbonates located directly above seismically prominent chimneys. The fact that the faults up-dip from the mature source leak raises the issue of how much of the generated hydrocarbons have been preserved in this area. Interpretation of new Synthetic Aperture Radar (SAR) data revealed a very low density of natural oil slicks along the West Tasmanian margin. Moreover, no SAR seepage slicks were observed over the area of identified active seepage within the Strahan Sub-basin. This could suggest that the area is condensate- or gas-prone, though hydrocarbon analyses of the seafloor sediments suggest that thermogenic hydrocarbons, some of which are moderately geochemically wet, are present along the West Tasmanian margin. This apparent contradiction might be explained by the fact that the seepage is intermittent, that the SAR data were at the upper end or lower end of the weather compliance envelope, or that the amount of liquid hydrocarbons leaking is relatively small, and hence the resulting SAR seepage slicks are too small to map. Further work to discriminate between these alternatives, and combinations thereof, is necessary. In particular, we would recommend the sampling of the seafloor seeps identified in the Strahan Sub-basin as a priority, as the presence of oil within these sediments would immediately high-grade this area significantly. Fault seal is quite likely to be a major risk within the Strahan Sub-basin due to the apparent relatively unfavourable alignment of the faults and the regional NNW stress trajectories. If the faults have relatively steep dips, they are probably leaky, as evidenced by the presence of gas chimneys developed preferentially along these faults in areas where the source is mature. In general, more north-east to east-west trending fault blocks will be likely to have higher seal integrity, but if such targets cannot be identified, then NNW trending faulted traps with shallow-dipping bounding faults represent a more attractive target than those with steeper dips, as would stratigraphic traps.

This is a compilation of all proven and probably producing source rocks from Australia. These can be grouped into 15 intervals ranging in age from Late neoproterozoic to Late Cretaceous-Eocene.

The objectives of Project 121.19 were: To understand the deep crustal architecture, the structural reactivation processes and the mechanisms of hydrocarbon generation, migration and entrapment within the Vulcan Sub-Basin, Timor Sea. To achieve the aims of the project, two surveys (Vulcan I & II) were conducted between October and December 1990. This report summarises the results of the Vulcan Sub-Basin I Survey (Survey 97), which focussed on the high resolution seismic and geochemical component of Project 121.19 (i.e. the structural reactivation, hydrocarbon generation and migration theme). The Timor Sea program achieved most of its objectives. The seismic data should, when processed, allow a much better understanding of the nature of the fault reactivation processes in the area. In addition, strike lines run along the Londonderry High show that near-vertical faults appear to correspond with the position of transfer faults which have been inferred from our interpretation of BMR's Timor Sea aeromagnetic data. The geochemical program identified a number of significant hydrocarbon anomalies in the area. The anomalies fell predominantly into two groups. One group was located over, and to the north-east to south-east of the Skua Field, while the other group was associated with transfer faulting, and a major aeromagnetic high, on the edge of the Vulcan Sub-Basin, south-east of Montara 1.