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.

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.

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.

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.

In October/November 1990 the Australian Bureau of Mineral Resources (BMR) carried out an 18 day combined water column geochemical and high resolution seismic survey on the Vulcan Sub-basin region of the Timor Sea. This report presents the results of the water column geochemical (direct hydrocarbon detection or DHD) aspects of that program. During the program, 2730 km of DHD data were obtained along 44 lines over the Vulcan Sub-basin, the Ashmore Platform and the Londonderry High. Ten water bottom hydrocarbon anomalies were detected during the program. Seven of these anomalies fell into two distinct groupings, which were associated with: - the Skua field and surrounding fault blocks, - the intersection of the NE-trending Vulcan Sub-basin/Londonderry High Boundary Zone with a prominent NW-trending transfer fault zone. The composition of the hydrocarbon anomalies within the Skua grouping was generally consistent with them having an oil-prone, Late Jurassic source,, and is thus compatible with the known composition of the hydrocarbons in the Skua accumulation. The composition of the other grouping was more consistent with a gas/condensate source; they may have originated from more gas prone Permo-Triassic source rocks on the edge of the Londonderry High. The remaining anomalies were all very weak, and may have been due to biogenic activity. The data indicate that the DHD technique can be useful at a prospect level within the Timor Sea (for example, it did remotely detect the Skua accumulation). The types of accumulations which are most easily detected using DHD are those with a significant gas cap, a relatively shallow (<2000 m) reservoir, and faulting which extends from the reservoir horizon to near the seafloor. Furthermore, the data suggest that transfer fault zones provide important pathways for hydrocarbon migration in this region.

No abstract available

Geoscience Australia has recently completed a survey searching for evidence of natural hydrocarbon seepage in the offshore northern Perth Basin, off Western Australia. The survey formed part of a regional assessment of the basin's petroleum prospectivity in support of ~17,000 sq km of frontier exploration acreage release in the region in 2011. Multibeam bathymetry, sub-bottom profiler, sidescan sonar and echosounder data were acquired to map seafloor and water column features and characterise the shallow sub-surface sediments. A remotely operated vehicle (ROV) was used to observe and record evidence of seepage on the seafloor. 71 sediment grabs and 28 gravity cores were collected and are currently being analysed for headspace gas, high molecular weight biomarkers and infaunal content. Survey data identified an area of high 'seepage' potential in the northernmost part of the study area. Recent fault reactivation and amplitude anomalies in the shallow strata correlate with raised, high-backscatter regions and pockmarks on the seafloor. A series of hydroacoustic flares identified with the sidescan sonar may represent gas bubbles rising through the water column. The ROV underwater video footage identified a dark-coloured fluid in 500 metres water depth proximal to the sidescan flares which may be oil that naturally seeped from the seafloor. The integration of the datasets acquired during the marine survey is indicative of natural oil seepage and provides additional support for the presence of an active petroleum system on this part of the continental margin.