A recent Geoscience Australia sampling survey in the Bight Basin recovered hundreds of dredge samples of Early Cenomanian to Late Maastrichtian age. Given the location of these samples near the updip northern edge of the Ceduna Sub-basin, they are all immature for hydrocarbon generation with vitrinite reflectance - 0.5% RVmax, Tmax < 440oC and PI < 0.1. Excellent hydrocarbon generative potential is seen for marine, outer shelf, black shales and mudstones with TOC to 6.9% and HI up to 479 mg hydrocarbons/g TOC. These sediments are exclusively of Late Cenomanian-Early Turonian (C/T) in age. The high hydrocarbon potential of the C/T dredge samples is further supported by a dominance of the hydrogen-rich exinite maceral group (liptinite, lamalginite and telalginite macerals), where samples with the highest HI (> 200 mg hydrocarbons/g TOC) contain > 70% of the exinite maceral group. Pyrolysis-gas chromatography and pyrolysis-gas chromatography mass spectrometry of the C/T kerogens reveal moderate levels of sulphur compounds and the relative abundances of aliphatic and aromatic hydrocarbons predict the generation of a paraffinic-naphthenic-aromatic low wax oil in nature. Not enough oom for rest of Abstract

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Surprisingly few natural hydrocarbon seeps have been identified in Australia's offshore basins despite studies spanning thirty years. Initial studies of natural hydrocarbon seepage around the Australian margin were generally based around the geochemical analysis of stranded bitumens, water column geochemical `sniffer' sampling, synthetic aperture radar or airborne laser fluorsensor. Later studies involved the integration of these remote sensing and geochemical techniques with mutli-channel and shallow seismic. A review of these earlier studies indicates that many seepage interpretations need to be re-evaluated and that previous data sets, when set in a global context, often represent normal background hydrocarbon levels. Relatively few sites of proven natural hydrocarbon seepage in Australia's offshore sedimentary basins can be reconciled with the dominantly passive margin setting and low recent sedimentation rates, which are not favourable for high rates of seepage, and difficulties in proving seepage on high energy, shallow carbonate shelves, where seabed features may be rapidly reworked and modern marine signatures are overprinted on authigenic seep carbonates. Active thermogenic methane seepage on the Yampi Shelf, the only proven documented occurrence in Australia, is driven by deposition of a thick Late Tertiary carbonate succession and Late Miocene tectonic reactivation. Therefore, to increase the success of detecting and correctly interpreting natural hydrocarbon seepage, data need to be analysed and integrated within the context of the local geological setting, and with an understanding of what is observed globally.

A wide variety of studies have been carried out around the Australian margin to infer or detect natural hydrocarbon seepage. Hydrocarbon seepage can, in selected geological settings, delineate subsurface petroleum accumulations and provide information on hydrocarbon charge type. However, the relationship between near-surface hydrocarbon seepage and subsurface petroleum generation and entrapment is often complex. Rates and volume of hydrocarbon seepage to the surface produce a variety of near-surface geological and biological responses, which require a range of sampling techniques to detect the seepage effectively. Interpreters must firmly grasp these issues to understand the significance of migrated hydrocarbons within near-surface sediments. Thus, it is important to understand the data types that have been used to infer seepage in Australia and the results of these studies, if natural hydrocarbon seepage is to be assumed in this region. Furthermore, the strengths and weaknesses of different approaches need to be understood and the data often need to be set in a global context to appreciate the significance of results obtained. This report is aimed at providing an overview of natural hydrocarbon seepage studies that have been carried out around Australia and to provide information on techniques and approaches that have proved to be successful during studies carried out by Geoscience Australian between 2004 and 2007. ... This investigation provides an increased understanding of seepage detection technologies and techniques, particularly in relation to the Australian environment, and appropriate interpretation of potential seepage indicators in a global context. Consequently, seepage studies can be undertaken with greater confidence in Australia's offshore jurisdiction, in locations and at times that are optimal for effective seepage detection.

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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.

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This publication is the sucessor to Oil and Gas Resources 2000 and continues as the definitive reference on exploration, development and production of Australia's petroleum resources. It covers exploration, reserves, undiscovered resources, development, production and supporting information and statistics. It includes a forecast of Australia's crude oil and condensate production from 2001 to 2015, and sustainability indicators for petroleum resources. Information on Australia's petroleum data availability is also included. A revised estimate of Australia's undiscovered resources is included. The Appendices describe wells drilled and seismic surveys carried out in 2001. There is also a chronological listing of offshore and onshore oil and gas discoveries to 2001, listings of all petroleum platforms and pipelines, and a map showing all Australian petroleum exploration and development titles, with a key of title holders and interests as at March 2001. OGRA 2001 provides the background for much of the advice on petroleum resources given to the Australian government and is a key source for petroleum exploration, production and service companies, petroleum engineers and geologists, energy analysts, stockbrokers and share investors.

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.

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