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.

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).

The Oil Identification Reference Kit (OIRK) is a subset of the oils registered in Australia's National Oil-on-the-Sea Identification Database (NOSID). It's purpose is to provide laboratories engaged in oil fingerprinting with a series of well characterised reference oils and the materials, methods and reference data to support quantitative analysis of petroleum biomarkers. Biomarker methods are rapidly being incorporated in oil identification protocols as they offer several advantages over traditional methods. There is a lack of commercially available reference materials, especially those suitable for quantitative determination. The NOSID database and the OIRK are the products of collaboration between the Australian Geological Survey Organisation (AGSO), the Australian Government Analytical Laboratories (AGAL) and the Australian Maritime Safety Authority (AMSA).

Oil sourced from terrestrial organic matter accounts for over half of Australia?s oil reserves. The majority of this lies with the 4 billion barrels of recoverable oil in Late Cretaceous?Early Tertiary reservoirs of the Gippsland Basin. However, the role of oil expulsion from coal still raises considerable debate, both in the regional and global context. This question was addressed by a detailed gas-oil-source correlation study in the Bass Basin with complementary geochemistry on gas, oil and coal from the adjacent Gippsland Basin. Both basins shared a similar extensional tectonic and depositional setting throughout the Cretaceous to Tertiary leading to the breakup and isolation of continental Australia. Potential oil-prone source rocks in the Bass Basin are the early Tertiary coals. These coals have hydrogen indices (HI) up to 500 mg HC/gTOC and H/C ratio of 0.8 to 1.0. Associated disseminated terrestrial organic matter in claystones is mainly gas prone. Maturity is sufficient for oil and gas generation with vitrinite reflectance up to 1.8 % attained solely through burial. The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are: (i) the onset of oil generation at a vitrinite reflectance (VR) of 0.65 %; (ii) the onset of expulsion (primary migration) at a VR of 0.75 %; (iii) the main oil window between VR of 0.75 % and 0.95 %; and, (iv) the main gas window at VR >1.2 %. Sub-economic oil accumulations in the Bass Basin form a single oil population, based on carbon isotopes and biomarker, and are distinct from the oils from the Gippsland Basin. Natural gases are generated over a broader maturity range than the oils but nonetheless are associated with the same source rocks. Oil-to-source correlation in the Bass Basin based on biomarkers shows that the latest Paleocene?Early Eocene coals are the effective source rocks in the Bass Basin and provides the strongest geochemical evidence yet that coal has sourced petroleum in Australia. Carbon isotopes provide the main discrimination for coals, and their derived gases and oils, with the Early Eocene coals being the most depleted in 13C compared to older Late Cretaceous and Early Tertiary coals. It is likely that the carbon isotopes reflect both secular changes in the isotopic composition of atmospheric CO2 and floral influences, with the Early Eocene isotopically-light, angiosperm-dominated coals and the Late Cretaceous?Paleocene isotopically heavier, gymnosperm-dominated coals being the sources for the oil in the Bass and Gippsland basins, respectively.

No abstract available

At this scale 1cm on the map represents 1km on the ground. Each map covers a minimum area of 0.5 degrees longitude by 0.5 degrees latitude or about 54 kilometres by 54 kilometres. The contour interval is 20 metres. Many maps are supplemented by hill shading. These maps contain natural and constructed features including road and rail infrastructure, vegetation, hydrography, contours, localities and some administrative boundaries. Product Specifications Coverage: Australia is covered by more than 3000 x 1:100 000 scale maps, of which 1600 have been published as printed maps. Unpublished maps are available as compilations. Currency: Ranges from 1961 to 2009. Average 1997. Coordinates: Geographical and either AMG or MGA coordinates. Datum: AGD66, GDA94; AHD Projection: Universal Transverse Mercator UTM. Medium: Printed maps: Paper, flat and folded copies. Compilations: Paper or film, flat copies only.

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.

With coal seam gas becoming an increasingly important contributor to the energy sector in eastern Australia, a critical factor is to understand the source of this gas, enabling migration fairways to be inferred and to access the risk of gas alteration and loss from source to reservoir. The paper will detail the use of stable carbon and hydrogen isotopic composition of individual coal seam gas components (methane, C2+ hydrocarbons and CO2) in determining the origin of the coal seam gases. The gas samples are from recent appraisal drilling by Queensland Gas Company Limited and Arrow Energy N.L. in the Jurassic Walloon Coal Measures, eastern Surat Basin, and are supplemented by Permian coal seam gas of a wide geographic distribution from the eastern (Moura and Peat ? Oil Company of Australia) and western margins of the underlying Bowen Basin (Fairway ? Tipperary Oil and Gas (Australia) Pty Ltd). The isotopic analyses from the coal seam gases are also compared with natural gases from conventional sandstone reservoirs in the Surat and Bowen basins. For methane from the Jurassic coals the carbon isotopes show a very narrow range from ?13C -57.3 to -54.2 ?. This compares to the much wider isotopic range for methane from the Permian coals (?13C -79.9 to -22.9 ?), reflecting a `continuum? from biogenic (isotopically light) to thermogenic (isotopically heavy) sources. On the other hand, the natural gases are isotopically heavy (?13C -43 to -31.9 ?), consistent with their thermogenic source from Permian coals and associated disseminated organic matter. Similarly, the hydrogen isotopes show a restricted range from ?D -215.5 to -203.3 ? compared with methane from Permian coals of ?D -255 to -152 ?. On the other hand, the carbon isotopes of the associated C2+ hydrocarbons (?13C -43.9 to -24.5 ?) are similar for the Jurassic coal seam gases and the conventional natural gases, suggesting a common thermogenic source for the wet gas components. Thus, the isotopic data for the hydrocarbon gases supports a mixed origin from local Jurassic coals and Permian sources. The former is the predominant source given that the associated CO2 is mostly isotopically light, ?13C range from -8 to -32 ?, and primarily sourced from decarboxylation of immature Jurassic coals.

The Bremer Sub-basin on the rifted southwestern continental margin of Australia is a frontier basin in which no wells have been drilled. The petroleum potential of such frontier basins is generally limited to theoretical assessments from seismic data and analogues. However, a series of submarine canyons have incised the Bremer Sub-basin, allowing geological sampling of the upper 2.5 km of the basin succession. Geochemical, petrographic and palaeontological analyses of 136 rock samples recovered from 30 dredge sites, integrated with interpretation from a regional seismic grid, indicate that the Bremer Sub-basin contains a succession of up to 7km of Jurassic to Tertiary age sediments containing the essential petroleum system elements (source, reservoir and seal) to generate and trap hydrocarbons. Source rock analyses indicate Early Cretaceous coaly and lacustrine organic facies have the best oil potential with hydrogen indices (HI) up to 370 mg hydrocarbons/g TOC. Similar fluvio-lacustrine organic facies are recognised sources for oil in the adjacent Perth and eastern Bight basins. Furthermore, the identification of late Early Cretaceous marine anoxic organic facies in the Bremer Sub-basin supports the concept of a local southern Australian margin origin for widespread coastal bitumens termed asphaltites. Berriasian to Hauterivian age strata within the Bremer Sub-basin have the greatest potential to reservoir hydrocarbons, where lacustrine mudstones overlie fluvial sandstones in anticlines and fault block traps. The largest anticline may be capable of trapping up to 500 million barrels of oil in-place (P50 estimate; 900 million barrels P10 estimate).

This is the final report of APCRC `Analytical Protocols? Project 5.1. It comprises the molecular and isotopic data of selected oil and source rock fractions obtained by the three participant organisations using partially aligned analytical protocols and a detailed correlation of the respective data sets. The participants in the project are Geoscience Australia (Stable Isotope and Organic Geochemistry Laboratory, Petroleum and Marine Division), Curtin University (Petroleum and Environmental Organic Geochemistry Group, Applied Chemistry) and CSIRO (Organic Geochemistry Group, Petroleum Resources Division). These laboratories are three of the main providers of organic geochemical data to the Australian petroleum exploration industry. The aim of the project was to compare and evaluate the different analytical protocols used in the three geochemical facilities in order to quantify and document variance between the geochemical datasets and to demonstrate that procedural modifications within the laboratories will increase the confidence in the ability to integrate inter-laboratory datasets.