Three economic (1 oil and gas/condensate, 1 gas/condensate, and 1 gas) and fourteen uneconomic (6 oil, 7 gas, and 1 oil/gas) petroleum accumulations have been discovered since 1963 in the Amadeus Basin of central Australia. The petroleum in the Amadeus Basin mainly occupies the structural, fold- related traps within the Upper Proterozoic to Upper Ordovician marine to marginal marine clastic and evaporitic sequences. It is believed to be of algal/bacterial origin. The API gravity ranges from 18 to 54o for crude oils, and from 52 to 64o for condensates; gases are dry and wet. The basin's estimated petroleum resources as at 31 December 1985 comprise 5.74 x 106m3 of oil, 1.53 x 106m3 of natural-gas liquids, and 14.93 x 109m3 of sales gas. Production from Mereenie (oil) and Palm Valley (gas/condensate) accumulations commenced during 1984. Up to 31 December 1985 the cumulative production from the basin stood at 156.3 x 103m3 of oil and condensate, and 44.0 x 106m3 of sales gas. The gas/condensate is transported 146 km to Alice Springs through a 20-cm-diameter pipeline; the oil is transported 269 km to Alice Springs through a 20cm pipeline and from there by rail tankers to Adelaide refinery. As from February 1987 gas from Palm Valley will also be transported to Darwin via a 1537-km pipeline of 35.3 cm diameter.

As at 31 December 1989 the Otway Basin, which is located along the southeast margin of the Australian mainland, was known to contain a total of seven economic and six subeconomic petroleum and non-petroleum gas accumulations. All have been discovered since the late 1950s as a result of petroleum exploration drilling. Three accumulations have been or could be used as a source of petroleum natural gas or carbon dioxide: the North Paaratte gas accumulation in Victoria and the Caroline carbon dioxide accumulation in South Australia, both of which are currently being exploited, and the Wallaby Creek gas accumulation in Victoria, which has been identified by permit holders as an accumulation likely to be developed in the future (1992-1994). In addition, the Katnook and Ladbroke Grove gas accumulations in South Australia are being considered for development in the near future. The initial petroleum reserves of the Otway Basin as at 31 December 1988 are estimated to be 0.483 billion cubic metres of sales gas and 0.002 million kilolitres of condensate (not including the reserves of the Katnook and Ladbroke Grove accumulations). Production from the Caroline carbon dioxide accumulation commenced in 1968, and this field continues to supply this commodity much of the South Australian and Victorian markets. Production of natural gas from the North Paaratte accumulation commenced in August 1986. This field supplies domestic and industrial users in Warrnambool, Victoria.

As at January 1993, nineteen hydrocarbon accumulations, six of which are commercial, have been discovered in the Canning Basin. The commercial accumulations occur in Permian to Devonian reservoirs on an area of relatively shallow basement (Lennard Shelf) flanking the northern margin of the Fitzroy Trough. Oil is produced from Famennian reefs, associated drape structures, and four-way dip closures in Permo-carboniferous, Grant Group and Anderson Formation sandstones. The most likely sources of these hydrocarbons are Late Devonian and Carboniferous marine shales in the Fitzroy Trough kitchen area. The small size of the accumulations in the Canning basin (less than 0.5 million barrels of recoverable oil) precludes the development of large infrastructure projects. Oil is trucked to the storage and shiploading facilities at Broome and then shipped to the Kwinana oil refinery in Western Australia. On the southern margin of the Fitzroy Trough, oil and gas have been recovered from a transgressive Ordovician sequence of sandstones shales and carbonates. Although the Ordovician has yet to yield a commercial discovery, Devonian reef plays in the overlying section may enhance the attractiveness of Ordovician objectives in this area. To date, exploration effort in the basin has been largely directed to the northern, onshore Canning Basin. The offshore Canning and the Kidson Sub-basin remain underexplored. Higher risk plays in these areas have yet to be adequately tested.

The Onshore Energy Security Program, funded by the Australian Government, Geoscience Australia has acquired deep seismic reflection data across several frontier sedimentary basins to stimulate interest in petroleum exploration in onshore Australia. Detailed interpretation of deep seismic reflection profiles from four onshore basins, focusing on overall basin geometry and internal sequence stratigraphy will be presented here, with the aim of assessing the petroleum potential of the basins. At the Southern end of the exposed part of the Mt Isa Province, northwest Queensland, a deep seismic line (06GA-M6) crosses the Burke River Structural Zone of the Georgina Basin. The basin here is >50 km wide, with a half graben geometry, and bound in the west by a rift border fault. The Millungera Basin in northwest Queensland is completely covered by the thin Eromanga basin and was unknown prior to being detected on two seismic lines (06GA-M4 and 06GA-M5) acquired in 2006. Following this, seismic line 07GA-IG1 imaged a 65 km wide section of the basin. The geometry of internal stratigraphic sequences and post-depositional thrust margin indicate that the original succession was much thicker than preserved today. The Yathong Trough in the southeast part of the Darling Basin in NSW has been imaged in seismic line 08GA-RS2 and interpreted in detail using sequence stratigraphic principles, with several sequences being mapped. The upper part of this basin contains Devonian sediments, with potential source rocks at depth.

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This year, the Commonwealth Government is offering 6 large exploration areas in the frontier Bight Basin. The release areas (Figure 1) are situated in the central Great Australian Bight off southern Australia, approximately 415 to 655 km west of Port Lincoln, South Australia and 250 to 530 km southwest of Ceduna, South Australia. The areas are located within the Ceduna Sub-basin, in the eastern part of the Bight Basin, in water depths ranging from 130 to 4600 m. At present, no permits are held in this part of the basin. The release areas range in size from 85 to 90 graticular blocks (6000 to 6395 km2), and bids for all 6 areas close on 29 April 2010. Most exploration drilling in the Bight Basin has focused on the margins of the Ceduna Sub-basin and the Duntroon Sub-basin to the southeast of the current release areas. Gnarlyknots 1A, drilled by Woodside Energy and partners in 2003, is the only well to have attempted to test the thick, prospective Ceduna Sub-basin succession away from the margins of the sub-basin. Unfortunately the well was not an exploration success, as it had to be abandoned due to deteriorating weather and ocean conditions without reaching all planned target horizons. In 2007, Geoscience Australia conducted a marine sampling survey in the Bight Basin that dredged a suite of organic-rich rocks of Cenomanian-Turonian age from the northwestern exposed edge of the Ceduna Sub-basin. Geochemical analyses have characterised these samples as world-class, oil-prone, marine potential source rocks. Seismic interpretation indicates that this interval can be mapped throughout most of the basin and is mature for oil and gas generation across much of the Ceduna Sub-basin.

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The Capel and Faust basins lie at water depths of 1500-3000 metres, 800 km east of Brisbane. Geoscience Australia began a petroleum prospectivity study of these remote frontier basins with acquisition of reflection and refraction seismic, gravity, magnetic and multi-beam bathymetry data across an area of 87,000 km2 during 2006/07. The approach mapped a complex distribution of sub-basins through an integration of traditional 2D reflection seismic interpretation techniques with 3D mapping and gravity modelling. Forward and inverse gravity models were used to inform the ongoing reflection seismic interpretation and test the identification of basement. Gravity models had three sediment layers with average densities inferred from refraction velocity modelling of 1.85, 2.13, 2.31 t/m3 overlying a pre-rift basement of density 2.54 t/m3, itself considered to consist in part of intruded older basin material. Depth conversion of horizon travel times was achieved using a function derived from models of refraction data. Gravity modelling of the simple density model arising from the initial interpretation of reflection seismic data indicated a first order agreement between observed and calculated data. The second order misfits could be accounted for by a combination of adjustments to the density values assigned to each of the layers, localised adjustments to the basin depths, and heterogeneity in the basement density values. The study concluded that sediment of average velocity 3500 m/s exceeds 6000 m thickness in the northwest of the area, which is sufficient for potential petroleum generation.