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.

The northern Pedirka Basin in the Northern Territory is sparsely explored compared with its southern counterpart in South Australia. Only seven wells and 2500 km of seismic data occur over a prospective area of 73,000 km2. In this basin three petroleum systems have potential related to important source intervals in the basal Jurassic (Poolowanna Formation), Triassic (Peera Peera Formation) and Early Permian (Purni Formation). They are variably developed in three prospective depocentres, the Eringa Trough, the Madigan Trough and the northern Poolowanna Trough. New basin modelling techniques indicate oil and gas expulsion responded to increasing early Late Cretaceous temperatures in part due to sediment loading (Winton Formation). Using a composite kinetic model, oil and gas expulsion from coal rich source rocks were largely coincident at this time when source rocks entered the wet gas maturation window. The Purni Formation coals provide the richest source rocks and equate to the lower Patchawarra Formation in the Cooper Basin. Widespread well intersections indicate that glacial outwash sandstones at the base of the Purni Formation, herein referred to as the Tirrawarra Sandstone, have regional extent and are an important exploration target as well as providing a direct correlation with the prolific Patchawarra/ Tirrawarra petroleum system found in the Cooper Basin. An integrated investigation into the hydrocarbon charge and migration history of Colson-1 was carried out using CSIRO Petroleum's OMI (Oil Migration Intervals), QGF (Quantitative Grain Fluorescence) and GOI (Grains with Oil Inclusions) technologies. In the basal Jurassic Poolowanna Formation between 1984 and 2054 mRT, elevated QGF intensities, evidence of oil inclusions and abundant fluorescencing material trapped in quartz grains and low displacement pressure measurements collectively indicate the presence of palaeo-oil and gas accumulation over this 70 m interval. This is consistent with the current oil show indications such as staining, cut fluorescence, mud gas and surface solvent extraction within this reservoir interval. Multiple hydrocarbon migration pathways are also indicated in sandstones of the lower Algebuckina Sandstone, basal Poolowanna Formation and Tirrawarra Sandstone. This is a significant upgrade in hydrocarbon prospectivity, given previous perceptions of relatively poor quality and largely immature source rocks in the Basin. Conventional structural targets are numerous but the timing of hydrocarbon expulsion dictates that those with an ?older? drape and compaction component will be more prospective than those dominated by Tertiary reactivation which may have resulted in remigration or leakage. Preference should also apply to those structures adjacent to generative source ?kitchens? on relatively short migration pathways. Early formed Tirrawarra Sandstone and Poolowanna Formation stratigraphic traps are also attractive targets. Cyclic sedimentation in the Poolowanna Formation results in two upward fining cycles which compartmentalise the sequence into two reservoir ? seal configurations. Basal fluvial sandstone reservoirs grade upwards into topset shale/ coal lithologies which form effective semi-regional seals. Onlap of the basal cycle onto the Late Triassic unconformity offers opportunities for stratigraphic entrapment.

The Bremer Sub-basin, which forms part of the Bight Basin off the southern coast of Western Australia, is a deep-water (100-4000 m water depth) frontier area for petroleum exploration. No wells have been drilled to test the sub-basin's petroleum potential, with company exploration limited to a regional seismic survey by Esso Australia Ltd in 1974. Early studies identified the Bremer Subbasin as a series of Middle Jurassic-Early Cretaceous half graben, which contain potentially prospective structures for trapping hydrocarbons. However, a lack of sub-surface geological data, along with the deep-water setting, discouraged exploration of this area for over 30 years. In 2003, the Bremer Sub-basin was identified as a key frontier area in Geoscience Australia's New Oil Program where new exploration opportunities might occur. Subsequently, Geoscience Australia's Bremer Sub-basin Study commenced in 2004 with an aim to determine if the sub-basin formed under suitable geological conditions to generate and trap large volumes of hydrocarbons.