The North West Margin Transects Cruise is part of a program being undertaken by AGSO to determine the structural architecture of the north-western margin of Australia and the influence of structuring on the location, migration and trapping ofhydrocarbons in the region. An important aspect of this program is the acquisition ofa series of full margin 'dip' transects extending from unrifted cratonic basement tobeyond the continent-ocean boundary, and at least two 'strike' transects that willextend along the full length of the shelf from the eastern Timor Sea to North WestCape. The major objective of the proposed cruise is to extend previous AGSO deepseismic surveys across the Browse (Survey 119), offshore Canning (SNOWS-3/Survey 120) and northern Carnarvon Basins (SNOWS-/Survey 101, SNOWS-2/Survey 110) to complete these margin transects. Specific objectives of theproposed survey are: *Determine the regional structural framework of the Scott Plateau area and itsrelationship to adjacent features such as the Argo Abyssal Plain, the BrowseBasin and the Rowley Sub-Basin of the offshore Canning Basin; *Determine the regional structural framework of the Exmouth Plateau and itsrelationship to adjacent features such as the Barrow-Dampier Sub-basin, and theArgo and Gascoyne Abyssal Plains. *Define the broad deep-crustal structure of the region and develop a modelexplaining the tectonic, subsidence and thermal history of the Scott Plateau andthe Exmouth Plateau in relation to the development of the continental margin andadjacent ocean basins. *Assess the effects of the deep crustal structures and their reactivation phases onthe development of known petroleum accumulations. To address these objectives it is proposed that RV Rig Seismic be used to acquireabout 3276 km of deep crustal (16 second record length) multichannel seismic andother geophysical data along 9 transects across the outer margins of the Browse,offshore Canning and northern Carnarvon Basins. The survey will tie into the 1991SNOWS-1 (101), 1992 SNOWS-2 (110), 1993 Browse Basin (119) and SNOWS-3(120) surveys.

Legacy product - no abstract available

The offshore Gippsland Basin is Australia's major producing hydrocarbon province. Acreage has historically been tightly held, and opportunities for new players in this highly prospective basin have been limited. However, recent relinquishments have allowed the Australian Federal and Victorian State Governments to offer three potential permits to petroleum exploration companies and consortia. The Bureau of Mineral Resources Petroleum Group, in collaboration with the Victorian Department of Manufacturing and Industry Development's Petroleum Branch, has produced a hydrocarbon prospectivity package for the Southeast Gippsland Basin, with particular emphasis on the three areas to be released. The package takes the form of this BMR Record 1991/9. The Package covers regional geology, geophysics, palaeogeography, and hydrocarbon play concepts, together with a new structural interpretation for the Gippsland Basin developed at BMR. In addition, for each release area the package covers previous exploration, local geology and play concepts, reservoir geology and engineering, and geohistory. Prospects and leads are described in detail, and the text is complemented by some 80 Plates and Figures.

Processed seismic data (SEG-Y format) and TIFF images for the Arrowie line acquired as part of the 2008 Curnamona-Gawler-Arrowie Deep Crustal Seismic Survey (L189), acquired by Geoscience Australia (GA) under the Onshore Energy Security Program (OESP). Stack and migrated data for line 08GA-A1 as well as CDP coordinates and gravity data. The Arrrowie line is 60km in length and was sited south of Lake Torrens and north of Port Augusta. Raw data for this survey are available on request from clientservices@ga.gov.au

2002 and 2003 may well prove to be pivotal years for petroleum exploration in Australia as we endeavour to meet our twin imperatives of finding more oil and using gas. Long term gas supply contracts have been signed with China and a number of key oil discoveries have been made both on and offshore. Deep water wells will be drilled that have the potential to usher in another phase of major oil discovery akin to bonanza of the 1960s, when the first steps into the offshore resulted in billion barrel discoveries in Bass Strait. By the close of the first successful cycle of exploration in Australia (1960 to 1972) all currently producing basins were identified as petroliferous, the major play types had been established and over 60% of Australia?s current oil reserves found. The key drivers of this phase were the access to new basins opened up by the move to offshore exploration and the stimulus to further exploration provided by discovery success. The same drivers are apparent now. Recent discoveries in the Perth, Carnarvon, Otway and Browse basins provide strong indications that a significant new cycle of exploration success is already underway. In many cases these finds represent the largest fields yet found in the basin or at least the largest in the last thirty years. The usual discovery history trend of declining field sizes over time has been turned on its head - clearly demonstrating that many of Australia?s currently producing basins still have a long way to run and encouraging further exploration efforts. Perhaps of even more importance to Australia?s long term liquids self sufficiency is the current deepwater drilling campaign which is stepping out beyond former geographic limits. The first wells in major Mesozoic depocentres on the outer margin of the North west Shelf and in the Great Australian Bight are being drilled with the potential to establish entirely new petroleum provinces.

The extreme variation in the natural endowment of petroleum resources between regions has been a key geo-political driver in the last century and may well remain so in the decades ahead. Most of the world?s oil is located in a latitudinal belt lying predominantly north of the equator, running from the Gulf of Mexico and Venezuela, to North Africa, through the Middle East, the Caspian and Central Asia and down to Indonesia. Klemme and Ulmishek (1991) calculated that this Tethyan Petroleum Province contained 68% of global original petroleum reserves. Its vast petroleum resources were derived largely from the organic rich marine rocks deposited in low latitude in restricted basins and on shallow carbonate shelves flanking the various Palaeozoic, Mesozoic and Cainozoic incarnations of the east-west orientated Tethys Ocean.

Conference volume and CD are available through the Petroleum Exploration Society of Australia

Few published studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. This paper presents strong geochemical evidence for coals being the source for the sub-economic oil accumulations in the Bass Basin. Oils in the Bass Basin form a single oil population. Biodegradation of Cormorant oil results in a separate oil family compared to Pelican and Yolla crudes. Oil-to-source correlation based on biomarkers and carbon isotopes shows that the Early Eocene to Palaeocene coals are effective source rocks in the Bass Basin. This is in contrast to previous work which favoured disseminated organic matter in claystone as the sole source (Miyazaki, 1995). Potential oil-prone source rocks in the Bass Basin are the early Tertiary coals, mainly concentrated in the Middle to Early Eocene succession. These coals have hydrogen indices (HI) up to 500 mg HC/gTOC) and are associated with disseminated organic matter in claystones that are mainly gas prone. Maturity is sufficient for oil and gas generation with vitrinite reflectance (VR) up to 1.8 % at base of Pelican-5. Igneous intrusions, mainly within Palaeocene, Oligocene and Miocene sediments, produce localised elevated maturity to 5 % VR. 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 VR of 0.65 % (2450m in Pelican-5); (ii) the onset of expulsion (primary migration) at a VR of 0.75 % (2700 to 3200m in Bass Basin; 2850m in Pelican-5); (iii) the main oil window between VR of 0.75 % and 0.95 % (2850-3300m in Pelican-5); and, (iv) the main gas window at VR >1.2 % (>3650m in Pelican-5).

This report is an annual report which provides information and statistics on Australia's oil and gas resources. The statistics in this report include data for the calendar year 1999.

D/H ratios of terrestrially-sourced whole oils and their respective saturated, aromatic, and polar fractions, individual n-alkanes, formation waters and non-exchangeable hydrogen in kerogen were measured from source rocks from seven Australian petroleum basins. Data for 75 oils and condensates, their sub-fractions, and 52 kerogens indicate that oil sub-fractions have deltaD values comparable to deltaDoil, with a deltadeltaD offset (deltaDkerogen - deltaDoil) averaging ca. 23?. The weighted-average deltaD of individual n-alkanes is usually identical to deltaDoil and deltaDsaturate. A trend of increasing deltaD with n-alkane chain length in most oils causes individual n-alkanes from an oil to vary in deltaD by 30? or more. A modest correlation between deltaD for aromatic sub-fractions and formation waters indicates that about 50% of aromatic C-bound H has exchanged with water. In contrast, deltaDoil and deltaDsaturated show no evidence for H-exchange with formation water under reservoir conditions at temperatures up to 150 oC. Acyclic isoprenoids and n-alkanes show essentially indistinguishable deltaD, indicating that primary isotopic differences from biosynthesis have been erased. Overall, extensive exchange of C-bound H in petroleum with other hydrogen is apparent, but seems to have affected most hydrocarbons only during their chemical genesis from precursor molecules. Our isotopic findings from terrestrial-sourced oils should be qualitatively relevant for marine oils as well.