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.

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.

Sandstone deposits are important sources of uranium, accounting for approximately 20 percent of global production, largely through in situ leach (ISL) mining. Most of this production has come from deposits in the western US, Niger and Kazakhstan. In Australia, sandstone-hosted uranium is being produced from the Beverley deposit in the Frome Embayment of South Australia, and a second ISL mine is under development at Honeymoon in the same region. Such deposits form where uranium-bearing oxidised ground waters moving through sandstone aquifers react with reducing materials. The locations of ore zones and the sizes of mineral deposits depend, amongst other factors, on the abundance and the reactive nature of the reductant. Hence the nature and abundance of organic material in the ore-bearing sedimentary sequence may be of critical importance in the formation of sandstone uranium deposits. In sandstones rich in organic material (containing debris of fossil plants or layers of authigenic organic material) the organic materials either reduce uranium directly with bacteria as a catalyst, or result in production of biogenic H2S. In sandstones relatively poor in organic material, that the reduction can be caused either by the introduction of hydrocarbons and/or H2S from oil/gas fields within underlying sediments; or by H2S produced from the interaction of oxidised ground water with pyrite in the sandstone aquifer. This paper outlines the geology of the world-class sandstone uranium deposits in the Chu-Sarysu and Syr-Darya Basins in the south-central portion of Kazakhstan, which are hosted by sandstones relatively poor in organic matter. It highlights the crucial role of that hydrocarbons appear to have played in the formation of these and other large sandstone type uranium deposits. Based on the model developed, it is concluded that there is considerable potential in Australia for discovery of large sandstone hosted uranium mineralisation, including in little explored regions underlain by basins with known or potential hydrocarbons.

Presentation delivered on 8 March 2012 at the Tasman Frontier Petroleum Industry Workshop, Geoscience Australia, Canberra.

In 2010 the Australian Government offered for the first time a large exploration block for acreage release in the frontier Mentelle Basin. This large sedimentary basin (36, 000 m2) is located about 150 km to the west of Cape Leeuwin. It lies beneath the continental slope off the Yallingup Shelf and the Naturaliste Though, a bathymetric saddle, separating the Australian margin from the Naturaliste Plateau. Water depths range from 500-1500 on the continental slope to almost 4000 m in the central part of the Naturaliste Trough. To enable petroleum prospectivity assessment of this frontier basin in 2008-09 Geoscience Australia acquired 2570 km of industry standard seismic, as well as gravity and magnetic data during the Southwest Margins seismic survey 310. Interpretation of the new seismic data resulted in mapping of the main structures and supersequences and led to a better undertsanding of the Mentelle Basin geology. Petroleum prospectivity assessment of the Mentelle Basin confirmed that the Mentelle Basin has a significant potential to become a new petroleum province. The work undertaken by Geoscience Australia team suggests that the Mentelle Basin has at least one active petroleum system. The basin is likely to contain multiple source rock intervals associated with coals and carbonaceous shales, as well as regionally extensive reservoirs and seals within fluvial, lacustrine and marine strata. A wide range of play types have been identified in the Mentelle Basin, including faulted anticlines and highside fault blocks, sub-basalt anticlines and fault blocks, drape and forced fold plays, and a large range of stratigraphic and unconformity plays.

The Bureau of Mineral Resources (BMR) collected 1430 line-km of bottom-water Direct Hydrocarbon Detection (DHD) data during a survey aboard R.V. Rig Seismic in the Durroon Sub-basin, the Otway Basin, the Torquay Sub-basin, and the Gippsland Basin, during late September and early October of 1991. No significant bottom-water anomalies were detected in the Durroon Sub-basin. Anomalous concentrations of light C2+ hydrocarbons were detected in the eastern Otway Basin. The anomalies were not extensive, comprising only a few data points representing a few kilometres in extent. One anomaly (of methane, ethane and propane) was accompanied by high levels of the biogenic hydrocarbons, ethylene and propylene, suggesting in-situ biogenic activity in the water column. However, anomalous concentrations of C7 and C8 hydrocarbons were also found here and at three other locations, and are from an unknown 'source'. A weak bottom-water anomaly was detected in the Torquay Sub-basin in the same location as an anomaly detected during an earlier survey (Rig Seismic Survey 89), two years previously. The weakness of the anomaly prevents a confident interpretation of the potential 'source' of the hydrocarbon anomaly, but the data suggests it is derived from a gas/condensate, or dry thermogenic gas 'source'. Several strong bottom-water anomalies were detected in the Gippsland Basin. Bottomwater anomalies were found near the Sunfish and Tuna oil/gas accumulations, in similar locations to anomalies found on Rig Seismic Survey 89, two years earlier. However, another previously-detected anomaly (near Barracouta) was not reproduced. Additional anomalies were found near Flathead, and to the west of Wahoo. The anomaly west of Wahoo was weak and in a similar area to that detected on Survey 89. The composition of most bottom-water hydrocarbon anomalies in the Gippsland Basin are indicative of a liquid-prone hydrocarbon 'source', while one anomaly in the northern sector of the survey area is indicative of a gas/condensate 'source'.

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.

The 50 major Australian source rock units can be grouped according to age into 15 intervals comprising Late Neoproterozoic, Middle Early Ordovician, late Early Ordovician, Middle to Late Devonian, Early Carboniferous, Early to early Late Permian, late Late Permian, Early to Middle Triassic, Early to Middle Jurassic, Middle to Late Jurassic, Late Jurassic, latest Jurassic to Early Cretaceous, Early Cretaceous, Late Cretaceous, latest Cretaceous to Eocene. Only marine source rocks are known older than Permian, while both marine and nonmarine source rocks are known from Permian and younger intervals. As expected, the marine source rocks are more common where there is a greater degree of continental inundation, while nonmarine source rocks are present only when the continent was at higher palaeolatitudes and when there was at least a moderate amount of continental inundation.

It appears that the hydrocarbon exploration industry will be able to enjoy today's vibrant times for years to come. In the current climate of high oil prices and ongoing expansion of global energy needs, many companies find themselves in the pursuit of new prospective acreage. It has long been acknowledged that Australia's early Palaeozoic sedimentary basins are largely under-explored. This may be partly due to the lack of infrastructure and partly due to the perceived high risk involved in committing to an expensive exploration program in remote areas. From a regional geological perspective however, several provinces can be earmarked as candidates that may emerge as future hydrocarbon producers. These include the western extension of the prolific Cooper/Eromanga hydrocarbon province (Pedirka and Warburton basins in SA, NT), the Georgina Basin (NT, Qld), the Amadeus Basin (NT, WA), the Officer Basin (SA, WA) and the southern Canning Basin (Kidson-Sub-basin, WA). As part of Geoscience Australia's Onshore Energy Security Program, new radiometric and aeromagnetic data have been acquired with the aim to better image crustal features such as regional tectonic lineaments that control basin evolution. A significant part of the program is devoted to the acquisition of deep seismic surveys over key areas in which petroleum systems are known to exist. Such surveys will target major basin-bounding lineaments and basinal deeps in order to improve the understanding of basin-fill processes. The effects of tectonism on the occurrence and preservation of petroleum systems elements is of particular interest. While source rocks are likely to be available in virtually all target areas, the distribution of permeable reservoir facies needs to be delineated. Moreover, trap configurations are crucially important to assess and the integrity of the sealing facies needs to be ascertained.

The Mentelle Basin is a large (36 400 m2) frontier basin lying less than 100 km to the west of the oil and gas producing Perth Basin. The basin was formed during Jurassic extension which preceded the breakup between Australia and Greater India in the Valanginian. The breakup was accompanied by significant volcanism with extensive lava flows overlying the Valanginian unconformity. The Mentelle Basin comprises two structurally different depocentres. The eastern depocentre lying in shallow water (less than 500 m) is a large complex half-graben with up to 8 km of sediments, most of which are synrift section. The Western Mentelle depocentre lies between 2000 to 3300 m water depths and contains up to 7 km synrift and 2.5 km postrift section. The Mentelle Basin has never been drilled. Seismo-stratigraphic correlations are made to the DSDP well 258 on the Naturaliste Plateau and to the exploration wells in the Southern Vlaming Sub-basin. However direct correlations are possible only for the Late Cretaceous to recent part of the section. Recent Geoscience Australia studies involving structural restoration of the margin have shown that major tectonic and accommodation cycles are the same for both basins. The ages of the synrift sequences in the Mentelle basin therefore have been interpreted using the new Vlaming Sub-basin tectonostratigraphic framework. Seismic facies analysis was then used to define potential source rock intervals and correlate them to the known source rocks in the Vlaming Sub-basin. To test petroleum potential of this frontier basin 2D burial history analysis has been performed for the three regional lines. For each line three different scenarios with varying source rock characteristics reflecting end member possibilities have been explored. The potential effect of heat flow variations and intrusive volcanics on the maturation history have also been assessed. The modelling results suggest that source rocks in the deepest part of the synrift section are overmature, while uppermost Berriasian source rocks are immature. Source rocks that are currently within the maturation window are Middle Jurassic to Early Cretaceous shaly and coaly intervals, which commenced generation in the Late Jurassic. The erosion of significant sedimentary thickness in the Eastern Mentelle during continental breakup slowed down and in some cases stopped hydrocarbon generation. As this part of the basin has less that 1 km of postrift section only source rocks with sufficient overburden are still generating. In the Western Mentelle the same source rocks are buried much deeper and continued to generate throughout the Tertiary and up to the present. In the Eastern Mentelle oil generation and migration was roughly synchronous with the development of most structures whereas in the western Mentelle more source rock intervals continued generating after the major structuring. The main risk in the Mentelle Basin is the presence of good quality seals at the right stratigraphic level. Existing seismic coverage is insufficient for detailed structural interpretation needed to define potential traps. Provided suitable structures are found in the Mentelle Basin it may have similar petroleum potential to the Vlaming Sub-basin.