Legacy product - no abstract available

Legacy product - no abstract available

Legacy product - no abstract available

The Triassic to Jurassic rocks of Clarence-Moreton Basin contain abundant oil-proneorganic matter of terrestrial origin particularly in the Walloon Coal Measures and to a lesserextent in the Koukandowie Formation. This is reflected in petrographic composition, pyrolysisyields, elemental composition and extractable hydrocarbon yields. Maturation levels vary fromimmature to marginally mature in the west to overmature in the eastern part of the basin inNSW. Calculations based on Rock Eval data show that significant oil generation occurred ina narrow maturation range (0.8-1.0% vitrinite reflectance) and that migration has been highlyefficient. Potential reservoirs are present in quartzose sandstones in the KoukandowieFormation, Gatton Sandstone, Ripley Road Sandstone and Raceview Formations. Maturation modelling and fission track analyses indicate that hydrocarbon generation occurred in theperiod 80-100 Ma during a period of high heat flow when the Tasman Sea spreading ridgewas adjacent to the southeastern side of the Logan Sub-basin. Despite the abundance ofoil-prone source rocks, the basin is considered to be largely gas-prone because the drainageareas for most larger structural traps are overmature. The main difficulty in exploration ispredicting the distribution of porosity and permeability which varies because of bothdepositional facies and diagenesis, even in quartzose units. The area with the greatest hydrocarbon prospectivity is the New South Wales part ofthe Logan Sub-basin which has gas potential throughout and a chance of minor oil discoveriesalong its western margin. The northern Logan Sub-basin has some prospectivity for oil andgas and the Laidley Sub-basin has minor prospectivity for oil in the Raceview Formation.

Petroleum source rocks are found at three levels in the Ordovician sectionin the Canning Basin and appear to be at similar stratigraphic levels and ofsimilar organic facies to the source rocks which have produced the gas andgas-condensate fields in the Amadeus Basin. In both basins shallowintersections in drillholes have yielded material at a low level of thermal maturity.Samples have shown that these immature source rocks contain algal-sourcedType 1 kerogens with a high hydrogen index and a large capacity to generate oil(eg Hoffmann et al., 1987). Deeper wells in both basins encountered sourcerocks at higher levels of maturity associated in some cases with oil fluorescenceand shows of live oil. By comparing the results of Rock-Eval pyrolysis analysisfor these more mature source rocks with those of the immature rocks the degreeof kerogen conversion to hydrocarbon (the Transformation Ratio of Espitalie eta)., 1986) can be estimated. The results from 14 wells along the BroomePlatform show a rapid downward increase in transformation ratio (TR) through theOrdovician section which can be correlated to the rapid downward increase in theconodont alteration index (CAI) previously documented by Nicoll & Gorter (1984).This correlation shows that the zone of peak oil generation lies between the endof CAI Zone 1 and the beginning of CAI Zone 2. The Ordovician in the Canning Basin is known mainly from intersectionsin 22 drillholes. It is thickest in two sub-basins: the Willara, bounded to the northby the Admiral Bay Fault, and a larger unnamed sub-basin (roughly coincidentwith the later Fitzroy Trough), bounded to the north by the Oscar Range-Pinnaclefault system. Both fault systems appear to have been active during thedeposition of the Ordovician. The best known source rocks occur along thesouthern side of the northern sub-basin; they appear to be poorly developed, orabsent, in the Willara Sub-basin. Overmature source beds are locally preservedin fault remnants under the Lennard Shelf and may exist at great depth in theFitzroy Trough.

Legacy product - no abstract available

Legacy product - no abstract available

The breakup of Gondwana during the Mesozoic resulted in widespread basin formation along Australia's southern margin, of which the Bight Basin is a component. In contrast to many other extensional margins, the Australian southern margin has been classified as a non-volcanic rifted margin, despite the reported occurrence of scattered volcanic and intrusive rocks in the geological literature. Public release of the Flinders 2D seismic survey data in the Bight Basin has allowed the accurate mapping of widespread sills, dykes, lava flows and volcanoes.

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.

The Gippsland Basin in southeastern Victoria is Australia's major crude oil and natural gas producing province. To the end of 1986 the basin had supplied 88 per cent of Australia's cumulative crude oil production and 48 per cent of cumulative natural gas production. Crude oil and natural gas were first discovered onshore in 1924, near Lakes Entrance, Victoria. Since then over 125 onshore wells have been drilled, resulting in the discovery of one (1) subeconomic and six (6) uneconomic petroleum accumulations. More than 80 exploration and step-out wells have been drilled offshore, resulting in the discovery of eleven (11) economic, twenty-six (26) subeconomic and six (6) uneconomic petroleum accumulations. The petroleum in the Gippsland Basin mainly occupies structural and structural/stratigraphic traps within the Oligocene, Eocene, Paleocene and Late Cretaceous marine, marginal marine and continental clastic sequences. The petroleum is believed to be of land-plant origin; crude oil results from thermal breakdown of exinite, and natural gas from thermal cracking of vitrinite and exinite. The crude oils are generally very light and paraffinic, ranging from 40 to 60oAPI. Some heavier oils discovered at shallow depths range from 14.6 to 26.5oAPI and are thought to have been biologically degraded. The condensates range from 48 to 63oAPI. The natural gases are generally low in condensate content. Some gas reservoirs contain a high proportion of carbon dioxide. Production of natural gas and oil commenced in 1969 and 1970 respectively. Cumulative production to 31 December 1986 was 344.66 x 106m3 of oil, 9.68 x 106m3 of condensate, 41.75 x 106m3 of LPG and 66.14 x 109m3 of sales gas. The oil and gas produced is transported from the twelve offshore production facilities (platforms) by pipeline to gas and crude oil stabilisation plant at Longford, Victoria for processing, and then to storage and distribution centres. Estimated remaining recoverable petroleum reserves in the Gippsland Basin as at 31 December 1986 are 202.44 x 106m3 of oil, 22.44 x 106m3 of condensate, 44.89 x 106m3 of liquid petroleum gas, and 206.39 x 109m3 of sales gas.