petroleum geology
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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.
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Legacy product - no abstract available
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Integrated geological and geochemical studies have demonstrated that mature, rich potential petroleum source rocks and adjacent potential reservoir beds exist in the Middle Proterozoic sequence (1400 - 1800 million years) of the McArthur Basin, Northern Territory. Standard organic petrographic and geochemical techniques can be used with only minor adaptions, to characterise the organic type and maturation level of the source beds and the likely composition of any derived hydrocarbons. 'Live' oil which was discovered during' stratigraphic drilling to obtain samples for this project provides further evidence of the potential of of this basin. Potential reservoir units exist at several stratigraphic levels. The geology and reservoir characteristics of these units in combination with the distribution of potential source beds, timing of hydrocarbon generation, evidence for migration and chances of preservation has been used to rank the prospectivity of various stratigraphic intervals in different parts of the basin.
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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. A Boreal Petroleum Province was also recognised by Klemme and Ulmishek (1991) located in high northerly latitudes and containing about 23% of the global resource in such oil rich regions as the North Slope of Alaska, North Sea and West Siberia. The Boreal belt demonstrates that not all major oil provinces require source rocks deposited in equatorial or tropical environments. The key source rocks in these basins are Late Jurassic and Cretaceous clastic marine facies deposited at high palaeo-latitudes. The Klemme and Ulmishek (1991) analysis indicated that less than ten percent of the world?s petroleum had been found outside the Tethyan and Boreal provinces. The major new deep-water oil provinces of the 1990?s, Brazil and West Africa, point to the increasing importance of the southern hemisphere in the distribution of remaining global petroleum resources. The petroliferous basins of offshore Brazil and West Africa are the product of Atlantic rifting which re-made the world in the late Mesozoic to be dominated by longitudinally oriented oceans, with the Mediterranean left as the last remanent of Tethys. Beyond the current day focus of the deepwater ?Golden Triangle? of the Gulf of Mexico, Brazil and West Africa, recent discoveries are starting to build the pattern of a southerly belt of oil occurrences to match the Boreal province. As with major oil reserves found in the far north, the key source rocks are clastic marine Cretaceous facies deposited in basins then located in high palaeo-latitudes. There is established production from the Magallanes/Austral Basin in Chile and Argentina at the southern tip of South America; and there is now oil production from the Oribi field in the Bredasdorp Basin, offshore the southern coast of South Africa, east of Cape Town. In both cases Early Cretaceous marine claystones are the source facies. However, in south-eastern Australia, Late Cretaceous fluvio-deltaic coaly facies are the source for the billion barrel oil fields in the world-class offshore Gippsland Basin. Source rocks of similar age and depositional facies have produced the petroleum accumulations of the Taranaki Basin in New Zealand. Where are the oil accumulations derived from high latitude marine Cretaceous sources that are so important in South America and South Africa, and in the corresponding Boreal belt? The current round of exploration along Australia?s southern margin may answer this question and clearly establish the pattern of a belt of petroleum basins in the far south related to marine deposition in the greenhouse world of the Cretaceous. Evidence from palaeogeographic reconstructions, limited offshore drilling, oil strandings, remote sensing and seismic data all point to the occurrence of Cretaceous clastic marine source facies in the deepwater basins along the southern margin of Australia. Reference Klemme, H.D. and Ulmishek, G.F., 1991 ? Effective petroleum source rocks of the world: stratigraphic distribution and controlling depositional factors. AAPG Bulletin, 75, 12, 1809-1851.
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Legacy product - no abstract available
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Coalbed methane (CBM) is emerging as an important energy resource in Australia. CBM is one of the products of coalification - the process by which peat is transformed into coal during progressive burial. The initial product is biogenic gas, thermogenic gas is produced with increasing pressure and temperature and further biogenic gas may be produced after burial has ceased if the coal becomes exposed to an active groundwater system containing methanogenic bacteria. The storage of CBM within a coalbed reservoir is complex, being a mixture of free gas, dissolved gas and absorbed gas. A number of gas and coal properties govern how much and how fast a coal seam will give up its methane, but the most economically productive seams are naturally fractured or are stimulated to induce and increase fracturing. Unlike conventional gas reservoirs, the continuous production of water from a coalbed reservoir results in a corresponding progressive increase in gas production (up to a certain limit). CBM production in Australia commenced in 1996 and most of Australias coal basins are now covered by production, exploration or application licences. The Cooper Basin contains a huge volume of coal that is recognised to be the source of much of the conventionally trapped gas. No attempt has been made to explore the basin for CBM due to the generally held belief that the coals are too deep. The Weena Trough has been identified as one area in the Cooper Basin in which the Permian coals may be at depths that are economic to exploit. Two wells drilled in the period 1968-70 encountered net coal thicknesses of more than 40m with individual seams up to 18 metres. The fact that elsewhere these coals are known to be the source of much of the basins conventionally trapped gas, combined with the advances made in understanding the nature of CBM generation, storage and production, makes the Weena Trough an ideal target for evaluation
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This "Petrel on WebBury" package presents interactive geohistory models of the regional burial, thermal and hydrocarbon maturation and expulsion history of the Petrel Sub-basin, Bonaparte Basin, NW Australia. These models are based on a comprehensive geohistory analysis undertaken by Geoscience Australia and Burytech Pty Ltd. The geohistory models are generated by the WinBuryTM 1D burial and thermal geohistory modelling software. The thermal history models are constrained by conventional vitrinite reflectance (VR), thermal alteration index (TAI), spore colour index (SCI), conodont colour alteration index (CAI) and limited fluorescence data (FAMM), together with limited apatite fission track analysis (AFTATM). The burial and thermal models are applied to potential Carboniferous-Cretaceous two source units within each well, and to three basin-wide source rock units - Lower Carboniferous Milligans Formation, Lower Permian Keyling Formation and Late Permian Hyland Bay Formation - to constrain the timing and relative volumes of expelled liquid/gaseous hydrocarbons. New kerogen kinetic data for these source facies are utilised in the expulsion models. The modelling package is divided into 5 sections: Wells: Geohistory models for 24 wells & 11 depocentre sites. X-sections: Cross-section geohistory models. Multi-well: Multiple-well geohistory curves and basin-wide maps for three source unit. Seismic: Interpreted seismic lines showing structural setting of the wells. Petroleum Systems: Schematic summary of the active petroleum systems. Multiple views within each section can be interactively selected by the user (eg. temperature, heatflow, subsidence, maturity and expulsion time-plots/contoured maps) by way of point and click buttons and drop-down windows. The user can make temporary modifications to existing, or add new, data in the well models, and view corresponding maturity, generation and expulsion models based on these changes. These revised models can be printed directly from the screen views but will not be saved on exit from the well. Current users of WinBuryTM modelling software can copy well data files from this package to their WinBury working directories. The package is run on a PC and requires 30MB hard disc space, Windows 95/98 or NT operating systems, and utilises a standard Web browser (Internet Explorer or Netscape Navigator).
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The Cambrian to Recent Bonaparte Basin is located on the North-west shelf of Australia and extends 329,000 sq. km offshore and onshore. The region is an established hydrocarbon province with a number of commercial discoveries. New infrastructure is being constructed within the region, such as the Bayu-Undan LNG plant, with a number of giant gas accumulations yet to be developed. The area has remaining oil and gas potential, particularly in the Vulcan Sub-basin, Laminaria-Flamingo High and northern Sahul Platform areas, with additional discoveries likely within the next decade. The main exploration risk in the region is fault seal breach. The Bonaparte Basin has seven petroleum systems based on geological and geochemical information. The systems are concentrated in the Jurassic, Permian and Carboniferous: Jurassic Elang-Elang (!): Sahul Syncline, Flamingo High Plover-Plover (.): Malita Graben Sahul Platform Vulcan-Plover (!): Vulcan Sub-basin Permian Hyland Bay-Hyland Bay (?): Kelp High Hyland Bay-Keyling-Hyland Bay (.): Central Petrel Sub-basin Permian-Hyland Bay (?): Londonderry High Permo-Carboniferous Milligans-Kuriyippi/Milligans (!): Southern Petrel Sub-basin (!) : Known hydrocarbon-source correlation (.) : Geochemical evidence for a hypothetical system (?) : Lack of direct evidence for a speculative system
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Presentation delivered on 9 March 2012 by Marita Bradshaw.
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A companion volume to 'The geology and petroleum potential of the Clarernce-Moreton Basin, New South Wales and Queensland' compiled and edited by A.T. Wells and P.E. O'Brien, Australian Geological Survey Organisation bulletin 241(1994).