Abstract More than two hundred sedimentary basins have been identified across onshore Australia and its offshore marine jurisdiction (Fig. 1). These basins cover in excess of 10 million square kilometres and host a great variety of petroleum systems ranging in age from Proterozoic to Cenozoic (Bradshaw et al. , 1994 ; Longley et al. , 2001 .) However, more than 95 percent of Australia’s known reserves of petroleum are located in Mesozoic and younger sediments within divergent margin basins encircling the continent. Figure 1. Map of Australian basins showing exploration maturity (from Williamson and Foster, 2003). The majority of the initial oil reserves (3.8 billion barrels of the 6.2 billion barrels of Australia’s initial commercial crude oil reserves) were discovered in just one of these basins, the Gippsland, located offshore, southeastern Australia. Other significant volumes of oil were discovered in the Carnarvon and Bonaparte basins on the North West Shelf; as well as major gas reserves, estimated in 2004 at over 100 trillion cubic feet. Australia ranked 30 th and 13 th in oil and gas global reserves, and 28 th and 17 th in oil and gas production at year end 2002 (Petrie et al. , 2005). Australia’s continental margin basins are the legacy of the breakup of Gondwana. The character and timing of the breakup varied along the margin and is reflected in the petroleum systems. The North West margin has a marine history extending back into the early Paleozoic. Successive continental slivers rifted away during the formation of the various incarnations of Tethys, continuing through to the development of the Indian Ocean in the Late Jurassic and Early Cretaceous. North West Shelf petroleum systems are characterized by marine shales providing oil source rocks and regional seals for fluvio-deltaic to shallow marine sandstone reservoirs. In contrast, the late Mesozoic breakup along the Southern Margin occurred between the two major continental blocks of Australia and Antarctica. Non-marine facies characterize the petroleum systems with coals and carbonaceous shales sourcing the hydrocarbons trapped in siliciclastic reservoirs. Most of the depocenters containing significant oil accumulations can be described as “failed rifts”, whether they are located on the North West Shelf or on the Southern Margin. The major oil fields of the Carnarvon basin are located in the Mesozoic Exmouth, Barrow, and Dampier sub-basins, which lie inboard of the giant gas province of the Exmouth Plateau (Fig. 2). The Exmouth Plateau is a submerged continental platform of earliest Jurassic age and older, surrounded on three sides by oceanic crust – the Argo Abyssal Plain to the northeast, the Gascoyne Abyssal Plain to the northwest, and the Cuvier Abyssal Plain to the southwest. The plateau is bounded to the southeast and east by the oil-prone Exmouth, Barrow, and Dampier sub-basins, which are intracratonic rifts that were initiated in the Pliensbachian. Figure 2. Tectonic elements of the Northern Carnarvon Basin (from Stagg and Colwell, 1994). Several kilometers of marine Jurassic sediments were deposited in these sub-basins that are age-equivalent to sections a few meters thick on the Exmouth Plateau. Breakup on the northern margin of the Exmouth Plateau during the Callovian was associated with the formation of the Argo Abyssal Plain and produced further movement on the faults bounding the sub-basins. Restricted, deep-marine environments were established in the subsiding troughs, and the primary oil source rock facies of the Dingo Claystone was deposited during the Late Jurassic (Bishop, 1999 ; Bradshaw et al. , 1998 ; Longley et al. , 2002). A similar pattern is repeated to the north, in the Bonaparte basin, where the oil-producing Vulcan subbasin is located inboard of the Ashmore Platform (Fig. 3). In this sub-basin, Late Jurassic marine source rocks deposited in restricted marine troughs are the key to the petroleum system (Edwards et al. , 2004). Figure 3. Tectonic elements of the Bonaparte Basin showing the location of petroleum discoveries (from Edwards et al. , 2004). On the southeastern continental margin of Australia, the Gippsland basin is one of Australia’s most prolific and mature petroleum provinces. The basin is an intact rift preserved from the later stages of Gondwana breakup. It was initiated as part of the east-west directed Early Cretaceous breakup rift system between Antarctica and Australia. In the Late Cretaceous, the oil kitchen and main depocenter of the Central Deep was established during renewed extension associated with the opening of the Tasman Sea (Bernecker, et al 2001 ; Norvick et al 2001). The first marine incursion occurred in the late Santonian. However, the lower coastal plain and coal swamp facies deposited in the Central Deep during the Late Cretaceous are regarded as the major source rocks for the billion-barrel accumulations of the Gippsland basin (Burns et al. , 1984 ; Rahmanian et al. , 1990). The vast majority of Australia’s discovered oil reserves are located within rift systems in three basins – the Carnarvon, Bonaparte, and Gippsland basins. In all three areas, the deposition of source rocks is controlled by rift-basin architecture. The deep-water, frontier Mentelle basin, located offshore of southwestern Australia, has several key features reminiscent of these proven oil provinces. The Mentelle basin is a thick, Mesozoic, depocenter located inboard of a submerged continental platform, the Naturaliste Plateau (Fig. 4). Its tectonic history has some similarities to the evolution of the Gippsland basin, having been formed near the failed arm of a triple plate junction during rifting of Australia, Antarctica, and Australia-Greater India breakup (Bradshaw et al , 2003). Geoscience Australia is currently undertaking number of studies in the Mentelle basin to ascertain whether there is any evidence of a petroleum system to compliment this apparently promising configuration. Figure 4. Tectonic elements of southwestern Australia (from Bradshaw et al. , 2003).