South Australia boasts significant hydrocarbon potential.

South Australia has a long history of petroleum exploration, extending to 1866, when the first well was sunk in the search for oil. The discovery of Permian gas in the Cooper Basin in 1963 was the first commercial discovery of hydrocarbons in the state. By 1969, gas from the Cooper Basin was being piped 490 miles (790 km) to Adelaide for sale, and a pipeline to Sydney markets followed soon after (Figure 1). The Cooper and Eromanga Basins, which span northeastern South Australia and southwest Queensland, comprise Australia's largest onshore petroleum province.
In February 1999, longstanding licenses held by the Santos Ltd. joint venture in the Cooper Basin since 1954 expired without right of renewal. A phased acreage release program began in October 1998 with three bidding rounds for 27 blocks, all of which are under application by a mix of local and US-based explorers. Further releases will be made as acreage becomes available. Santos Ltd. is conducting an aggressive program of development drilling and seismic acquisition in its production licenses, and the new explorers are awaiting resolution of native title issues before beginning a new phase of exploration activity in the basin.
The Cooper region remains the best known and most explored area, followed by the onshore Otway Basin. Large areas of the state remain only lightly explored for petroleum, including onshore Early Paleozoic basins and the offshore Otway, Duntroon and Bight basins. A major exploration program is under way in the Bight Basin, with the Woodside-Anadarko-PanCanadian joint venture acquiring about 10,000 miles (17,000 km) of 2-D seismic this year with a guaranteed exploration well to be drilled in 2002 and 2003.
New infrastructure development projects also recently emerged with two proposals for gas pipelines linking Adelaide markets to major eastern Otway Basin gas discoveries including Minerva 1, Thylacine 1 and Geographe 1, drilled this year (Figure 1).
Infrastructure
Petroleum provides the majority of the state's primary energy needs, and 51% of its electricity was generated from gas (42 Bcf) in 1999. South Australia production in 2000 was 154 petajoules (PJ) of sales gas, 18 PJ of ethane, 2.92 million bbl of crude oil, 2.45 million bbl of condensate and 1.96 million bbl of liquefied petroleum gas.
Some 3,254 miles (5,240 km) of pipelines transport Cooper Basin gas to all eastern and southern Australian capital cities. The Australian Gas Association predicts gas will be the fastest growing energy source in Australia to 2030, with annual growth of 3% predicted. Gas supplies about 18% of Australia's primary energy needs, and the Australian Gas Association predicts this will increase to 28% by 2030. Its study of future Australian gas supplies and demand forecasts that gas reserves in southern and eastern Australia will be insufficient to supply market demand within a decade.
Petroleum geology
South Australia has preserved a unique record of sedimentation from the Neoproterozoic to Ordovician and from the Early Devonian to Tertiary (Figure 2). Prospective basins may be subdivided into three groups. Basins of Mesozoic age, which either overlie older intracratonic basins or are developed on the rifted southern continental margin of Australia, include the oil-producing Eromanga Basin and the Simpson Basin onshore. The Duntroon, Bight and gas-producing Otway basins are rift basins on Australia's southern margin, and the latter two extend onshore. The second group, Permo-Carboniferous to Early Triassic basins, overlie older Palaeozoic basins and include the oil- and gas-producing Cooper Basin and the Pedirka and Arckaringa basins. And Cambrian to Ordovician basins include the Warburton, Arrowie, Stansbury and Officer basins with mixed carbonates, clastics, volcanics and minor evaporites. The last three basins are underlain by extensive Neoproterozoic sediments, which are largely unmetamorphosed and thus also prospective for hydrocarbons. The Officer Basin contains a Devonian section preserved in a foreland trough setting.
The Permian and Mesozoic intracratonic basins contain largely nonmarine fluvial and lacustrine clastics and coal measures. The Cretaceous continental margin basins have very thick Early Cretaceous rift and Late Cretaceous-Cenozoic post-rift sequences. The Bight Basin contains an underexplored Cretaceous delta that forms an enormous bathymetric feature, the Ceduna Terrace.
Duntroon basin
Three offshore blocks are available for application in the Duntroon Basin with a closing date for bids of April 11, 2002. Areas S01-1, S01-2 and S01-3 comprise 80 (2,162 sq miles, 5,600 sq km), 76 (2,052 sq miles, 5,315 sq km) and 80 (2,046 sq miles, 5,300 sq km) graticular blocks, respectively (Figure 3). Water depths range from 197 ft to 9,843 ft (60 m to 3,000 m), with the majority of the license areas lying in water depths less than 650 ft (200 m).
The Duntroon Basin is one of a series of basins developed along the southern margin of Australia that resulted from the separation of the Australian and Antarctic continents. The southern limit of the basin is delineated by the continent-ocean boundary. The basin comprises a thick Jurassic to Early Cretaceous rift greater than 36,000 ft (11,000 m) and Late Cretaceous to Tertiary post-rift succession. The rift succession consists of nonmarine fluvial to lacustrine and deltaic sediments unconformably overlain by marine to nearshore marine Late Cretaceous to Early Tertiary sediments from the drift phase following continental breakup. Late Eocene to Oligocene carbonates deposited during the passive margin phase unconformably overlie this sequence.
The basin can be divided into three zones - the inner half-grabenal basin, an intrabasin high and an outer step-faulted basin. Each of these zones hosts a variety of play types and fairways. Extensive rift-related tectonism has provided anticlinal collapse resulting from shale movement, especially in the outer basin. Crestal erosion along the intrabasin high (e.g., Echidna 1) has developed significant stratigraphic plays.
These areas have been explored as part of offshore exploration permits by Shell (1966-1976), Outback (1981-1984) and Getty/BP (1982-1986). During this time, only three dry wells were drilled over an area of 22,000 sq miles (57,000 sq km). In 1991, BHP Petroleum (Victoria) Pty. Ltd. reprocessed older seismic lines and acquired 7,200 miles (11,578 km) of high-quality modern seismic. This indicated all prior drilling was on invalid structures.
BHP drilled three wells in 1993, and although all were plugged and abandoned, their results were encouraging and emphasize the highly unpredictable stratigraphy and complex structural history of the basin. One of these wells, Greenly 1, tested a basal Late Cretaceous play and reached a 15,945-ft (4,860-m) TD with significant oil and gas shows. These shows represent the first major indication of hydrocarbons in the region. There is considerable potential updip from Greenly 1 at the Rocky Prospect.
Significant hydrocarbon prospectivity exists within the Duntroon Basin, and at least 20 leads identified require minimal infill seismic to move ahead to prospect status. The richest and most oil-prone source rocks consist of coals (average hydrocarbon index 210-330, total organic carbon content up to 56%) and claystones (average hydrocarbon index 120-170, total organic carbon content up to 5.5%) of the Early Cretaceous Borda Formation (Figure 3). Principal reservoirs are delta distributary channel sandstone of the Ceduna Formation and fluvial to upper delta plain sandstones of the Platypus Formation. Marine sands within the Wigunda and Potoroo formations and Pidinga Sandstone also have excellent reservoir quality. Major seals exist in the Early and Late Cretaceous sequences, and shales of the upper Borda Formation form a regional seal. An airborne laser fluorescence survey conducted in 1990 over the Great Australian Bight region identified several weak and strong fluors, the majority of which are clustered in the Duntroon Basin area.
Potential risked oil and gas in place is about 3 billion bbl, based on unpublished company reports.
For more information on offshore South Australian opportunities, visit www.isr.gov. au/resources/petro leum.html or www. petroleum.pir. sa.gov.au.

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