The Carnarvon Basin is currently Australia's most prolific hydrocarbon-producing basin; 76.3 MMbbl (12.4 GL) of oil, 1022 Bcf (28.9 Bcm) of gas and 38 6 MMbbl (6.1 GL) of condensate were produced in 2007 (Department of Mines and Petroleum, Western Australia, 2008).
This represents more than half of Australia's total hydrocarbon production. During the 2007-08 fiscal year, 18 new field wildcats were drilled in the offshore Northern Carnarvon Basin and there were 51 producing fields, including Barrow Island (Department of Industry and Resources, Petroleum and Royalties Division, 2008).
The majority of the hydrocarbons discovered to date in the Northern Carnarvon Basin are hosted by highly porous reservoirs beneath the Early Cretaceous Muderong Shale, which forms the regional seal. The presence of this effective regional seal is a major contributing factor to exploration success in the basin (Baillie and Jacobson, 1997). One of the notable exceptions is the Barrow Island oil field, where the oil-bearing Windalia Sandstone of the Muderong Shale is top-sealed by the Aptian Windalia Radiolarite. Another exception is the Maitland gas accumulation, in which a Paleocene sandstone is the reservoir. Intra-formational seals are also an important element of hydrocarbon accumulations in the basin, resulting in stacked hydrocarbon-bearing reservoirs beneath a regional unconformity surface. Individual pools in gas accumulations on the Rankin Platform are top-sealed by a combination of the regional seal and intra-formational claystones. Figure 3 [PDF, 77KB] shows the major oil and gas accumulations discovered, to date, in the Northern Carnarvon Basin.
The main trap styles in the basin are drape anticlines, horsts, fault roll-over structures and stratigraphic pinch-outs beneath the regional seal. The stratigraphic level of top-porosity, ranging from the Late Triassic Mungaroo Formation to the Early Cretaceous Mardie Greensand beneath the regional seal, generally becomes progressively younger in the landward direction.
Hydrocarbon Families and Source Rocks
Two broad hydrocarbon families are recognised in the Northern Carnarvon Basin - one gas prone and derived from Triassic fluvio-deltaic facies, and the other oil prone and sourced from Late Jurassic marine sediments. The giant gas fields on the Exmouth Plateau are considered to have been charged from the deeply buried coals and carbonaceous claystones of the deltaic Mungaroo Formation. Peak gas generation from these Triassic source rocks is interpreted to occur now at depths greater than 5000 m below the sea floor (Bussell et al, 2001). The Rankin Platform is assumed to have access to this active gas source and geochemical studies (Boreham et al, 2001; Edwards and Zumberge, 2005; Edwards et al, 2007) are consistent with these giant gas accumulations being sourced from deltaic Triassic to Middle Jurassic source rocks. However the Rankin Platform fields may also have contributions from late gas generation from the Jurassic in the adjacent Barrow and Dampier depocentres.
The Late Jurassic Dingo Claystone is the principal source for oil in the Northern Carnarvon Basin. It is a fine-grained marine unit deposited in deep water and partly restricted marine environments in the Exmouth, Barrow and Dampier sub-basins. Biomarker and other geochemical studies of the Northern Carnarvon Basin oils indicate that although they are derived from a marine source rock there was also a significant contribution from terrestrial organic matter (Summons et al, 1998) and that the Oxfordian interval (W. spectabilis biozone) is the particularly organic rich part of the Dingo Claystone (van Aarssen et al, 1996). Hydrocarbon generation from the Dingo Claystone commenced in the Exmouth Sub-basin and southern parts of the Barrow Sub-basin in the Early Cretaceous with the loading of the Barrow Delta (Tindale et al, 1998; Smith et al, 2003). Further north in the Barrow Sub-basin, beyond the main delta front, significant oil expulsion may have occurred as early as the Late Cretaceous. In contrast, the main phase of generation in the Dampier Sub-basin was in the Cenozoic, in response to the progradation of the carbonate shelf.
These two broad hydrocarbon families are overwhelmingly dominant in the Northern Carnarvon Basin and are considered to be the source of almost all the commercially developed accumulations found to date. Geochemical studies have recognised some vagrant oils which do not fall into these families (Summons et al, 1998). The oil accumulation at Nebo in the Beagle Sub-basin is interpreted as being derived from an Early to Middle Jurassic lacustrine source rock and the original oil discovery onshore at Rough Range, on the margin of the Exmouth Sub-basin, has also been interpreted as having a lacustrine source (Edwards & Zumberge, 2005).
Regional Petroleum Systems
The USGS analysis (Bishop, 1999) of the petroleum systems of the Northern Carnarvon Basin mapped a'Locker-Mungaroo/Barrow' Petroleum System across most of the basin out to the margins to the Exmouth Plateau. However there is no geochemical evidence of a contribution from the Early Triassic marine Locker Shale, and the Mungaroo Formation fluvio-deltaic facies are now considered to as the primary source of the large gas fields. Given the low geothermal gradient on the Exmouth Plateau, basin modelling indicates that it is not impossible that deeply buried Locker Shale has contributed to the hydrocarbon charge. Exploration has recently extended the proven extent of the retitled'Locker/Mungaroo-Mungaroo/Barrow' Petroleum System further north on the Exmouth Plateau with the Thebe 1 and Martell 1 gas discoveries (Figure 2 [PDF, 582KB]).
From the regional perspective of the North West Shelf the'Locker/Mungaroo-Mungaroo/Barrow' Petroleum System can be considered as part of the Westralian 1 Petroleum Supersystem (Bradshaw et al, 1994; Edwards et al, 2007). This Supersystem includes giant gas accumulations sourced mainly from deltaic Triassic to Early-Middle Jurassic source rocks in the Bonaparte, Browse and Northern Carnarvon basins. Similar carbon isotopic profiles are seen in the gases and associated condensates from fields in the Westralian Superbasin as far apart as Sunrise in the Bonaparte Basin, Torosa (Scott Reef) in the Browse Basin and North Rankin in the Northern Carnarvon Basin. This similar geochemistry reflects similar source facies deposited in fluvio-deltaic environments throughout the Westralian Superbasin in the Triassic to Middle Jurassic (Edwards and Zumberge, 2005; Edwards et al, 2007).
The oil prone'Dingo-Mungaroo/Barrow' Petroleum System (Bishop, 1999) has a more limited distribution than the'Mungaroo-Mungaroo/Barrow' Petroleum System, being restricted to the Exmouth, Barrow and Dampier sub-basins. The proven extent of this system has encroached further to both the south and north with oil discoveries in the Exmouth Sub-basin and at Mutineer/Exeter in the northern end of the Dampier Sub-basin. From the regional perspective of the North West Shelf the'Dingo-Mungaroo/Barrow' Petroleum System can be considered as part of the Westralian 2 Petroleum Supersystem (Bradshaw et al, 1994; Edwards and Zumberge, 2005; Edwards et al, 2007). Geochemically similar oils are recognised in the Northern Carnarvon, Bonaparte and Papuan basins, all derived from Late Jurassic marine source rocks deposited in incipient rifts that developed along the northern and north-western continental margin during Gondwana break-up.