Bonaparte Basin

The Bonaparte Basin joins the Browse Basin to the west and the Money Shoals Basin to the northeast. The Timor Trough defines the northern boundary. The basin developed as a v-shaped, north-opening rift during the Devonian to Early Carboniferous.

Exploration in the area has defined a sedimentary succession that regionally dips to the north, with the oldest strata outcropping in the south. The dominant feature of the basin is the north-northwesterly oriented Petrel Sub-basin, in which up to 17 km of Paleozoic to Cenozoic sedimentary fill is preserved.

The structural orientation of this sub-basin contrasts with that of the northern sub-basins (the Ashmore and Sahul Platforms, Vulcan Sub-basin, Londonderry High, and Malita Graben) where the predominant northeasterly fault trends are orthogonal to those of the Petrel Sub-basin, and the sedimentary fill is dominantly Mesozoic to Cenozoic. The change in orientation is related to the Late Jurassic breakup of Gondwana.

In the southern part of the Bonaparte Basin, two periods of deposition have been recognised.

The initial period (Late Devonian to Early Carboniferous) was associated with the remnants of a rift system controlled by numerous north-northwesterly oriented normal faults.

During the second period, Upper Carboniferous and younger sedimentary rocks draped the earlier rift blocks and lapped onto Proterozoic rocks forming the flanking shelves. This later part of the succession is relatively unfaulted.

In the northern part of the basin, where the structural configuration is dominated by the Late Jurassic breakup that formed northeasterly oriented fault blocks, the oldest part of the succession known from drilling is Late Permian in age.

However, the presence of an even older section is indicated by rare salt-related structures similar to those at the southern end of the Petrel Sub-basin, although these structures are not as common.

In the Cenozoic, a prograding wedge of carbonates was deposited across the western passive margin of Australia, including the Bonaparte Basin. Faults were rejuvenated and small anticlines produced in the Middle Miocene during the collision with the Indonesian Plate to the north.

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Petroleum exploration of the Bonaparte Basin commenced in the late 1940s, with reconnaissance work in the onshore area. In 1963, the first well in the Western Australian area, Bonaparte 1, was drilled by Alliance Oil Development NL.

Since then, 82 wells have been drilled offshore and 10 onshore in the Western Australian portion of the basin (see the Western Australian Petroleum Information Management System database (WAPIMS) under Online Databases)

Seismic exploration to date in the Western Australian portion of the basin includes more than 200 000 line km of 2D and 18 000 km2 of 3D seismic data offshore and 6650 line km onshore.

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The prospectivity of the Bonaparte Basin is evident from the known oilfields and gasfields (Table 4), particularly in the northwestern Timor Sea area. Subcommercial gas accumulations in the lower Paleozoic strata indicate that even the older sedimentary rocks have potential.

Onshore, the units considered most likely to generate hydrocarbons are the predominantly shaly Lower Carboniferous Milligans Formation (total organic carbon up to 1.82% and S1+S2 up to 4.5 mg/g rock) and Upper Devonian Bonaparte Formation.

Vitrinite reflectance measurements suggest that these units are immature to mid-mature in the onshore part of the basin, apart from near the Pincombe Inlier where Devonian rocks are in the gas generation window, possibly related to high heat flow in this area.

The success to date is considered to be directly related to the amount of exploration in the basin, with seven known gas accumulations in the Western Australian portion (Blacktip, Tern, Petrel, Penguin, Waggon Creek, Vienta, and Bonaparte), oil and gas accumulations (Buffalo and Laminaria East), an inferred oil accumulation (Turtle), and several extensive residual oil columns (Avocet, Barita, Drake and Lacrosse).

The best onshore gas show was from Waggon Creek 1A in 1995, which tested 7079 m3/day (250 000 ft3/day) from two combined zones in the Lower Carboniferous Milligans Formation. The well also produced a small amount of oil, but the rate was not measured.

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