Petroleum Occurrence
Onshore exploration in the Bonaparte Gulf Basin Province began in 1959 with the drilling of Spirit Hill-1 (Fig. 6), which showed residual oil in the Carboniferous Milligans Formation. Bonaparte-1 and -2, were drilled in 1963, followed by Kulshill-1 and -2, and Moyle-1, in 1965. Discoveries thus far have been concentrated onshore in fault blocks and anticlines and offshore on fault block highs, flanks of salt diapirs, and drape anticlines.

Onshore in the south, most of the discoveries have been gas with some associated oil, whereas, just to the north a band of offshore and onshore oil discoveries occurs. At Turtle-2 (Fig. 6), 34.5° API oil was recovered from the Milligans Formation and 36° API oil from the overlying Lower Carboniferous Tanmurra Formation (Fig. 5) (McConachie and others, 1996). The Upper Carboniferous Kuriyippi Formation yielded 14.3° API oil in the Turtle-2 well and 38.6° API oil in Barnett-2 (Fig. 6) (DPIE, 1998).

Source Rock
The Milligans-Carboniferous, Permian TPS 391001 contains one source rock complex and one assessment unit, the Barnett assessment unit 39100101 (Fig. 6). The Carboniferous Milligans Formation is the source rock for sandstone reservoirs in the Kuriyippi Formation, Milligans Formation, and Langfield Group, and the probable source of some of the oil in the underlying Devonian carbonate reservoirs (Fig. 5 and Fig. 7) (DPIE, 1998; McConachie and others, 1996). This petroleum system was referred to as the Larapintine/Gondwanan Transitional system of McConachie and others (1996) and Larapintine 4 of Edwards and others (1997).

The Milligans Formation of the Weaber Group consists of 200 to more than 2000 m of offshore-to-basinal shale containing submarine fan deposits that are proven reservoirs. The Milligans Formation unconformably overlies marine carbonates and shales of the Keep River Group (Bonaparte) and in turn is overlain disconformably by the transgressive Tanmurra Formation (Fig. 5) (Lavering and Ozimic, 1988). The formation thickens rapidly from the shelf into the basin indicating a high rate of basin subsidence during Early Carboniferous time (Visean) (Fig. 4, G-H) (McConachie and others, 1996). Biomarkers of marine (sapropelic) algal and bacterial lipids mixed with terrestrial material from anoxic clay-rich sediments, a total organic carbon (TOC) content range of 0.1 to 2.0 wt%, hydrocarbon index (HI) from 10-100 mg hydrocarbon (HC)/g TOC, Sulfur < 0.3%, pristane/phytane (Pr/Ph) 1.1-2.3, and vitrinite reflectance in oil (R_o) 0.95% characterize the Milligans Formation source rocks (Jefferies, 1988). It is considered to be the source rock for accumulations in the onshore and offshore at Turtle and Barnett fields, at Waggon Creek-1, Keep River-1, Weaber-1 and 2A, Bonaparte-2, Garimala, and perhaps at Kulshill and Lacrosse (Fig. 6) (DPIE, 1998; Edwards and others, 1997). It possibly also contributes to Ningbing, but analysis of oil shows at Ningbing-1 indicate a carbonate marine source rock rather than the clastic marine source rock of the Milligans Formation; a petroleum system based on carbonate source rocks will not be addressed in this report (McConachie and others, 1996). The area of mature source rock in the Milligans Formation extends onshore south of Waggon Creek-1 and Weaber-1 offshore to approximately lat 14° S. (Fig. 6) (DPIE, 1998) and is interpreted, from multiple migration and biodegradation events, to have remained in the oil generating window from Carboniferous/Permian time (McConachie and others, 1996; DPIE, 1998) to recent times (Fig. 7) (Durrant and others, 1990).

Reservoir Rock
Reefs of the Devonian (Fammenian) Ningbing Formation (Group in Warris, 1993) have porosities as much as 20% and numerous oil shows (Warris, 1993). The Ningbing reefs and the Tournaisian Langfield Group are equivalents onshore of clastic turbidity current deposits and shales of the Bonaparte Group (Formation in Warris, 1993) offshore. Ningbing reefs are located on high-standing fault blocks on the western side of the Paleozoic basin (Warris, 1993; Gunn, 1988b). Gas discoveries at Garamala-1 are in the carbonate shelf rocks of the Langfield Formation (Group in Warris, 1993). Marine shales of the Bonaparte Group (Formation in Warris, 1993) seal these traps.

Turbidite sandstones of 25% porosity and 500 millidarcy (mD) permeability within the Milligans Formation are oil and gas reservoirs at Waggon Creek-1 (Fig. 6) (DPIE, 1998; Jefferies, 1988). Shallow marine sandstones at Barnett and Turtle contain both oil and gas shows but may not be good quality reservoirs (DPIE, 1998; Jefferies, 1988). Carbonates of the Tanmurra Formation also contain oil at Turtle.

The Turtle discovery has several other oil reservoir horizons, in addition to the Milligans Formation, including the Carboniferous Kuriyippi Formation of the Kulshill Group, which consists of fluvial and shallow marine sandstones with porosity of 20% and good permeability (DPIE, 1998). The Kuriyippi Formation is present in the Lacrosse terrace and Plover shelf area and is as much as 1,017 m thick in the southern Petrel sub-basin. The sandstone, conglomerate and tillite at the top of the formation are interpreted to be of glacial origin (Mory, 1988). The Lower Permian Keyling Formation is also part of the Kulshill Group (Fig. 5), and three oil shows in that unit were reported by Jefferies (1988). The Keyling Formation is described as dominantly clastic with minor limestones and coals and is distributed across the Lacrosse terrace and Plover shelf. In the southern Petrel sub-basin, the Keyling Formation is as much as 973 m thick (Mory, 1988).

Gas shows were reported in the Lower Permian Fossil Head Formation and the Upper Permian Hyland Bay Formation of the Permian-Triassic Kinmore Group (Jefferies, 1988). The Fossil Head Formation, as much as 650 m thick in the southern Petrel sub-basin, is described by Mory (1988) as siltstones and sandstones with minor limestones. The Hyland Bay Formation is widely distributed across the Bonaparte basin and consists of as much as 520 m of carbonates, sandstones, mudstones, and coals that were deposited in shelf and deltaic environments (Mory, 1988; Gunn, 1988b).

Seal Rock
The Lower Permian Treachery Shale of the Kulshill Group is a regional seal in the onshore and offshore Petrel sub-basin (Fig. 5 and Fig. 7) (DPIE, 1998). The Treachery Shale, consisting of carbonaceous shale and tillite, is present across the Petrel sub-basin and on the Plover-Lacrosse terrace, and is as much as 219 m thick, (McConachie, 1996). Intraformational seals in the Kulshill Group are locally important in the Turtle-Barnett area (McConachie, 1996).

Trap Types
Anticlines are the most common type of hydrocarbon trap for accumulations of both oil and gas in the two Paleozoic petroleum systems. Draping structures are also important along with fault blocks and reefs. These traps involve Paleozoic sandstone reservoirs and contain approximately 1% of the reported oil equivalent reserves in the province (Petroconsultants, 1996). Middle Triassic to Early Jurassic regional compression uplifted the flanks of the sub-basin, causing erosion of the margins and forming inversion anticlines associated with fault blocks, large anticlines and monoclines (DPIE, 1998).