Oil and gas accumulations in Mesozoic strata are found in (1) trapping structures that overlie subsided areas where source rock was deposited and is mature, and where faults facilitated vertical migration; and (2) in traps directly adjacent to the subsided areas of mature source rocks, where there was vertical migration out of the syncline followed by lateral migration into adjacent reservoir rocks.

Source Rock
The Jurassic, Early Cretaceous-Mesozoic TPS 391003 contains source rocks of Jurassic and Early Cretaceous age and sandstone reservoirs of various Mesozoic ages that were deposited in a complex of sub-basins formed by Mesozoic faulting and subsidence (Fig. 11). One assessment unit has been assigned to this TPS, Malita 39100301 (Fig. 10). Specific stratigraphic names and ages vary locally among areas. In particular, terminology from exploration leases assigned to different companies in this unit has not been fully correlated in the literature and reflects local differences in deposition and erosion (Fig. 5). The Pliensbachian to Callovian Plover Formation consists of organic-rich claystones and coals deposited in fluvial to marginal marine environments (Botten and Wulff, 1990). Residual oils from wells on the Londonderry high have been typed to this claystone in the Sahul syncline (Fig. 4, A-B) (Whibley and Jacobson, 1990). The source potential is fair to good for gas/condensate and some oil; TOC > 4 wt%, S₁+S₂ (petroleum potential) approximately 8 mg/g (Botten and Wulff, 1990). The Oxfordian to Valanginian Flamingo Group (Upper Petrel Formation) has good oil source-rock potential in the Bonaparte Basin; TOC ranges from 1-2.4 wt% and S₂ values range from 2-3.1 mg/g (Botten and Wulff, 1990; McLennan and others, 1990). The Oxfordian to Valanginian interval is also known as part of the Elang Formation (Plover Formation), Frigate Formation (Frigate Shale, Sandpiper sands), Flamingo Formation (Flamingo shale, Darwin Formation), and part of the Echuca Shoals Formation (Darwin Formation) (Brooks and others, 1996). Burial history models for the Flamingo and Sahul synclines indicate initial source-rock maturation at the start of the Paleocene for Upper Flamingo claystones in the Flamingo syncline, and in the Cretaceous for the Sahul syncline (Brooks and others, 1996). Peak oil generation of Upper Flamingo claystones in the Sahul syncline was in Late Cretaceous time, and in the Flamingo syncline in Middle Eocene time (Brooks and others, 1996). Equivalent Mesozoic source rocks in the Malita graben matured and expelled hydrocarbons during latest Cretaceous to Tertiary subsidence (Miyazaki, 1997). At present, Mesozoic source rocks may still be generating gas in the Malita graben (Fig. 4, A-B and C-D) (Miyazaki, 1997).

The Valaginian-Barremian Darwin Formation (Echuca Shoals Formation) and the Turonian-Maastrichtian Bathurst Island Group (Fig. 5) also have good source-rock properties but are immature or marginally mature for oil over most of the area (Fig. 4, A-B and C-D) (Robinson and others, 1994). The restricted marine shale of the Darwin Formation is interpreted to be an excellent source rock and to be mature in the Sahul and Flamingo synclines (Brooks and others, 1996). These strata overlie most of the good reservoir rocks in the area so migration would require faulting to position older reservoir rocks updip from local, low lying mature areas (Fig. 4, A-B and C-D) (Robinson and others, 1994). Oil at Elang-1 is geochemically mature, vitrinite reflectance = 0.9-1.1, and is derived from a source rock of algal/marine organic matter with a terrestrial component (Young and others 1995). The Darwin Formation in the Sahul syncline and Malita graben is suggested as the source rock for this oil (Young and others, 1995). Condensate from the Bayu/Undan area has been closely correlated to claystones of the Echuca Shoals Formation (Fig. 5) (Brooks and others, 1996). Migration is considered to be out of the Malita graben, where the Echuca Shoals Formation is thought to be thicker and more deeply buried, or possibly from the Flamingo syncline (Brooks and others, 1996).

The Jurassic-Cretaceous Lower and Upper Vulcan Formations (Frigate and Flamingo equivalents) of the Swan Group, with possible contributions from the Lower Cretaceous Echuca Shoals Formation of the Bathurst Island Group, provide source rocks for gas, oil, and condensate accumulations within the Vulcan graben sub-basin (Fig. 5) (Bourne and Faehrmann, 1991; Smith and Sutherland, 1991). Late Jurassic and Early Cretaceous source rocks are juxtaposed by normal faulting against Triassic and Early Jurassic reservoir rocks (Bourne and Faehrmann, 1991; Pattillo and Nicholls, 1990). Hydrocarbons migrate along sandstone units and across faults to source reservoirs in high-standing and basin-margin fault blocks (Bourne and Faehrmann, 1991).

Drilling of Paqualin-1, to test a salt structure, encountered more than 1,640 m of Upper and Lower Vulcan Formation claystones of restricted marine origin (Smith and Sutherland, 1991). Geochemical analysis indicates excellent oil and gas source-rock quality; type II/III kerogen, TOC averaging 2 wt%, HI as much as 300 mgHC/gTOC, and S₁+S₂ (petroleum potential) > 6.0 mg/g (Smith and Sutherland, 1991).

The Lower to Middle Jurassic Plover Formation is present only within the Vulcan graben sub-basin; the formation was eroded or was not deposited across the Ashmore platform and is only partially preserved on the Londonderry high. The Plover Formation is a possible gas-prone source rock of fluvial deltaic sandstones and carbonaceous deltaic mudstones. The possible source of hydrocarbons on the Ashmore platform would be thick, shallow, and marginal marine facies of the Triassic Sahul Group (DPIE, 1998). Hydrocarbons in fields on the structural terraces surrounding the Londonderry high (Challis field) and Ashmore platform (Puffin and Skua fields) probably migrated from the local troughs within the Vulcan graben sub-basin where Upper Jurassic source rock is present and buried to depths of 4,000 m (Wormald, 1988; Ormerod and others, 1995).

Reservoir Rock
The Lower Jurassic (Rhaetian-Pleisbachian) Malita Formation consists of sandstones and shales of continental redbed and shallow marine to fluvial-deltaic origin (Killick and Robinson, 1994). These rocks reach thicknesses of more than 500 m in the Sahul syncline but are present on the Sahul platform in thicknesses less than 25 m. Fluvial influence is greater in the lower Malita and increases to the south whereas marine influence is greater in the upper Malita and increases to the north (Killick and Robinson, 1994).

The lower Plover Formation is characterized by strata deposited in a regressive fluvial-deltaic depositional environment (Killick and Robinson, 1994). The upper Plover was deposited in a transgressive nearshore marine setting. On the margins of the Petrel sub-basin the Plover Formation reaches a thickness of 200 m and in the Sahul syncline a thickness of 1,200 m (Killick and Robinson, 1994). Sedimentation of the Plover Formation was controlled by continued subsidence of the Flamingo trough and the Sahul syncline. Significant erosion (possibly 400 m) occurred on the Sahul platform during Late Callovian to Early Oxfordian time (Killick and Robinson, 1994). The Callovian to Oxfordian Montara beds at the top of the Jurassic Plover Formation are of fluvio-deltaic to marginal marine origin and have excellent reservoir qualities in the Elang-1 discovery, including porosities of 20-25% and permeabilities of 880 to 2000 mD (Young and others, 1995; Petroconsultants, 1996).

The Upper Jurassic to Lower Cretaceous Flamingo Group is thin or absent over the Londonderry high and Sahul platform due to nondeposition, low sedimentation rates and erosion (Killick and Robinson, 1994). Several lowstand events during deposition of the Flamingo Group could produce erosion, valley-fill type prospects, and basin-floor fans. The Flamingo Group is more than 1,000 m thick in the Sahul syncline, Flamingo trough and the Malita graben. Subsidence of the Sahul syncline and the Flamingo trough was greatest in Late Jurassic whereas subsidence in the Malita graben was greatest in the Early Cretaceous (Killick and others, 1994). The "sandpiper sands" of Oxfordian to Valanginian age are described as shoreface to marine fan sands, the fans having been deposited by mass flow and rapid traction events.

Oil reserves at Challis and Cassini fields in the Vulcan graben sub-basin are in stacked sandstone reservoirs of the Middle to Upper Triassic Challis and Pollard Formations of the Sahul Group (Gorman, 1990). The reservoir rocks originated in upper deltaic, barrier, and shoreline settings. Sandstones are 100-200 m thick in the deltaic setting and 10-20 m thick in the barrier/shoreline setting. Porosity ranges from 25-30% and permeability is as much as 10 darcies. Cementation by carbonates and clays and creation of secondary porosity by dissolution of grains and cements has occurred (Gorman, 1990).

Also in the Vulcan graben sub-basin, oil in the Jabiru field is found in Early and Late Jurassic age sandstones, lower Vulcan and Plover Formations of the Swan and Troughton Groups, and beneath the same Early Cretaceous unconformity that traps oil at Challis and Cassini fields. These Jurassic sandstones have porosity of 18-26% and permeability of 1.6 darcies (Nelson, 1989). Depositional environments are described as coastal and barrier island for the 100-200 m thick Lower Jurassic sandstone reservoirs and nearshore marine for the 10-100 m thick Upper Jurassic reservoirs (Nelson, 1989).

Seal Rock
Top and lateral seals for the Laminaria field are formed by 300 m of Lower Cretaceous (Neocomian) claystone of the Upper Flamingo Group and Darwin Formation (Fig. 11). The Frigate Shale provides a seal to the Plover and Malita Formations and the Cape Londonderry Formation where it is present. The Flamingo Shale is both a seal and a source rock in the Mesozoic basins (Fig. 3, Fig. 4 and Fig. 5). It was deposited when the Malita graben was subsiding and capturing sediments from the south while the north was more distal and starved of sediment (Fig. 5) (Killick and others, 1994). The thick Cretaceous Bathurst Island Group shale is the regional seal for the Mesozoic basins.

Trap Types
Most of the reserves reported (Petroconsultants, 1996) in the Mesozoic petroleum system occur in fault-block traps. This petroleum system accounts for 67% of the oil equivalent reserves in the Bonaparte Gulf Basin Province (Petroconsultants, 1996). The Vulcan graben is dominated by horst-blocks traps. Kimmeridgian faulting further subdivided Callovian fault blocks into narrower grabens and fault block trends (Pattillo and Nicholls, 1990) and changed the earlier structural grain from NE-SW to ENE.

Late Miocene to Pliocene collision tectonics reactivated many Late Jurassic normal faults, mobilized Paleozoic salt in the Vulcan graben, formed possible inverted structures, and increased the risk of releasing trapped hydrocarbons (DPIE, 1998; Pattillo and Nicholls, 1990; Bourne and Faehrmann, 1991; Smith and Sutherland, 1991).