Australia's southeastern Bonaparte basin has plenty of potential

Shige Miyazaki
Bureau of Resource Sciences Canberra, Australia

Drilling success rate for this basin is one of the highest in Australia in the last 5 years. New opportunities are available in the southeastern Bonaparte basin, where seven vacant tracts have just been released for application for exploration permits.

Gazettal areas W97-8, 9, and 10 (Fig. 1 [156849 bytes]) comprise a total of 10,000 sq km in the southwestern coastal part of Joseph Bonaparte Gulf. Water depths range from less than 10 m to 60 m. These areas lie 350 km southwest of Darwin, the base for Timor Sea seismic and drilling operations.

Gazettal areas NT97-1, 2, 3, and 4, 120-310 km west of Darwin, occupy the Darwin shelf and the northeastern part of the Petrel sub-basin. These areas cover 32,000 sq km in total. Water depths range generally from 30-100 m but exceed 100 m in the westernmost part of NT97-2 and 3.

One of the proposed development methods for the Bayu/Undan gas/condensate accumulation discovered in Area A of the Australia/Indonesia Zone of Cooperation involves construction of an onshore LNG plant and a 470 km subsea pipeline to Darwin; should they be built, the pipeline would cross the Darwin shelf.

Regional geology

The northwest-trending Paleozoic Petrel sub-basin (Fig. 1) occupies the southern part of the Bonaparte basin. The northeast-trending Mes- ozoic Malita graben crosses diagonally the central part of the basin.

The Darwin shelf has existed as a regional structural high, flanked by the Petrel sub-basin to the southwest and by the Malita graben to the northwest.

Sedimentation in the Petrel sub-basin was initiated during a period of Cambrian pre-rifting ( Fig. 2 [113086 bytes]). Rifting commenced in the Late Devonian, resulting in extensive sedimentation during late Paleozoic time.

The east and west boundary faults of the Petrel sub-basin converge to form the southerly termination of the sub-basin. The sub-basin plunges to the northwest, resulting in cropping-out of early Paleozoic formations in its southern onshore area and, offshore, in progressive subcropping of late Paleozoic to Tertiary formations to the northwest beneath a thin veneer of Quaternary cover.

The pre-rift sequence of the Petrel sub-basin contains extensive Silurian evaporite deposits. Salt movement (diapirism, withdrawal, and flow) has created numerous structures capable of trapping petroleum in the sub-basin, and dens of salt diapirs have been identified in various parts of the sub-basin.

The Malita graben was initiated during the Triassic and developed into a major depocenter with the main phase of mid-Mesozoic rifting. Sediments in the graben attain their greatest thickness in ZOC Area B at the confluence of the Paleozoic and Mesozoic extensional regimes.

Mesozoic source facies in the Malita graben attained sufficient thermal maturity to generate and expel hydrocarbons during renewed subsidence of the graben in the Tertiary.

The Darwin shelf has long been a structurally positive province ( Fig. 3 [115488 bytes]), with a core consisting of Proterozoic basement rocks. These are draped by Permian to Cenozoic sediments, which dip gently towards the depocenters of the Petrel sub-basin and Malita graben.

Previous exploration

Exploratory drilling in the Bonaparte basin commenced onshore in 1964. A total of 18 onshore and 31 offshore exploration and appraisal wells have been drilled in a 90,000 sq km area within the Petrel sub-basin, but only two wells have been drilled in an area of 45,000 sq km on the Darwin shelf.

The Petrel and Tern gas accumulations (Fig. 3) were discovered in the central offshore Petrel sub-basin. The Turtle oil and Barnett oil and gas accumulations (Fig. 2) were discovered in the coastal southern part of the sub-basin. Although a series of appraisal wells were drilled, all these accumulations are yet to be declared commercial.

Situated near NT97-4, the Petrel gas accumulation in the Hyland Bay formation is the most significant discovery made in the Petrel sub-basin. The Tern gas accumulation lies a little farther to the southwest. Salt withdrawal was a tectonically integral part of forming the anticlines hosting these gas accumulations.

The Turtle oil and Barnett oil and gas accumulations were discovered on the Turtle high, close to W97-9 and 10. Oil is reservoired in the Keyling formation, Treachery shale, and Kuriyippi, Tanmurra, and Milligans formations, and gas is reservoired in the Langfield Group.

A summary follows of all wells drilled in the gazettal areas, where no wells have been drilled in the last 12 years.

Lacrosse-1 was drilled in 1969 in W97-9 to test Kulshill Group reservoirs in a dip rollover feature into the upthrown bounding fault. Two cores taken from the Kuriyippi formation were partially saturated with residual oil and have porosities of up to 26% and permeabilities of up to 514 md. The residual oil has gravities of 15-20° API. The reservoir sands appear to be lenticular and have poor lateral continuity at this location.

Newby-1 was drilled in 1969 in NT97-2 to test a stratigraphic pinchout feature with upper Paleozoic and Mesozoic reservoirs. No significant hydrocarbon shows were encountered. This well is not regarded as a valid test because of the absence of suitable trapping geometry at its location.

Flat Top-1 was drilled in 1970 in NT97-3 to test a stratigraphic pinchout play of Permian sands at the basin margin. Shows of bitumen and biodegraded oil were observed on cuttings from the Fossil Head formation. A small quantity of gas with air contamination, recovered by FIT from the Hyland Bay formation, is interpreted as dissolved gas in formation water. The failure of this well is attributed to the absence of an effective stratigraphic trap.

Lesueur-1 was drilled in 1980 in W97-8 to test Kulshill Group and Tanmurra formation reservoirs in a dip rollover feature into the upthrown bounding fault. Gas was recovered during a number of FITs run in the Tanmurra formation and Langfield Group. The size of its closure diminishes significantly from Permian to Carboniferous levels.

Berkley-1 was drilled in 1982 in W97-8 to test a Devonian Ningbing limestone reefal anticline. After intersecting the Kulshill Group, the well drilled into basement. The anticipated reefal anticline turned out to be a paleohigh of basement. It is unlikely a valid closure is present at any level.

Cambridge-1 was drilled in 1984 in W97-9 to test Kulshill Group reservoirs in a fault trap. Numerous oil stains and shows were observed on cuttings and sidewall core samples taken from the Hyland Bay and Fossil Head formations and the Kulshill Group.

Matilda-1 was drilled in 1985 in W97-10 to test Kulshill Group reservoirs on a salt diapir. Fluorescence was observed on cuttings taken from the top Keyling and basal Fossil Head formations. Failure of the test is possibly attributable to the presence of leaky faults over the diapir.

Southern potential

The Treachery shale of the Kulshill Group and shaly members of the Milligans formation and Langfield Group contain oil-prone source facies in the coastal southern Petrel sub-basin (Fig. 2).

Oils recovered from the Turtle and Barnett accumulations are likely to have generated from the marine Milligans formation. Petroleum migration to traps may have been triggered by salt movement at various times. Salt movement may also have influenced migration pathways.

Two different play types have been identified in this region: Kulshill Group rollover plays on the basin-margin terrace; and salt-related plays around the Turtle high. Except for these rollover features, practically all structural and many stratigraphic features in this region are more or less related to salt movement.

Potential reservoirs include not only sandstones of the Devonian, Carboniferous, and Permian but also the reefal carbonates of the Carboniferous Tanmurra formation and Devonian Ningbing limestone.

Onlapping on the basement, glacial Kulshill Group sands may be contained in rollover features formed in downthrown fault blocks. Oil-bearing reservoirs were discovered in the Kulshill Group in Turtle and Barnett wells, and oil shows or residual oils were observed in the Kulshill Group in Bougain- ville-1, Cambridge-1, La- crosse-1, Kulshill-1, Matilda-1 and Torrens-1.

Salt-related plays can be sub-divided into a number of categories, and the timing of salt movement varies widely in this area. The Turtle High, a prominent subsurface feature in the coastal southern Petrel sub-basin, is likely to have been formed as a salt dome, which stopped growing by the time the Milligans formation was prograding onto the sea floor over the eroded Langfield Group. The reef facies of the Tanmurra formation appears to have developed on salt-induced seafloor mounds.

The Fossil Head formation and Treachery shale provide regional seal, and shaly members of the Milligans formation and Langfield Group would form effective seal locally in a host of prospects and leads. Wide overhangs of salt diapirs are likely to provide excellent top seal.

Darwin shelf potential

The underexplored Darwin shelf (Fig. 3) is situated updip from a number of potential hydrocarbon sources in the Petrel sub-basin and Malita graben.

The historic lack of interest in this area is due to relatively thin sedimentary sequence on the shelf and to the lack of structural complexity. However, discoveries such as Wandoo, Gwydion, and Cornea indicate that basin margin shelf plays may be successful in this part of the North West Shelf.

The few wells drilled provide limited evidence for source rock types in this area. Gas discovered in Hyland Bay formation reservoirs of the Petrel and Tern accumulations is likely to have been generated from the Fossil Head formation. Hydrocarbon migration is likely to have followed pathways from Petrel sub-basin kitchens updip into fault terraces flanking the Darwin shelf and onto the shelf itself.

Regionally in the Bonaparte basin, rich oil-prone facies of Upper Jurassic and Lower Cretaceous source rocks have been identified within the Nancar trough, Sahul syncline, Laminaria-Flamingo high, Flamingo syncline, and in the deepest part of the Malita graben (Fig. 1). Source quality tends to increase to the southwest in the Malita graben.

These Mesozoic source rocks are at present within the high-thermal end of the oil generation window. Oil generation and expulsion would have started in the latest Cretaceous or earliest Tertiary and reached a maximum during the late Tertiary. At present, some gas expulsion is also taken place in the deepest part of the Malita graben. Thus Darwin shelf traps may have been charged with oil and gas from northwest.

The Mt. Goodwin formation provides Hyland Bay formation reservoirs with the most important regional seal in the Petrel sub-basin. The Frigate shale of the Flamingo Group is the key seal for Plover, Elang, and Laminaria formation reservoirs in a host of major oil or gas discoveries in the Mesozoic province of the Timor Sea. The Darwin formation of the Bathurst Island Group and Tertiary calcareous mudstones retain potential to provide effective seal.

Sedimentary onlaps onto the Darwin shelf offer the chance of stratigraphic closures, and both Newby-1 and Flat Top-1 were drilled in the pursuit of such traps. Scant seismic survey coverage over this large area has left plenty of room for further exploration opportunities.

Definition of stratigraphic pinchout plays relies on high-quality seismic data. Since Newby-1 and Flat Top-1 were drilled in 1969 and 1970, the principle of sequence stratigraphy has evolved in conjunction with significant improvements on seismic data quality. These should enable new explorers to identify valid stratigraphic pinch-out plays in the fringe of the Darwin shelf.

Additionally, potential reservoir sandstones may be developed at and below the base of the regionally sealing Darwin formation of the Bathurst Island Group and be draped over basement topography.

Both Gull-1 and Curlew-1 were drilled unsuccessfully near NT97-2 and 3 on the crest of large-scale salt diapirs. Domal closures above these diapirs may have become leaky through faults, the growth of which was induced by diapirism. However, these same diapirs may still offer wedge-shaped overhanging traps sealed by the salt itself. Such traps may extend into the gazettal areas.

Salt flow towards diapirs has also created four-way dip closures around their fringes. These closures are expected to comprise sandstones of the Hyland Bay formation sealed by shales of the Mt. Goodwin formation. Potential traps are likely to have formed as a result of salt withdrawal towards the nearby diapirs. This type of play has been proven at the Petrel and Tern gas accumulations.

The Author