Potential seen in areas off Northwest, Southeast Australia

Paul E. Williamson
Bureau of Resource Sciences
Canberra

Effective with its 1997 release of offshore acreage, Australia launched a new system of offering two groups of areas with different closing dates. In the group for which bids close in March 1998:

The Browse basin, which has supergiant gas reserves and now the major Cornea oil discovery, has the potential for more major discoveries in moderate to deep water between the petroleum kitchens and basin margin fields;
Elsewhere, shallow water, underexplored parts of the oil productive Bonaparte basin have intriguiging oil and gas shows, noncommercial discoveries, and seismic anomalies. Small and large companies, with bids guaranteed by seismic-only to multiwell work programs, were successful in gaining exploration permits from the previous bidding round.

Bidding areas

Areas with a Nov. 27, 1997, closing date in the 1997 release cover three regions in the Southwest margin (Fig. 1 [ 68,500 bytes]). In the frontier Duntroon basin, the 1993 Greenly-1 well raised exploration interest with good oil shows.

Four areas flanking the world ranked, oil and gas productive Gippsland basin bear comparison with the basin margin Cornea play on the Northwest Shelf.

The Sydney basin is immediately offshore from Australia's largest concentration of population.

The Sydney basin is expected to have a thick Permian-Triassic section which, while it may have oil potential, may attract particular interest from gas explorers given the current deregulation of Australia's gas pipeline systems.

Two regions of the Northwest Shelf also have the November 1997 bid-closing date (Fig. 2 [83,790 bytes]). The Darwin Shelf flanks gas/condensate accumulations in the Petrel sub-basin. It is additionally open to oil charge from Permian source rocks in the sub-basin and from Mesozoic sources in the Malita graben to the north.

In the Vulcan sub-basin, areas on an intra-graben horst trend and on the flanks of the graben offer a variety of opportunities in this productive oil province.

Areas with the Mar. 26, 1998, closing date for work program bids are all on the Northwest Shelf. They are in the Browse and Bonaparte basins off Western Australia and in the Territory of Ashmore and Cartier Islands Adjacent Area:

Browse basin

Areas W97-11 to 16 and Areas AC97-5 to 7 lie in the Browse basin offshore from Western Australia and in Australia's Territory of Ashmore and Cartier Islands Adjacent Area (Fig. 3 [51,881 bytes]).

After the discovery of the supergiant Scott Reef gas/ condensate accumulation on the western basin margin and lesser gas discoveries and oil shows in the center of the basin, interest has been revitalized by the oil discoveries at Gwydion and Cornea on the basin's eastern flank. Estimates of 600 million to 2.6 billion bbl of oil in place have been reported for Cornea field.

These major gas and oil fields are substantiation for Triassic to Cretaceous source rocks in the 18,000 m of sediment in the central basin having expelled very large volumes of oil and gas. Also, importantly, there has been long range migration and charge.

Gas discoveries and oil shows more centrally in the basin and the limited exploration carried out to date indicate that there is potential for petroleum charge of large traps between the central basin kitchens and the basin margin discoveries.

The areas offered cover a total of about 35,000 sq km and have been only lightly drilled. They contain 9 exploration wells in all (1978-93), 5 of which are in the northeasternmost area, AC97-5. There is fair seismic coverage, with a mixture of vintages; however, recent extensive reprocessing has enhanced data, and there is a reconnaissance grid of 8,000 line km of good quality data to 16 sec two-way time obtained by the Australian Geological Survey Organisation. Water depths range from 150 m to more than 1,100 m at the western limits.

Late Paleozoic structuring and Triassic reactivation established the main northeast oriented high trends in the Browse basin. Callovian continental breakup is marked by a regional unconformity and some additional faulting. Marine transgression followed, peaking in the Turonian.

Fluctuating Cretaceous sea levels led to shallow marine sands and fan sands being deposited with the generally finer grained clastic sequence. Thick Tertiary carbonates prograded across the mid to outer parts of the basin, interrupted by mid mid-Miocene transpressional tectonism.

Discoveries and shows have been made in Upper Triassic to Paleocene reservoirs.

At present, the main plays are identified as Permian-Triassic and Jurassic fault blocks sealed by Jurassic and Cretaceous shales, and drape over the fault blocks (Fig. 4 [126,028 bytes]). There is potential for large stratigraphic traps in Upper Jurassic and Lower Cretaceous lowstand fans, Lower Cretaceous transgressive sands, and Upper Cretaceous lowstand fans.

Bonaparte basin

Areas are offered in two parts of the basin: in the Southern Timor Sea region and in the southern Petrel sub-basin in the Joseph Bonaparte Gulf (Fig. 2).

Southern Timor Sea

In the south-central part of the Bonaparte basin, between the Vulcan sub-basin and the Sahul syncline, seven areas are offered on the Londonderry high and southwestern part of the Sahul syncline and its extensions. Water depths are about 100 m. The region lies about 400 km west of the city of Darwin, the major operations base for exploration in the region and one option being considered as the site for an LNG plant for gas from Undan-Bayu field, which lies northeast of the areas.

The Londonderry high comprises a sequence of Paleozoic to Middle Jurassic sediments eroded during the Late Jurassic and onlapped by Upper Jurassic and younger sediments (Fig. 5 [108,174 bytes]). The Londonderry high dips regionally northeast, indicating the potential for petroleum charge from the Sahul and Echo synclines as well as from the thick Paleozoic source rocks within the high. The combination of multiple periods of faulting, abundant clastic reservoirs, adjacent and internal sourcing, and regional and intraformational seals provide numerous play scenarios. The main trap types are structural, but plays include stratigraphic traps in slope turbidite deposits in the synclines and pinchouts to the south and west (Fig. 6 [140,693 bytes]).

This is a region regarded as having potential for significant gas and oil discoveries. This perception is supported by several petroleum occurrences from the limited drilling in the region to date: by oil recoveries from Late Jurassic-Early Cretaceous reservoirs in the Rambler-1 in the northernmost area and from the Upper Permian in Torrens-1 southeast of the areas; also by gas recoveries in Halcyon-1 to the northwest and a 130 m gross gas column in Ascalon-1A to the east. Several seismic anomalies identified in a recent study may also prove to be indirect evidence of petroleum.

While there has been recent exploration in the northeast, the most recent seismic in the southern areas was 1988 vintage until a new speculative survey was carried out in late 1996. Ten wells have been drilled in the approximately 17,000 sq km covered by the areas, and wells in surrounding permits provide additional control. The current interest in discoveries gas reserves for LNG development in the region and the possibility of developing even small oil discoveries with FPSOs also supports the timeliness of another round of exploration in this area.

Petrel sub-basin

Areas W97-8, 9, and 10 in the southern Petrel sub-basin contain oil plays in the Upper Paleozoic adjacent to the Turtle and Barnett oil discoveries. Large gas fields have been discovered farther north in the sub-basin, and onshore there have been smaller gas discoveries and oil shows.

Of the five wells drilled in the areas between 1969-85, Lacrosse-1 yielded 15-20° gravity residual oil, Lesueur-1 tested gas and had oil shows, and there were oil shows in Cambridge-1. Two other wells are interpreted as valid tests. Although there has been little recent exploration in the areas, quality of 1980s seismic data is generally fair to good and has been enhanced in recent speculative reprocessing.

The areas incorporate a central horst block, flanked to the south and north by thick Late Paleozoic depocenters (the Cambridge trough and Petrel Deep, respectively). Within these depocenters, oil prone Lower Carboniferous marine shales of the Milligans formation have sourced the oils found at Turtle and Barnett, and gas-prone Permian marine shales have been identified in the northern depocenter.

Reservoir facies occur in Lower Carboniferous basinal turbidite and coastal sandstones, shallow shelf carbonates, draped carbonate mounds, and Carboniferous-Permian sandstones deposited in fluvial, deltaic, and shallow marine environments. There are intraformational seals throughout the Carboniferous section, and the Permian Fossil Head and Treachery shale units have widespread seal potential at younger levels (Fig. 7 [100,329 bytes]).

Several trap types may be identified: structural traps are formed by Late Devonian extensional faulting and Triassic fault inversion; combined structural-stratigraphic traps formed by multiple movement and diapirism of Early Paleozoic salt beds; and stratigraphic traps associated with Lower Carboniferous lowstand coastal wedges and basin floor fans shed from the eroded crest of the Cambridge-Turtle-Barnett horst (Fig. 8 [108,957 bytes]).

Petroleum has been recovered from Carboniferous and Permian units, but the potentially highly prospective lowstand and mound-drape stratigraphic plays have yet to be tested.

Acknowledgments

This article was compiled in Australia's Department of Primary Industries and Energy with contributions from the Australian Bureau of Resource Sciences and the Australian Geological Survey Organisation.

Information on Australian petroleum geology and offshore acreage releases is available on:

http://www.dpie.gov.au/resources.energy/petroleum/exploration/
http://www.brs.gov.au:80/ and
http://www.agso.gov.au/marine/