PROMISE SEEN IN PETREL SUB-BASIN OFF NORTHWESTERN AUSTRALIA

Tun U. Maung, Virginia Passmore
Bureau of Resource Sciences
Parkes, ACT, Australia

The Australian government during the past 11 years has been regularly releasing vacant areas on the Australian continental shelf for exploration. Although Australia's offshore basins cover an area of 12 million sq km, only about 1,100 exploration and development wells have been drilled, and most of the basins are underexplored by world standards. One of these areas is the Petrel sub-basin of the Bonaparte basin in water shallower than 100 m off Northwest Australia.

The government recently released six areas in the southern offshore Petrel subbasin for petroleum exploration in Release 2 of 1994 (Fig. 1) (12869 bytes). The blocks are large, ranging from 3,520 sq km to 7,920 sq km, and contain or are adjacent to discoveries or encouraging shows.

The Petrel and Tern gas accumulations and Barnett and Turtle oil discoveries are located in the offshore area of the Petrel sub-basin. The offshore Lesueur-1, Penguin-1, and Fishburn wells also have encountered gas bearing reservoirs, as have the onshore Bonaparte-2, Garimala-1, Keep River-1, Weaber-1, and Weaber-2A wells (Fig. 1) (12869 bytes). These discoveries demonstrate that Petroleum generation and migration has occurred in the Petrel sub-basin.

Except for the Turtle oil discovery, which is located in Permit WA-128P (Fig. 1) (12869 bytes), and the Petrel and Tern gas accumulations and Fishburn gas discovery, which lie immediately north of the release areas, the remaining discoveries in the offshore Petrel sub-basin lie within the six release areas.

The results of a study by the Petroleum Resources Branch of the Bureau of Resource Sciences have been synthesized into a Petrel Sub-basin Bulletin, some selections of which are discussed in this article. Although there are over 44,000 km of seismic data recorded in the sub-basin, the quality of pre-1979 data is very poor to poor, and only 15,800 km of data recorded between 1980-94 (including 1,000 km of 3D seismic data over the Barnett structure) are of fair to good quality.

REGIONAL GEOLOGY, SETTING

The Petrel sub-basin is a Paleozoic rift in the eastern part of the Bonaparte basin, the most northern basin on Australia's Northwest Shelf. The sub-basin straddles the Western Australia-Northern Territory state boundary, extending from the onshore northern edge of the continent to the Zone of Cooperation with Indonesia, with most of the sub-basin underlying the Joseph Bonaparte Gulf and Timor Sea. It has a northwest axial orientation and a length of approximately 600 km, and broadens in width from approximately 80 km in the south to over 250 km in the north at the northeasterly trending Malita graben (Fig. 1) (12869 bytes).

The Petrel sub-basin evolved from an initial rift which began in the Devonian and ended in the Carboniferous; the rift appears to have developed in a Cambrian intracratonic depression associated with extensive volcanics. Whereas the primary rifting direction was to the northeast, an element of northwesterly extension also occurred, thus the rift had a transtensional component and was not purely extensional. Basin development since the Carboniferous has been dominated by thermal and sediment-load induced subsidence relating to both the initial rift and subsequent rift phases to the north in the Bonaparte basin. Fig. 2 (9823 bytes) shows the half graben development of the subbasin.

The developing rift became a major depocentre of the Bonaparte basin. Between the Late Devonian and the Middle Triassic, 12,000 m of synrift and postrift sediments were deposited in the Petrel area, as shown in red on Fig. 3 (19533 bytes). Up to 6,000 m of Devonian and Carboniferous dominantly clastic sediments were deposited during the synrift phase of the sub-basin.

Significant salt tectonism was also initiated during this period resulting in upward movement of underlying Silurian age halite deposits and the development of numerous salt structures such as the salt diapir on Fig. 2 (9305 bytes).

After the Late Carboniferous, an additional 6,000 m (Kulshill and Kinmore groups) of clastics and some carbonates filled the Petrel sub-basin. The thick sediments deposited from the Late Carboniferous to the Middle Triassic were draped over the pre-existing highs, infilled the broad basin downwarp, and eventually onlapped the eastern and western flanks of the subbasin. These postrift sediments thicken to the north and towards the basin axis (Fig. 2) (9823 bytes)(Fig. 4) (7686 bytes). Some reactivation and later phase faulting occurred, particularly close to major structural features, until the end of the Permian. Structures have also been induced by renewed upward movement of salt.

Although major subsidence shifted away from the Petrel sub-basin to other areas of the Bonaparte basin in the Triassic, deposition continued in the area and the Petrel sub-basin was blanketed with up to 3,000 m of Mesozoic and Tertiary sediments. Reactivation of faulting in the Late Triassic to Early Jurassic in the Petrel sub-basin was oblique compressional. This resulted in uplift and the formation of transpressional anticlines in various parts of the subbasin.

RESERVOIR AND SEALS

Some 45 wells have been drilled in the sub-basin and immediate adjacent areas, and hydrocarbon discoveries and shows were found in many wells.

The petroleum-bearing reservoirs in the Petrel subbasin range in age from Carboniferous to Permian. The oldest reservoirs are sandstones of the Langfield group and the youngest reservoirs are sandstones of Hyland Bay formation. Fig. 4 (7686 bytes) indicates that the older formations plunge to the north and the younger formations are absent in the south.

. The main regional seals in the Petrel sub-basin are the shales of the Mount Goodwin and Fossil Head formations which seal the Hyland Bay and Keyling formation reservoirs, and the Treachery shale above which seals Kuriyippi formation reservoirs. Tanmurra formation shales and limestones may act as seals for Upper Milligans formation and Langfield group reservoirs.

The Tanmurra formation is also considered a reservoir as gas was recovered from limestones and calcareous sandstones of this formation in the Lesueur-1 well.

A study of porosity data from about 2,400 sets of core plugs indicates that the Hyland Bay formation retains a high porosity of 15-25% even below 3,500 m. In the Barnett Turtle area (Fig. 1) (12869 bytes) porosities of 15-20% are observed in the Kuriyippi formation at a depth of 1,500 m and a porosity of 10% is observed in the Langfield group at a depth of 2,500 m.

SOURCE ROCKS

Gas in the Petrel and Tern accumulations and in the Penguin 1 well are thought to be sourced from Permo-Carboniferous shales in the surrounding deep areas of the sub-basin. The probable period of gas generation was Middle Triassic to Late Cretaceous. The results of the Barnett-2 well indicate that oil in the Barnett-Turtle area is sourced from shales of the Milligans formation.

Vitrinite reflectance values are found to be generally low even though the Petrel sub-basin is a Paleozoic province. The oil window extends from 1,500 to 4,000 m and is much wider than those observed in most sedimentary basins in Australia.

A study of the coal maceral group and extractable organic matter indicates that exinite and saturated and aromatic hydrocarbons are more abundant in the older formations and source rock quality is therefore better in older formations.

On the other hand, the Rock-Eval analysis indicates that the younger Hyland Bay and Fossil Head formations have higher TOC contents than the older formations such as the Langfield group, Ningbing limestone and. Cockatoo group. A plot of pristane/phytane and pristane/n-C-17 ratios indicates that many source rocks were deposited in a reducing and relatively open water environments.

TRAP TYPES

The leads and structures identified in the six release areas in the Petrel sub-basin, as shown in Fig. 5 (12092 bytes), can be grouped into seven trap types. They are:

Broad anticlines such as the Petrel, Tern, and Penguin structures and leads WA/5-A, WA/5-C, and WA/7-B.
Faulted anticlines such as the Barnett and Turtle structures and leads WA/6B, NT/3-A, and NT/4-A.
Salt diapirs, either (1) piercing as in the case of the Kinmore structure and leads NT/3-G and NT/4-B, or (2) not piercing as in the case of the Bougainville structure and leads WA/6-A.
Fault traps such as the Lesueur structure and leads WA/5 B, WA/6-C, WA/7A, NT/3-B, NT/3-C, NT/3D, and NT/4-C.
Draping of Paleozoic sediments over basement and pre Tanmurra formation horst blocks such as the Stilt structure.
Three-way dip closure with erosional truncation on the fourth side such as the Crocodile and Cape Scott structures.
Stratigraphic traps such as pinchouts at the Turtle mid-basin highs or Turtle south highs, salt-wall-flank thinning, mound and turbidite plays, and time transgressive reefal plays such as the Tanmurra reef play.

Salt movement ranges from Late Devonian/Early Carboniferous to Tertiary and the timing of salt movement is a key element in exploring for petroleum. The structures and leads in the northern release areas are generally mapped at the top or base of the Hyland Bay formation, and those in the southern release areas are generally mapped at the top of the Kuriyippi formation or Langfield group.

The most significant structures mapped are the Barnett and Barnett East structures (Fig. 5) (12092 bytes). The Barnett-2 well, drilled in 1989, recovered oil in reservoirs at the top of the Kuriyippi formation, and also a large gas flow and some oil was recovered from the deeper marine sandstones of the Langfield group. Therefore a deep Barnett-2 play is possible as Barnett-1 and Barnett-3 wells did not penetrate the Langfield group.

CONCLUSIONS

The main reservoir objectives in the Petrel sub-basin are Permian and Carboniferous sandstones of the Hyland Bay, Keyling, Kuriyippi, and Upper Milligans formations, and the Langfield group. Limestones and calcareous sandstones in the Tanmurra formation also have reservoir potential.

The large Petrel and Tern gas accumulations and the gas reservoir sands in the Penguin-1 well occur in the Hyland Bay formation, while the Barnett and Turtle oil discoveries are reservoired in the Kuriyippi formations. Gas was recovered from Tanmurra formation and Langfield group in the Lesueur-I well. Gas flows were also recorded from the Milligans formation in the onshore Bonaparte-2 and Keep River-1 wells.

Our study identified over 30 structures and leads in the offshore southern Petrel subbasin. Significant opportunities exist for delineation and definition of drillable prospects in this promising Australian petroleum province.

ACKNOWLEDGMENTS

Tony Stephenson of Bureau of Resource Sciences reviewed the article, and Brian Pashley and Mark Sands of the cartographic unit of the Australian Geological Survey Organisation drafted the figures.

BIBLIOGRAPHY

Maung, T.U., Miyazaki, S., Lavering, I.H., Passmore, Y.L., Stephenson, S., Williamson, P.E., Radke, S., and Staunton, J., Petrel sub-basin petroleum prospectivity bulletin and database, Bureau of Resource Sciences, Petroleum Prospectivity Bulletin 1994/2, AGPS, Canberra.

O'Brien, G.W., Etheridge, M.A., Willcox, J.B., Morse, M., Symonds, P., Norman, C., and Needham, D.J., The structural architecture of the Timor Sea, northwestern Australia: implications for basin development and hydrocarbon exploration, AREA Journal, Vol. 33, Nov. 1, 1993, pp. 258-278.

THE AUTHORS

Tun U. Maung is principal petroleum geophysicist in the BRS Petroleum Resources Branch. He has led several petroleum prospectivity studies of offshore basins and published geological and geophysical studies on Burma, Tonga, Solomon Islands, Fiji, and Australia. He was supervisor/chief geophysicist and general manager, offshore division, Myanmar Oil Corp. (formerly Burmah Oil Co.)

After leaving Burma, he worked as a consulting geophysiscist with Petronas in Malaysia and petroleum geologist with UNDP in Fiji. Since 1983 he has been senior/principal petroleum geophysicist with the Petroleum Branch of the former BMR. He obtained a BSc (Hons.) in geology from the University of Rangoon and BSc and MSc in geophysical engineering from Colorado School of Mines.

Virginia Passmore is a senior petroleum geologist in the BRS Petroleum Resources Branch, involved in hydrocarbon prospectivity packages that review the hydrocarbon plays and potential of the offshore basins and technical advice to goverment. She worked for Texaco Inc. as an exploration geologist in the Williston basin before moving to Australia in the 1970's.

She joined BMR and undertook geological studies and hydrocarbon assessments of a number of Australian basins, including Adavale, Bonaparte, Carpentaria, Canning, and Eromanga. She transfered to the BRS n its formation in 1992. She abtained a BSc and MSc from the University of Arizona.