Petroleum Geological Summary

Petroleum geological summary

Release areaS W12-1, W12-2 AND NT12-3
PETREL Sub-Basin, BONAPARTE basin, western Australia and Northern Territory

HIGHLIGHTS

· Paleozoic gas and oil province

· Shallow water depths 10–125 m

· Adjacent to the Petrel, Tern, Frigate and Blacktip gas fields and Blacktip pipeline

· Proven plays in anticlines, tilted fault blocks and structural/stratigraphic traps

· Proven oil and gas-prone Paleozoic petroleum systems

Release Areas W12-1, W12-2 and NT12-3 are located in the Joseph Bonaparte Gulf, in the vicinity of the Petrel, Tern, Frigate and Blacktip gas fields; the latter commenced production via the Blacktip pipeline in 2009.

The Petrel Sub-basin in the southern Bonaparte Basin was formed during Paleozoic NE–SW extension and contains a thick succession of Paleozoic and Mesozoic sediments. Proven Permian petroleum systems in the region have charged the numerous gas accumulations. There is an oil- and gas-prone early Carboniferous petroleum system, with Bonaparte Formation (Langfield Group) source rocks, in the inboard part of the sub-basin. The Release Areas offer a range of play types including early generated structures such as horst blocks and rotated fault blocks as well as inversion-related anticlines. Stratigraphic traps are represented by pinch-outs and truncations across unconformities. Infrastructure in the region is expanding and will facilitate development of any new discovery.

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Location

Release areas W12-1, W12-2 and NT12-3 are located in the shallow water of the Joseph Bonaparte Gulf, between 7 km and 110 km off the coast of northwestern Australia (Figure 1). The Release Areas are located adjacent to current offshore petroleum exploration permits and overlie the offshore Petrel Sub-basin, a Paleozoic depocentre of the Bonaparte Basin. The Release Areas are in proximity to the Petrel, Tern, Frigate and Blacktip gas fields. The exploration wells Lacrosse 1 (1969), Cambridge 1 (1984), Matilda 1 (1985), Sandbar 1 (2001), Weasel 1 (2003) and Windjana 1 (2009) are located within Release Area W12-2. Release Areas W12-1 and NT12-3 do not contain any wells. Water depths range from about 10 m to 125 m.

Release Area W12-1 consists of 79 graticular blocks covering 6,208 km2. Release Area W12-2 consists of 62 graticular blocks covering 4,084 km2, whilst Release Area NT12-3 comprises 51 graticular blocks covering 4,070 km2. The graticular block maps and graticular block listings for the Release Areas are shown in Figure 2.

Gas from the Blacktip gas field is piped to Darwin via the onshore plant near Wadeye and the Bonaparte trans-territory pipeline. This pipeline connects to an existing pipeline transporting gas from the Amadeus Basin to Darwin. The gas export pipeline from the producing Blacktip gas field passes through Release Area W12-2. Gas production facilities are being developed for the Ichthys gas field and a final investment decision (FID) was announced on the 13 January 2012 (Inpex, 2012). The facilities will include the construction of a gas export pipeline from the Ichthys gas field to onshore facilities at Blaydin Point near Darwin in the Northern Territory (Inpex, 2011). The proposed Ichthys gas export pipeline may pass through the Release Areas W12-1 and NT12-3.

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Release Area Geology

The Petrel Sub-basin is located in northwestern Australia, with most of the sub-basin occurring offshore in the Joseph Bonaparte Gulf, where water depths are typically less than 100 m (Figure 1). The southernmost part of the sub-basin extends onshore in the area lying between the Ord and Victoria rivers. The Northern Territory/Western Australia boundary trends northwest along the axis of the sub-basin.

Local tectonic setting

The tectonic and stratigraphic development of the Petrel Sub-basin has been discussed in detail by Gunn (1988), Lee and Gunn (1988), Mory (1988, 1991), Gunn and Ly (1989), Petroconsultants Australasia Pty Ltd (1990), BRS (1994), McConachie et al (1996) and Colwell and Kennard (1996). It has been most recently summarised by Kennard et al (2002), and Cadman and Temple (2004). Details of the onshore part of the sub-basin are discussed by Mory and Beere (1988).

The Petrel Sub-basin is an asymmetric, northwest-trending Paleozoic rift (Figure 3) that contains a succession of thick Paleozoic and thinner Mesozoic sediments (Figure 4 and Figure 5). The eastern and western faulted margins of the sub-basin converge onshore to form the southern termination. To the south and east of the Petrel Sub-basin, extensions of the Halls Creek-Fitzmaurice Mobile Zone separate this sub-basin from Precambrian terranes. Extensive basement shelves are overlain by a thin cover of Phanerozoic sediments and are developed on the eastern, western and southern margins of the Petrel Sub-basin. To the east, the Kulshill Terrace and Moyle Platform extend to the north-northeast into the Darwin Shelf. In the southwest, the Berkley Platform extends to the southeast into the Cambridge and Turtle-Barnett highs, where it is flanked by the Lacrosse Terrace (Figure 3).

Structurally, the Petrel Sub-basin consists of a broad northwest-trending syncline that plunges to the northwest, resulting in exposure of lower Paleozoic sediments in the southern onshore area, and in the progressive subcropping of upper Paleozoic, Mesozoic and Cenozoic sediments offshore. The upper Paleozoic–Mesozoic succession exceeds 15,000 m in thickness in the central and northern Petrel Sub-basin.

Regional seismic lines through Release Areas NT12-3 and W12-1 in the Petrel Deep are shown in Figure 6 and Figure 7, respectively, with the interpreted seismic horizons being shown in Figure 4 and Figure 5. Industry seismic lines through Release Area W12-2 in the inboard Petrel Sub-basin are shown in Figure 8.

Structural evolution and depositional history of the area

Late Givetian/Frasnian to Tournaisian upper-crustal extension produced a series of rift-related structures, particularly in the south and southwest of the basin (Gunn, 1988; O’Brien et al, 1993; Colwell and Kennard, 1996). These structures lie to the southwest of the axis of the main Visean basin ‘sag’ known as the Petrel Deep (Figure 3), indicating a possible partitioning between the mechanisms that controlled upper-crustal extension and the subsequent sag-dominated phase of the basin’s tectonic evolution (Baxter, 1996).

The rift-related extensional structures are bounded by major normal faults (and/or fault systems) and include planated basement platforms (e.g. Berkley Platform and Moyle Platform), horst blocks (e.g. Cambridge High and Turtle-Barnett High), rotated fault-blocks (e.g. Lacrosse Terrace and Kulshill Terrace) and graben (e.g. Cambridge Trough and Keep Inlet Sub-basin).

The basin continued to receive sediment during post-rift subsidence that occurred throughout the Carboniferous, Permian and Triassic. These sediments contain the source rocks, reservoirs and seals for the majority of hydrocarbon accumulations found within the central Petrel Sub-basin. The Fitzroy Movement, a compressional event during the Late Triassic to Early Jurassic, resulted in widespread reactivation, folding and inversion of many earlier extensional faults, and is associated with salt mobilisation. This phase of deformation was responsible for creating many traps within the sub-basin, including the anticlinal structures that host the Petrel and Tern gas fields. During this event, the onshore portion of the sub-basin was uplifted and eroded, resulting in the rapid thickening of the sediments from the south to the north.

The stratigraphy of the Petrel Sub-basin has been compiled from Beere and Mory (1986), Mory and Beere (1988), Mory (1991), Gorter (1998) and Gorter et al (1998). The stratigraphy shown in Figure 4 and Figure 5 is from Nicoll et al (2009), which has been calibrated to the geological timescale of Gradstein et al (2004) and Ogg et al (2008), and revised to incorporate the most recent stratigraphic definitions by Gorter et al (2004, 2005, 2008, 2009). Due to the complexity of the revised Petrel Sub-basin stratigraphy, Figure 5 shows the relationships of the Devonian to Triassic subgroups and formations in greater detail.

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Exploration History

In 1839, the crew of HMS Beagle found bitumen in water wells sunk on the banks of the Victoria River in the southern Petrel Sub-basin. This is one of the earliest oil shows documented in Australia. Initial petroleum exploration began in the early 1950s and resulted in seismic, aeromagnetic and gravity surveys being undertaken by the Bureau of Mineral Resources (BMR) in 1956. The first well to be drilled in the Bonaparte Basin was the onshore stratigraphic well Spirit Hill 1, which was spudded in 1959 by Westralian Oil Limited. It penetrated Carboniferous to Upper Devonian sediments in which oil indications were recorded. This well was followed in 1964 by the onshore gas discovery at Bonaparte 2 by Alliance Oil Development Australia where gas flowed from reservoirs within the Mississippian Kingfisher Shale to Milligans Formation. Keep River 1, drilled by Australian Aquitaine Petroleum Pty Ltd in 1969, also flowed gas from the Milligans Formation. Other wells drilled by Australian Aquitaine Petroleum Pty Ltd in 1966 were Kulshill 1 and 2 which recorded oil shows, and Moyle 1, which was plugged and abandoned without encountering any hydrocarbons.

Some of the earliest offshore geological and geophysical surveys were undertaken by the Scripps Institute of Oceanography and the BMR, and included sea bottom echo profiling and sampling (van Andell and Veevers, 1967). Offshore exploration was conducted by several consortia, including the Arco Australia Ltd (Arco) led joint venture, which drilled the first offshore well, Lacrosse 1, in 1969. Arco then went on to drill Petrel 1, 1A.and 2, Gull 1, Tern 1, Sandpiper 1, Pelican Island 1 and Penguin 1 throughout the early 1970s, resulting in the discovery of gas at Petrel, Tern and Penguin. Arco’s later drilling of Curlew 1 (1975) and Frigate 1 (1978) was not able to maintain their earlier successes. Also during the 1970s, Australian Aquitaine Petroleum Pty Ltd (Australian Aquitaine) was actively drilling in the offshore Petrel Sub-basin; however, none of their wells (Newby 1, Flat Top 1, Bougainville 1 and Kinmore 1) resulted in discoveries.

Australian Aquitaine continued to drill exploration wells in both the onshore and offshore Petrel Sub-basin throughout the early 1980s, as well as appraising the Petrel and Tern accumulations. However, it was Western Mining Corporation Limited that discovered the small oil accumulation in Turtle 1 (1984) in the southern, offshore part of the sub-basin. Petroleum-bearing reservoirs were found in numerous Carboniferous and Permian formations. The Barnett oil accumulation was discovered in 1989 with the drilling of Barnett 2 by Elf Aquitaine Exploration Australia Pty Ltd. Onshore, gas was discovered by Santos Ltd in the Garimala 1 well drilled in 1988.

In the early 1990s, appraisal of the offshore Petrel and Tern accumulations continued, as did the appraisal of the onshore Weaber gas accumulation, first discovered in 1982 by Australian Aquitaine. Of the eight offshore exploration wells drilled at this time, only Fishburn 1, drilled by BHP Petroleum Pty Ltd, was successful in making another gas discovery. Of the four wells drilled onshore in the 1990s, Waggon Creek 1 and Vienta 1 were gas discoveries made by Amity Oil NL.

Since the gas discovery at Blacktip 1 (2001) by Woodside Energy Ltd, eight exploration wells have been drilled. These include Sandbar 1 (2001), Shakespeare 1 (2003), Weasel 1 (2003), Blacktip North 1 (2006), Sidestep 1 (2008), Windjana 1 (2009), Marina 1 (2007) and Frigate Deep 1 (2008). Only the last two were discoveries: Marina 1 was drilled in October 2007 by Drillsearch Energy Limited and reported as a gas discovery (Department of Mines and Petroleum, Petroleum Division, 2009b); Frigate Deep 1 was drilled in August 2008 by Santos Ltd and reported as a gas discovery (Department of Mines and Petroleum, Petroleum Division, 2009a) with gas being hosted in the Tern and Mount Goodwin formations (Mount Goodwin Subgroup) (Santos Limited, 2008).

Two appraisal wells have been drilled since 2001, Polkadot 1 (2004), an extension to the Penguin 1 gas discovery, and Petrel 7 (2011). Onshore, production testing is being carried out at Waggon Creek 1 and Vienta 1 by Advent Energy (2011).

The Eni Australia B.V. owned Blacktip gas-condensate field is the only accumulation that has been commercialised in the Petrel Sub-basin and is delivering gas to the Northern Territory’s Power Water Corporation in Darwin for power generation (Department of Mines and Petroleum, Petroleum Division, 2011). GDF Suez and Santos are continuing to develop the Petrel, Tern and Frigate gas fields, which have a gross contingent resource of 2.1 Tcf gas (Santos, 2009b). The Bonaparte LNG project plans to develop a floating liquefied natural gas (FLNG) facility (Santos, 2009a) and entered pre-Front End Engineering and Design (pre-FEED) in January 2011 (Santos, 2011).

Under the 2010 Offshore Petroleum Exploration Acreage Release, exploration permits adjacent to Release Area W12-1 were awarded to MEO Australia Limited in July 2011 (WA-454-P released as W10-2; Minister for Resources and Energy, 2011b) and Santos in November 2011 (WA-459-P released as W10-1; Minister for Resources and Energy, 2011a).

Well control

Release Areas W12-1 and NT12-3 do not contain any wells. However, the Petrel, Tern and Frigate gas fields are in proximity to these Release Areas. The Fishburn 1 (1992) gas discovery is located immediately to the west of Release Area W12-1. Sandpiper 1 (1971) was drilled to the southwest of Release Area W12-1 and Flat Top 1 (1970) was drilled to the northeast of Release Area NT12-3.

Release Area W12-2 contains the explorations wells Lacrosse 1 (1969), Cambridge 1 (1984), Matilda 1 (1985), Sandbar 1 (2001), Weasel 1 (2003) and Windjana 1 (2009), with the Blacktip gas field and Blacktip North 1 (2006) being located immediately to the north. The Turtle and Barnett oil accumulations and Cape Ford 1 (1997) are located to the east of Release Area W12-2. Pelican Island 1 (1972) and Kingfisher 1 (1994) were drilled to the south and southeast of Release Area W12-2, respectively.

Lacrosse 1 (1969)

Lacrosse 1, drilled by Arco Limited (1969) on the Lacrosse Terrace in the Petrel Sub-basin, was the first well to be drilled in the offshore Bonaparte Basin. The well, drilled in 32 m of water, was designed to evaluate the hydrocarbon potential of the Lacrosse Structure and identify the major seismic reflectors mapped over the Lacrosse Terrace. Although the well was drilled 'on-structure', it was considered a stratigraphic test. It targeted Permian and Carboniferous reservoirs in a dip-rollover feature on the up-thrown side of a bounding fault.

The well penetrated Permian and Carboniferous sediments and terminated at a TD of 3,054 mKB within the Medusa Beds [reinterpreted as the Tanmurra Formation]. Two cores taken over the depth range 1,742.5–1,758.7 mKB [lower Treachery Formation to upper Kuriyippi Formation] were partially saturated with residual dark-brown oil with an estimated API gravity of 15–20°. The reservoir units have porosities of up to 26% and permeabilities of up to 514 mD. However, DST 1 (1,717–1,759 mKB) failed to recover hydrocarbons, probably because of the poor lateral permeability exhibited by the lenticular reservoir sandstones.