Petroleum Geological Summary s2

Petroleum geological summary

Release areas W12-8 and W12-9
Barrow Sub-basin and Exmouth Sub-Basin, northern Carnarvon basin, Western Australia

HIGHLIGHTS

•  Adjacent to Australia’s major new oil producing province

•  Shallow water depths 50–600m

•  Active exploration and production area with established infrastructure in close proximity

•  Three proven petroleum systems; Triassic fault block and Barrow Group plays

Release Area W12-8 is located in the Barrow and Exmouth sub-basins, and Release Area W12-9 is located in the Barrow Sub-basin. These two southernmost sub-basins are part of a series of Jurassic depocentres that form the Northern Carnarvon Basin.

The petroliferous Barrow Sub-basin is located in shallow water within Australia’s premier hydrocarbon province. The sub-basin comprises a major Jurassic depocentre bordered to the west by the Rankin Platform and Alpha Arch and, to the east, by the Barrow Island Anticline. The highly productive Locker/Mungaroo-Mungaroo/Barrow petroleum system and Dingo-Barrow petroleum system continue to be successfully tested.

The Exmouth Sub-basin is the southernmost in a series of Jurassic depocentres that form the Northern Carnarvon Basin. Oil production commenced in the Exmouth Sub-basin in 2006 and since 1993, numerous oil and gas accumulations of the productive Dingo-Barrow petroleum system have been discovered.

Both sub-basins offer a wide range of play types, including tilted fault blocks, en-echelon and rollover anticlines, rollover anticlines associated with antithetic faults, stratigraphic traps, pinchouts and onlap plays. Modern data-sets, including open file seismic, support ongoing exploration activity.

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LOcation

Release Area W12-8 is located predominantly in the northern Exmouth Sub-basin, approximately 75–110km offshore from Onslow (Figure1). The southeastern portion of this Release Area extends onto the Alpha Arch in the southwestern Barrow Sub-basin. Water depths vary from 100–800m. There are 23 graticular blocks within Release Area W12-8, with a total area of approximately 1,837km2 (Figure2).

Release Area W12-9 is located within the southwestern part of the Barrow Sub-basin, approximately 45–60km offshore from Onslow (Figure1). The Release Area is in water depths that range between 50–150m. There are 13 graticular blocks within Release Area W12-9, with a total area of approximately 607km2 (Figure2).

Both Release Areas are located close to numerous oil and gas fields that include: the Van Gogh development—part of the greater Vincent oil field (Gascoyne Development Commission, 2010); the Macedon gas field, planned for domestic gas production from 2013; the Chinook/Scindian oil and gas field; and the Corowa and Griffin oil fields (Figure1).

Release Area Geology

The geological evolution of the Northern Carnarvon Basin, and Exmouth and Barrow sub-basins, has been described in detail by many authors, and the summary presented below is derived from the work of Veevers (1988), Hocking (1990), Arditto (1993), Jablonski (1997), Tindale et al (1998), Bussell et al (2001), Norvick (2002), Longley et al (2002), Hearty et al (2002), Smith et al (2003), Scibiorski et al (2005) and Bailey et al (2006).

Local tectonic setting

The Exmouth Sub-basin is separated from the Barrow Sub-basin by the north–south-trending Triassic high of the Alpha Arch (Figure3). The Exmouth Sub-basin is bounded by the Exmouth Plateau to the north and west. To the east and south, the sub-basin is bounded by the Alpha Arch and the Southern Carnarvon Basin, respectively. The Barrow Sub-basin is bounded by the Dampier and Exmouth sub-basins to the east and west, respectively; and the Rankin Platform and Peedamullah Shelf to the north and south, respectively.

Structural evolution and depositional history of the area

The Exmouth and Barrow sub-basins, along with the Dampier and Beagle sub-basins, formed as a series of northeast–southwest-trending, en-echelon structural depressions during the Pliensbachian to Oxfordian (Tindale et al, 1998; Smith et al, 2003; Scibiorski et al, 2005). These Jurassic depocentres developed during the early syn-rift phase of the Northern Carnarvon Basin and contain thick successions of oil-prone sediments.

Pre-rift sequences in both the Exmouth and Barrow sub-basins consist of Permian and Lower to Middle Triassic sediments that are gas-prone. The extensive Locker Shale was deposited during a widespread Early Triassic marine transgression and is overlain by the thick, prograding, fluvio-deltaic Mungaroo Formation (Figure4, Figure5 and Figure6).

Middle Jurassic rifting between Australia and Greater India opened a narrow basin allowing for the intermittently restricted to open marine Dingo Claystone to be deposited during the Late Jurassic across the Exmouth, Barrow and Dampier sub-basins (Figure4 and Figure5). The Dingo Claystone is the main oil-prone source rock for the region. Further episodic movement during the Late Jurassic resulted in reactivation of older extensional faults, block faulting and erosion. Eroded material provided coarser grained clastics, within the deep-water setting, and formed the reservoir units of the Biggada and Dupuy formations; primarily seen in the Barrow Sub-basin (Figure5 and Figure6).

Rift related uplift of the Cape Range Fracture Zone, south of the Exmouth Sub-basin, provided a sediment source for the progradational Barrow Group delta. Progradation of this delta continued northward over the Exmouth Sub-basin and Exmouth Plateau. By the mid-Berriasian the Barrow Group delta had covered the Alpha Arch and by the Valanginian it had prograded across the Barrow Sub-basin as far south as the southern edge of the Gorgon field. Within the Northern Carnarvon Basin, the Barrow Group is a coarsening upward sequence, comprising two seismic stratigraphic units: the Malouet Formation (delta bottomsets) and the Flacourt Formation (delta topsets and foresets). Barrow Group sediments have excellent reservoir properties, with northeast–southwest-trending syn-sedimentary faults providing localised stratigraphic and structural traps.

Continued separation of Greater India and Australia in the Valanginian (Veevers, 1988) is correlated with major structural inversion of the Ningaloo Arch, with associated erosion of the Barrow Group and older Jurassic sediments across much of the Exmouth and Barrow sub-basins (Figure3 andFigure7; Tindale et al, 1998). The delta sediments were reworked and redeposited in the parasitic deltaic wedges of the Birdrong Sandstone in the Exmouth and Barrow sub-basins, and the Zeepaard Formation in the Exmouth Sub-basin (Figure4 and Figure5: Arditto, 1993; Tindale et al, 1998). This event is associated with the development of structural dip to the north by tilting of the east–west-trending Ningaloo Arch to the south. This resulted in the formation of complex trapping architecture within the late Berriasian arch that extends in a north-northeast direction across the western edge of the sub-basin (e.g., Eskdale structure).

A marine transgression during the Hauterivian marked the beginning of thermal relaxation during the post-rift stage, and resulted in the deposition of the Muderong Shale; the regional top seal for most fields of the Northern Carnarvon Basin (Figure4 and Figure5). South of Release Area W12-8 this formation thins as it onlaps the Ningaloo Arch, which was a positive feature at the time of deposition (Tindale et al, 1998).

In the Barrow Sub-basin, the porous Windalia Sand Member overlies the Muderong Shale (Figure5 and Figure6) and is the main reservoir of the Barrow Island oil field. However, its low permeability elsewhere in the sub-basin makes it unsuitable as a reservoir. Both in the Exmouth and Barrow sub-basins the Muderong Shale is overlain by the Windalia Radiolarite, a porous but low permeability thief zone. Above the radiolarite, the lower Gearle Siltstone, consisting of a thick sequence of Albian to mid-Cenomanian claystones and siltstones, was deposited in an outer-shelf environment and is considered to be an effective top seal for accumulations in the both the Barrow and Exmouth sub-basins, such as in the Pyrenees/Macedon field (Figure1 and Figure7: Bailey et al, 2006).

Basin inversion and uplift of the Exmouth Sub-basin in the Late Cretaceous formed the Novara Arch and the Resolution Arch (Figure3) and effectively shut off the Jurassic source kitchen. Uplift began in the early Santonian which overprinted and reactivated previously formed structures (Tindale et al, 1998). In the Barrow Sub-basin, this inversion resulted in numerous structural closures; including the Rankin Trend, John Brookes, Spar, Alpha Arch, Woollybutt South Lobe, and Barrow Island, which were ideally placed for oil charge after the Barrow Group deposition.

From the Late Cretaceous to the Holocene, fine grain siliciclastic deposition gave way to marls and calcilutites (Figure4 and Figure5). This change was largely governed by the marine, passive margin environment, as well as climatic change and peneplanation of the clastic source area. The Cenozoic succession comprises a thick wedge of prograding marine carbonates deposited during various transgressive and regressive stages.

The final stage of tectonism is recorded in the middle to late Miocene, when the Australian-Indian plate collided with the Eurasian plate. In the Exmouth Sub-basin this last event saw gross tilting of the margin to the west due to progradation of a thick Paleogene–Neogene carbonate wedge and fault reactivation. At this time, a new phase of compression enhanced the Pyrenees/Macedon structure and it is interpreted to have tilted many structures to the south and west, as well as modifying existing hydrocarbon accumulations (Tindale et al, 1998). In the Barrow Sub-basin, this collision event enhanced pre-existing structures, such as the Woollybutt South Lobe, Spar, John Brookes and the Barrow Island Trend, and created new structures, including the Woollybutt North Lobe and East Spar (Hearty et al, 2002).

Exploration History

Exploration in the region around the Release Areas has been episodic over the last 35 years. The Exmouth Sub-basin, along with the Barrow Sub-basin, received some interest during the first phase of West Australian Petroleum Pty Ltd’s (WAPET) ‘island and shallow water drilling program’ in the 1960s and early 1970s (Mitchelmore and Smith, 1994). In 1972, the first gas shows were recorded in the Exmouth Sub-basin when WestMuiron1 was drilled on the feature which was later to be recognised as hosting the Pyrenees/Macedon gas and oil accumulations. This was the first indication that the Exmouth Sub-basin was petroliferous. Exploration, however, was largely focused on other regions of the Northern Carnarvon Basin, namely the Barrow and Dampier sub-basins, where giant discoveries like the billion barrels (1.59 × 108kL) of oil-in-place at Barrow Island in 1964 and multi-Tcf (>5 × 1010m3) gas fields on the Rankin Platform in 1972. Also in 1972, gas discoveries were made in Triassic sandstones at WestTryalRocks1 and later in Lower Cretaceous sandstones in Spar1 (1976) in the Barrow Sub-basin. It was not until 1983 that the first commercial discovery of oil was made in the offshore part of the Barrow Sub-basin in the SouthPepper1 well (Baillie and Jacobson, 1997).

During the late 1970s and early 1980s exploration concentrated on deep-water drilling of the Exmouth Plateau. Initially these drilling programs were conducted by Esso and Phillips (Barber, 1988) and led to the giant gas discovery at Scarborough (Walker, 2007).

With the permit sizes and prospect volumes within the permits decreasing, the 1980s saw the general offshore exploration focus in Australia shift inboard. In the shallower water sections of the Exmouth Sub-basin, Jurabi1 was drilled by Esso Australia Ltd in 1982 as another test of the West Muiron structure. However, the test failed and it was not until the 1990s that a significant hydrocarbon column was intersected on this structure (Mitchelmore and Smith, 1994). The early 1990s also saw a significant Cenozoic gas discovery in the Barrow Sub-basin in Maitland1 (1992), near the base Paleocene sand play previously recognised on 1985 2Dseismic data as an amplitude anomaly (Sit et al, 1994).

Following the oil discovery at Vincent1 in 1998, eight deep-water wells were drilled in the southern Exmouth Sub-basin between 1999 and 2004. The discovery of the Enfield oil field in 1999 was followed by the Laverda and Scafell oil discoveries in 2000 and numerous other successes throughout 2003–2007, including Bleaberry West, Eskdale, Crosby/Harrison/Ravensworth/Stickle, Langdale, Skiddaw and Stybarrow, that increased interest in the Exmouth Sub-basin. These discoveries formed a new oil province. The drilling program was successful, due to the extensive quantitative interpretation of 3Dseismic data (Walker, 2007). Combined initial production of major fields, including Enfield, Vincent, Pyrenees, Stybarrow and Laverda, indicates the province contains more than 300MMbbl (48GL) of heavy crude reserves (Department of Mines and Petroleum, Petroleum and Royalties Division, 2008). Production is estimated to reach 250,000bbl/d (40,000kL/d) (Department of Mines and Petroleum, Petroleum and Royalties Division, 2008). Other projects that commenced in 2010 include the Van Gogh oil field, which started production in February, and the Pyrenees project (comprising Crosby, Harrison, Ravensworth and Stickle oil fields) which started production in March (Department of Mines and Petroleum, Petroleum Division, 2010). The last two years has seen a continued interest in and around the Exmouth Sub-basin with Sappho1 (2010) encountering gas with 75m of pay interpreted from logs; Zola1ST1 (2010–2011) discovering approximately 125m of net gas pay in several sandstones and confirmed as a significant discovery in the Mungaroo Formation; and Cimatti1 and2 intersecting a gross oil column of 15m, and a 7m thick oil bearing sandstone in close tie-back distance to Enfield (Department of Mines and Petroleum, Petroleum Division, 2010, 2011a, 2011b).

The Barrow Sub-basin has been one of the most actively and continuously explored offshore area in Australia for the better part of the last 25 years. The Harriet Joint Venture made several small oil and gas discoveries in the Flag Sandstone, including the Wonnich (1995), Montgomery (2003) and Kultarr (2005) accumulations. Producing fields closer to the W12-9 Release Area include Griffin (1990), Chinook/Scindian (1989/1990) and Woollybutt (1997) to the north; Saladin (1985) to the east; and Corowa (2001) and Pyrenees/Macedon (1994) to the west.

Well control

Anchor1(1969)

Anchor1 is located approximately 43km west-northwest of Onslow in the Barrow Sub-basin. The well was drilled by WAPET to a total depth (TD) of 3,048.6m in a water depth of 18m. The primary objective was to investigate the reservoir potential of the Lower Cretaceous Barrow Group and Upper Jurassic Dupuy Formation sandstones. Structurally, the prospect area was a fault trap lying on the north (downthrown) side of the Long Island Fault System (the east–west-trending fault system south of the Blencathra, Corowa and Saladin fields). The system provides a southern closure, while the critical dip is to the east and the regional dip to the north and west.

Geophysical interpretations suggested that the Anchor prospect area provided excellent possibilities for stratigraphic traps, both sand pinch-outs and overlapped basal sand units. Cores in the top of the Barrow Group indicated the presence of sandstone units with excellent reservoir qualities with porosities ranging between 20% and 30% and permeabilities of 1–9D. Sonic and density logs from the Dupuy Formation indicated porosities of about 25%, while permeabilities were expected to have been very low (West Australian Petroleum Pty Ltd, 1969). Although excellent reservoir sandstones were encountered, no hydrocarbon accumulations were identified. The well was subsequently plugged and abandoned.