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DISCLAIMER: This document has been developed as a guide only. Explorers should not rely solely on this information when making commercial decisions. Image courtesy of BHP Billiton Petroleum Pty Ltd.

OFFSHORE PETROLEUM EXPLORATION ACREAGE RELEASE | AUSTRALIA 2014

Regional Geology of the Northern Carnarvon Basin

Basin outlineThe predominantly offshore Northern Carnarvon Basin is located on Australia’s northwestern margin and covers an area of approximately 535 000 km2 (Figure 1), in water depths of up to 4500 m. As Australia’s premier hydrocarbon province, the basin contains, and has ready access to, established oil and gas production infrastructure (Figure 2). Oil and gas production areas are located in the Barrow (including Barrow, Thevenard and Varanus islands) and Dampier sub-basins plus the northern Exmouth Sub-basin, where the Macedon natural gas project started production in August 2013. Gas is also produced from the northern Rankin Platform through Australia’s first liquefied natural gas (LNG) project, the North West Shelf (NWS) Venture. Other recent developments to come to fruition are the Pluto LNG Project on the Rankin Platform/Exmouth Plateau, which commenced production in March 2012, and the Reindeer–Devil Creek Project in the Dampier Sub-basin which has produced domestic gas since December 2011. LNG developments in progress include the Gorgon, Wheatstone, Scarborough and Equus projects. The Gorgon and Wheatstone LNG projects will also produce domestic gas; the Scarborough and Equus projects are likely to announce domestic gas arrangements once a final investment decision (FID) is taken on each project. Redevelopment and expansion projects are either under construction or in planning in several areas to extend the life of existing fields and production facilities, including the redevelopment of the NWS Venture through the North Rankin Redevelopment Project and the Greater Western Flank Development. A major LNG loading terminal and processing centre is located at Karratha with new facilities under construction on Barrow Island and at Ashburton North, near Onslow.

The Northern Carnarvon Basin is close to the major settlements of Port Hedland, Karratha, Dampier, Onslow, Exmouth and Carnarvon, and the North West Coastal Highway (Figure 1). The Dampier to Bunbury Natural Gas Pipeline (DBNGP) and the Goldfields Gas Transmission Pipeline (Figure 2) provide a direct connection with the major domestic and industrial markets of southern Western Australia (Perth, Bunbury and the Goldfields). The basin is also favourably located in relation to the main export markets in Southeast and East Asia.

The Northern Carnarvon Basin is the southernmost of the late Paleozoic to Cenozoic basins that form the northwestern continental margin of Australia (Bradshaw et al, 1988). The basin is bounded to the northeast by the Roebuck and offshore Canning basins, to the southeast by the Pilbara Block, to the south by the Bernier Platform, Gascoyne Sub-basin and Merlinleigh Sub-basin of the Southern Carnarvon Basin, to the southwest by the Cuvier Abyssal Plain, and to the northwest and north by the Gascoyne and Argo abyssal plains, respectively. The sedimentary fill of the basin is up to 15 000 m thick and dominated by deltaic to marine siliciclastics and shelfal carbonates of Mesozoic to Cenozoic age.

Well locations and gravity data are shown in Figure 3 and Figure 4 respectively. The stratigraphy of the basin is shown in Figure 5 and regional seismic lines across the basin are shown in Figure 6, Figure 7 and Figure 8. Figure 9 shows the distribution of petroleum systems in the basin.

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Tectonic developmentThe Northern Carnarvon Basin evolved from a broad intracontinental basin in the late Paleozoic, through syn-rift sub-basins in the Jurassic, to a passive margin carbonate shelf in the Cenozoic. The regional geology, structural evolution and petroleum potential have been discussed by many authors, including Kopsen and McGann (1985), Boote and Kirk (1989), Hocking (1990), Stagg and Colwell (1994), Jablonski (1997), Romine et al (1997), Westphal and Aigner (1997), Driscoll and Karner (1998), Bussell et al (2001), Longley et al (2002), Barber (2013) and Tao et al (2013). In addition, comprehensive summaries of the petroleum geology are presented by Tindale et al (1998) for the Exmouth Sub-basin, Stagg et al (2004) for the Exmouth Plateau, Nishimori (1999) for the Rankin Platform, Hearty et al (2002) for the Barrow Sub-basin, Woodside Offshore Petroleum Pty Ltd (1988) and Barber (1994a) for the Dampier Sub-basin, and Blevin et al (1994) and Lech (2013) for the Beagle Sub-basin. A regional tectonostratigraphic model for the North West Shelf, including the Northern Carnarvon Basin, has recently been developed by Marshall & Lang (2013).

The offshore basin consists of three broad structural zones:

• an inboard, structurally high zone—the Lambert and Peedamullah shelves

• an intermediate zone of large depocentres comprising the Beagle, Dampier, Barrow and Exmouth sub-basins

• the extensive, marginal Exmouth Plateau and its uplifted margin, the Rankin Platform (Figure 1)

The Argo, Cuvier and Gascoyne abyssal plains bound the distal margins of the Exmouth Plateau and the Exmouth Sub-basin.

Polycyclic extension, culminating in the Jurassic to Early Cretaceous breakup of the northwest Australian continental margin, produced a dominant northeast structural trend that is apparent in the alignment of major faults and depocentres (Figure 1). A secondary north to north-northwest trend is also apparent, especially in accommodation zones and associated faults linking northeast-trending en echelon faults.

The main structural elements of the Northern Carnarvon Basin are described briefly below, with representative geologic sections through the basin shown in Figure 6, Figure 7, and Figure 8.

Beagle Sub-basinThe Beagle Sub-basin comprises a structurally complex series of fault blocks, anticlines and troughs with a general northerly trend, oblique to the regional northeast trend dominant in the other sub-basins (Figure 1). The sub-basin developed from several pre-rift, syn-rift and post-rift cycles (Lech, 2013), and lateral fault movements dominated the sub-basin’s evolution with localised areas of extension and compression (Blevin et al, 1994). The sedimentary succession attains a thickness of up to 12 000 m, and is dominated by Triassic to Middle Jurassic sediments (Figure 6). In contrast to the other sub-basins, the Upper Jurassic succession is thin or absent.

Dampier, Barrow and Exmouth sub-basinsThe Dampier, Barrow and Exmouth sub-basins are a series of large en echelon rift depocentres (Figure 1) that contain a dominantly Triassic, Jurassic and Lower Cretaceous sedimentary succession (Figure 5). Maximum sediment thickness exceeds 10 000 m in the Dampier and Exmouth sub-basins and 15 000 m in the Barrow Sub-basin (Figure 7 and Figure 8). The Barrow Delta dominates the Lower Cretaceous succession in the Exmouth and Barrow sub-basins (Tindale et al, 1998). By contrast, fine-grained marine sediments dominate the Upper Jurassic and Lower Cretaceous in the Dampier Sub-basin. The sub-basins themselves comprise a series of en echelon structural highs and troughs with an overall northeast trend formed by oblique extension (Romine et al, 1997).

The sub-basins are separated from each other by Paleozoic–Triassic fault blocks that have been modified by faulting, uplift and/or rotation: the Alpha Arch between the Exmouth and Barrow sub-basins, the Sultan Nose between the Barrow and Dampier sub-basins (Polomka and Lemon, 1996), and the De Grey Nose between the Dampier and Beagle sub-basins (Figure 1).

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The sub-basins are separated from the structurally high areas of the Rankin Platform and Exmouth Plateau to the northwest, and the Lambert and Peedamullah shelves to the east and south, by major extensional fault systems (Figure 1). The Rankin Fault System separates the Rankin Platform from the Dampier Sub-basin (Stagg and Colwell, 1994), and the Flinders and Sholl Island fault systems separate the Peedamullah and Lambert shelves from the Barrow and Dampier sub-basins (Kopsen and McGann, 1985). Broad marginal terraces, overlain by mainly Triassic to Cenozoic sediments, have formed over down-faulted or rotated blocks along these faulted margins. These include the Enderby Terrace in the Dampier Sub-basin and the Bruce and North Turtle terraces in the Beagle Sub-basin. These terraces were major Silurian–late Permian extensional depocentres that were only moderately affected by the subsequent Mesozoic rifting events, due to a general westward shift in the locus of extension (Hocking, 1990; Polomka and Lemon, 1996).

Exmouth PlateauThe Exmouth Plateau (Figure 1) is a subsided continental platform characterised by a faulted, dominantly Triassic sedimentary succession attaining a thickness of up to 15 000 m (Figure 5, Figure 7 and Figure 8). Jurassic sediments are generally thin or absent. The major elements of the plateau include the Rankin Platform, Kangaroo Syncline, Investigator Sub-basin and Wombat Plateau (Tindale et al, 1998; Stagg et al, 2004; Figure 1). The dominant structural trend varies between north and northeast, reflecting the interplay between the oblique extensional vectors and the pre-existing structural grain of the basement (Stagg et al, 2004).

Lambert and Peedamullah shelvesThe Lambert and Peedamullah shelves form a rift shoulder to the Northern Carnarvon Basin (Figure 1). They comprise planated Precambrian cratonic basement mantled by landward-thinning, dominantly Cretaceous–Cenozoic sedimentary rocks up to 2000 m thick (Figure 6). In addition, Silurian–Permian successions underlie parts of the Peedamullah Shelf.

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Basin evolution A generalised stratigraphy of the basin is shown in Figure 5 and comprises the following six phases:

1. Pre-rift (Silurian to Toarcian)

2. Early syn-rift (Toarcian to earliest Callovian)

3. Main syn-rift (earliest Callovian to Berriasian)

4. Late syn-rift Barrow Delta (Berriasian to Valanginian)

5. Post-breakup subsidence (Valanginian to mid-Santonian)

6. Passive margin (mid-Santonian to present)

(The term ‘rift’ used in the naming of basin phases refers to the phase of extension that culminated in continental breakup in the Early Cretaceous).

Hydrocarbon generation, migration and entrapment in the basin have been strongly controlled by syn-rift structuring and deposition, and post-rift reactivation.

Pre-rift (Silurian to Toarcian)The onset of rifting of the Sibumasu Block from Gondwana (Metcalfe, 1999) resulted in widespread deposition from the late Carboniferous, and initiation of the Westralian Superbasin, which includes the Northern Carnarvon Basin (AGSO North West Shelf Study Group, 1994). By the late Permian, northeast-trending depocentres had formed, with shallow marine clastic and carbonate deposition (Longley et al, 2002). At the beginning of the Triassic, a regional marine transgression deposited the Locker Shale, dominated by marine claystone and siltstone with minor paralic sandstone and shelfal limestone (Figure 5). The Locker Shale grades upwards into the Middle to Upper Triassic Mungaroo Formation, a thick succession of sandstone, claystone and minor coal which was deposited by a fluvio-deltaic system that prograded to the northwest, covering much of the offshore Northern Carnarvon Basin (‘Intra-Triassic’ to ‘Base Jurassic’ succession, Figure 6, Figure 7 and Figure 8). The upper Mungaroo Formation consists of shoreline sandstone, shallow marine claystone and minor limestone. The Middle Triassic Cossigny Member of the Mungaroo Formation (paralic and marine siltstone, claystone and limestone) is a significant regional seismic marker (the mtri seismic horizon; Figure 5), particularly in the Beagle Sub-basin (Figure 6). Fluvial and shoreline sandstones of the Mungaroo Formation host the giant gas accumulations on the Rankin Platform (Figure 9) and the formation is also the inferred main gas-prone source rock in the Barrow, Dampier and Exmouth sub-basins and the Exmouth Plateau.

Deposition throughout the Triassic occurred within broad, gently structured downwarps. The large volume of the Mungaroo Delta suggests that some sediment may have been delivered via transcontinental river systems from central Australia, Argo Land, West Burma, and/or Greater India (Jablonski and Saitta, 2004).

Thinly bedded shelfal siltstone, claystone and marl of the Brigadier Formation and Murat Siltstone were deposited in response to rapid subsidence from the latest Triassic to the Early Jurassic (Figure 5). On the Wombat Plateau, uppermost Triassic reefal limestone caps the Mungaroo Formation (von Rad et al, 1992a, 1992b). In the outer part of the basin, the Brigadier Formation is well preserved and is particularly thick in the Kangaroo Syncline in the southern Exmouth Plateau (Bussell et al, 2001). The Brigadier Formation is a significant gas source in the Barrow and Dampier sub-basins and also hosts some accumulations (Figure 9). Thin, reservoir-quality sandstones on some horst blocks along the Rankin Platform are known as the North Rankin Formation (Seggie et al, 2007).

In the Beagle Sub-basin, the Fitzroy Movement formed a series of structural highs and lows, isolating it from the Dampier Sub-basin during the Late Triassic (Blevin et al, 1994; Smith et al, 1999).

By the Pliensbachian, continued rifting resulted in the general structural configuration of the Northern Carnarvon Basin that is apparent today. Major bounding faults (e.g. the Rosemary, Flinders and Rankin fault systems) developed, delineating the Barrow, Dampier and Exmouth sub-basins, the Rankin Platform, and the Lambert and Peedamullah shelves (Figure 1). An oblique extension direction combined with the pre-existing Proterozoic to Paleozoic northerly structural grain resulted in an en echelon arrangement and compartmentalisation of the sub-basins (Romine et al, 1997). The formation of tilted fault blocks, horsts and graben strongly controlled the pattern of deposition (Barber, 1988). The large amount of observed subsidence relative to faulting suggests that lower crustal processes also played a major role during crustal extension (Stagg and Colwell, 1994; Driscoll and Karner, 1998).

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Early syn-rift (Toarcian to earliest Callovian)The Toarcian to earliest Callovian syn-rift succession comprises restricted marine claystone and siltstone of the Athol Formation and regressive deltaic sandstone of the Legendre Formation (Figure 5). The Legendre Delta had expanded westward from the Beagle Sub-basin into the Dampier Sub-basin and the central Exmouth Plateau by the Bathonian. Sediment was supplied from fault blocks and platforms at the depocentre margins. The Legendre Formation is the likely source for some of the hydrocarbon accumulations in the Dampier Sub-basin (e.g. the Legendre-Jaubert and Sage oil accumulations (Edwards and Zumberge, 2005)). It hosts, and is the source of, gas in accumulations such as Reindeer and Saffron-Rosemary (Thomas et al, 2004).

Main syn-rift (earliest Callovian to Berriasian)During the Callovian to Oxfordian, Argo Land separated from Australia and seafloor spreading commenced in the Argo Abyssal Plain (Jablonski, 1997). Uplift and erosion associated with initial extension produced the Callovian unconformity (Figure 5). The main phase of syn-rift deposition in the Northern Carnarvon Basin followed, initially resulting in the transgressive deposition of the Callovian Calypso Formation claystone and sandstone in the Barrow and Dampier sub-basins. Major rift-related faults developed along the northern edge of the Exmouth Plateau.

The basal Oxfordian unconformity or the ‘Breakup Unconformity’ corresponds to the so-called ‘Main Unconformity’ in some places. However, the latter is a diachronous sequence boundary, of earliest Jurassic to Aptian age (Newman, 1994; Jablonski, 1997) and is also referred to as the ‘Intra-Jurassic Unconformity’ (Sibley et al, 1999).

Continued post-breakup faulting during the Late Jurassic, uplifted and tilted the Exmouth Plateau and the Rankin Platform, supplying sediment to adjacent depocentres. Rapid tectonic subsidence resulted in a thick, deep marine succession, the Dingo Claystone (Figure 5), which progressively filled and overlapped the flanks of the Barrow, Dampier and Exmouth sub-basins (see the ‘Callovian’ to ‘Base Cretaceous’ succession in Figure 7 and Figure 8; Tindale et al, 1998). The maximum flooding phase during the Oxfordian provided a favourable depositional environment for high-quality, oil-prone source rocks (Longley et al, 2002). At the depocentre margins, reservoir-quality turbidite, submarine fan, shoreline and fluvial sandstones were deposited.

Over parts of the Exmouth Plateau, sandy shallow-marine deposition occurred within confined depocentres during the Late Jurassic. The Kangaroo Syncline formed in the southern Exmouth Plateau and northern Exmouth Sub-basin in response to extensional reactivation of tilted Triassic fault blocks on the Rankin Platform (Jenkins et al, 2003). Coarse clastic sediments were derived from the erosion of the Mungaroo Formation in uplifted areas and transported into the syncline until the Berriasian (Jenkins et al, 2003). Upper Jurassic sandstones are significant reservoirs in parts of the Northern Carnarvon Basin (Figure 9). These include turbiditic sandstones of the Biggada, Eliassen, Dupuy and Angel formations, and the shallow-marine to shoreline Jansz and Linda sandstones (Jenkins et al, 2003; Moss et al, 2003; Figure 5). The Angel Formation is the main oil- and gas-bearing reservoir unit in the Dampier Sub-basin, and the Jansz Sandstone hosts the giant Io/Jansz gas accumulation on the Exmouth Plateau.

Deposition was terminated during the early Berriasian by another episode of uplift and erosion, marking the onset of rifting between Greater India and Australia.

Late syn-rift Barrow Delta (Berriasian to Valanginian)The late syn-rift phase (Berriasian to Valanginian) was dominated by the extensive Barrow Delta and the resultant deposition of the Barrow Group (Figure 5), which attains a thickness of up to 2500 m (‘Base Cretaceous’ to ‘Valanginian’; Figure 8). Initial deposition occurred over the Exmouth Sub-basin, fed by sediment input from the south. The delta initially prograded northward, to the west of Barrow Island and across to the Exmouth Plateau, to form the lower Barrow Delta lobe which comprises approximately 75 per cent of deposition by the Barrow Delta (Ross and Vail, 1994). The second phase of progradation commenced in the late Berriasian, forming the upper Barrow Delta lobe in the Barrow and Dampier sub-basins, 250 km to the east of the delta’s earlier depocentre. The lower Barrow Delta lobe experienced erosion in the shoreward part of the Exmouth Sub-basin as the delta prograded northward to the Gorgon horst.

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The sediments of the lower (or western) Barrow Delta lobe are collectively known as the Malouet Formation, and those of the upper (or eastern) lobe as the Flacourt Formation. The boundary between the two lobes is markedly diachronous (Baillie and Jacobson, 1997). Dominant facies include basin-floor fan sandstone, pro-delta to foreset claystone, and top-set sandstone. The sandstone at the top of the Barrow Group is known locally as the Zeepaard Formation and the Flag Sandstone (Figure 5). The Zeepaard Formation was deposited extensively across the Barrow and Exmouth sub-basins, Rankin Platform and Exmouth Plateau as progradational top-set units of the Barrow Delta in the early Valanginian. In contrast, the Flag Sandstone was deposited as a basin-floor fan in the northeastern Barrow Sub-basin, in front of the delta foresets. Barrow Group sandstones are predominantly quartzose, weakly cemented, with excellent porosity and permeability. The giant Scarborough gas accumulation is hosted within a Barrow Group basin-floor fan sandstone (Tao et al, 2013; Figure 9).

Sediment supply to the Barrow Delta system ceased due to the commencement of continental breakup to the southwest of the Exmouth Plateau during the Valanginian (Hocking, 1990). The Exmouth Sub-basin and Exmouth Plateau were tectonically inverted during breakup, but subsidence and marine sedimentation continued throughout the Barrow and Dampier sub-basins.

Post-breakup subsidence (Valanginian to mid-Santonian)Continental breakup and the onset of seafloor spreading in the Gascoyne and Cuvier abyssal plains during the Valanginian resulted in widespread peneplanation in the Northern Carnarvon Basin and the formation of the Valanginian unconformity (Figure 5). Rapid subsidence following breakup resulted in a widespread transgression and deposition of a fining-upward marine sequence over the Valanginian unconformity surface (Figure 6, Figure 7 and Figure 8).

Localised paralic and shelf deposition formed the Birdrong Sandstone and glauconitic Mardie Greensand, followed by the basin-wide deposition of the transgressive Muderong Shale, Windalia Radiolarite and Gearle Siltstone (Figure 5). The Muderong Shale is a regional seal, but also contains economically important petroleum-bearing glauconitic sandstones such as the M. australis Sandstone Member (also known as the Stag Sandstone) and Windalia Sandstone in the Dampier and Barrow sub-basins, respectively (Figure 5 and Figure 9). The Windalia Sandstone contained over 90 per cent of the initial oil reserves of the Barrow Island oil accumulation (Ellis et al, 1999). A phase of uplift during the early Santonian in the southern Exmouth Sub-basin formed the Novara Arch (Figure 1) and caused erosion of the Gearle Siltstone (Tindale et al, 1998).

Passive margin (mid-Santonian to present)Siliciclastic sedimentation had ceased by the mid-Santonian, as a result of tectonic stability and a decreasing supply of terrigenous sediment. Prograding shelfal carbonate sediments were deposited on the passive continental margin in the Late Cretaceous and Cenozoic (Figure 6, Figure 7 and Figure 8).

During the Campanian, a period of regional compression resulted in uplift of the hinterland and structural inversion in the Exmouth Sub-basin and further west, and led to the formation of the Exmouth Plateau Arch, Resolution Arch and Kangaroo Syncline (Tindale et al, 1998). Pre-existing rift-related structures experienced transpressional reactivation within the Dampier and Barrow sub-basins, forming Barrow Island (Longley et al, 2002; Cathro and Karner, 2006). During the Oligocene and Miocene, prograding shelf carbonates (Mandu and Trealla limestones) were deposited (Tindale et al, 1998; Figure 5).

In the Miocene, a major compressional event associated with the convergence of the Australia–India and Eurasia plates affected the entire northwest Australian margin, including the Northern Carnarvon Basin (Longley et al, 2002). This event caused tilting, inversion and renewed faulting (Malcolm et al, 1991; Cathro and Karner, 2006). This is also the time when many structural traps within the Cretaceous and Cenozoic section were formed.

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Regional petroleum systemsTwo petroleum systems of Mesozoic age have been mapped within the Northern Carnarvon Basin by combining geochemical studies of hydrocarbon families with their postulated source rocks, interpreted from geological and palaeogeographical studies. Bradshaw (1993) and Bradshaw et al (1994, 1997) developed a petroleum systems and supersystems framework linking together Australian basins of similar age, facies, structural history and generated hydrocarbons. Each petroleum system within a supersystem is defined by a combination of play elements separated by either tectonic and/or climatic events. The petroleum systems of the Northern Carnarvon Basin were characterised by Spencer et al (1993, 1994,1995) and Bradshaw et al (1994) as belonging to the Westralian 1 and Westralian 2 supersystems.

On the basis of a USGS resource assessment analysis, Bishop (1999) further defined two petroleum systems for the Northern Carnarvon Basin following the source–reservoir couplet nomenclature of Magoon and Dow (1994):

• The ‘Locker–Mungaroo/Barrow’ Petroleum System. This Petroleum System is renamed the ‘Locker/Mungaroo–Mungaroo/Barrow’ Petroleum System herein.

• The ‘Dingo–Mungaroo/Barrow’ Petroleum System.

These two petroleum systems are considered to be the source of the majority of the commercially developed accumulations within the basin (Figure 9).

The gas-prone ‘Locker/Mungaroo–Mungaroo/Barrow’ Petroleum System covers most of the basin, extending to the margins of the Exmouth Plateau (Figure 9). The primary source rock for this petroleum system is regarded as the Upper Triassic deltaic Mungaroo Formation facies (and marine equivalents) with an additional possible contribution from organic-rich units in the Lower Triassic marine Locker Shale. The majority of recent exploration activities on the Exmouth Plateau are based on a model that invokes gas charge from the deeply buried coals and carbonaceous claystones of the Mungaroo Formation.

From a regional perspective, the ‘Locker/Mungaroo–Mungaroo/Barrow’ Petroleum System can be considered part of the Westralian 1 Petroleum Supersystem (Bradshaw et al, 1994; Edwards and Zumberge, 2005; Edwards et al, 2007). This Supersystem includes giant gas accumulations sourced mainly from fluvio-deltaic Triassic to Lower–Middle Jurassic source rocks in the Bonaparte, Browse and Northern Carnarvon basins. Similarities in the carbon isotopic profiles of gases and condensates across the Westralian Superbasin reflect the regional extent of fluvio-deltaic environments that developed from the Triassic to Middle Jurassic (Edwards and Zumberge, 2005; Edwards et al, 2006).

The oil-prone ‘Dingo–Mungaroo/Barrow’ Petroleum System (Bishop, 1999) is restricted to the Exmouth, Barrow and Dampier sub-basins, and is principally sourced from the Upper Jurassic Dingo Claystone. It can be considered part of the Westralian 2 Petroleum Supersystem (Bradshaw et al, 1994) as geochemically similar oils are recognised in the Northern Carnarvon, Bonaparte (Vulcan Sub-basin and Laminaria High) and Papuan basins (AGSO and GeoMark, 1996; Edwards and Zumberge, 2005).

Some oils and condensates that could not be attributed to either of these two petroleum systems were termed ‘vagrants’ by Summons et al (1998) and used to indicate that additional source rocks were effective within the basin. For example, lacustrine sources have been ascribed to the Nebo 1 oil accumulation in the Beagle Sub-basin, and at Parrot Hill 1 and Rough Range 1, 1A in the onshore Exmouth Sub-basin (Longley et al, 2002; Edwards and Zumberge, 2005).

Source rocksThe main gas-prone source rocks in the Barrow, Dampier and Exmouth sub-basins are inferred to be the Triassic fluvio-deltaic sediments of the Mungaroo Formation, with an additional contribution from the overlying Lower to Middle Jurassic marine and deltaic Murat Siltstone and Athol/Legendre formations. Geochemical studies indicate that the gas accumulations of the Rankin Platform accessed these Triassic sources, as well as Lower–Middle Jurassic sources in the adjacent Barrow and Dampier sub-basins (Boreham et al, 2001; Edwards and Zumberge, 2005). The giant gas accumulations of the Exmouth Plateau are inferred to have been charged from deeply buried coal and carbonaceous claystone in the Mungaroo Formation (Cook et al, 1985; Bussel et al, 2001) although a contribution from the Locker Shale has not been discounted.

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The principal oil-prone source rock in the Barrow, Dampier and Exmouth sub-basins is the Upper Jurassic Dingo Claystone. It was deposited under deep, restricted marine conditions in incipient rifts that developed along the northern and northwestern continental margin during Gondwana breakup. The Oxfordian (W. spectabilis biozone) sediments are particularly organic-rich (van Aarssen et al, 1996; Thomas et al, 2004). Biomarker and geochemical studies of oils derived from the marine Dingo Claystone indicate that there is a significant supplementary contribution from terrestrial organic matter (Summons et al, 1998; Edwards and Zumberge, 2005).

Reservoirs and sealsReservoir rocks in the Northern Carnarvon Basin are dominated by fluvio-deltaic and marginal marine sandstones, including those within the Triassic Mungaroo Formation, the Bajocian–Callovian Legendre Formation in the Beagle and Dampier sub-basins, and the Berriasian–Valanginian Barrow Group in the Barrow and Exmouth sub-basins and the Exmouth Plateau (Figure 9). Additionally, Upper Triassic carbonate reef build-ups may provide an additional reservoir type on the outboard Exmouth Plateau (Grain et al, 2013).

Most hydrocarbon discoveries within the basin are hosted by reservoirs beneath the Lower Cretaceous Muderong Shale, which forms an effective regional seal and has contributed to the high exploration success rate (Baillie and Jacobson, 1997). Notable exceptions occur in the Barrow Sub-basin, where top-seals are formed by the Aptian Windalia Radiolarite at the Barrow Island oil accumulation (Ellis et al, 1999) and the Paleocene Dockrell Formation at the Maitland gas accumulation (Sit et al, 1994).

In addition, intraformational seals result in stacked hydrocarbon-bearing reservoirs. Gas accumulations on the Rankin Platform are top-sealed by a combination of the regional seal and intraformational claystones. Significant intraformational seals occur within the Berriasian–Valanginian Barrow Group, Forestier Claystone and equivalents, the Toarcian–Callovian Athol and Legendre formations, and the Triassic Mungaroo Formation.

The main structural trap styles in the basin are horsts, tilted fault blocks, drapes and fault roll-over anticlines. Stratigraphic trap styles include basin-floor and turbidite fans, unconformity pinch-outs and onlaps. Structural compartmentalisation of the basin has resulted in complex trap evolution and charge histories.

Timing of generationHydrocarbon generation from the Dingo Claystone commenced in the Exmouth Sub-basin and southern parts of the Barrow Sub-basin in the Early Cretaceous with the loading of the Barrow Delta (Tindale et al, 1998; Smith et al, 2003). Hydrocarbon generation from potential Lower to Middle Jurassic source rocks in the Beagle Sub-basin began prior to deposition of the Lower Cretaceous Muderong Shale regional seal; however the loading of a major Cenozoic carbonate wedge has driven a pulse of maturation, with a higher chance of remaining trapped (Lech, 2013).The main phase of generation in the Dampier Sub-basin was also in response to the progradation of the Cenozoic carbonate shelf (Thomas et al, 2004). On the Exmouth Plateau, peak gas generation from the Mungaroo Formation is currently expected at depths of over 5000 m below the sea floor (Cook et al, 1985; Bussel et al, 2001).

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Exploration historyThe Northern Carnarvon Basin is Australia’s most prolific hydrocarbon-producing basin, with 86.2 million barrels (MMbbl) (13.7 Gl) of oil and 1198.1 Bcf (33.9 Bcm) of gas produced in 2010 (Geoscience Australia, 2010a). Western Australian gas production represented about two thirds of national production in 2011-12 and the Northern Carnarvon basin accounts for the majority of that production (Bureau of Resource and Energy Economics, 2013). The basin is estimated to contain 22.2 billion barrels of oil equivalent (Bboe) (3529.5 Gl) of resources (Barber, 2013) and most of the offshore part of the basin in Commonwealth waters is currently under permit (NOPTA, 2013).

In 2012, six 3D seismic surveys and two 2D seismic surveys were undertaken in the offshore Northern Carnarvon Basin. In 2013, a further four 3D seismic surveys, plus the Pyrenees 4D monitoring and WestraliaSPAN 2D seismic surveys, were undertaken. Fifty-nine wells were spudded during 2012, of which 15 were wildcat wells and the remainder were extension/appraisal or development wells (Brooks, 2013). As of 1 November 2013, six exploration wells were spudded in the basin during 2013 (Figure 3). Information on drilling, permit histories, production and reserves are given by Geoscience Australia (2010a, 2010b), Australian Bureau of Agricultural and Resource Economics (2011), and Department of Mines and Petroleum, Petroleum Division (2011a, 2011b). Accompanying the recent discoveries have been a series of new, large-scale development projects and associated investment in infrastructure, as well as the expansion of existing facilities. A review of production and development/appraisal drilling in 2012 is provided by Jurinak and Anderson (2013).

The first flow of oil to the surface in Australia was recorded in 1953 at Rough Range 1, in the onshore part of the Exmouth Sub-basin. The well recorded an oil flow of 500 bbl/d (79.5 kl/d) from the Lower Cretaceous Birdrong Sandstone, but further drilling on the same anticline failed to replicate the initial success (Bradshaw et al, 1999; Ellis and Jonasson, 2002).

Exploration in the offshore Northern Carnarvon Basin during the 1960s and early 1970s established the basin as a major hydrocarbon province (Mitchelmore and Smith, 1994). The giant Barrow Island oil accumulation was discovered in 1964 (Ellis et al, 1999), and the Griffin oil accumulation was discovered in 1974 by Hilda 1A (Figure 2). The Legendre 1 oil discovery in 1968 attracted exploration interest to the Dampier Sub-basin, with success continuing at Angel in 1972 and Lambert in 1973. A series of multi-Tcf gas discoveries were made in the 1970s on the adjacent Rankin Platform (e.g. Goodwyn, North Rankin/Perseus and Rankin; Barber, 1994a, 1994b; Thomas et al, 2004). In 1972 in the Barrow Sub-basin, gas discoveries were made in Triassic sandstones at West Tryal Rocks 1. In the same year, the first gas shows were recorded in the Exmouth Sub-basin when West Muiron 1 was drilled on the feature that was later (in 1994) recognised as the Macedon/Pyrenees gas and oil accumulation.

Significant gas discoveries were made in the late 1970s to early 1980s. On the deep-water Exmouth Plateau, a giant gas accumulation in a Lower Cretaceous Barrow Group basin floor fan was discovered at Scarborough 1 in 1979 (Figure 9) and is estimated to hold a 5.2 Tcf (147.2 Bcm) gas resource and 882.5 million barrels of oil equivalent (MMboe) (140.3 Gl; Barber, 2013). The gas discovery at Spar 1 (1976) in the Barrow Sub-basin was also made in Lower Cretaceous sandstones. The Gorgon accumulation, is one of the largest gas accumulations to be discovered (in 1981) within the Northern Carnarvon Basin, with an estimated resource of 16.8 Tcf (475.7 Bcm) of gas and 121 MMbbl (19.2 Gl) of liquids (Barber, 2013).

From the early 1980s to the mid-1990s, a number of mostly medium-sized oil and gas discoveries were made in the Barrow and Dampier sub-basins as a result of the application of 2D seismic surveys with high line density (Longley et al, 2002). These include discoveries at South Pepper, Chervil, Harriet, Outtrim, Rosily and Saladin in the southern Barrow Sub-basin (Baillie and Jacobson, 1997); East Spar and Wonnich northwest of Barrow Island; Scindian/Chinook on the Alpha Arch; and Cossack, Talisman, Stag, Wanaea and Wandoo in the Dampier Sub-basin (Figure 2; Vincent and Tilbury, 1988; Bint, 1991). Also at this time in the Barrow Sub-basin, Maitland 1 (1992) discovered gas reservoired in sandstone near the base of the Paleocene (Figure 8; Sit et al, 1994). The oil discovery at Nebo 1 in 1993 extended exploration interest into the under-explored Beagle Sub-basin (Osborne, 1994). In the Exmouth Sub-basin, oil at Novara 1 was discovered in 1982, but the biodegraded nature of the accumulation (16.7°API; Smith et al, 2003) deterred further exploration. Exploration on the Rankin Platform and adjacent Exmouth Plateau continued to target Triassic fault block and intra-Triassic plays resulting in the discovery of Chrysaor in 1994–1995 and Dionysus in 1996. The supergiant Io/Jansz gas accumulation on the Exmouth Plateau was discovered in 2000 and is hosted by Oxfordian shallow-marine sandstone with the gas having migrated through a Triassic reservoir at Geryon (Jenkins et al, 2003). The Io/Jansz accumulation constitutes the largest gas resource yet discovered in the Northern Carnarvon Basin, with an estimated 20.1 Tcf (569 Bcm) of gas and 16 MMbbl (2.5 Gl) of liquids (Barber, 2013).

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Over the last decade there has been increasing focus on the commercialisation of existing discoveries, as indicated by the number of ‘step-out’ exploration wells, extension/appraisal wells and development wells drilled, which reflects the maturity of exploration within the basin. 3D seismic and AVO technology have contributed to an improvement in the success rate of recent activities (Kingsley and Tilbury, 1999; Longley et al, 2002; Korn et al, 2003; Williamson and Kroh, 2007).

Dampier and Beagle sub-basinsIn the Dampier Sub-basin, re-evaluation of the earlier discoveries on the Enderby Terrace and the testing of new play concepts led to the discoveries of oil at Chamois, Oryx, Sage and Tusk, and gas at Reindeer/Caribou and the nearby Corvus accumulation (Figure 2; Seggie et al, 2003). During 2013, development wells were drilled at Stag by Apache Energy Ltd and at Wandoo by Vermillion Energy Inc.

During 2012, two wells were drilled southwest of the Legendre accumulation. Hoss 1 found oil shows (Santos, 2012) and Jalfrezi 1 found oil and gas shows (Santos 2013a). Santos drilled Winchester 1 in the western end of the sub-basin; this was then sidetracked in 2013, with Winchester 1 ST1 confirming 58 m of net gas pay in the Jurassic Angel and Triassic Mungaroo formations (Santos, 2013b).

The productive northern end of the sub-basin has been extended from the Mutineer and Exeter oil accumulations (discovered by Pitcairn 1 in 1997 and Exeter 1 in 2002, respectively; Auld and Redfearn, 2003) into the adjacent Beagle Sub-basin, with oil discoveries at Fletcher 1 (2007) and Finucane South 1A (2011) by Santos Offshore Pty Ltd (Department of Mines and Petroleum, Petroleum Division, 2011b). These discoveries have been followed up by numerous extension/appraisal wells during 2012 and 2013. Two 3D seismic surveys conducted during 2013 collected data in the Beagle Sub-basin. Woodside’s Polly 3D seismic survey collected 6980 km2 of 3D data covering a small portion of the northeast Dampier Sub-basin, as well as a large part of the southern Beagle Sub-basin and Lambert Shelf. The northern Beagle Sub-basin was surveyed by Karoon’s 2376 km2 Chrysalids 3D survey which also covered part of the eastern Exmouth Plateau.

Barrow Sub-basinThe Barrow Sub-basin and, in particular, Barrow Island and the inshore part along the Barrow Island Trend, has been actively and continuously explored since 1964 with production commencing on Barrow Island in 1966 (Ellis et al, 1999). Production facilities for Campbell, Harriet, Rosette and neighbouring accumulations are located on Varanus Island, and for Saladin and neighbouring accumulations on Thevenard Island (Figure 2).

In the Barrow Sub-basin in 2013, Apache Energy Ltd drilled Bianchi 1 (2013) 6.4 km north of the Zola 1 gas discovery. Wireline logging and pressure testing confirmed 112 m of net gas pay in the Triassic Mungaroo Formation (Apache Corporation, 2013a). Apache Energy Ltd also drilled Beam 1 (2012) as an extension/appraisal well near the Spar accumulation. Other extension/appraisal and development drilling has been undertaken over the last few years around the John Brookes, Rosella, Spar, Linda and Maitland gas accumulations as well as at the Woollybutt oil accumulation in the northwestern part of the sub-basin, at Taunton in the southeast and on Barrow Island.

Exmouth Sub-basinIn the Exmouth Sub-basin, the Vincent and Enfield oil discoveries were made in 1998 and 1999, respectively. These were 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. Cimatti 1 was drilled by Woodside Energy Ltd to test a prospect within tieback distance to Enfield and intersected a gross 15 m oil column in the Macedon Formation before being sidetracked as Cimatti 2 to further appraise the discovery (Woodside, 2010). To the north of Cimatti, Furness 1 (2010) and Crusader 1 (2011) were drilled by BHP Billiton Petroleum Pty Ltd and Apache Energy Ltd, respectively. Woodside Energy Ltd drilled Opel 1 in 2011 in a separate fault block on the western flank of the Laverda accumulation and encountered oil (Woodside Petroleum Ltd, 2011a). To date, none of the exploration wells spudded in the Exmouth Sub-basin during 2012 or 2013 have encountered commercial hydrocarbons. These include Gumbo 1, drilled by Woodside Energy Ltd on the northwestern flank of the sub-basin, 8 km from the Ragnar 1 gas discovery, and Minarelli 1, near the edge of the Enfield oil accumulation (Woodside Petroleum Ltd, 2013a, 2013b,). Palta 1, drilled by Shell Development (Australia) Pty Ltd in the southern portion of the sub-basin was plugged and abandoned with no commercial hydrocarbon shows (Octanex N. L., 2012).

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Extension/appraisal and development wells have been drilled in the Exmouth Sub-basin since the discovery of the Vincent/Van Gogh and Enfield oil accumulations. During 2012–2013, development wells were drilled at Stickle and Pyrenees by BHP Billiton Petroleum Pty Ltd, and in the Novara and Coniston oil accumulations by Apache Oil Australia Pty Ltd.

Rankin Platform and Exmouth PlateauGrowing demand for LNG in the Asia–Pacific region has stimulated exploration along the Rankin Platform and on the Exmouth Plateau in recent years, mostly targeting Triassic fault block and intra-Triassic plays. Around the northern Rankin Platform, recent exploration drilling by Woodside Petroleum Ltd has sought to extend beyond the known accumulations, and includes Ananke 1 (2012) and Goodwyn North 1 (2013). In the central part of the Rankin Platform in the region of the Iago, Pluto and Wheatstone gas discoveries (discovered between 2000 and 2005), Eris 1 (2009), Emersons 1 (2011) and Xeres 1A (2011) were drilled by Woodside Petroleum Ltd. Apache Energy Ltd has made several significant oil discoveries in the Mungaroo Formation in reservoirs that are separate from the Julimar and Brunello gas accumulations (discovered in 2007 and 2008, respectively) with the drilling of Balnaves 1 to 4 and Balnaves Deep 1 (Apache Corporation, 2011a). The appraisal wells Balnaves Deep 2 and 3 were drilled in the second quarter of 2012. Throughout 2012 and 2013, numerous development wells were also drilled at Brunello by Apache Energy Ltd and at Goodwyn and Tidepole by Woodside Energy Ltd. To further asses these accumulations, Apache conducted the 446 km2 Harmony 3D survey in permit WA-49-L during 2013, covering the Julimar, Brunello and Brokenwood gas and Balnaves oil accumulations. Additionally, Chevron ran the 2000 km2 Aperio 3D survey covering 11 permits on the Rankin Platform and neighbouring part of the Exmouth Plateau, covering the West Tryal Rocks, Chrysaor and Dionysus gas accumulations.

On the southern Rankin Platform at Gorgon, Chevron Australia Pty Ltd encountered 97 ft (30 m) of net gas pay in the exploration well Pontus 1 (Chevron Australia Pty Ltd, 2012a) and also drilled several development wells. Located to the south of, and on trend with the Gorgon accumulation, is Zola 1 ST1, drilled by Apache Northwest Pty Ltd in 2011, which discovered over 100 m of net gas pay sands over a 400 m gross section in the Mungaroo Formation (Apache Corporation, 2011b).

On the Exmouth Plateau to the south of the Io/Jansz accumulation are the Maenad and Orthrus gas accumulations, discovered in 1999–2000. Success at Achilles 1 (Chevron Australia Pty Ltd, 2009a) and Acme 1 (Chevron Australia Pty Ltd, 2010) has increased the reserves in this area, with extension and appraisal drilling by Chevron Australia Pty Ltd continuing at Acme West 1 and 2, Clio 3, Iago 5 and Geryon 2 in 2010–2011. Orthrus 2 (2010), also drilled by Chevron Australia Pty Ltd, proved a deeper discovery in the Orthrus gas accumulation (Department of Mines and Petroleum, Petroleum Division, 2011b). Success at Satyr 1 (2009) led to extension and appraisal drilling undertaken at Satyr 2, 3 and 4 and confirmed 128 ft (39 m), 243 ft (74 m) and 220 ft (67 m) of net gas pay, respectively (Chevron Australia Pty Ltd, 2009b, 2012b, 2012c).

To the southwest of Io/Jansz are the Briseis, Glencoe and Nimblefoot gas discoveries (made by Hess in 2008) which occur within the post-Callovian section, with an additional pay in the Triassic Mungaroo Formation at Briseis 1 (Smallwood et al, 2010). Between 2009 and 2011, Hess drilled 16 wells within WA-390-P, of which 13 are reported as gas discoveries (Hess, 2011). In 2012, Hess commenced extension and appraisal drilling at Glencoe with Glencoe 2/RE.

The southern margin of the Exmouth Plateau has seen some recent activity with the drilling of four exploration wells during 2012–2013, two of which are reported as gas discoveries. Tallaganda 1, drilled by BHP Billiton Petroleum in 2012, was confirmed as a gas discovery in the Triassic Mungaroo Formation (Tap Oil Limited, 2012), while Apache Northwest’s Olympus 1, drilled in 2013, discovered gas in the Cretaceous lower Barrow Group, as well as the Triassic Mungaroo Formation (Finder Exploration, 2013).

The gas discoveries at Larsen 1, Larsen Deep 1, Martell 1, Martin 1, Noblige 1 and Remy 1A (Woodside Petroleum Ltd 2011b) have extended the northerly limit of known gas accumulations on the Exmouth Plateau. Gas discoveries west of the Io/Janz gas accumulation include Chevron’s Chandon 1 (2006) and Yellowglen 1 (2009), and more recently, Elfin 1 discovered 132 ft (40 m) of net gas pay in upper Mungaroo sandstones (Chevron Australia Pty Ltd, 2013a). In the north and east of the sub-basin, three wells were drilled in 2011, La Rocca 1 by Apache Northwest Pty Ltd, and Galahad 1 and Gawain 1 by Eni Australia Ltd. Banambu Deep 1 was drilled by Woodside Petroleum Ltd in 2012, seeking to define the limit of these gas plays.

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Gas discoveries at Brederode 1, Kentish Knock 1/Guardian 1, and Thebe 1 and 2 in 2011 extended the northwesterly limit of known gas accumulations on the outer Exmouth Plateau. More recently, the discovery of approximately 45.5 m of net gas pay in Barrow and Mungaroo sands at Arnhem 1 (Chevron Australia Pty Ltd, 2012d), and approximately 75 m of net gas pay in upper Mungaroo sandstones at Kentish Knock South 1 (Chevron Australia Pty Ltd, 2013b), have further confirmed the extent of these gas plays. In addition, gas south of the Scarborough accumulation has been confirmed with 60 m of net gas pay in Barrow and Mungaroo sands at Pinhoe 1 (Chevron Australia Pty Ltd, 2012d).

The most westerly exploration wells drilled to date include Tiberius 1, Alaric 1, Cadwallon 1 and Genseric 1 by Woodside Petroleum Ltd from 2010 to 2011, and Vucko 1 by Woodside Energy Ltd in 2012. Alaric 1 discovered a 185 m gas column (Woodside Petroleum Ltd, 2010) and Cadwallon 1, a 27 m gross hydrocarbon column (Woodside Petroleum Ltd, 2011a), proving that the prospective zone extends to the deep-water western margins of the Exmouth Plateau. Vos 1, drilled by Chevron Australia Pty Ltd, encountered 138 m net gas pay (Chevron Australia Pty Ltd, 2011), further supporting the prospectivity of the far western part of the Exmouth Plateau.

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Production statusFor 2012 and the first quarter of 2013, the Australian Petroleum Production and Exploration Association (2013) reported that there were 15 production areas in the Northern Carnarvon Basin:

• NWS Venture and the NWS Development Project (NSWDP) located mostly on the northern Rankin Platform (North Rankin, Cossack, Wanaea, Lambert, Hermes);

• Pluto LNG project on the Rankin Platform/Exmouth Plateau (Pluto, Xena);

• Devil Creek (tied-in to Reindeer), Mutineer/Exeter, Stag and Wandoo in the Dampier Sub-basin, plus Fletcher/Finucane (tied-in to Mutineer/Exeter) in the Beagle Sub-basin;

• Barrow, Thevenard and Varanus islands, and Woollybutt (recently decommissioned) in the Barrow Sub-basin; and

• Enfield, Pyrenees, Macedon, Stybarrow and Vincent/Van Gogh in the Exmouth Sub-basin.

Currently, there are four sources of domestic natural gas from the Northern Carnarvon Basin; the NWSDP, Varanus Island, the Devil Creek Development Project and, since August 2013, the Macedon Natural Gas Project. Production areas in the Dampier and Barrow sub-basins produce predominantly light sweet crude oil, and those in the Exmouth Sub-basin produce predominantly heavy crude oil.

Rankin PlatformThe NWS Venture is one of the world’s largest LNG producers; the offshore production facilities are operated by Woodside Energy Ltd with joint venture partners BHP Billiton Petroleum (North West Shelf) Pty Ltd, BP Developments Australia Pty Ltd, Chevron Australia Pty Ltd, Japan Australia LNG (MIMI) Pty Ltd and Shell Development (Australia) Pty Ltd (North West Shelf Gas, 2013). The facilities constitute Australia’s largest oil and gas resource development and account for more than 40 per cent of Australia’s oil and gas production. It has been producing domestic gas for 29 years, with first production coming from North Rankin in 1984, and it has been exporting LNG to the Asia Pacific region for 24 years (since 1989). Gas production facilities include the North Rankin A, Goodwyn A and Angel A platforms that process gas from Angel, Echo/Yodel, Goodwyn, North Rankin, Perseus and Searipple. Oil production from Cossack, Hermes, Lambert and Wanaea is processed via the Okha floating production storage and offloading (FPSO) facility which produces approximately 30 000 bbl/d (4.77 Ml/d) of crude oil products (Woodside Petroleum Ltd 2011c). Hydrocarbons from the offshore production facilities are transported to the Karratha Gas Plant for processing via two subsea pipelines.

Located 1260 km north of Perth and covering approximately 200 hectares, the Karratha Gas Plant includes five LNG processing trains, two domestic gas trains, six condensate stabilisation units and three LPG fractionation units, as well as storage and loading facilities for LNG, LPG and condensate. The plant has the capacity to produce 16.3 million tonnes per annum (mtpa) of LNG, 12 000 t/day domestic gas and 130 000 bbl/d (20.7 Ml/d) of condensate (North West Shelf Gas, 2013).

The NWSDP involves the redevelopment of the NWS Venture to extend the life of this established facility (Woodside, 2013c). This initiative included the North Rankin Redevelopment Project, which involved the construction and installation of North Rankin B and refurbishment of North Rankin A. The project achieved start-up in October 2013 and will enable the recovery of approximately 5 Tcf (141.58 Bcm) of low pressure reserves from the North Rankin and Perseus accumulations (Woodside Petroleum Ltd, 2013c). The NWSDP also includes the Cossack–Wanaea–Lambert–Hermes (CWLH) Redevelopment Project, which commenced production in September 2011 after the replacement of the previous Cossack Pioneer FPSO with the Okha, and a subsea infrastructure upgrade (Woodside Petroleum Ltd, 2011c). In addition, planning is underway for the Greater Western Flank Development project to commercialise the gas and condensate located to the southwest of Goodwyn with a subsea tieback to the Goodwyn A platform. Phase 1 of the project is expected to start in early 2016 (Woodside, 2013b).

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The Pluto LNG project, operated by Woodside Petroleum Ltd with Kansai Electric and Tokyo Gas as joint venture partners, consists of a 4.3 mtpa single train LNG plant on the Burrup Peninsula supplied from the Pluto discovery (Woodside, 2013a). The plant commenced processing in March 2012. From commencement to the end of the 2012 financial year, Pluto LNG produced 599 564 tonnes of LNG and 513 038 bbl (81.57 Ml) of condensate (Woodside Petroleum Ltd, 2012). The initial phase of the project comprises an offshore platform in 85 m of water, connected to five subsea wells at Pluto. Gas is piped in a 180 km trunkline to an onshore facility located between the NWS Project and Dampier Port on the Burrup Peninsula. Storage and loading facilities at the plant include two LNG tanks, three smaller condensate tanks, and an LNG and condensate export jetty (Woodside, 2013a). During the third quarter of 2013, Woodside announced that the Pluto Joint Venture participants approved the FID for Phase 1 of the Xena tie-in project, which will tieback the Xena gas accumulation to Pluto in 2015 and access 250 Bcf (7.08 Bcm) of gas reserves (Woodside Petroleum Ltd, 2013b).

Dampier and Beagle sub-basinsApache Corporation’s Devil Creek Development Project, located south of Karratha, commenced supply of domestic gas from the Reindeer accumulation to the DBNGP via a new offshore pipeline and an onshore processing plant in December 2011 and the official opening of the plant was held in February 2012. The two-train plant is designed to process 200 MMcf/d (5.66 Mcm/d) gas, as well as delivering up to 1000 bbl/d (160 kl/d) condensate into the pipeline (Apache Corporation, 2013b).

The Mutineer/Exeter facilities are operated by Santos with joint venture partners KUFPEC, Nippon Oil and Woodside and commenced production in March 2005 via an FPSO vessel that is currently recovering approximately 6000 bbl/d (954 kl/d; Santos, 2013c). The Fletcher/Finucane oil project in the Beagle Sub-basin commenced production in May 2013, with a three well tieback to the Mutineer/Exeter FPSO, and is projected to have an average gross production rate of 15 000 bbl/d (2.4 Ml/d of oil) for the first 12 months of production (Santos, 2013d).

Oil has been produced from the Stag accumulation since May 1998 via an FPSO facility operated by Apache and partner Santos. The accumulation comprises eight production wells (supported by three water injection wells) that currently produce approximately 7000 bbl/d (1113 kl/d) (Santos, 2013e). Further extension/appraisal wells were drilled in 2012 and 2013.

The Wandoo oil accumulation is operated by Vermilion Energy Inc. and produces from the Wandoo A Monopod and Wandoo B platform. During 2013, a two-well sidetrack drilling program resulted in the longest horizontal section yet drilled at Wandoo and both sidetracks were brought into production at restricted rates in April 2013, demonstrating productive capabilities in excess of 6000 bbl/d (954 kl/d) and 3000 bbl/d (477 kl/d) respectively (Vermillion Energy Inc, 2013).

Barrow Sub-basinThe Barrow Island production facility is operated by Chevron Australia with partners Santos and ExxonMobil. The accumulation was discovered in 1964 by West Australian Petroleum Pty Ltd and is the largest oil accumulation in Western Australia. Appraisal drilling has defined in-place oil reserves of 1250 MMbbl (198.7 Gl) and in-place gas reserves of 580 Bcf (16.4 Bcm) (Ellis et al, 1999). Oil production commenced in April 1967, with more than 300 MMbbl (47.7 Gl) oil recovered to date (Chevron Australia Pty Ltd, 2013c). The primary reservoir is the Lower Cretaceous Windalia Sandstone Member. Hydrocarbons also occur within the Upper Jurassic Dupuy Formation, Lower Cretaceous Malouet and Flacourt formations of the Barrow Group, the Tunney, Mardie Greensand and M. australis members of the Muderong Shale, and in the Upper Cretaceous Gearle Siltstone (Ellis et al, 1999). Oil is produced from approximately 420 wells, with production sustained by approximately 208 water injection wells (Santos, 2013f). Oil is collected from eight gathering stations and stored in a one million barrel (159 Ml) storage facility on the island and exported via an offshore tanker mooring. Gas reserves within the Biggada Formation, estimated to contain 515 Bcf (14.6 Bcm) in-place (Ellis et al, 1999), have yet to be developed.

The Thevenard Island production facility is operated by Apache Corporation with partners Santos and ExxonMobil. Saladin 1 was the discovery well for the Saladin accumulation and oil production commenced in 1989. Currently, oil and gas from Cowle, Crest, Roller, Saladin, Skate and Yammaderry are produced through this facility (Chevron Australia Pty Ltd, 2013d). The facilities are capable of processing 120 000 bbl/d (19 Ml/d) oil and 18 MMscf/d (0.51 Mcm/d) gas, but are currently producing 1700 bbl/d (270.28 kld) oil (Santos, 2013g). Oil is stored at a one million barrel (159 Ml) storage facility on the island and exported via an offshore tanker mooring.

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The Varanus Island production facility is operated by Apache Corporation with partner Santos and is located approximately 75 km offshore northwestern Australia. It is the hub for the Harriet Joint Venture and John Brookes Joint Venture and has infrastructure for the collection and processing of oil, condensate and gas. Domestic gas supplied by the facility is transported to mainland Western Australia via two 100 km pipelines that connect into the DBNGP and Goldfields Gas Transmission trunklines (Santos, 2013h). Currently, the reserves from the many oil and gas discoveries in the northeastern Barrow Sub-basin are produced through Varanus Island. In June 2011, gas and condensate production from the Halyard Development was transported to market via a sub-sea tieback to the East Spar accumulation and from there to the Varanus Island facilities (Apache Corporation, 2011a).

The Woollybutt oil accumulation was operated by Eni Australia Ltd, with partners Mobil Australia Resource Co Pty Ltd and Tap West Pty Ltd, and commenced production in 2003. Woollybutt was discovered with the drilling of West Barrow 1A (1982) with oil in the top Barrow Group and Mardie Greensand. After suspending production in 2009, the accumulation recommenced production from the Four Rainbow FPSO facility in March 2010 and ceased production at the end of May 2012 (Tap Oil Limited, 2013).

Exmouth Sub-basinThe BHP Billiton-operated Pyrenees project commenced production from the Crosby, Ravensworth and Stickle oil accumulations through the Pyrenees FPSO facility at Pyrenees in March 2010 (BHP Billiton, 2010). Production from the Pyrenees Expansion Project (Wild Bull, Tanglehead and Moondyne oil fields) is scheduled to commence in 2014. Produced gas from the accumulations is reinjected into the nearby Macedon gas reservoir. The latter has been developed through the BHP Billiton-operated Macedon Project, which was commissioned in August 2013 with a production capacity of 200 MMcfd (5.7 Mcm/d) of domestic gas. A pipeline connects the Macedon gas treatment plant at Ashburton North Strategic Industrial Area to the DBNGP for domestic gas production (Apache Corporation, 2013c).

The Enfield oil accumulation is operated by Woodside, with partner Mitsui E&P Australia Pty Ltd, and production through the Nganhurra FPSO facility commenced in July 2006 (Woodside, 2013b). The vessel has a maximum production rate of 100 000 bbl/d (15.9 Mld) and 900 000 bbl (143 Ml) of oil storage capacity. Enfield was discovered in 1999 along with the nearby Vincent/Van Gogh and Laverda oil accumulations.

The Stybarrow oil project has been developed by BHP Billiton (operator) and Woodside, and commenced production through the Stybarrow Venture FPSO facility in November 2007 (BHP Billiton, 2008).

The Vincent oil accumulation is operated by Woodside, with partner Mitsui E & P Australia Pty Ltd, and commenced production in August 2008 (Woodside, 2013d). The Van Gogh extension of the Vincent accumulation commenced production in February 2010 using the Ningaloo Vision FPSO facility operated by Apache Corporation. It is planned that the Coniston and Novara oil accumulations will also tieback to this FPSO facility, with first production scheduled for 2014 (Apache Corporation, 2013d).

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Development statusCurrently there are five LNG development projects in progress in the Northern Carnarvon Basin: Gorgon, Wheatstone, NWS Venture’s Greater Western Flank (GWF), Scarborough and Equus.

The Gorgon LNG project is the largest single resource development in Australia’s history and will produce gas initially from the Greater Gorgon accumulation, followed by the Io/Jansz accumulation. This project is operated by Chevron Australia Pty Ltd, with joint venture partners ExxonMobil, Shell, Osaka Gas, Tokyo Gas and Chubu Electric Power Co. Production facilities incorporate a three-train export LNG plant on Barrow Island with an initial combined capacity of 15.6 mtpa, a 300 terajoule per day (TJ/d) domestic gas plant to supply the Western Australian markets, and a large-scale carbon dioxide reinjection project. First LNG production is planned for first quarter 2015 (Chevron Australia Pty Ltd, 2013e).

In September 2011, Chevron delivered FID on the Wheatstone LNG Project, with Apache, Kuwait Foreign Petroleum Exploration Co (KUFPEC), Shell and Kyushu together with PE Wheatstone Pty Ltd (part owned by TEPCO) as equity participants (Chevron Australia Pty Ltd, 2013f). The project will process gas from the Wheatstone and Iago discoveries via a two-train plant with a combined capacity of 8.9 mtpa at Ashburton North, 12 km west of Onslow. The Wheatstone project will also have a 265 TJ/d domestic gas plant. Apache Julimar Pty Ltd and KUFPEC Australia (Julimar) Pty Ltd will supply additional gas from the Julimar and Brunello accumulations (Julimar Development Project) to the Wheatstone LNG plant. The Julimar-Brunello fields are expected to produce approximately 140 MMcf/d (4 Mcm/d) of LNG, 22 MMcf/d (0.623 Mcm/d) of sales gas into the domestic market and 3250 bbl/d (516.61 kl/d) of condensate (Apache Corporation, 2012). Moreover, Apache also plans to produce oil from the Balnaves accumulation underlying Brunello via an FPSO by 2014 (Apache Corporation, 2011a).

The NWS Venture participants have approved Phase 1 of the Greater Western Flank (GWF) Project with project start-up expected for early 2016. The GWF will develop the Goodwyn and Tidepole gas and condensate accumulations through a sub-sea tieback to the Goodwyn A platform. Several development wells were drilled in both accumulations during 2012. It is estimated that the 16 accumulations that make up the broader GWF hold up to 3 Tcf (84.9 Bcm) of recoverable gas and 100 MMbbl (15.9 Gl) of recoverable condensate (Woodside, 2013e).The Greater Western Flank Project will maintain offshore supply to the Karratha Gas Plant for both domestic gas and LNG (Woodside Petroleum Ltd, 2011d).

The Scarborough gas accumulation is being developed jointly by Esso Australia Resources Pty Ltd (operator; an affiliate of ExxonMobil) and BHP Billiton. Recent developments in the accumulation include the drilling of the appraisal well North Scarborough 1 ST1, extending the Scarborough gas resource (Figure 2; BHP Billiton, 2012). During November 2013, environmental approval was granted for a floating liquid natural gas (FLNG) development option for this accumulation (Klinger, 2013); however further engineering and design work will be undertaken before an FID is announced (ExxonMobil, 2013).

The announcement of a gas discovery at Glencoe 1 in June 2008 marked the first of three discoveries in 2008 within WA-390-P (Hess, 100 per cent). Sixteen wells were drilled in the permit with 13 announced as discoveries. The appraisal program of the discoveries was completed in mid-2012 with the drilling and flow testing of Glencoe 2 2H, the last well drilled. The combined project is now known as Equus (Hess, 2013). Development plans for Equus continued through 2012 with the awarding of front-end engineering design (FEED) contracts. Negotiations for the formation of partnerships with potential liquefaction players has continued throughout 2013 (Hess, 2013).

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SPENCER, L., SAYERS, J., BRADSHAW, J., BRADSHAW, M., FOSTER, C., MURRAY, A., EDWARDS, D., ZUCCARO, G., BUCHANAN, C. AND APPS, H., 1995—Australian Petroleum Systems Exmouth Plateau & Outer Rankin Platform Module. Australian Geological Survey Organisation Record, 1995/80, 365pp.

STAGG, H.M.J., ALCOCK, M.B., BERNARDEL, G., MOORE, A.M.G., SYMONDS, P.A. AND EXON, N.F., 2004—Geological framework of the Outer Exmouth Plateau and adjacent ocean basins. Geoscience Australia Record, 2004/13, 160pp. https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS&catno=60864 (last accessed 15 January 2013).

STAGG, H.M.J. AND COLWELL, J.B., 1994—The structural foundations of the Northern Carnarvon Basin. In: Purcell, P.G. and Purcell, R.R. (eds), The Sedimentary Basins of Western Australia: Proceedings of the Petroleum Exploration Society of Australia Symposium, Perth, 1994, 349–364.

SUMMONS, R.E., BRADSHAW, M., CROWLEY, J., EDWARDS D.S., GEORGE, S.C. AND ZUMBERGE, J.E., 1998—Vagrant oils: geochemical signposts to unrecognised petroleum systems. In: Purcell, P.G. and Purcell, R.R. (eds), The Sedimentary Basins of Western Australia: Proceedings of Petroleum Exploration Society of Australia Symposium, Perth, 1998, 169–184.

TAO C., BAI G., LIU J., DENG C., LU X., LIU H. AND WANG D., 2013—Mesozoic lithofacies, palaeogeography and petroleum prospectivity in North Carnarvon Basin, Australia. Journal of Palaeogeography, 2 (1), 81-92.

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THOMAS, G.P., LENNANE, M.R., GLASS, F., WALKER, T., PARTINGTON, M., LEISCHNER, K.R. AND DAVIS, R.C., 2004—Breathing new life into the eastern Dampier Sub-basin: an integrated review based on geophysical, stratigraphic and basin modelling evaluation. The APEA Journal, 44(1), 123–150.

TINDALE, K., NEWELL, N., KEALL, J. AND SMITH, N., 1998—Structural evolution and charge history of the Exmouth Sub-basin, Northern Carnarvon Basin, Western Australia. In: Purcell, P.G. and Purcell, R.R. (eds), The Sedimentary Basins of Western Australia 2: Proceedings of the Petroleum Exploration Society of Australia Symposium, Perth, 1998, 447–472.VAN AARSSEN, R., ALEXANDER, R. AND KAGI, R.I., 1996—The origin of Barrow Sub-basin crude oils: a geochemical correlation using land-plant biomarkers. The APPEA Journal, 36(1), 131–144.

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VON RAD, U., EXON, N.F., BOYD, R. AND HAQ, B.U., 1992a—Mesozoic paleoenvironments of the rifted margin off NW Australia (ODP Legs 122/123). American Geophysical Union, Geophysical Monograph, 70, 157–184.

VON RAD, U., HAQ, B.U. AND OTHERS, 1992b—Proceedings of Ocean Drilling Program, Initial Reports, 122. Ocean Drilling Program, College Station, Texas, 934pp.

WESTPHAL, H. AND AIGNER, T., 1997—Seismic stratigraphy and subsidence analysis in the Barrow-Dampier Sub-basin, northwest Australia. AAPG Bulletin, 81(10), 1721–1749.

WILLIAMSON, P.E. AND KROH, F., 2007—The role of amplitude versus offset technology in promotion of offshore petroleum exploration in Australia. The APPEA Journal, 47(1), 161–174.

WOODSIDE, 2010—[Web page] Woodside Annual Report 2010. http://www.woodside.com.au/Investors-Media/Annual-Reports/Documents/Woodside%20Interactive%20Annual%20Report%202010.pdf (last accessed 6 November 2013).

WOODSIDE, 2013a—[Web page] Pluto LNG Project.http://www.woodside.com.au/Our-Business/Pluto/Pages/default.aspx (last accessed 4 November 2013).

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WOODSIDE, 2013c—[Web page] North West Shelf Project. http://www.woodside.com.au/Our-Business/North-West-Shelf/Pages/default.aspx (last accessed 4 November 2013).

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WOODSIDE, 2013d—[Web page] Vincent. http://www.woodside.com.au/Our-Business/Australia-Oil/Pages/Vincent.aspx (last accessed 4 November 2013).

WOODSIDE, 2013e—[Web page] Greater Western Flank. http://www.woodside.com.au/Our-Business/North-West-Shelf/Projects/Pages/Greater-Western-Flank.aspx (last accessed 4 November, 2013).

WOODSIDE OFFSHORE PETROLEUM PTY LTD, 1988—A review of the petroleum geology and hydrocarbon potential of the Barrow-Dampier Sub-basin and environs. In: Purcell, P.G. and Purcell, R.R. (eds), The North West Shelf Australia: Proceedings of the Petroleum Exploration Society of Australia Symposium, Perth, 1988, 115–128.

WOODSIDE PETROLEUM LTD, 2010—[Web page] Gas Discovery at Alaric. ASX Announcement. http://www.woodside.com.au/Investors-Media/Announcements/Documents/16.08.2010 Gas Discovery at Alaric.pdf 16 August 2010 (last accessed 4 November 2013).

WOODSIDE PETROLEUM LTD, 2011a—[Web page] Annual Investor Update. http://www.woodside.com.au/investors-media/announcements/documents/25.11.11 annual investor update.pdf (last accessed 4 November 2013).

WOODSIDE PETROLEUM LTD, 2011b—[Web page] Gas Discovery at Martin-1. http://www.woodside.com.au/investors-media/announcements/documents/17.03.2011%20gas%20discovery%20at%20martin-1.pdf (last accessed 4 November 2013).

WOODSIDE PETROLEUM LTD, 2011c—[Web page] Production Commences from Okha FPSO.. http://www.woodside.com.au/Investors-Media/Announcements/Documents/26.09.2011 Production Commences From Okha FPSO.pdf (last accessed 4 November 2013).

WOODSIDE PETROLEUM LTD, 2011d—[Web page] North West Shelf Project participants approve Greater Western Flank Phase 1 Project. http://www.woodside.com.au/Investors-Media/Announcements/Documents/08.11.12%20NWS%20Project%20Approves%20Greater%20Western%20Flank%20Phase%201%20Project.pdf (last accessed 18 November 2013).

WOODSIDE PETROLEUM LTD, 2012—[Web page] Woodside reports 2012 half-year profit of $812 Million. http://www.woodside.com.au/Investors-Media/Announcements/Documents/22.08.2012%20Woodside%20Reports%202012%20Half-Year%20Profit%20of%20$812m.pdf (last accessed 4 November 2013).

WOODSIDE PETROLEUM LTD, 2013a—[Web page] First Quarter Report for period ended 31 March 2013 http://www.woodside.com.au/Investors-Media/Announcements/Documents/18.04.2013%20First%20Quarter%202013%20Report.pdf (last accessed 6 November 2013).

WOODSIDE PETROLEUM LTD, 2013b—[Web page] Third Quarter Report for period ended 30 September 2013. http://www.woodside.com.au/Investors-Media/Announcements/Documents/17.10.2013%20Third%20Quarter%20Report%20for%20period%20ended%2030%20September%202013.pdf (last accessed 6 November 2013).

WOODSIDE PETROLEUM LTD, 2013c—[Web page] North Rankin Redevelopment Project Achieves Start Up. http://www.woodside.com.au/Investors-Media/Announcements/Documents/07.10.13%20North%20Rankin%20Redevelopment%20Project%20Achieves%20Start-Up.pdf (last accessed 6 November 2013).

AUSTRALIA 2014 Offshore Petroleum Exploration Acreage Release 25

%

% Seismic section figure location

Fault

Syncline

Oil pipelineGas pipelineGas pipeline (proposed)

Basin outlineSub-basin outline

%

%

%

%%

%

FLIN

DERS F.S.

SH

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ND F.S.

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ROSEMARY F.S.

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h

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Figure 7

Figure 6

Scarborough

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Gorgon

Phoenix

WombatPlateau

NORTHERN CARNARVON BASIN

Exmouth Plateau

InvestigatorSub-basin

ExmouthSub-basin

BarrowSub-basin

DampierSub-basin

RankinPlatform

BeagleSub-basin

Lambert Shelf

BedoutSub-basin

RowleySub-basin

ROEBUCKBASIN

Argo Abyssal Plain

Gascoyne Abyssal Plain

Cuvier Abyssal Plain

BernierPlatform

SOUTHERN CARNARVON BASINGascoyneSub-basin

MerlinleighSub-baisn

PeedamullahShelf

Dampier

Exmouth

WESTERN AUSTRALIA

BarrowIsland

Thebe

118°116°114°112°

16°

18°

20°

22°

13-7715-1

Pipeline and field outlines are provided by Encom GPinfo, a Pitney Bowes Software (PBS) Pty Ltd product. Whilst all care is taken in the compilation of the field outlines by PBS, no warranty is provided re the accuracy or completeness of the information, and it is the responsibility of the Customer toensure, by independent means, that those parts of the information used by it are correct before any reliance is placed on them.

NTQLD

NSW

TAS

VIC

WASA

0 100 km

Oil field

Gas field

Figure 1 Structural elements of the Northern Carnarvon Basin and adjacent basins showing the locations of regional seismic sections and petroleum accumulations

AUSTRALIA 2014 Offshore Petroleum Exploration Acreage Release 26

Well symbol information is sourced either from "open file" data from titleholders where this is publicly available as at 1 November 2013 or from other public sources. Pipelines and field outlines are provided by Encom GPinfo, a Pitney Bowes Software (PBS) Pty Ltd product. Whilst all care is taken in the compilation of the field outlines by PBS, no warranty is provided re the accuracy or completeness of theinformation, and it is the responsibility of the Customer to ensure, by independent means, that those parts of the information used by it are correct before any reliance is placed on them.

WESTERNAUSTRALIA

See Inset A

See Inset B

Fletcher

Scafell

Sage

Echo/Yodel

Rankin

Halyard

Zola

Finucane South

Rosella North

RosellaSouth

GungurruUnicorn

Haycock

Balnaves

Antiope

Keto

Brocket

Okapi

WickhamDampier

Exmouth

KarrathaRoebourne

Wanaea

Egret

Wandoo

Woollybutt

Legendre

Stybarrow

Hermes

Oryx

Corowa

Leatherback

Amulet

Blencathra

Chamois

Exeter

Griffin

Lambert

SkiddawLaverda

Coniston/Novara

Mutineer

Tusk

Cossack Hurricane

South Pepper

Dixon

Ridley

Talisman

Eskdale

North Herald

Eaglehawk

Antler

Io/Jansz

Scarborough

Gorgon

Eurytion

Perseus

Pluto

Spar

Goodwyn

Maenad

Wheatstone

Geryon

Angel

Iago

Orthrus

Julimar

Chrysaor

Keast/Dockrell

Pyrenees/Macedon

Caribou

East Spar

Dionysus

Tubridgi

NorthRankin

West Tryal Rocks

Corvus

Errol (Flinders Shoal)

Urania

Brunello

Lady Nora

WilcoxBrulimar

Tidepole

Elk

Sculptor

Reindeer

Chinook/Scindian

Gaea

EnfieldNasutus

Montague

Saffron

Vincent/Van Gogh

Bleaberry West

Pemberton

RavensworthCrosbyStickle

Harrison

StagClioAcme

Thebe

Satyr

Gaius

Mardie

Sappho

Larsen

Nimrod

Outtrim

Toporoa

Rimfire

Noblige

Mentorc

Martell

Chandon

Achilles

Brederode

Yellowglen

Rough Range

Kentish Knock

Glenloth

Jupiter

0 100 km

NTQLD

NSW

TAS

VIC

WASA

13-7715-2

See Inset C

Highgrove

Josephine

BarrowIsland

Doric

Pasco

Narvik

Campbell

Rose

Linda

Sinbad

Lee

Bambra EastKultarr

Baker

Monty

BarrowIsland

WonnichBambra

Gipsy

West Cycad

WA

Crest

Blackthorn

Saladin

Roller

ChervilTaunton

Australind

Yammaderry

Coaster

Cowle

Cadell

Skate

South Chervil

Onslow

Elder

Cyrano

Inset A

Inset B

Maitland

Zephyrus

GingerArtreus

Mohave

Albert

Rosette

Alkimos

NorthMarra

Harriet

Simpson

Tanami

Victoria

Pedirka

South Plato

Agincourt

Gudrun

Double Island

Little Sandy

Monet

Hoover

North Alkimos

North Pedirka

Gibson

Inset C

0 10 km

0 10 km

0 5 km

115°00' 115°15'

115°30'

117°116°115°114°113°112°

20°

21°

22°

21°30'

23°

115°35'

20°40'

115°45'115°30'

20°30'

20°45'

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Floating production storage andoffloading vessel

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Oil field

Gas subsea tiebackOil subsea tieback

Gas pipeline (proposed)

Oil pipeline

Conventional oil platform

Conventional gas platform

Onshore oil plant

Onshore gas plant

Monopod/Minipod

Abandoned field' Petroleum exploration well - Oil

discoveryPetroleum exploration well - Gasdiscovery

*'* Petroleum exploration well - Oil

and gas discovery

Road

Gas pipeline

Figure 2 Petroleum production facilities, petroleum fields and current and proposed pipeline infrastructure in the Northern Carnarvon Basin

AUSTRALIA 2014 Offshore Petroleum Exploration Acreage Release 27

%

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BarrowSub-basin

DampierSub-basin

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BeagleSub-basin

Lambert Shelf

BedoutSub-basin

RowleySub-basin

ROEBUCKBASIN

Argo Abyssal Plain

Gascoyne Abyssal Plain

Cuvier Abyssal Plain

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Exmouth

WESTERN AUSTRALIA

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Thebe

118°116°114°112°

16°

18°

20°

22°

13-7715-3

Well symbol information is sourced either from "open file" data from titleholders where this is publicly available as at 1 November 2013 or from other public sources. Pipelines and field outlines are provided by Encom GPinfo, a Pitney Bowes Software (PBS) Pty Ltd product. Whilst all care is taken in thecompilation of the field outlines by PBS, no warranty is provided re the accuracy or completeness of the information, and it is the responsibility of the Customer to ensure, by independent means, that those parts of the information used by it are correct before any reliance is placed on them.

NTQLD

NSW

TAS

VIC

WASA

0 100 km

Oil field

Gas field

Petroleum exploration well - Oil discovery with gas show'+Petroleum exploration well - Gas discovery with oil showµ*

Petroleum exploration well - Oil discovery'Petroleum exploration well - Gas discovery*Petroleum exploration well - Oil and gas discovery'*

Petroleum exploration well - Drilled 2013'

%

% Seismic section figure locationBasin outlineSub-basin outlineOil pipelineGas pipelineGas pipeline (proposed)

Figure 3 Petroleum fields and well locations in the Northern Carnarvon Basin, highlighting wells drilled in 2013

AUSTRALIA 2014 Offshore Petroleum Exploration Acreage Release 28

Gorgon

Phoenix

WombatPlateau

NORTHERN CARNARVON BASIN

Exmouth Plateau

InvestigatorSub-basin

ExmouthSub-basin

BarrowSub-basin

DampierSub-basin

Beagle Sub-basin

Lambert Shelf

BedoutSub-basin

RowleySub-basin

ROEBUCKBASIN

Argo Abyssal Plain

Gascoyne Abyssal Plain

Cuvier Abyssal Plain

BernierPlatform

SOUTHERN CARNARVON BASINGascoyneSub-basin

MerlinleighSub-baisn

PeedamullahShelf

Dampier

Exmouth

WESTERN AUSTRALIA

Scarborough

Io/Jansz

RankinPlatform

BarrowIsland

118°116°114°112°

16°

18°

20°

22°

13-7715-4

Well symbol information is sourced either from "open file" data from titleholders where this is publicly available as at 1 November 2013 or from other public sources. Pipelines and field outlines are provided by Encom GPinfo, a Pitney Bowes Software (PBS) Pty Ltd product. Whilst all care is taken in thecompilation of the field outlines by PBS, no warranty is provided re the accuracy or completeness of the information, and it is the responsibility of the Customer to ensure, by independent means, that those parts of the information used by it are correct before any reliance is placed on them.

NTQLD

NSW

TAS

VIC

WASA

0 100 km

Oil field

Gas field

Oil pipelineGas pipelineGas pipeline (proposed)

Basin outlineSub-basin outline

Gravity (µm/s2)

0-200-400

200400

Figure 4 Residual Bouguer satellite gravity data for the Northern Carnarvon Basin. Data derived from the DNSC08GRA satellite altimetry derived gravity dataset (Andersen et al, 2010)

AUSTRALIA 2014 Offshore Petroleum Exploration Acreage Release 29

10

20

30

40

50

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120

130

140

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190

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240

250

260

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Guadalupian Capitanian

InduanOlenekianEarly

Anisian

LadinianMiddle

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Carnian

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Rhaetian

Hettangian

Sinemurian

Pliensbachian

Toarcian

AalenianBajocian

BathonianCallovian

Middle

Early

Jura

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Oxfordian

Kimmeridgian

Tithonian

Late

Berriasian

Valanginian

Hauterivian

Barremian

Aptian

Cre

tace

ous

Albian

Early

Cenomanian

Turonian

ConiacianSantonian

Campanian

Late

Maastrichtian

Danian

SelandianThanetian

Ypresian

Lutetian

Bartonian

Priabonian

Eocene

Paleocene

Pale

ogen

e

Rupelian

ChattianOligocene

Aquitanian

Burdigalian

LanghianSerravallianTortonian

MessinianZanclean

PiacenzianGelasianCalabrian

IonianTarantianHolocene

Pleistocene

Pliocene

Miocene

Neo

gene

Quaternary

lmio

beoc

bter

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WalcottFormation

WilcoxFormation

DockrellFormation

ToolongaCalcilutite

GearleSiltstone

WindaliaRadiolarite

MuderongShale

UndifferentiatedBarrowGroup

AtholFormation

MuratSiltstone

BrigadierFormation

MungarooFormation

PilgramunnaFormation

TreallaLimestone

UnnamedTulki

Limestone

BullaraLimestone

ManduLimestone

GiraliaCalcarenite

CardabiaCalcarenite

KorojonCalcarenite

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LockerShale

DelambreFormation

DelambreFormation

DelambreFormation

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ManduLimestone

ManduLimestone

ManduLimestone

BrigadierFormation

BrigadierFormation

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LockerShale

LockerShale

LockerShale

LockerShale

ChintyFormation

ChintyFormation

NorthRankin

Formation

CalypsoFormation

CalypsoFormation

CalypsoFormation

LegendreFormation

LegendreFormation

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Wal

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BareFormation

BareFormation

TreallaLimestone

TreallaLimestone

TreallaLimestone

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13-7715-6

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MiriaFormation

MiriaFormation

LambertFormation

LambertFormation

LambertFormation

BiggadaFormation

MiriaFormationMiria

Formation

LambertFormation

LambertFormation

ExmouthSandstone

MungarooFormation

MungarooFormation

EliassenFormation

ToolongaCalcilutite

BeedagongClaystone

MungarooFormation

WindaliaRadiolarite

MungarooFormation

Brig

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JanszSandstone

DingoClaystone

DupuyFormation(includingEskdaleMember)

UndifferentiatedBarrow Group

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Macedon andPyreneesMembers)

MuderongShale

MardieGreensand

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KorojonCalcarenite

MiriaFormation

WindaliaSand

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FlagSandstone

CossignyMember

WindaliaSand

Member

WindaliaSand

Member

M.australisSandstoneMember

M.australisSandstoneMember

CossignyMember

CossignyMember

CossignyMember

Period Epoch StageAge(Ma)

Basinphases Exmouth Plateau Exmouth Sub-basin Barrow Sub-basin Beagle Sub-basin Rankin PlatformDampier Sub-basin

Cap

e R

ange

Gro

upW

inni

ng G

roup

Win

ning

Gro

up

Cap

e R

ange

Gro

up

Cap

e R

ange

Gro

up

Cap

e R

ange

Gro

up

Cap

e R

ange

Gro

up

Win

ning

Gro

up

Win

ning

Gro

up

Win

ning

Gro

up

Win

ning

Gro

up

Barro

w G

roup

Barro

w G

roup

Barro

w G

roup

Seismic horizon(AGSO, 2001)

Figure 5 Stratigraphy and hydrocarbon discoveries of the Northern Carnarvon Basin based on the Northern Carnarvon Basin Biozonation and Stratigraphy Chart (Kelman et al, 2013). Geologic Time Scale after Gradstein et al (2012). Regional seismic horizons after AGSO (2001)

AUSTRALIA 2014 Offshore Petroleum Exploration Acreage Release 30

0

Two-

way

tim

e (s

)

0

50 km

Line 110/03

SENW

10

8

6

4

2

Cossigny 1Ronsard 1

Valanginian

Base

Late Miocene

Base Miocene

Mid Oligocene

Top Permian

Late Carboniferous

Basement

Turonian

BaseCretaceous

Base Eocene

AptianCallo v ian

Intra Triassic

13-7715-7

Jurassic

CenozoicBase

Beagle Sub-basin Lambert ShelfExmouthPlateau

Delambre 1

Figure 6 AGSO seismic line 110/03 across the southwestern Beagle Sub-basin and Lambert Shelf. Interpretation after AGSO (2001). Location of the seismic line is shown in Figure 1. Regional seismic horizons are shown in Figure 5

AUSTRALIA 2014 Offshore Petroleum Exploration Acreage Release 31

0

Two-

way

tim

e (s

)

0

50 km

Line 101r/09

Rosemary 1 Hampton 1NW

2

4

6

8

10

Base Eocene

Base Cretaceous

Late CarboniferousTop Permian

Basem

ent

Late Miocene

Mid OligoceneBase Miocene

Turonian

ValanginianAptian

Intra Triassic

13-7715-8

Base

Jura

ssic

Exmouth PlateauRankin

Platform Dampier Sub-basin

Cenozoic

Base

Callovian

Strickland 1SE

Goodwyn 7

Figure 7 AGSO seismic line 101r/09 across the central Exmouth Plateau and Dampier Sub-basin. Interpretation after AGSO (2001). Location of the seismic line is shown in Figure 1. Regional seismic horizons are shown in Figure 5

AUSTRALIA 2014 Offshore Petroleum Exploration Acreage Release 32

0

Two-

way

tim

e (s

)

0

Line 110/12

2

4

6

8

10

Investigator 1Eendracht 1SENW

Base EoceneBase Cenozoic

Late Miocene

Top Permian

Valanginian Turonian

Mid Oligocene

Aptian

Base Cretaceous

Late Carboniferous

Basement

IntraTriassic

Callovian

Triassic

13-7715-9

Volcanics

Exmouth Plateau Exmouth Sub-basinExmouth Plateau

50 km

Ramillies 1

Top

Investigator Sub-basin Barrow Sub-basin

Figure 8 AGSO seismic line 110/12 across the western Exmouth Plateau, northern Investigator Sub-basin, northern Exmouth Sub-basin and southwestern Barrow Sub-basin. Interpretation after AGSO (2001). Location of the seismic line is shown in Figure 1. Regional seismic horizons are shown in Figure 5

AUSTRALIA 2014 Offshore Petroleum Exploration Acreage Release 33

AlaricEendracht

Vinck

Sirius

Zeewulf

Nimblefoot

GlencoeBriseis

Jupiter

Thebe

Kentish Knock

Chandon

Martell Noblige

Saturn

Lago

Clio

Venture

Haycock

Falcone

Rivoli

Cape Range

Rough RangeParrot Hill

ResolutionNovara

Topaz

PascoPepper

Gungurru

ForestierAjax

Fletcher

Scarborough

Io/Jansz

EskdaleStybarrow Enfield

Tubridgi

Skate

ImmortelleBennet

Cyrano

Santa Cruz

Gorgon

Pluto

WheatstoneGoodwyn

Perseus

Wandoo

Stag

NorthRankin

Barrow Island

Maitland

East Spar

John Brookes

CorvusReindeer Saffron

Legendre

Angel

Iago

Maenad

Mutineer

Exmouth

Dampier

WESTERN AUSTRALIA

116°114°112°

20°

22°

0 100 km

NTQLD

NSW

TAS

VIC

WASA

Field outlines are provided by Encom GPinfo, a Pitney Bowes Software (PBS) Pty Ltd product. Whilst all care is taken in the compilation of the field outlines by PBS, no warranty is provided re the accuracy or completeness of the information, and it is the responsibility of the Customer to ensure, by independent means, that those parts of theinformation used by it are correct before any reliance is placed on them.

13-7715-10

Locker-Mungaroo/Barrowtotal petroleum systemDingo-Mungaroo/Barrowtotal petroleum systemLimit of Coastal Waters

Rankin Platform

Reservoir age. (Formation)

Paleocene

Barremian

Valanginian and Berriasian

Tithonian, Oxfordian and Middle Jurassic

Late Triassic (Brigadier andMungaroo formations)

Oil fields anddiscoveries

Gas fields anddiscoveries

Figure 9 Petroleum systems of the Northern Carnarvon Basin (Bishop, 1999), with the reservoir age of the major oil and gas accumulations shown