Northern Carnarvon Regional Geology

The Northern Carnarvon Basin is the southernmost of the late Paleozoic to Cenozoic basins that form the northwest 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 in the basin is up to 15 000 m thick and dominated by deltaic to marine siliciclastics and shelfal carbonates of Mesozoic to Cenozoic age.

The location of discovery wells is shown in Figure 1 and highlighted are wells drilled since late 2015. The stratigraphy of the basin is shown in Figure 3. Figure 4 and Figure 5 show regional seismic lines across the basin. Figure 6 shows the active permits and their operators across the basin. Figure 7 shows the Commonwealth Marine Reserve Zones and Key Ecological Features.

The 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). A regional tectonostratigraphic model of the North West Shelf, which includes the Northern Carnarvon Basin, has recently been developed by Marshall and Lang (2013).

The offshore basin consists of three broad structural zones  (Figure1):

• an inboard, structural high (the Lambert and Peedamullah shelves);
• an intermediate zone of large depocentres (the Beagle, Dampier, Barrow and Exmouth sub-basins); and
• a large outboard area (the Exmouth Plateau) and its uplifted inboard margin (the Rankin Platform).

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

Multiple phases of extension, which culminated in the Jurassic to Early Cretaceous breakup of the northwest Australian continental margin, produced a dominant northeast structural grain, which is evident from the alignment of major faults and depocentres. A secondary north to north-northwest trend is also apparent, particularly in accommodation zones and associated faults that link the northeast-trending en echelon faults.

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) and Jablonski et al (2013) for the Rankin Platform, Hearty et al (2002) for the Barrow Sub-basin, Woodside Petroleum Ltd (1988) and Barber (1994a) for the Dampier Sub-basin, and Blevin et al (1994) and Lech (2013) for the Beagle Sub-basin.

The main structural elements of the Northern Carnarvon Basin (Figure 1) are described briefly below—two representative seismic sections across the basin are shown in Figure 4 and Figure 5.

Beagle Sub-basin

The Beagle Sub-basin is a structurally complex, northerly trending series of fault blocks, anticlines and troughs. This structural trend is oblique to the regional northeast trend that dominates the other sub-basins inboard of the Rankin Platform. The sub-basin developed through several pre-, syn- and post-rift phases (Lech, 2013). Lateral fault movements dominated the sub-basin’s tectonic evolution in conjunction 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. In contrast to the other sub-basins, the Upper Jurassic succession is thin or absent.

Dampier, Barrow and Exmouth sub-basins

The Dampier, Barrow and Exmouth sub-basins are a series of large rift depocentres (Figure 1), which contain a predominantly Triassic, Jurassic and Lower Cretaceous sedimentary succession (Figure 3, Figure 4 and 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. The Barrow Delta dominates the Lower Cretaceous succession in the Exmouth and Barrow sub-basins (Tindale et al, 1998). By contrast, in the Dampier Sub-basin, marine environments prevailed during the Upper Jurassic and Lower Cretaceous, resulting in the deposition of fine-grained claystones. The sub-basins comprise a series of en echelon troughs separated by structural highs, with an overall northeast trend formed by oblique extension (Romine et al, 1997).

The sub-basins are separated by large Paleozoic–Triassic fault blocks that have been internally faulted, uplifted or rotated. Examples include 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).

The sub-basins are separated from the structural highs 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. 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 predominantly Triassic to Cenozoic sediments have formed over down-faulted or rotated blocks along the faulted margins. These include the Enderby Terrace in the Dampier Sub-basin and the Bruce and North Turtle terraces in the Beagle Sub-basin. From the Silurian to the Late Permian, the terraces were major extensional depocentres. Due to a general westward shift in the locus of extension, they were only moderately affected by subsequent Mesozoic rifting events (Hocking, 1990; Polomka and Lemon, 1996).

Exmouth Plateau

The Exmouth Plateau (Figure 1) is a subsided continental platform that is characterised by a faulted, predominantly Triassic sedimentary succession attaining a maximum thickness of up to 15 000 m. Jurassic sediments are generally thin or absent. The major structural elements of the plateau comprise the Rankin Platform, the Kangaroo Syncline, the Investigator Sub-basin and the 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 shelves

The 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. Silurian–Permian successions underlie parts of the Peedamullah Shelf.

The generalised stratigraphy of the basin, shown in Figure 3, can be related to six tectonic phases, which, in turn, are related to the rifting phases that culminated in the continental breakup of the west Australian margin in the Middle–Late Jurassic and Early Cretaceous:

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)

Hydrocarbon generation, migration and trap formation 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, where shallow marine clastics and carbonates were then deposited (Longley et al, 2002). At the beginning of the Triassic a regional marine transgression deposited the Locker Shale, a predominantly marine claystone and siltstone with minor paralic sandstone and shelfal limestone (Figure 3). The Locker Shale grades upwards to the Middle–Upper Triassic Mungaroo Formation; a thick succession of sandstone, claystone and minor coal that was deposited in a fluvio-deltaic environment. The Mungaroo Delta prograded to the northwest and covered much of the offshore Northern Carnarvon Basin. The upper Mungaroo Formation consists of shoreline sandstone, shallow marine claystone and minor limestone. The Middle Triassic Cossigny Member of the Mungaroo Formation (a paralic siltstone, claystone and limestone unit) is a significant regional seismic marker, particularly in the Beagle Sub-basin. Fluvial and shoreline sandstones of the Mungaroo Formation host the giant gas accumulations on the Rankin Platform. The formation is also considered to be the primary 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 sediments suggests that some clastics may have been delivered via transcontinental river systems from central Australia, Argo Land, West Burma 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 3). On the Wombat Plateau, Upper 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 and Victoria synclines on the eastern Exmouth Plateau where it may have additional gas potential (Bussell et al, 2001; Jablonski et al, 2013). In the Barrow and Dampier sub-basins, the Brigadier Formation is considered to be both a gas source and a reservoir. Thin, reservoir-quality sandstones preserved 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 that isolated 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 present day structural configuration of the Northern Carnarvon Basin. Major bounding faults (e.g. the Rosemary, Flinders and Rankin fault systems) developed and delineated the Barrow, Dampier and Exmouth sub-basins, the Rankin Platform, and the Lambert and Peedamullah shelves (Figure 1). Oblique extension, combined with the pre-existing Proterozoic to Paleozoic northerly structural grain, resulted in en echelon faulting 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 subsidence that is observed, relative to faulting, suggests that lower crustal processes also played a major role during extension (Stagg and Colwell, 1994; Driscoll and Karner, 1998).

Early syn-rift (Toarcian to earliest Callovian)

The Toarcian to earliest Callovian syn-rift succession comprises restricted marine claystone and siltstone (Athol Formation) and regressive deltaic sandstone (Legendre Formation) (Figure 3). By the Bathonian, the Legendre Delta had expanded westward from the Beagle Sub-basin into the Dampier Sub-basin and across the Rankin Platform. Sediment was supplied from fault blocks and platforms on the margins of the depocentre. The Legendre Formation is the likely source of some of the hydrocarbon accumulations in the Dampier Sub-basin (the Legendre–Jaubert and Sage oil accumulations) and in the southern Beagle Sub-basin (Edwards and Zumberge, 2005; Jablonski et al, 2013). It hosts, and is the source of, the gas in the Reindeer and Saffron–Rosemary accumulations (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 4 and Figure 5). This was followed by the main phase of syn-rift deposition in the Northern Carnarvon Basin that commenced with the deposition of the transgressive Callovian Calypso Formation claystone and sandstone in the Barrow and Dampier sub-basins (Figure 3). Major rift-related faults developed along the northern edge of the Exmouth Plateau at this time.

In parts of the basin, the basal Oxfordian unconformity or the ‘Breakup Unconformity’ corresponds to the so-called ‘Main Unconformity’. However, elsewhere, 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).

Post-breakup faulting during the Late Jurassic uplifted and tilted the Exmouth Plateau and the Rankin Platform and allowed them to supply sediment to adjacent depocentres. Rapid tectonic subsidence resulted in the deposition of a thick, deep marine succession (the Dingo Claystone; Figure 3). This unit progressively filled and overlapped the flanks of the Barrow, Dampier and Exmouth sub-basins (Figure 4 and Figure 5; Tindale et al, 1998). During the Oxfordian, a maximum flooding phase 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, shallow-marine sandstones were deposited within restricted depocentres during the Late Jurassic. The Kangaroo Syncline formed on the Exmouth Plateau in response to extensional reactivation of tilted Triassic fault blocks on the Rankin Platform (Jenkins et al, 2003). Coarse clastic sediments derived from the erosion of the Mungaroo Formation in uplifted areas were transported into the syncline until the Berriasian. Upper Jurassic sandstones constitute significant petroleum reservoirs in parts of the Northern Carnarvon Basin. These include turbiditic sandstones of the Biggada, Eliassen, Dupuy and Angel formations, and the shallow-marine to shoreline Jansz Sandstone (Jenkins et al, 2003; Moss et al, 2003; Figure 3). 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 a further episode of uplift and erosion that marked the final major pulse 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 Barrow Delta. The delta system covered a large area and resulted in the deposition of the Barrow Group (Figure 3), which attains a thickness of up to 2500 m. Initial deposition occurred in the Exmouth Sub-basin, fed by sediments 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. Approximately 75% of the Barrow Delta succession is attributed to the lower lobe (Ross and Vail, 1994). A second progradational phase commenced in the late Berriasian and formed the upper Barrow Delta lobe in the Barrow and Dampier sub-basins, 250 km to the east of the delta’s earlier depocentre. As the delta prograded northward towards the Gorgon Horst, the lower Barrow Delta lobe was eroded in the shoreward part of the Exmouth Sub-basin.

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 sandstones, pro-delta to foreset claystones, and top-set sandstones. 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).The sandstones above the Barrow Group are known locally as the Flag Sandstone and Zeepaard Formation (Figure 3). The Flag Sandstone was deposited as a basin-floor fan in the northeast part of the Barrow Sub-basin. In the early Valanginian, deposition of progradational top-set units of the Zeepaard Formation was widespread within the Barrow and Exmouth sub-basins and on the Rankin Platform.

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. Rapid subsidence following breakup resulted in a widespread transgression and the deposition of a fining-upward marine sequence over the unconformity surface.

Deposition in localised paralic and shelfal environments gave rise to the Birdrong Sandstone and the glauconitic Mardie Greensand. This was followed by the basin-wide deposition of the transgressive Muderong Shale, Windalia Radiolarite and Gearle Siltstone (Figure 3). The Muderong Shale forms a regional seal, and for the Barrow Sub-basin, hosts commercial oil accumulations within glauconitic sandstones of the M. australis Sandstone Member. In the Dampier Sub-basin, oil is found in the Windalia Sand Member (Figure 3), which contained over 90% of the initial oil reserves of the Barrow Island oil field (Ellis et al, 1999). During the early Santonian, uplift 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)

By the mid-Santonian, tectonic stability and a decreasing supply of terrigenous sediment caused siliciclastic sedimentation to cease. Prograding shelfal carbonates were deposited on the passive continental margin in the Late Cretaceous and Cenozoic.

During the Campanian, a period of regional compression resulted in uplift of the hinterland and structural inversion in the Exmouth Sub-basin. Further west, compression led to the formation of the Exmouth Plateau Arch, Resolution Arch and Kangaroo Syncline (Figure 1; Tindale et al, 1998). Pre-existing rift-related structures experienced transpressional reactivation within the Dampier and Barrow sub-basins and led to the formation of Barrow Island (Longley et al, 2002; Cathro and Karner, 2006). During the Oligocene and Miocene, prograding shelfal carbonates continued to be deposited (Tindale et al, 1998).

In the Miocene, a major compressional event, associated with the convergence of the Australian and Eurasian 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) and led to the formation of many structural traps within the Cretaceous and Cenozoic sections.

Two Mesozoic petroleum systems have been identified within the Northern Carnarvon Basin. Bradshaw (1993) and Bradshaw et al (1994, 1997) developed a petroleum system and supersystem framework that linked Australian basins by age, facies, tectonic history and hydrocarbon generation history. 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 and 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 in the Northern Carnarvon Basin using 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 systems are considered to be the source of the majority of the commercial petroleum discoveries within the basin.

The gas-prone ‘Locker/Mungaroo–Mungaroo/Barrow’ Petroleum System covers most of the basin and extends to the margins of the Exmouth Plateau. The primary source rock for this petroleum system is the Upper Triassic deltaic Mungaroo Formation (and marine equivalents) with a possible secondary contribution from organic-rich marine units in the Lower Triassic Locker Shale. The majority of recent exploration on the Exmouth Plateau has been based on a model that invokes gas charge from deeply buried coals and carbonaceous claystones within 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 that have been predominantly sourced from fluvio-deltaic Triassic to Lower–Middle Jurassic source rocks in the Bonaparte, Browse and Northern Carnarvon basins. Similarities between carbon isotopic profiles of gases and condensates within the Westralian Superbasin reflect recurring organofacies that existed in the fluvio-deltaic environments developed from the Triassic to the 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 by 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 have been termed ‘vagrants’ by Summons et al (1998) and used as evidence that additional source rocks have been generating hydrocarbons within the basin. For example, lacustrine sources have been ascribed to the Nebo 1 oil accumulation in the Beagle Sub-basin, and to oils recovered at Parrot Hill 1 and Rough Range 1, 1A in the onshore Exmouth Sub-basin (Longley et al, 2002; Edwards and Zumberge, 2005).

Source rocks

The primary 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 a secondary contribution from the overlying Lower–Middle Jurassic marine and deltaic Murat Siltstone and Athol/Legendre formations (Figure 3). Geochemical studies indicate that the gas accumulations on the Rankin Platform accessed both Triassic and Lower–Middle Jurassic source rocks 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 primarily charged from deeply buried coal and carbonaceous claystone in the Mungaroo Formation (Cook et al, 1985; Bussell et al, 2001). A secondary contribution from the Locker Shale has not been discounted.

The principal oil-prone source rock in the Barrow, Dampier and Exmouth sub-basins is the Upper Jurassic Dingo Claystone (Figure 3). The unit was deposited in deep water, restricted marine conditions within incipient rifts that developed along the northern and northwestern continental margin during the breakup of Gondwana. 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 preserved within the marine claystones (Summons et al, 1998; Edwards and Zumberge, 2005).

Reservoirs and seals

Reservoir rocks in the Northern Carnarvon Basin are dominated by fluvio-deltaic and marginal marine sandstones 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 3). In addition, Upper Triassic carbonate reefs may constitute valid reservoirs on the outboard Exmouth Plateau (Grain et al, 2013).

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

Intraformational seals commonly form stacked hydrocarbon-bearing reservoirs in the basin. Gas accumulations on the Rankin Platform are top-sealed by a combination of regional seals 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-related roll-over anticlines. Stratigraphic traps in the basin are formed by basin-floor and turbidite fan sands, and unconformity pinch-outs and onlaps. Structural compartmentalisation of the basin has resulted in complex trap evolution and charge histories.

Timing of generation

Hydrocarbon generation from the Dingo Claystone commenced in the Exmouth Sub-basin and southern parts of the Barrow Sub-basin in the Early Cretaceous as a consequence of sediment loading by the Barrow Delta (Tindale et al, 1998; Smith et al, 2003). In the Beagle Sub-basin, hydrocarbon generation from Lower–Middle Jurassic source rocks began prior to the deposition of the Lower Cretaceous Muderong Shale regional seal. Loading of the sub-basin during the Cenozoic, due to the deposition of a carbonate wedge, has driven late-stage maturation. As a result, there is the possibility that hydrocarbons generated during the Cenozoic may have been trapped and preserved (Lech, 2013).The main phase of hydrocarbon generation in the Dampier Sub-basin was also driven by the progradation of a Cenozoic carbonate shelf across the sub-basin (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; Bussell et al, 2001).

The first flow of oil from a well to the surface in Australia was recorded in 1953 at Rough Range 1 in the onshore Exmouth Sub-basin. Oil flowed at a rate of 500 bopd (79.5 kl/d) from the Lower Cretaceous Birdrong Sandstone. Subsequent appraisal drilling on the Rough Range feature 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. In 1968, the discovery of oil by Legendre 1 stimulated exploration in the Dampier Sub-basin. In 1972 and 1973, further discoveries were made at Angel and Lambert. A series of multi-Tcf gas discoveries were made on the adjacent Rankin Platform (Goodwyn, North Rankin/Perseus and Rankin; Barber, 1994a, 1994b; Thomas et al, 2004). In 1972, gas discoveries were made in Triassic sandstones at West Tryal Rocks 1 in the Barrow Sub-basin. In the same year, the first gas shows were recorded in the Exmouth Sub-basin by West Muiron 1.

Significant gas discoveries were made in the late 1970s to early 1980s. In 1979, a giant gas accumulation within a Lower Cretaceous Barrow Group basin-floor fan sand was discovered at Scarborough 1, in relatively deep water on the Exmouth Plateau. Scarborough is estimated to hold 5.2 Tcf (147.2 Bcm) of gas, or 882.5 MMboe (Barber, 2013). The gas discovery at Spar 1 (1976), in the Barrow Sub-basin, was also made in Lower Cretaceous sandstones. Discovered in 1981 the Gorgon field is one of the largest gas accumulations in the basin, and has a resource of 16.8 Tcf (475.7 Bcm) of gas and 121 MMbbl (19.2 Gl) of liquids for a total of 2976.2 MMboe (Barber, 2013).

From the early 1980s to the mid-1990s, a number of predominantly medium-sized oil and gas discoveries were made in the Barrow and Dampier sub-basins as a result of 2D seismic surveys that were acquired with high line densities (Longley et al, 2002). These included South Pepper, Chervil, Harriet, Outtrim, Rosily and Saladin in the southern Barrow Sub-basin (Baillie and Jacobson, 1997); East Spar and Wonnich to the 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). During this period, Maitland 1 (1992) discovered gas in a sandstone near the base of the Paleocene in the Barrow Sub-basin (Sit et al, 1994). In 1993, the oil discovery by Nebo 1 stimulated exploration interest into the under-explored Beagle Sub-basin (Osborne, 1994). In 1982, oil was discovered by Novara 1 in the Exmouth Sub-basin; however, the biodegraded nature of the Novara oil (16.7°API; Smith et al, 2003) proved to be a disappointment. Exploration on the Rankin Platform and adjacent Exmouth Plateau continued to target Triassic fault block and intra-Triassic plays. This resulted in the discovery of Chrysaor in 1994–1995 and Dionysus in 1996.

Major discoveries continued from the mid-1990s to the mid-2000s, punctuated by that of the giant Io–Jansz gas accumulation in 2000 on the Exmouth Plateau. The primary reservoir at Io–Jansz is an Oxfordian shallow-marine sandstone (the ‘Jansz Sandstone’; Figure 3). The gas is thought to have migrated into the Oxfordian sandstone after spilling from a gas-charged Triassic reservoir at Geryon (Jenkins et al, 2003). The Io–Jansz accumulation constitutes the largest gas resource discovered in the basin. It is estimated that the Io–Jansz feature holds 20.1 Tcf (569.2 Bcm) of gas and 16 MMbbl (2.5 Gl) of liquids, for a total of 3436.3 MMboe (Barber, 2013).

Over the period of the mid-2000s to the mid-2010s there has been an increasing focus on the commercialisation of discoveries. Large numbers of ‘step-out’ exploration wells, extension/appraisal wells and development wells have been drilled to delineate and develop accumulations. The relatively high well and seismic data density/coverage over much of the basin is such that the Dampier and Barrow sub-basins, the Rankin Platform and parts of the Exmouth Plateau and Exmouth Sub-basin are now considered to constitute mature exploration provinces. With the application of modern 3D seismic acquisition, seismic reprocessing, and specialised techniques such as seismic amplitude-vs-offset (AVO) modelling, drilling success rates (particularly on the Exmouth Plateau) have improved (Kingsley and Tilbury, 1999; Longley et al, 2002; Korn et al, 2003; Williamson and Kroh, 2007).

For the two years 2015-16, 12 exploration wells had been drilled in the offshore Northern Carnarvon Basin. Pyxis 1 (Woodside Petroleum Ltd, 2015b) and Isosceles 1 (Chevron Australia Pty Ltd, 2015) are reported gas discoveries for the eastern Exmouth Plateau. Davis 1 (Santos, 2016a) and Spartan 1A (The Australian Pipeliner, 2016a) are reported gas discoveries, and Outtrim East 1 (Carnarvon Petroleum Ltd, 2016) is a reported oil discovery, for the Barrow Sub-basin (Figure 1). Reported dry holes include: Levitt 1 (Oil & Gas Australia, 2015) and Hyde 1A (Finder Exploration, 2016) for the northern Exmouth Plateau (Figure 1); Driftwood 1/ST 1 (Offshore Energy Today, 2016) for the Barrow Sub-basin (Figure 1); Malaguti 1 for the Exmouth Sub-basin; Skippy Rock 1/Stokes 1 (Woodside Petroleum Ltd, 2016e) for the Beagle Sub-basin (Figure 1); and Satyr 5 and Snapshot 1 for the central Exmouth Plateau. Woodside has reported plans to continue drilling in the Beagle Sub-basin on the ‘Buttons Crossing’ and ‘Big Brooks’ prospects (Woodside Petroleum Ltd, 2015d).

In 2015 International Ocean Discovery Program (IODP) Expedition 356 sampled the western Australian margin from Fremantle to Darwin (International Ocean Discovery Program, 2015). Several shallow holes were drilled in the Northern Carnarvon Basin and provide some insight into the shallow sedimentary section and seafloor conditions.

In 2016, two marine seismic surveys were conducted in the basin: multi-client NWS Renaissance MC 2D MSS (Dampier and Beagle sub-basins); and Pluto 4D MSS (Rankin Platform) (Woodside Petroleum Ltd, 2016e). In addition, the Gorgon Ocean Bottom Node 3D MSS Survey (Rankin Platform; NOPSEMA, 2015c) was acquired to monitor reservoir behaviour over the Gorgon gas field. Planned surveys beyond 2016 include: Exmouth SLB15 MC3D MSS (Exmouth and Barrow sub-basins; NOPSEMA, 2015a); Capreolus Phase 2 multi-client MSS (Dampier and Beagle sub-basins; NOPSEMA, 2016a); Hockey and Bianchi 3D MSS (Barrow and Exmouth sub-basins; NOPSEMA, 2016b); and Davros Phase 2 multi-client 3D MSS (Dampier Sub-basin; NOPSEMA, 2015b).

In late 2016, BP farmed in with Cue Energy for permit WA-409-P, with an option for permit WA-359-P in 2017, which are adjoining permits overlying the large Ironbark prospect (Cue Energy Resources Ltd, 2016) on the eastern Exmouth Plateau. The prospect targets Mungaroo Formation sands and is estimated to hold up to 15 Tcf (424.8 Bcm) of gas. Also for 2016, Woodside firmed up plans to drill the Swell prospect in WA-483-P, in the Exmouth Sub-basin (Woodside Petroleum Ltd, 2016a).

Dampier and Beagle sub-basins

In the Dampier Sub-basin, re-evaluation of early 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 (Seggie et al, 2003; Figure 2).

During 2012, two wells were drilled southwest of the Legendre accumulation. Hoss 1 encountered oil shows and Jalfrezi 1 contained oil and gas shows. Santos drilled Winchester 1 (Santos, 2013) towards the western margin of the Dampier Sub-basin and Winchester 1 ST1 confirmed the presence of 58 m of net gas pay in the Jurassic Angel and Triassic Mungaroo formations.

The northern extent of production in the Dampier Sub-basin was 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 by the discovery of oil at Fletcher 1 (2007) and Finucane South 1A (2011) by Santos Offshore Pty Ltd (Department of Mines and Petroleum, 2011). The resultant fields have been delineated by several extension/appraisal wells. In March 2014, Santos spudded Vanuatu 1 in WA-54-L (the Fletcher–Finucane production licence), which was plugged and abandoned as a dry hole.

In 2015, three 3D seismic surveys were conducted in the Dampier and Beagle sub-basins: the multi-client Capreolus 3D seismic survey, covering 22 132 km² across the boundary between the Roebuck and Northern Carnarvon basins (including the northern Beagle Sub-basin; Polarcus Ltd, 2015), was conducted by Polarcus Seismic Limited; CGG Services (Australia) Pty Ltd completed Phase 1 of the 11 000 km² Davros 3D seismic survey, which will cover much of the Dampier Sub-basin, as well as areas of the northern Barrow Sub-basin, southern Beagle Sub-basin and central Rankin Platform; and Rosemary 3D seismic survey acquired 9400 km² of 3D seismic data over the Dampier Sub-basin, the southern Beagle Sub-basin, the southern Rankin Platform and the northernmost Barrow Sub-basin.

In 2016, Skippy Rock 1 was drilled by Woodside in the eastern Beagle Sub-basin. It was declared a dry hole (Woodside Petroleum Ltd, 2016e).

Barrow Sub-basin

The Barrow Sub-basin, Barrow Island and the inshore part of the Barrow Island Trend have been foci of exploration since 1964 (Figure 2). Oil production commenced on Barrow Island in 1966 (Ellis et al, 1999).

In 2013, Apache drilled Bianchi 1, 6.4 km north of the Zola 1 gas discovery. Wireline logging and pressure data confirmed the presence of 112 m of net gas pay in the Triassic Mungaroo Formation (Apache Corporation, 2013a). In 2014, although no exploration wells were drilled in the Barrow Sub-basin, TGS acquired 2129 km² of new 3D seismic data (Huzza MC3D survey) across numerous permits in the southern part of the sub-basin. This was followed by the acquisition of 192 km² of multi-client 3D seismic data (Huzza Phase 2 MC3D survey) over the adjacent margins of the Barrow and Exmouth sub-basins. In 2015, the Davros (~11 000 km²) multi-client 3D seismic survey was conducted and included areas of the northern Barrow Sub-basin.

For 2016, Davis 1 was spudded in January by partners Quadrant Energy and Santos, which tested the northern extension of the Maitland field; with Santos reporting the well as a gas discovery, as it encountered hydrocarbons in the ‘Maitland sandstone’ (Santos, 2016a). Outtrim East 1 was spudded in June by partners Carnarvon Petroleum and Quadrant Energy, in the southern part of the basin, to test the eastwards extent of the Outtrim 1 oil discovery, particularly for sandstones of the Lower Cretaceous Barrow Group (Oil & Gas Journal, 2016a). Driftwood 1 was spudded in August by Quadrant Energy to test Lower Cretaceous sandstones, but failed to find hydrocarbons (Offshore Energy Today, 2016). Spartan 1/1A was spudded in September by partners Quadrant Energy and Santos, east of the Maitland gas field, and is a gas discovery (The Australian Pipeliner, 2016a).

Tap Oil has maintained interest in drilling its Palmerston prospect in the Barrow Sub-basin (Tap Oil Ltd, 2016). The structure is argued to be similar to the Triassic fault block setting hosting the Zola 1 gas discovery to its north.

Exmouth Sub-basin

In 1998 and 1999, respectively, the Vincent and Enfield oil discoveries were made in the Exmouth Sub-basin (Figure 2). In 2000, these successes were followed by the Laverda and Scafell oil discoveries. Between 2003 and 2007, numerous successful wells were drilled; these included Bleaberry West, Eskdale, Crosby–Harrison–Ravensworth–Stickle, Langdale, Skiddaw and Stybarrow. Cimatti 1 was drilled by Woodside to test a prospect within tie-back 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. To the north of Cimatti 1, Furness 1 (2010) and Crusader 1 (2011) were drilled by BHP Billiton Petroleum Pty Ltd and Apache. In 2011, Woodside drilled Opel 1 in a separate fault block on the western flank of the Laverda accumulation and encountered oil (Woodside Petroleum Ltd, 2011a).

Exploration wells spudded in the Exmouth Sub-basin during 2012 and 2013 did not encounter commercial hydrocarbons. Palta 1 was drilled by Shell Development (Australia) Pty Ltd in the southern portion of the sub-basin. The well was plugged and abandoned after it failed to encounter significant hydrocarbon shows (Offshore Energy Today, 2013). Other wells drilled during 2013 included: Gumbo 1 (dry well) by Woodside on the northwest flank of the sub-basin, 8 km from the Ragnar 1A gas discovery; Minarelli 1 (dry well) located near the edge of the Enfield oil accumulation (Woodside Petroleum Ltd, 2013a, 2013b); and BHP Billiton’s Stybarrow East 1 (oil shows), drilled northeast of the Stybarrow oil accumulation.

In 2014, two exploration wells were drilled and one 3D seismic survey was undertaken in the Exmouth Sub-basin. In January, BHP Billiton drilled Rydal 1, which encountered non-commercial hydrocarbons. Woodside then drilled Toro 1, which intersected approximately 150 m of gross (65 m of net) gas pay within the Mungaroo Formation (Woodside Petroleum, 2014a). During early 2014, Woodside acquired the Babylon 3D seismic survey (1266 km²) within exploration permit WA-483-P, on the eastern margin of the sub-basin (Woodside Petroleum Ltd, 2013c).

For 2015–16, a single exploration well, Malaguti 1, was drilled by Woodside in the sub-basin. It was declared a dry hole.

In early 2017, NOPSEMA accepted environmental plans submitted by Woodside (NOPSEMA, 2017) to drill Swell 1 in the sub-basin (Woodside Petroleum Ltd, 2016a; Energy News Bulletin, 2016a), which targets a medium-sized prospect previously worked up by BHP Billiton and Apache Energy. It is a Triassic tilted fault-block play with three-way dip closure, hosting sandstone targets in the Mungaroo, Brigadier and Barrow formations.

Rankin Platform and Exmouth Plateau

In recent years, growing demand for LNG in the Asia–Pacific region has stimulated exploration on the Rankin Platform and adjoining Exmouth Plateau (Figure 1). Most wells tested Triassic fault blocks with top and intra-Mungaroo Formation objectives.

On the northern Rankin Platform, exploration drilling by Woodside has sought to extend the area of known accumulations by drilling wells such as Ananke 1 (2012) and Goodwyn North 1 (2013). In the central part of the Rankin Platform (in the vicinity of the Iago, Pluto and Wheatstone gas fields discovered between 2000 and 2005), Eris 1 (2009), Emersons 1 (2011) and Xeres 1A (2011) were also drilled by Woodside. In 2015 Woodside drilled Pyxis 1, just north of the Pluto field on the Exmouth Plateau, and intersected approximately 18.5 m of net gas within the Jurassic sandstone target (Woodside Petroleum Ltd, 2015b). Apache made several significant oil discoveries in the Mungaroo Formation (Balnaves 1–4 and Balnaves Deep 1; Apache Corporation, 2011a) in reservoirs that are distinct from those that host the nearby Julimar and Brunello gas accumulations (discovered in 2007 and 2008, respectively). The appraisal wells Balnaves Deep 2 and 3 were drilled in 2012 and development drilling occurred at Balnaves in 2014. Early in 2014, Apache Energy continued drilling in the Balnaves area with Balnaves West 1, which was plugged and abandoned as a dry hole. Between 2012 and 2014, numerous development wells were drilled at Brunello by Apache, at Wheatstone by Chevron and at Goodwyn, Xena and Tidepole by Woodside. To further assess the Goodwyn accumulation, Woodside acquired the ~4000 km² Fortuna 3D seismic survey across multiple permits on the northern Rankin Platform in 2014. During 2015 the Dunnart 2D seismic survey was also collected over the western Dampier Sub-basin, the central Rankin Platform and Exmouth Plateau, including over the Jansz gas discovery, while the Davros 3D seismic survey also included areas in the central Rankin Platform. The Northern Carnarvon Basin MC3D multi-client survey was commenced in June 2015, with data collection over large areas of the Exmouth Plateau. Over late 2015 to early 2016, Woodside undertook the Pluto four-dimensional time-lapse marine seismic survey (Pluto 4D MSS), on the Rankin Platform and Exmouth Plateau, to better characterise the Pluto gas reservoir (Woodside Petroleum Ltd, 2016b).

In 2012, on the southern Rankin Platform, Chevron drilled Pontus 1, which encountered 97 ft (30 m) of net gas pay. During 2014, development drilling at Gorgon continued. Zola 1 ST 1, to the south of, and on trend with the Gorgon field, encountered 100 m of net gas pay over a 400 m gross interval within the Mungaroo Formation (Apache Corporation, 2011b). Drilled in 2013, Apache’s Olympus 1 discovered gas in the Cretaceous lower Barrow Group and in the Triassic Mungaroo Formation (Finder Exploration, 2013).

Further west, on the central Exmouth Plateau, the Maenad and Orthrus gas accumulations (Figure 1) were discovered in 1999–2000, to the south of the Io–Jansz accumulation. Subsequent gas discoveries at Achilles 1 and Acme 1 led to an increase in the known gas reserves on this part of the plateau. Over 2010–2011, extension and appraisal drilling by Chevron continued at Acme West 1 and 2, Clio 3, Iago 5 and Geryon 2. Also drilled by Chevron in 2010, Orthrus 2 intersected a deeper gas pool to the Orthrus gas accumulation (Department of Mines and Petroleum, 2011). Success at Satyr 1, drilled in 2009, led to further extension and appraisal drilling at Satyr 2–4. These wells confirmed the presence of 128 ft (39 m), 243 ft (74 m) and 220 ft (67 m) of net gas pay, respectively. Satyr 5 was drilled in 2015, and was plugged and abandoned as a dry hole. Chevron drilled Dino North 1 and Isosceles 1 in the area in 2014 and 2015, respectively, both of which encountered gas (Chevron Australia Pty Ltd, 2015).

To the southwest of Io–Jansz are the Briseis, Glencoe and Nimblefoot gas discoveries (Figure 1), made by Hess in 2008. Gas is trapped in the post-Callovian section, though at Briseis 1 there is additional pay in the Triassic Mungaroo Formation (Smallwood et al, 2010). Between 2009 and 2011, Hess drilled 16 wells within WA-390-P, of which 13 are gas discoveries. More recent drilling on the central plateau includes extension and appraisal drilling in 2012 by Hess at Glencoe (Glencoe 2/RE) and exploration drilling by Chevron at Cloverhill 1 in 2014, approximately 20 km north of Glencoe 1.

Exploration on the southern margin of the Exmouth Plateau includes the acquisition of Woodside’s Centaurus 3D survey in WA-478-P (801 km²) (Woodside Petroleum Ltd, 2013c) and the discovery of the Tallaganda and Bunyip gas accumulations. BHP Billiton drilled Tallaganda 1 in 2012 and intersected gas in the Triassic Mungaroo Formation (Tap Oil Limited, 2012). To its south, Bunyip 1 was drilled in 2014 and encountered hydrocarbons (BHP Billiton, 2014).

Just to the north of the giant Io–Jansz field, the gas discoveries at Larsen 1, Larsen Deep 1, Martell 1, Martin 1, Noblige 1 and Remy 1A (Woodside Petroleum Ltd, 2011b; Figure 1) have extended the northerly limit of known gas accumulations on the central Exmouth Plateau. Gas discoveries just west of the Io–Jansz gas accumulation include Chevron’s Chandon 1 (2006) and Yellowglen 1 (2009) and, more recently, Elfin 1 (2013). The latter intersected 132 ft (40 m) of net gas pay in upper Mungaroo Formation sandstones (Chevron Australia Pty Ltd, 2013b).

In 2011, three wells were drilled in the north and east of the Exmouth Plateau. La Rocca 1 was drilled by Apache Northwest Pty Ltd and Galahad 1 and Gawain 1 were drilled by ENI Australia Ltd. In 2012, Woodside sought to define the extent of these gas plays on the plateau and drilled Banambu Deep 1. In 2014, CNOOC Limited acquired a ~2000 km² 3D seismic survey in exploration permit WA-484-P. In 2015–16, the most northeastern well on the plateau, Levitt 1, was drilled by Quadrant Energy. It encountered no hydrocarbons in the targeted Jurassic reservoir, and was plugged and abandoned (Karoon Gas Australia Ltd, 2015). In 2016, Hyde 1A, drilled to the southwest of Levitt 1, also encountered no hydrocarbons, though the Joint Venture partners have identified several other surrounding leads and prospects (Finder Exploration, 2016).

To the central western limit of the Exmouth Plateau, gas discoveries at Brederode 1, Kentish Knock 1, Guardian 1, and Thebe 1 and 2 extended the western limit of known gas accumulations on the outer plateau (Figure 1). In 2012, the discovery in upper Mungaroo Formation sandstones of 45.5 m of net gas pay at Arnhem 1 (Chevron Australia Pty Ltd, 2012), and 75 m of net gas pay at Kentish Knock South 1 (Chevron Australia Pty Ltd, 2013a), have confirmed the extent of these gas plays. The presence of gas south of the Scarborough accumulation was confirmed by the intersection of 60 m of net gas pay in Barrow and Mungaroo sands at Pinhoe 1 (Chevron Australia Pty Ltd, 2012). Also in the area are Chevron’s Lympstone 1 and Blake 1 wells, drilled in 2014, for which results are yet to be announced. In early 2016, Hess drilled Snapshot 1, midway between the Io–Jansz and Scarborough fields, and its status is yet to be reported.

The exploration wells that have been drilled farthest to the west on the Exmouth Plateau are Tiberius 1, Alaric 1, Cadwallon 1, Genseric 1 and Vos 1, which were all drilled by Woodside between 2010 and 2012 (Figure 1). Alaric 1 intersected a 185 m gross gas column (Woodside Petroleum Ltd, 2010) and Cadwallon 1 intersected a 27 m gross gas column (Woodside Petroleum, 2011a). Gas discoveries by Alaric 1, in a reported Triassic target, and Cadwallon 1 suggests that the petroleum plays present on the central and eastern parts of the plateau extend to the deep-water western margin. Vos 1 (drilled by Chevron) encountered 138 m of net gas pay (Chevron Australia Pty Ltd, 2011) and also confirmed the prospectivity of the western margin of the Exmouth Plateau. During 2014, Chevron drilled Royal Oak 1 in WA-367-P, which was a reported gas discovery. For 2014–15 Shell completed its DAB 3D seismic program which comprised data from the Dirk 3D, Adventure 3D and Bart 3D seismic surveys in WA-491-P, WA-439-P and WA-496-P, respectively.

The Northern Carnarvon Basin is one of Australia’s most prolific hydrocarbon-producing basins. As of 2014, 2.7 Bbbl (429.3 Gl) of oil and 16.7 Tcf (472.9 Bcm) of gas have been produced (Geoscience Australia and Bureau of Resource and Energy Economics, 2014). The Northern Carnarvon Basin accounted for 64% of Australia’s crude oil and condensate production in 2014–15 (Department of Industry, Innovation and Science, 2016). The basin is estimated to contain 22.2 Bboe (3529.7 GL) resources (Barber, 2013). Most of the offshore part of the basin is located in Commonwealth waters and is currently under title (NOPTA, 2016) (Figure 6).

The Australian Petroleum Production and Exploration Association (APPEA) reported that there were 15 producing areas/hubs in the Northern Carnarvon Basin during 2014 (APPEA, 2016; Figure 2):

• North West Shelf Venture’s (NWS Venture) North West Shelf Project (NWSP) located primarily on the northern Rankin Platform (fields: Angel, Goodwyn, North Rankin, Perseus, Searipple, Cossack, Wanaea, Lambert and Hermes);
• Pluto LNG project on the Rankin Platform/Exmouth Plateau (fields: Pluto and Xena);
• Devil Creek project (tied in to Reindeer field), 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 in the Barrow Sub-basin; and
• Enfield, Pyrenees, Macedon, Stybarrow, Vincent and Van Gogh in the Exmouth Sub-basin.

Of the above, five produce natural gas—the NWSP, Pluto, Varanus Island Gas Hub, the Devil Creek Gas Plant and the Macedon Domestic Gas Project. The remaining facilities produce, or have produced oil. Oil production from the Balnaves field, on the Rankin Platform, commenced in late 2014, but then ceased in 2016, earlier than predicted (Woodside Petroleum Ltd, 2016j).

For all northern Carnarvon Basin offshore producing fields/hubs (Figure 2) the latest APPEA full year production figures are available for 2014 (APPEA, 2016):

• Barrow Island: 1 763 852 bbl (280.44 Ml) of crude;
• Devil Creek: 100 479 bbl (15.98 Ml) of condensate and 24 552 MMcf (695.26 Mcm) of sales gas;
• Enfield: 2 204 603 bbl (350.52 Ml) of crude;
• Macedon: 3096 bbl (492.24 kl) of condensate and 54 477 MMcf (1.54 Bcm) of sales gas;
• Mutineer/Exeter: 3 558 881 bbl (565.84 Ml) of crude;
• NWSP: 8 915 220 bbl (1.42 Gl) of crude, 29 262 048 (4.65 Gl) bbl of condensate, 6 790 890 (1.08 Gl) bbl of LPG, 754 938 MMcf (21.38 Bcm) of LNG and 181 020 MMcf (5.13 Bcm) of sales gas;
• Pluto: 3 180 600 bbl (505.70 Ml) of condensate and 213 864 MMcf (6.06 Bcm) of LNG;
• Pyrenees: 13 511 802 bbl (2.15 Gl) of crude;
• Stag: 1 683 133 bbl (267.61 Ml) of crude;
• Stybarrow: 1 977 055 bbl (314.34 Ml) of crude;
• Thevenard Island: 63 155 bbl (10.04 Ml) of crude;
• Van Gogh: 3146 bbl (500.19 kl) of crude;
• Varanus Island: 399 795 bbl (63.57 Ml) of crude, 1 098 775 bbl (174.7 Ml) of condensate and 90 093 MMcf (2.55 Bcm) of sales gas;
• Vincent: 8 329 794 bbl (1.32 Gl) of crude; and
• Wandoo: 2 438 378 bbl (387.69 Ml) of crude.

Thevenard Island production facilities are to be dismantled, after production from the fields Saladin, Cowle, Yammaderry, Crest, Roller and Skate ceased in early 2014, while Stybarrow ceased production in 2015 (BHP Billiton, 2015). A review of production and development in 2014 is provided by Henzell and Cooper (2015).

As of 2015, production from Van Gogh, via the Ningaloo FPSO, includes oil from the Coniston and Novara fields (Figure 2).

For the 12 months ended December 2016 the Carnarvon Basin produced 36 MMbbl (5.72 Gl) of oil, 23.773 Mt of LNG, 576 000 t of LPG, 35.638 MMbbls (5.67 Gl) of condensate, for a total petroleum production equivalent of 364.779 MMboe (EnergyQuest, 2017).

Rankin Platform

The NWS Venture is one of the world’s largest consortia of 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, 2016). The fields and facilities constitute Australia’s largest oil and gas resource development (NWSP) and account for more than one third of Australia’s oil and gas production. The NWS Venture has been producing domestic gas for 32 years, with first production coming from North Rankin in 1984. It has been exporting LNG to the Asia Pacific region, via the Karratha Gas Plant, since 1989. Gas and condensate production facilities include the North Rankin Complex (i.e. North Rankin A and North Rankin B platforms; Woodside Petroleum Ltd, 2013e), Goodwyn A and Angel platforms (North West Shelf Shipping Services Company, 2016). The platforms process gas from Angel, Goodwyn, North Rankin, Perseus and Searipple fields. Oil production from Cossack, Hermes, Lambert and Wanaea fields is processed via the Okha floating production storage and offloading (FPSO) facility, which produces approximately 30 000 bopd (4.8 Ml/d) of crude oil products (Woodside Petroleum Ltd, 2011c). Gas from the offshore production facilities is transported to the Karratha Gas Plant for processing via two sub-sea pipelines (Figure 2).

Located 1260 km north of Perth and covering approximately 200 hectares, the Karratha Gas Plant (Figure 2) includes five LNG processing trains, two domestic gas trains, six condensate stabilisation units and three LPG fractionation units. The facility also houses storage and loading facilities for LNG, LPG and condensate. The plant has the capacity to produce 52 000 t/d of LNG, 12 000 t/d of domestic gas, 4200 t/d of LPG and 165 000 bopd (26.2 Ml/d) of condensate (North West Shelf Gas, 2016).

The NWS Venture has undertaken a number of projects to extend the life of the NWSP (Woodside Petroleum Ltd, 2013d). These include the North Rankin Redevelopment Project, which involved the construction and installation of the North Rankin B Platform and refurbishment of the North Rankin A Platform. The project achieved start-up in October 2013 enabling potential recovery of approximately 5 Tcf (141.6 Bcm) of low pressure reserves from the North Rankin and Perseus accumulations (Woodside Petroleum Ltd, 2013c). The NWSP also includes the Cossack–Wanaea–Lambert–Hermes (CWLH) Redevelopment Project, which commenced production in September 2011 when the Cossack Pioneer FPSO was replaced by the Okha FPSO and sub-sea infrastructure was upgraded (Woodside Petroleum Ltd, 2011c).

The Balnaves Oil Project was a joint venture between Kuwait Foreign Petroleum Exploration Company (KUFPEC) and Woodside, after Woodside purchased Apache Corporation’s interest in the project (Woodside Petroleum Ltd, 2015a). The development processed oil from the Balnaves oil field for export via a dedicated FPSO (the Armada Claire). The FPSO had been producing oil at an average of 30 000 bopd (4.8 Ml/d) since start-up in late 2014. Balnaves ceased production in 2016 (Woodside Petroleum Ltd, 2016j).

The Pluto LNG Project is operated by Woodside (with Kansai Electric and Tokyo Gas as joint venture partners) and consists of a 4.9 MMtpa single train LNG plant located on the Burrup Peninsula (Burrup Park (Pluto) LNG plant; Figure 2), supplied with gas from the Pluto and Xena fields (Woodside Petroleum Ltd, 2016c). The plant commenced processing gas from Pluto in March 2012. By the end of 2016 the project produced 4.5 MMt of LNG and 3.1 MMbbl of condensate (Woodside Petroleum Ltd, 2017).

Dampier and Beagle sub-basins

In 2011 the Devil Creek processing plant, located south of Karratha, began supplying gas and condensate to the domestic market from the Reindeer gas and condensate field (Santos, 2016b) via an offshore pipeline and onshore processing plant (Devil Creek gas plant; Quadrant Energy, 2017a; Figure 2). The two-train plant is designed to process 220 Terajoules (TJ) of gas per day. Quadrant Energy operates the Reindeer/Devil Creek development in joint venture with Santos (Quadrant Energy, 2017a).

The Mutineer–Exeter facilities are operated by Santos with joint venture partners KUFPEC and JX Nippon Oil & Gas (Santos, 2015a). Mutineer–Exeter commenced oil production in March 2005 and produces via the Modec Venture II FPSO. In 2015 approximate production was 1 MMbbl of oil. The Fletcher–Finucane Oil Project, in the Beagle Sub-basin, commenced production in May 2013, and consists of a tie-back to the FPSO. Approximate production in 2015 from Fletcher–Finucane was 1.8 MMbbl of oil (Santos, 2015b).

Oil has been produced from the Stag oil field since May 1998. Oil is extracted from horizontal wells and processed through a fixed central production facility, where it is then transported by pipeline to the Dampier Spirit FSO, and then on to shuttle tankers. The field has produced up to 8800 bopd (1400 kl/d) of oil (Quadrant Energy, 2015a), though is now producing 3400 bopd (540 kl/d) as reported by Jadestone after its purchase of the field and associated infrastructure (Jadestone Energy Australia Pty Ltd, 2017).

The Wandoo oil field is operated by Vermilion Energy Inc. and produces via the Wandoo A monopod and the Wandoo B platform. Production rates for the field are expected to be maintained at 6000–8000 bbls/d (954–1272 kl/d). Further drilling work for 2015–16 aims to enhance production via sidetrack wells (Vermilion Energy, 2016).

Barrow Sub-basin

The Barrow Island production facilities (Figure 2), on Barrow Island, are operated by Chevron, with partners Santos and ExxonMobil, and includes the Gorgon Project. Gorgon gas production from Barrow Island commenced in March 2016 (Chevron Australia Pty Ltd, 2016a) with Trains 1 and 2 recently reporting a ‘near capacity’ output of 200 000 boepd, and Train 3 slated for completion in 2017 (Energy News Bulletin, 2017b). The Barrow Island oil field is the largest oil accumulation in Western Australia. Production peaked at 50 000 bopd (7950 kl/d) in 1971, but has now declined to 5000 bopd (795 kl/d). In-place oil reserves are 1250 MMbbl (198.7 Gl) and in-place gas reserves are 580 Bcf (16.4 Bcm) (Ellis et al, 1999). As of 2014, over 320 MMbbl (50.9 Gl) of oil has been produced (Chevron Australia Pty Ltd, 2014). Production is mostly via horizontal wells, collected at eight gathering stations, and stored on the island before transfer via an offshore tanker mooring.

The Thevenard Island Joint Venture production facility, is owned by Chevron, Santos and ExxonMobil. In early 2014, production at the facility permanently ceased after producing over 150 MMbbl (23.8 Gl) of oil. As well as the Saladin field, oil and gas from other fields in surrounding waters (Cowle, Crest, Roller, Saladin, Skate and Yammaderry) were also produced. The partners will decommission the facility with plans to disconnect the subsea pipelines, but leave them in place (Department of Mines and Petroleum, Government of Western Australia, 2016).

The Varanus Island Gas Hub, is operated by Quadrant Energy, with partner Santos, and is located approximately 75 km offshore northwest Australia (Quadrant Energy, 2017b). It is the production facility for the Harriet, East Spar and John Brookes Quadrant Energy-operated joint ventures, as well as other nearby producing fields, and has infrastructure that produces up to 6000 bbl (954 kl) of oil and condensate, as well as up to 390 TJ of gas per day (Quadrant Energy, 2015b). Oil is transferred to tankers for export while gas is transported onshore via two 100 km pipelines that connect into the Dampier to Bunbury Natural Gas Pipeline (DBNGP) and Goldfields Gas Transmission pipelines.

Exmouth Sub-basin

In March 2010, the BHP Billiton-operated Pyrenees Project commenced production from the Crosby, Ravensworth and Stickle oil fields through the Pyrenees Venture FPSO facility (Figure 2). Production from the Wildbull, Tanglehead and Moondyne fields commenced in 2013–2014—gas produced from these fields is reinjected into the nearby Macedon gas field (Offshore Technology, 2016b). The latter has been developed by the BHP Billiton-operated Macedon Project, which was commissioned in August 2013 and has a gas production capacity of 200 MMcfd (5.7 Mm³/d) (Offshore Technology, 2016a). A pipeline connects the Macedon Gas Plant to the DBNGP (Apache Corporation, 2013b) for supply to the domestic market (Figure 2). A planned Phase 3 expansion of the Pyrenees Project was due to commence in 2016 and includes expanding four existing wells, a new exploration well and a tie-back of a Stickle field well to the Tanglehead manifold (Offshore Technology, 2016b).

The Enfield oil field is operated by Woodside in conjunction with partner Mitsui E&P Australia Pty Ltd (Offshore Technology, 2016c). Production via the Nganhurra FPSO commenced in July 2006. The FPSO has a maximum production capacity of 100 000 bopd (15.9 MMl/d) and a storage capacity of 900 000 bbl (143 MMl) of oil. Produced water and surplus gas can be reinjected into the reservoir (Woodside Petroleum Ltd, 2013f).

The Stybarrow oil project was developed by BHP Billiton (operator) and Woodside, and commenced production via the Stybarrow Venture FPSO in November 2007 (BHP Billiton, 2008). Oil was produced from the Stybarrow and Eskdale fields. The highly successful Stybarrow project reached the end of its field life and ceased production in June 2015 (BHP Billiton, 2015), having produced approximately 60 MMbbl (9.5 Bl) of oil.

The Vincent oil field is operated by Woodside in conjunction with partner Mitsui E & P Australia Pty Ltd (Offshore Technology, 2016d). Production is via the Ngujima-Yin FPSO, which commenced in August 2008. The Van Gogh oil field (an extension of the Vincent oil field) commenced production in February 2010 via the Ningaloo Vision FPSO, which is operated by Quadrant Energy. The Coniston and Novara oil fields are operated by Quadrant Energy and commenced production in 2015, via subsea tie-backs to the Ningaloo Vision (Quadrant Energy, 2015a).

Currently there are five LNG development projects in various stages of progress in the Northern Carnarvon Basin: Gorgon, Wheatstone, NWS Venture’s Greater Western Flank, Scarborough and Equus. In addition, there are several smaller-scale tie-in field extension developments: Julimar–Brunello, Persephone and Greater Enfield. In contrast, a Final Investment Decision (FID) on Woodside’s Lambert Deep project has been deferred (Oil & Gas Journal, 2016b).

The Gorgon LNG project is the largest single resource development in Australia's history and is to produce gas from the Gorgon (Maftei et al, 2013) and Io–Jansz accumulations (Figure 2). The project is operated by Chevron, with joint venture partners ExxonMobil, Shell, Osaka Gas, Tokyo Gas and JERA. Production facilities include a three-train LNG plant on Barrow Island with an initial capacity of 15.6 MMtpa, a 300 TJ/d domestic gas plant to supply the Western Australian markets, a 2.1 km long loading jetty for transport to international markets and a large-scale carbon dioxide reinjection project (Chevron Australia Pty Ltd, 2016a). The Project shipped its first LNG cargo from Train 1 in March 2016, followed by Train 2 in October 2016 and Train 3 in March 2017 (Chevron Australia Pty Ltd, 2017).

In September 2011 Chevron made the FID on the Wheatstone LNG Project, with equity participants KUFPEC, Woodside, PE Wheatstone Pty Ltd (part owned by JERA) and Kyushu Electric Power Company (Chevron Australia Pty Ltd, 2016b). The project will process gas from the Wheatstone and Iago gas fields (~80% supply capacity) via a two-train plant, with a combined capacity of 8.9 MMtpa, at Ashburton North Strategic Industrial Area, 12 km west of Onslow (Figure 2). The Wheatstone Project will also have a domestic gas plant. The Woodside operated Julimar Development Project will supply additional gas (~20% supply capacity) to the Wheatstone LNG plant from the Julimar and Brunello gas accumulations. The Wheatstone LNG Project is targeting the first LNG cargo by mid-2017. The Julimar Project is a Woodside development of the Brunello and Julimar gas and condensate fields (Figure 2), employing a subsea tie-back to the Wheatstone Platform—construction completion was recently confirmed (Woodside Petroleum Ltd, 2016h). The Julimar–Brunello fields are expected to produce approximately 140 MMcf/d (3.9 MMm³/d) of LNG, 22 MMcf/d (0.62 MMm³/d) of sales gas into the domestic market and 3250 bopd (516.7 kl/d) of condensate (Apache Corporation, 2012). Produced gas and condensate will then be processed by the Wheatstone LNG trains onshore.

The NWS Venture’s Greater Western Flank (GWF) Project Phases 1 and 2 will maintain offshore supply to the Karratha Gas Plant for both domestic gas and LNG (Woodside Petroleum Ltd, 2011d). Phase 1 commenced production in December 2015 (Woodside Petroleum Ltd, 2016f) and brings the Goodwyn and Tidepole gas and condensate accumulations through a sub-sea tie-back to the Goodwyn-A platform. The GWF Phase 2 Project, consisting of the development of the Keast, Dockrell, Sculptor, Rankin, Lady Nora and Pemberton accumulations, also via sub-sea tie-backs to Goodwyn-A, was approved by the joint venture participants in December 2015. Initial production from this second phase is not expected till 2019. The US $2 billion Phase 2 project will develop 1.6 Tcf (45.3 Bcm) of gas (Woodside Petroleum Ltd, 2015c).

The remote and deep-water Scarborough gas accumulation (Figure 1) is being considered for development jointly by Esso Australia Resources Pty Ltd (operator; an affiliate of ExxonMobil), BHP Billiton and Woodside (Woodside Petroleum Ltd, 2016g). Given its remoteness a floating liquid natural gas (FLNG) facility is considered the best development option (Oil & Gas Journal, 2014), with a production estimate of 6–7 MMtpa of LNG (S&P Global Platts, 2013a). Environmental approval for a FLNG facility and subsea infrastructure was granted in 2013 (S&P Global Platts, 2013b). Further engineering and design work will be undertaken and economic conditions considered before the FID is announced (Bloomberg, 2015; ExxonMobil, 2016). Wider Scarborough area assets may include the Thebe and Jupiter gas fields (Woodside Petroleum Ltd, 2016g).

Hess discovered gas at Glencoe 1, midway between the Scarborough and Io–Jansz gas fields, in June 2008. Sixteen exploration wells have been drilled in permit WA-390-P, of which thirteen are gas discoveries. Hess has proposed to develop the gas discoveries as the Equus Development Project and began front-end engineering studies in 2015 (Hess Corporation, 2016). However, in late 2016, Hess announced that it was deferring a decision on the Equus LNG Project (Energy News Bulletin, 2016b).

The Persephone Project—part of the NWS Project—is a Woodside development involving a 7 km subsea tie-back from the Persephone gas field to the North Rankin Complex platforms (Woodside Petroleum Ltd, 2014b). Production is expected to commence in 2018.

The Greater Enfield Project is a Woodside development to provide a 31 km subsea tie-back of the Laverda Canyon, Norton over Laverda and Cimatti oil fields to the Ngujima-Yin FPSO, serving the Vincent oil field (Offshore Technology, 2016e; Woodside Petroleum Ltd, 2016d). Production is targeted to commence in 2019, after approval was granted in mid-2016 (Woodside Petroleum Ltd, 2016i; Energy News Bulletin, 2016c).

Finally, DUET plans to use the depleted onshore Tubridgi gas reservoir (Figure 2) as a large gas storage facility to serve the northern Carnarvon region (The Australian Pipeliner, 2016b), which has recently been approved (Energy News Bulletin, 2017a).

This section provides an overview of the environmental characteristics of the Acreage Release areas and the general setting of the region overlying the Northern Carnarvon Basin (Figure 1), together with information focused on the environmental geoscience characteristics of individual acreage release blocks.

The Northern Carnarvon Basin is located on the northwest margin of Australia and primarily includes continental shelf and slope with isolated canyons, valleys, plateau and terrace located offshore from the Kimberley region.

Dampier, Karratha and Port Hedland are the closest industrial ports and towns in the Pilbara region.

Climate of the region

Climate statistics for Port Hedland indicate a mean annual rainfall of 315.5 mm and mean annual high and low temperatures of 33.3°C and 19.5°C, respectively (average over 69 years, www.bom.gov.au). Mean maximum and minimum temperatures and precipitation for Barrow Island are similar; 30.2°C and 21.5°C, and 318.2 mm of rainfall per annum (average over 22 years, www.bom.gov.au). Approximately half of the precipitation in this coastal region is associated with tropical cyclones, and most precipitation occurs between December and June.

Oceanic regime

The oceanic regime of the Pilbara to Gascoyne shelf is characterised by the general poleward flow of surface currents, with the seasonal poleward flowing Leeuwin current strongest in autumn, and diminished in strength during the wet monsoon season. The wettest months are normally January to March. Surface waters, generally sourced from the north, are warm, nutrient poor and of slightly lowered salinity compared to normal marine values (Waite et al, 2007). The Leeuwin Current strongly influences the types and ranges of biota in this region. Tidal ranges are small in Exmouth Gulf (microtidal, <2 m) and increase to macrotidal ranges close to Broome (Dix, 1989). Inshore of Barrow Island tidal heights are of 3–4 m (Dix, 1989).

The region supports mesotrophic ecosystems (intermediate productivity, surface chlorophyll-a between 0.1 and 1.0 mg/m³) in winter and spring, while the deeper offshore regions shift to oligotrophic systems (low primary productivity, surface chlorophyll-a <0.1 mg/m³) in summer and autumn.

Seabed environments: regional overview

The Exmouth Plateau and the adjacent shelf regions are located on the southwestern section of the extensive Australian North West Shelf (NWS). They are characterised by a variety of seabed geomorphic features, the largest of which include terrace, slope, shelf and deep hole/valley (Heap and Harris, 2008). Additionally, canyons are present to the west of Exmouth Gulf. The continental shelf adjacent to Exmouth Gulf is 50 km wide, and is the narrowest section of the NWS.

Sediment on the NWS generally consists of medium- to coarse-grained bioclastic material with a carbonate content that is commonly between 60% and 90% (McLoughlin and Young, 1985). This shelf is a region of net sediment loss to deeper water, resulting in areas rich in ‘relict’ material (James et al, 2004; Margvelashvili et al, 2006). In shallow waters on the Carnarvon shelf, including, for example, around Barrow Island, shelf sediments are generally composed of carbonate sand and gravel (Dix, 1989). Several major seafloor sedimentary facies are present. These include a calcareous tube and pelagic facies, an ooid-peloid facies, a relict and biofragmental facies and a large benthic foraminiferal facies (James et al, 2004). Relict particles largely deposited during the sea-level rise (~18 000 years before present), which followed the Last Glacial Maximum, contribute >25% to 50% of the sediments on the mid to inner shelf (mid to inner ramp) (James et al, 2004). Shallow water environments are dominated by the geomorphic feature ‘shelf’ and by banks/shoals.

The acreage Release Areas that overlie the Exmouth Plateau are located in water depths of 800–3500 m. In comparison with the adjacent shelf areas, the Exmouth Plateau and surrounds are relatively poorly known. To a large extent, modern sediment is composed of hemipelagic plankton ooze that is moderately high in carbonate (>55% CaCO₃), and low in terrestrial sediment (Veeh et al, 2000; Baker et al, 2008). Sediment textures on the Exmouth Plateau are largely sandy mud and muddy sand, while further inshore, toward Barrow Island, gravelly textures are more common (Baker et al, 2008). Four sedimentary facies have been documented: 1. shelly carbonate sand facies in <200 m water depth; 2. foraminiferal oozes and sands containing pteropod pieces in 200–800 m water; 3. foraminiferal oozes and sands in 800–4500 m water; and 4. siliceous clays in water depths >4500 m (Colwell and von Stackelberg, 1981). The composition of sediment at the seabed is strongly influenced by depth and currents, with increasing proportions of siliceous sediment as depths increase towards the abyssal zone. The presence of clay minerals and the general sandy composition overall, at depth, strongly suggests the influence of bottom currents. The clays present are most likely from the early Holocene rather than modern terrestrial sources (Gingele et al, 2001).

Two offshore (Rowley and Sahul) and three coastal (Kimberley, Pilbara and Ningaloo) bioregions have been defined for the NWS, each with distinct histories of coral reef development (Wilson, 2013). The coastal Pilbara Coral Reef Province has developed within the Northern Carnarvon Basin, and extends from North West Cape to just north of Barrow Island and surrounds, to the coast just north of Dampier. The Pilbara Province is composed of fringing and patch reefs, lies in shallow water, and has developed on late Pleistocene limestone platforms, bare pavement and Holocene sediment banks. Although wave energy is low, water conditions in this environment are moderately turbid.

Ecology

The ecological knowledge of this region is limited to the shelf. Patches of coral reefs and rhodolilth beds can occur in shallow water of the inner shelf (Brooke et al, 2009), while deeper shelf water (>40 m) are dominated by sponges and soft corals, which provide habitat to other organisms (Brooke et al, 2009; Schoenberg and Fromont, 2011). These environments also support diverse assemblages of small macrofauna and infauna dominated by crustaceans (Przeslawski et al, 2013). The benthic invertebrate megafauna of the upper continental slope, off the Cape Range peninsula, may be distinct from those along the rest of the slope in the North-West bioregion, showing more similarity to those in the South-West bioregion (Williams et al, 2010). Video transects from the lower continental slope along the Cuvier margin (2123–4660 m) reveal scattered benthic invertebrates and demersal fish, with the nearshore mouth of the Cloates Canyon home to comparatively higher abundances of suspension feeders, particularly gorgonians (Daniell et al, 2009). There have been no targeted surveys over the vast abyssal plains of this region, so that the understanding of this environment is limited to the knowledge of other regions, notably, the assumption that the abyssal plain supports cosmopolitan deep-water communities with patches of highly diverse and specialised communities supported by rocky outcrops, hydrothermal vents and whale falls (Levin et al, 2001).

Recent geological history

Core collected during IODP Expedition 356 on the NWS has had preliminary analysis (Gallagher et al, 2017) and will provide a 5 million year history of the Indonesian Throughflow, Australian monsoon and subsidence on the northwest shelf of Australia. Previous work on emergent Miocene terraces at Cape Range indicate that coastal uplift has occurred prior to and during the Quaternary (Allen, 1993; Denniston et al, 2013), and Pliocene-Pleistocene initiated neotectonic reactivation is ongoing (Whitney et al, 2016). Evidence from a number of Ocean Drilling Program (ODP) sites located on or near the Wombat and Exmouth plateaus indicate that near-continuous sedimentary successions have accumulated during the Quaternary (Wells and Chivas, 1994; Sinha et al, 2006). Evidence from these cores, and from late Quaternary regional climate reconstructions (Denniston et al, 2013), indicate arid conditions during glacials and more humid conditions during interglacials over the past 550 ka (Stuut et al, 2014). During the glacial–interglacial cycles of the middle and late Pleistocene, the Exmouth Plateau was exposed to varying amounts of terrestrially sourced clays and to changing marine currents (Gingele et al, 2001; Sanchez et al, 2016), while the shelf was subaerially exposed for varying periods down to the present 125 m isobath.

Several flat-topped carbonate platforms of the Pliocene-Pleistocene, which formed on topographic highs afforded by lowstand delta lobes, were subsequently drowned by either preferential compaction of the underlying strata, or by tectonic subsidence (Sanchez et al, 2016) and are no longer growing. However, coral of Last Interglacial, Marine Isotope Stage 5e (MIS5e) age is present at Cape Range (Kendrick et al, 1991). The modern monsoon system commenced in this region at approximately 13 ka BP, and the El Niño–Southern Oscillation (ENSO) was enhanced by 5 ka BP (De Deckker et al, 2014). Denniston et al (2013) presented a detailed local climate record, which similarly shows increased early Holocene rainfall, followed by a middle Holocene rainfall peak, a significant decline until approximately 1.5 ka BP, then a resurgence of rainfall.

Commonwealth Marine Reserves

Argo-Rowley Terrace Marine Reserve

Major Conservation Values:

(www.environment.gov.au/topics/marine/marine-reserves/north-west/argo-rowley-terrace)

• Important foraging areas for migratory seabirds and the endangered Loggerhead Turtle.
• Important area for sharks, which are more abundant around the Rowley Shoals than in other areas in the region.
• Provides protection for the communities and habitats of the deeper offshore waters of the region, in depth ranges from 220 m to over 5000 m.
• Provides protection for many seafloor features, including aprons and fans, canyons, continental rise, knolls/abyssal hills and the terrace and continental slope.
• Has examples of the communities and seafloor habitats of the Northwest Transition and Timor Province provincial bioregions.
• Provides connectivity between the existing Mermaid Reef Marine National Nature Reserve and reefs of the Western Australian Rowley Shoals Marine Park and the deeper waters of the region.

The reserve (Figure 7) is currently zoned as a Multiple Use IUCN Category VI and Marine National Park IUCN Category II. Management plans for the Northwest Commonwealth marine reserves network are not yet in place.

Dampier Commonwealth Marine Reserve

Major Conservation Values:

(www.environment.gov.au/topics/marine/marine-reserves/north-west/dampier)

• Foraging areas adjacent to important breeding areas for migratory seabirds.
• Foraging areas adjacent to important nesting sites for marine turtles.
• Includes part of the migratory pathway of the protected Humpback Whale.
• Provides a high level of protection for offshore shelf habitats adjacent to the Dampier Archipelago.
• Provides high level protection for the shallow shelf with depths ranging from 15 m to 70 m.
• Has examples of the communities and seafloor habitats of the Northwest Shelf Province provincial bioregion, as well as the Pilbara (nearshore) and Pilbara (offshore) meso-scale bioregion.

The reserve (Figure 7) is currently zoned as a Marine National Park IUCN Category II and Habitat Protection Zone IUCN Category IV. Management plans for the Northwest Commonwealth marine reserves network are not yet in place.

Montebello Commonwealth Marine Reserve

Major Conservation Values:

(www.environment.gov.au/topics/marine/marine-reserves/north-west/montebello)

• Foraging areas adjacent to important breeding areas for migratory seabirds.
• Foraging areas for vulnerable and migratory Whale Shark.
• Foraging areas adjacent to important nesting sites for marine turtles.
• Includes part of the migratory pathway of the protected Humpback Whale.
• Includes shallow shelf environments with depths ranging from 15 m to 150 m, and provides protection for shelf and slope habitats, as well as pinnacle and terrace seafloor features.
• Has examples of the seafloor habitats and communities of the Northwest Shelf Province provincial bioregions, as well as the Pilbara (offshore) meso-scale bioregion.

The reserve (Figure 7) is currently zoned Multiple Use Zone IUCN Category VI. Management plans for the Northwest Commonwealth marine reserves network are not yet in place.

Ningaloo Commonwealth Marine Reserve

Major Conservation Values:

(www.environment.gov.au/topics/marine/marine-reserves/north-west/ningaloo)

• Foraging areas for vulnerable and migratory Whale Shark.
• Foraging areas and adjacent to important nesting sites for marine turtles.
• Includes part of the migratory pathway of the protected Humpback Whale.
• Includes shallow shelf environments and provides protection for shelf and slope habitats, as well as pinnacle and terrace seafloor features.
• Has examples of the seafloor habitats and communities of the Central Western Shelf Transition.

The reserve (Figure 7) is currently zoned Recreational Use Zone IUCN Category II. Management plans for the Northwest Commonwealth marine reserves network are not yet in place.

Gascoyne Commonwealth Marine Reserve

Major Conservation Values:

(www.environment.gov.au/topics/marine/marine-reserves/north-west/gascoyne)

• Important foraging areas for:
  • migratory seabirds;
  • the threatened and migratory Hawksbill and Flatback turtles; and
  • the vulnerable and migratory Whale Shark.
• Provides a continuous connectivity corridor from shallow depths around 15 m out to deep offshore waters on the abyssal plain at over 5000 m.
• Provides protection to many seafloor features including canyon, terrace, ridge, knolls, deep hole/valley and continental rise. It also provides protection for sponge gardens in the south of the reserve adjacent to Western Australian coastal waters.
• Has examples of the ecosystems of the Central Western Shelf Transition, the Central Western Transition and the Northwest provincial bioregions, as well as the Ningaloo meso-scale bioregion.

The reserve (Figure 7) is currently zoned Marine National Park Zone, IUCN Category II, Habitat Protection Zone IUCN Category, IV and Multiple Use Zone IUCN Category VI. Management plans for the Northwest Commonwealth marine reserves network are not yet in place.

Western Australian Marine Parks

Montebello Islands Marine Park

Coral reefs and tropical fish are protected in the marine area surrounding the 265 low-lying islands and islets. The management plan for the Montebello Islands Marine Conservation reserves is currently in place and show a multiuse approach.

Barrow Island Marine Park and Management Area

The park protects Biggada Reef, Green Turtle breeding and nesting and occasional visits by Hawksbill and Flatback turtles. Barrow Island is a sanctuary zone, and a Management plan for the Barrow Island Marine Conservation reserves is currently in place and show a multiuse approach.

Proposed Dampier Archipelago Marine Park and Regnard Marine Management Area

Currently, 25 of the islands in the archipelago are classed as nature reserves and are proposed to be included in a national park. The rocky islands are fringed by mangroves and sandy beaches where Green, Loggerhead, Flatback and Hawksbill turtles nest and migratory birds feed and rest. Dugong, dolphin and Humpback Whale inhabit the waters. An indicative management plan has been released for the area.

Fisheries

The following Commonwealth fisheries occur in the Northern Carnarvon Basin area:

• North West Slope Trawl Fishery operates in the area between 200 m water depth to the outer limit of the Australian fishing zone. The fishing season runs year round. (www.afma.gov.au/fisheries/north-west-slope-trawl-fishery/)
• Western Deepwater Trawl Fishery, operated in waters deeper than 200 m, offshore Exmouth to Augusta. The fishing season runs year round. (www.afma.gov.au/fisheries/western-deepwater-trawl-fishery/)
• Southern Bluefin Tuna Fishery. The fishing season runs year round. (www.afma.gov.au/fisheries/southern-bluefin-tuna-fishery/)
• Western Tuna and Billfish Fishery operates in the Australian Fishing Zone and adjacent high seas. The fishing season runs year round. (www.afma.gov.au/fisheries/western-tuna-and-billfish-fishery/)
• Western Skipjack Tuna Fishery is not active. (www.afma.gov.au/fisheries/skipjack-tuna-fishery/)

The Northern Carnarvon Basin crosses the Western Australian North Coast and Gascoyne Coast bioregions. The boundary between the bioregions runs along longitude 114°50’ E. The Western Australian Government manages 15 commercial fisheries within the North Coast bioregion (Fletcher and Santoro, 2015). Tropical finfish, Spangled Emperor, Snapper and Cod are targeted in the Northern Demersal Scalefish (trap and line) fishery. The Mackeral Managed Fishery targets Spanish Mackeral (Fletcher and Santoro, 2015). Three of Western Australia’s more valuable fisheries occur in the Gascoyne Coast bioregion, Shark Bay Prawn, Exmouth Gulf Prawn and Shark Bay Scallop fisheries. Other important fisheries include: Gascoyne Demsersal Scalefish Fishery, Shark Bay Beach Seine and Mesh Net Fishery and Mackeral Managed Fishery. Invertebrate species targeted include: Prawns, Scallops, Blue Swimmer and deep sea crabs and Pearl Oysters (Fletcher and Santoro, 2015).

Heritage

The Ningaloo marine area and coastline is World, National and Commonwealth Heritage listed. The Dampier Archipelago and Murujuga, also known as the Burrup Peninsula, are National Heritage listed. There are no historic shipwrecks located in the Release Areas. (environment.gov.au/heritage/heritage-places).

Information resources

Bureau of Meteorology www.bom.gov.au

National Conservation Values Atlas www.environment.gov.au/webgis-framework/apps/ncva/ncva.jsf

Argo-Rowley Terrace Commonwealth Marine Reserve www.environment.gov.au/topics/marine/marine-reserves/north-west/argo-rowley-terrace

Dampier Commonwealth Marine Reserve www.environment.gov.au/topics/marine/marine-reserves/north-west/dampier

Gascoyne Commonwealth Marine Reserve www.environment.gov.au/topics/marine/marine-reserves/north-west/gascoyne

Montebello Commonwealth Marine Reserve www.environment.gov.au/topics/marine/marine-reserves/north-west/montebello

Western Australian Marine Parks and Reserves:

www.dpaw.wa.gov.au/management/marine/marine-parks-and-reserves#

parks.dpaw.wa.gov.au/park/barrow-island

parks.dpaw.wa.gov.au/park/dampier-archipelago

parks.dpaw.wa.gov.au/park/montebello-islands

www.dpaw.wa.gov.au/images/documents/parks/management-plans/decarchive/montebello-barrow-mp_final.pdf

Commonwealth Fisheries www.afma.gov.au/fisheries/

Heritage www.environment.gov.au/topics/heritage

AGSO AND GEOMARK, 1996—The Oils of Western Australia. Petroleum Geochemistry and Correlation. Australian Geological Survey Organisation and GeoMark Research, Inc., Proprietary report, Canberra and Houston, https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS&catno=36999 (last accessed 30 December 2016).

AGSO NORTH WEST SHELF STUDY GROUP, 1994—Deep reflections on the North West Shelf: Changing perceptions of basin formation. In: Purcell, P.G. and Purcell, R.R. (eds), The Sedimentary Basins of Western Australia 1. Proceedings of the Petroleum Exploration Society of Australia Symposium, Perth, 1994, 63–76.

ALLEN, A.D., 1993—Outline of the geology and hydrology of Cape Range, Carnarvon Basin, Western Australia. Records of the Western Australian Museum: Supplement, 45, 145–164.

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