AUSTRALIA 2012
Offshore Petroleum Exploration Acreage Release
REGIONAL GEOLOGY OF THE
NORTHERN CARNARVON BASIN
BASIN OUTLINE
The Northern Carnarvon Basin is located predominantly offshore, covering an area of
approximately 535,000 km2, in water depths of up to 4,500 m (Figure 1). As one of Australia’s most
explored and prospective basins, the Northern Carnarvon Basin 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. In the
Damper Sub‑basin, the most recent development to come to fruition is the Reindeer–Devil Creek
Project which produced gas in December 2011. Gas is also produced from the northern Rankin
Platform and oil from the northern Exmouth Sub‑basin, where there are also plans to produce
domestic gas from the Macedon discovery. LNG developments in progress include the Gorgon,
Pluto, Scarborough and Wheatstone projects. Redevelopment and expansion projects are
planned in several areas to extend the life of existing fields and production facilities, including the
redevelopment of the North West Shelf Venture. A major LNG loading terminal and processing
centre is located at Karratha.
The Northern Carnarvon Basin is proximal 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 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 Asia and East Asia.
The Northern Carnarvon Basin is the southernmost of the late Paleozoic to Cenozoic basins that
underlie 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 and Gascoyne and Merlinleigh sub‑basins of the
Southern Carnarvon Basin, and to the northwest by the Argo, Cuvier and Gascoyne abyssal plains.
The sedimentary fill of the Northern Carnarvon Basin is up to 15,000 m thick and dominated by
deltaic to marine siliciclastics and shelfal carbonates of Mesozoic to Cenozoic age (Figure 3).
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TECTONIC DEVELOPMENT
The offshore part of the Northern Carnarvon Basin evolved from a pre-rift broadly sagging basin
in the late Paleozoic, through tectonically active 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), Norvick (2002) and
Longley et al (2002). In addition, comprehensive summaries of petroleum geology are presented by
Tindale et al (1998) for the Exmouth Sub‑basin, Stagg et al (2004) for the Exmouth Plateau, 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) for the Beagle Sub‑basin.
The offshore Northern Carnarvon Basin consists of three broad structural zones: an inboard,
structurally high zone of the Lambert and Peedamullah shelves; an intermediate zone of large
depocentres comprising the Beagle, Dampier, Barrow and Exmouth sub‑basins; and 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–southwest structural trend that is
apparent in the alignment of major faults and depocentres (Figure 1). A secondary north–south or
north-northwest to south-southeast trend is also apparent, especially in accommodation zones and
transfer 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 being shown in Figure 4, Figure 5, Figure 6
and Figure 7.
Beagle Sub‑basin
The Beagle Sub‑basin comprises a structurally complex series of fault blocks, anticlines and
troughs with a general north–south trend, oblique to the regional northeast–southwest trend
dominant in the other sub‑basins (Figure 1). 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 4 and Figure 5). In contrast to the other sub‑basins, the Upper Jurassic
succession is thin or absent.
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Dampier, Barrow and Exmouth Sub‑basins
The 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 3). Maximum sediment thickness exceeds 10,000 m in the Dampier and
Exmouth sub‑basins and 15,000 m in the Barrow Sub‑basin (Figure 6 and Figure 7). 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–southwest trend formed by oblique extension.
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).
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 represent 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 Plateau
The 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 3,
Figure 6 and Figure 7). 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–south and northeast–southwest, 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 2,000 m thick (Figure 5). 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 3 and comprises the following phases:
•
Pre-rift (Silurian to Toarcian)
•
Early syn-rift (Toarcian to earliest Callovian)
•
Main syn-rift (earliest Callovian to Berriasian)
•
Late syn-rift Barrow Delta (Berriasian to Valanginian)
•
Post-breakup subsidence (Valanginian to mid-Santonian)
•
Passive margin (mid-Santonian to present)
Hydrocarbon generation, migration and entrapment in the Northern Carnarvon Basin have been
strongly controlled by syn-rift structuring and deposition, and post-rift reactivation.
Pre-rift (Silurian to Toarcian)
Onset of rifting of the Sibumasu Block from Gondwana (Metcalfe, 1999) resulted in regional
deposition from the late Carboniferous, forming the Westralian Superbasin that includes the
Northern Carnarvon Basin (AGSO North West Shelf Study Group, 1994). By the late Permian,
northeast–southwest-trending depocentres were forming, 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 3). The Locker Shale grades upwards into the Middle
to Upper Triassic Mungaroo Formation. Thick sandstone and claystone with minor coal were
deposited by a northwest-prograding fluvio-deltaic system that covered much of the offshore
Northern Carnarvon Basin (see the ‘Intra-Triassic’ to ‘Base Jurassic’ succession in Figure 5,
Figure 6 and Figure 7). 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 3), particularly in the Beagle Sub‑basin (Figure 5).
Fluvial and shoreline sandstone of the Mungaroo Formation host the giant gas accumulations
on the Rankin Platform (Figure 8). The Mungaroo Formation is also the inferred main gas-prone
source 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
(Norvick, 2002; Jablonski and Saitta, 2004).
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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, uppermost Triassic reefal limestone caps the Mungaroo
Formation (von Rad et al, 1992a, 1992b). In the outer part of the Northern Carnarvon 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 8).
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 (Smith et al, 1999) formed a series of structural
highs and lows, isolating it from the Dampier Sub‑basin during the Late Triassic (Blevin et al, 1994).
By the Pliensbachian, the Northern Carnarvon Basin developed the general structural configuration
that is apparent today. Initial crustal extension formed major bounding faults (e.g. the Rosemary,
Flinders and Rankin fault systems) that delineated 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 north–south 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). Moreover, the large amount of observed subsidence relative to faulting
suggests that lower crustal processes played a major role during crustal extension (Stagg and
Colwell, 1994; Driscoll and Karner, 1998; Norvick 2002).
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 3). The Legendre Delta 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 fields: Edwards and Zumberge, 2005). It hosts, and is the source of, gas in fields 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 3). 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.
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Continental breakup and the onset of seafloor spreading in the Argo Abyssal Plain occurred
in the Oxfordian (Norvick, 2002). The resultant 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 called 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 3), which
progressively filled, and overlapped the flanks of the Barrow, Dampier and Exmouth sub‑basins
(see the ‘Callovian’ to ‘Base Cretaceous’ succession in Figure 6 and Figure 7; Tindale et al, 1998).
The maximum flooding phase during the Oxfordian provided a favourable depositional environment
for high-quality, oil-prone source rocks (Norvick, 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 footwall uplift 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 as reservoir formations
in parts of the Northern Carnarvon Basin (Figure 8). These include turbiditic sandstone 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 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 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 3), which attains a thickness of up to
2,500 m (see the ‘Base Cretaceous’ to ‘Valanginian’ unit in Figure 7). Initial deposition occurred
over the Exmouth Sub‑basin, fed by sediment input from the south. The delta prograded northward
to the west of Barrow Island, and across to the Exmouth Plateau, to form the lower Barrow Delta
lobe. Approximately 75% of deposition by the Barrow Delta occurred during this phase (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 Barrow Group is known in parts as the Zeepaard Formation and Flag
Sandstone (Figure 3). 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, and of excellent porosity and
permeability. The Scarborough giant gas accumulation is hosted within a Barrow Group basin-floor
fan sandstone (Norvick, 2002: Figure 8).
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 3). Rapid subsidence following breakup
resulted in a widespread transgression and deposition of a fining-upward marine sequence over the
Valanginian unconformity surface (Figure 5, Figure 6 and Figure 7).
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 3). 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 Barrow and Dampier sub‑basins (Figure 3). The Windalia Sandstone has historically been a
major exploration target in the Barrow Sub‑basin (Figure 8). It contained over 90% of the initial oil
reserves of the Barrow Island oil field (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 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 5, Figure 6,
and Figure 7).
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During the Campanian, uplift of the hinterland resulted in a phase of inversion in the Exmouth
Sub‑basin and further west, forming the Exmouth Plateau Arch, Resolution Arch and Kangaroo
Syncline (Tindale et al, 1998). Pre-existing rift-related structures experienced transpressional
reactivation within the Barrow and Dampier 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 3).
In the Miocene, a major compressional event associated with the collision 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 strata were formed.
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REGIONAL HYDROCARBON POTENTIAL
Regional Petroleum Systems
Two 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, 1998) 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 following petroleum systems were
characterised in the Northern Carnarvon Basin by Spencer et al (1993, 1994, 1995) and Bradshaw
et al (1994):
•
Lower–Middle Jurassic-sourced petroleum system (Westralian 1); and
•
Upper Jurassic-sourced petroleum system (Westralian 2).
On the basis of a USGS resource assessment analysis, Bishop (1999) 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, and the
‘Dingo–Mungaroo/Barrow’ Petroleum System (Figure 8). The ‘Locker–Mungaroo/Barrow’ Petroleum
System has been renamed the ‘Locker/Mungaroo–Mungaroo/Barrow’ Petroleum System herein.
These two petroleum systems are considered to be the source of the commercially developed
accumulations within the basin.
The gas-prone ‘Locker/Mungaroo–Mungaroo/Barrow’ Petroleum System covers most of the basin,
extending to the margins of the Exmouth Plateau (Figure 8). 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 coal and carbonaceous
claystone 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).
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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) where 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).
Oils and condensates that could not be attributed to either of these two aforementioned 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 Rocks
The 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 fields of the Exmouth Plateau are inferred to have been charged from deeply buried coal
and carbonaceous claystone in the Mungaroo Formation, where peak gas generation is currently
expected at depths of over 5000 m below the sea floor (Bussell et al, 2001), although a 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. 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 into the source rock (Summons et al, 1998; Edwards and Zumberge, 2005).
Reservoirs and Seals
Reservoir formations 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 8).
The stratigraphic level of top-porosity across the basin generally becomes younger landward.
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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
field (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 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 with the loading of the Barrow
Delta (Tindale et al, 1998; Smith et al, 2003). In contrast, the main phase of generation in the
Dampier Sub‑basin was in the Cenozoic, in response to the progradation of the carbonate shelf
(Thomas et al, 2004).
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EXPLORATION HISTORY
The Northern Carnarvon Basin is Australia’s most prolific hydrocarbon-producing basin, with
86.2 MMbbl (13.7 GL) of oil, and 1,198.1 Bcf (33.9 Bcm) of gas having been produced in 2010
(Geoscience Australia, 2010). The basin accounts for over 95% of Western Australian and over
60% of the Australian total hydrocarbon production (Australian Bureau of Agricultural and Resource
Economics, 2010). Currently, most of the offshore part of the basin in Commonwealth waters is
under permit (Figure 8).
In the 2010–2011 fiscal year, one 2D seismic survey, thirteen 3D seismic surveys and three
4D seismic surveys were undertaken in the offshore Northern Carnarvon Basin, and 49 wells
were spudded, of which 24 were wildcat wells (Department of Mines and Petroleum, Petroleum
Division, 2011b). Other information on exploration drilling is provided by Lavin et al (2011).
Updated information on drilling, permit histories and reserves are given by Geoscience Australia
and Australian Bureau of Agricultural and Resource Economics (2010), Geoscience Australia
(2009a, 2009b) and Department of Mines and Petroleum, Petroleum Division (2010, 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 2010 is provided by Sebire (2011).
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 bopd (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 field was discovered in 1964 (Ellis et al, 1999), and the Griffin oil field 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, and
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 field.
Significant gas discoveries were made in the late 1970s to early 1980s. On the deepwater Exmouth
Plateau, a giant gas accumulation in a Lower Cretaceous Barrow Group basin floor fan was
discovered at Scarborough 1 in 1979 (Figure 8). The gas discovery at Spar 1 (1976) in the Barrow
Sub‑basin was also made in Lower Cretaceous sandstones. The Gorgon field, discovered in 1981,
is one of the largest gas fields within the Northern Carnarvon Basin.
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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, located 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.
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 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 Sub‑basin
In 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 field (Figure 2: Seggie et al, 2003). Development
wells continue to be drilled at Stag and Wandoo. Seraph 1 was recently drilled by Woodside
Energy Ltd through the Angel gas field and encountered a 26 m gross gas column within the North
Rankin Formation, and two thin gas columns within secondary objectives (Woodside Petroleum
Ltd, 2011a). The productive northern-end of the sub‑basin has been extended from the Mutineer
and Exeter oil fields (discovered in 1997 by Pitcairn 1 and Exeter 1 in 2002, respectively: Auld
and Redfearn, 2003) into the adjacent Beagle Sub‑basin, with oil discoveries having been made
at Fletcher 1 (2007) and recently at Finucane South 1A (2011) by Santos Offshore Pty Ltd
(Department of Mines and Petroleum, Petroleum Division, 2011b).
Barrow Sub‑basin
The Barrow Sub‑basin, in particular Barrow Island and the inshore part along the Barrow Island
Trend, has been the most actively and continuously explored offshore area in Australia over the last
25 years. Production facilities for Campbell, Harriet, Rosette and neighbouring fields are located on
Varanus Island, and for Saladin and neighbouring fields on Thevenard Island (Figure 2).
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13
Recent drilling in the Barrow Sub‑basin includes the Barberry 1, Bath 1 and Laurel 1 exploration
wells that were drilled in 2010 by Apache Oil Australia P/L near to Airlie Island (Figure 2). Bath 1
discovered oil in a shallow secondary objective which is the oil-bearing (Mardie Greensand)
reservoir of the Taunton discovery (TapOil Limited, 2010). Chutney 1, also drilled in 2010 by
Apache Energy Limited, is located in proximity to the John Brookes gas field. Extension/appraisal
and development drilling has been undertaken over the last few years around the John Brookes,
Rosella, Spar and Maitland gas fields and the Woollybutt oil field in the northwestern Barrow
Sub‑basin, and at Linda North near to Varanus Island.
Exmouth Sub‑basin
In the Exmouth Sub‑basin, the Vincent and Enfield oil discoveries were made in 1998 and 1999,
respectively, and 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. In 2010, Black Pearl 1 was drilled by
BHP Billiton Petroleum Pty Ltd into the Macedon field. Recently, Cimatti 1 was drilled by Woodside
Energy Ltd to test a near field prospect within tieback distance to Enfield and intersected a gross
15 m oil column in the Macedon Formation (Woodside, 2010). It was sidetracked as Cimatti 2
to further appraise the discovery. 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).
Extension/appraisal and development wells have been drilled in the Exmouth Sub‑basin since the
discovery of the Vincent/Van Gogh and Enfield oil fields. During 2010–2011, BHP Billiton Petroleum
Pty Ltd drilled development wells at Macedon, Ravensworth, Sickle and Stybarrow, and Woodside
drilled development wells in the Vincent/Van Gogh and Enfield oil fields, as well as completing the
Laverda East 1, Laverda North 1 and 2 and Opel 2 extension/appraisal wells.
Rankin Platform and Exmouth Plateau
Growing 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. The supergiant Io/Jansz gas field, discovered in 2000 on the Exmouth Plateau,
is hosted by Oxfordian shallow-marine sandstone (Jenkins et al, 2003), with the gas migrating
through a Triassic reservoir at Geryon.
On the northern Rankin Platform, recent exploration drilling has sought to expand beyond the
known fields, and includes Tidepole East 1 (2011) drilled by Woodside Petroleum Ltd, Fullswing 1
(2011) drilled by Japan Energy Corporation northeast of Perseus, and Artemis 1 (2009) and Zeus 1
(2009) drilled by MEO Australia Limited to the west of Perseus.
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14
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 fields (discovered in 2007 and 2008, respectively) with the drilling of Balnaves 1 to 4
and Balnaves Deep 1 (Apache Corporation, 2011c). Apache Energy Ltd also drilled the Julimar
South West 1 and 2 extension/appraisal wells in 2010, with Woodside Petroleum Ltd continuing to
drill development wells at Pluto, and Chevron Australia Pty Ltd drilling an extension/appraisal well at
West Tryal Rocks.
On the southern Rankin Platform at Gorgon, Chevron Australia Pty Ltd drilled several development
wells, in addition to discovering gas at Satyr 1 (2009) and Sappho 1 (2010) to the southwest of the
Gorgon field on the Exmouth Plateau (Chevron Australia Pty Ltd, 2009a, 2010b, 2011c). Located
to the south of, and on trend with the Gorgon field is Zola 1 ST1, drilled by Apache Northwest P/L
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 field are the Maenad and Orthrus gas fields,
discovered in 1999–2000. Recent success at Achilles 1 (Chevron Australia Pty Ltd, 2009b) and
Acme 1 (Chevron Australia Pty Ltd, 2010a) 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 field (Department of Mines and Petroleum, Petroleum
Division, 2011b).
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). Hess has since drilled 16 wells within
WA-390-P, of which 13 are reported as gas discoveries (Hess, 2011).
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15
The recent gas discoveries by Woodside Petroleum Ltd (2011b) at Larsen 1, Larsen Deep 1,
Martell 1, Martin 1, Noblige 1 and Remy 1A have extended the northerly limit of known gas
accumulations on the Exmouth Plateau. Chandon 1 and Yellowglen 1 are gas discoveries, west of
the Io/Janz gas field. To the north, Camus 1, Hine 1, Kelt 1 and Moyet 1 were drilled by Woodside
in 2010–2011, and, even further north; Delia South 1 (Woodside Petroleum Ltd), and La Rocca 1,
Galahad 1 and Gawain 1 (Apache Northwest Pty Ltd) were drilled in 2011, as companies look to
define the limit of the gas plays. Similarly, the gas discoveries at Brederode 1, Kentish Knock 1/
Guardian 1, and Thebe 1 and 2 have extended the northwesterly limit of known gas accumulations
on the outer Exmouth Plateau. The most westerly exploration wells drilled to date are Tiberius 1,
Alaric 1 and Cadwallon 1 by Woodside Petroleum Ltd in 2010. Alaric 1discovered 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 deepwater
western margins of the Exmouth Plateau. Another two wells are scheduled to be drilled on the
outer limits of the plateau in late 2011 to early 2012; Vos 1 by Chevron Australia Pty Ltd, in permit
WA-439-P and Genseric 1, in permit WA-434-P by Woodside Petroleum Ltd.
Production Status
In 2010, the Australian Petroleum Production and Exploration Association (2011) reported that there
were 13 production areas in the Northern Carnarvon Basin:
•
The North West Shelf Development Project located mostly on the northern Rankin Platform;
•
Mutineer/ Exeter, Legendre, Stag and Wandoo in the Dampier Sub‑basin;
•
Barrow, Thevenard and Varanus islands in the Barrow Sub‑basin; and
•
Enfield, Pyrenees, Stybarrow, Vincent/Van Gogh in the Exmouth Sub‑basin.
Since that report, the Legendre oil field has been decommissioned (Wilkinson, 2010) and the
Woollybutt oil field resumed production in March 2010 (TapOil Limited, 2011). Currently there are
three sources of domestic natural gas produced from the Carnarvon Basin; the Northwest Shelf
Development Project, Varanus Island, and as of December 2011, the Devil Creek Development
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.
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16
Rankin Platform
The North West Shelf Venture’s 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 (Woodside, 2011b). Representing an investment of A$27 billion,
the facilities constitute Australia’s largest oil and gas resource development and accounts for more
than 40% of Australia’s oil and gas production. In 2009, it had been producing domestic gas for
25 years, with first production occurring from North Rankin and had been exporting LNG to the
Asia Pacific region for 20 years. 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 was processed via
the Cossack Pioneer floating production storage and offloading (FPSO) facility which produced
approximately 40,000 bopd (Woodside, 2011b). Hydrocarbons from the offshore production facilities
are transported to the Karratha Gas Plant for processing via two subsea pipelines.
Located 1,260 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, three LPG fractionation units, as well as storage and loading facilities for LNG, LPG
and condensate. The plant has the capacity to produce 12,000 tonnes a day of domestic gas,
52,000 tonnes a day of LNG, 4200 tonnes a day of LPG and 165,000 bcpd. In 2008, annual LNG
production capacity at the Karratha Gas Plant increased to 16.3 million tonnes (Woodside, 2011b).
The North West Shelf Development Project (NWSDP) involves the redevelopment of the
North West Shelf Venture to extend the field life of this established facility (Woodside, 2011b).
This initiative includes the A$5 billion North Rankin Redevelopment Project, which will result in
a second offshore gas processing facility to commence operation in 2013, and the A$1.8 billion
Cossack–Wanaea–Lambert–Hermes (CWLH) Redevelopment Project, which commenced
production in September 2011 after the replacement of the previous FPSO with the Okha and a
subsea infrastructure upgrade (Woodside Petroleum Ltd, 2011d). 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 tie-back to the Goodwyn A platform.
Dampier Sub‑basin
Apache Corporation’s Devil Creek Development Project (Apache DCDP, 2011), located south of
Karratha, commenced supply of domestic gas from the Reindeer field to the Dampier–Bunbury
Natural Gas Pipeline via a new offshore pipeline and an onshore processing plant in December
2011. The two-train plant is designed to process 200 MMcfd gas, as well as delivering up to
500 bcpd condensate into the pipeline.
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17
The Mutineer/Exeter facilities are operated by Santos with joint venture partners KUFPEC, Nippon
oil and Woodside which commenced production in March 2005 via a FPSO vessel that is currently
recovering approximately 8,000 bopd (Santos, 2011c). A final investment decision (FID) by Santos
to develop the Fletcher and Finucane South oil discoveries was announced in January 2012
(Santos, 2012). The A$490 million project will be developed through a three well sub-sea tie back
to the Mutineer/Exeter FPSO facility. Oil production is expected to commence in the second half of
2013, at an estimated average gross production rate of 15,000 bopd for the first year.
Oil has been produced from the Stag field since May 1998 via an FPSO facility that is operated by
Apache and partner Santos. The field comprises eight production wells (supported by three water
injection wells) which currently produces approximately 8,000 bopd (Santos, 2011d).
The Wandoo oil field is operated by Vermilion Energy Inc and produces from the Wandoo A
Monopod and Wandoo B Platform.
Barrow Sub‑basin
The Barrow Island production facility is operated by Chevron Australia with partners Santos
and ExxonMobil. The field was discovered in 1964 by West Australian Petroleum Pty Ltd and
is the largest oil field in Western Australia. Appraisal drilling has defined in-place oil reserves of
1,250 MMbbls and in-place gas reserves of 580 Bcf (Ellis et al, 1999). Oil production commenced
in April 1967, with more than 300 MMbbls oil recovered to date (Chevron Australia, 2011a).
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 Sandstone
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, 2011a). Oil is collected from eight gathering stations and stored in
a one million barrel storage facility on the island and exported via an offshore tanker mooring. Gas
reserves within the Biggada Formation, estimated to contain 515 Bcf 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 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, 2011b). The facilities are capable of processing
120,000 bopd and 18 MMscfd (Santos, 2011e). Oil is stored at a one million barrel 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 oil,
condensate and gas. It is also Western Australia’s second largest domestic gas facility, transporting
gas to mainland Western Australia via two 100 km sales gas pipelines which connect into the
Dampier–Bunbury and Goldfields Gas Transmission trunklines (Santos, 2011b). A review in 1997 of
the Tryal Rocks 1 data, suggested the presence of a hydrocarbon column and subsequent drilling
led to the discovery of the John Brookes gas accumulation in 1998. Currently, the reserves from the
many oil and 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 tie back to the East Spar field and from there to the Varanus
Island facilities (Apache Corporation, 2011a). It is predicted that other resources, such as the
Spar discovery (planned for 2012), will continue to be brought on-stream as additional capacity
becomes available.
The Woollybutt oil field is 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.
Recent development included the drilling of horizontal wells, with the field recommencing production
from the Four Rainbow FPSO facility in March 2010 at rates of approximately 8,000 bopd
(TapOil Limited, 2011).
Exmouth Sub‑basin
Combined reserves of major fields in the Exmouth Sub‑basin, including Enfield, Laverda, Pyrenees,
Stybarrow and Vincent/Van Gogh, indicate that the province contains more than 300 MMbbl (48 Gl)
of heavy crude, with production estimated to reach 250,000 bopd (40,000 kl/d) (Department of
Mines and Petroleum, Petroleum and Royalties Division, 2008).
The BHP Billiton-operated Pyrenees project commenced production from the Crosby, Ravensworth
and Stickle oil discoveries through the Pyrenees FPSO facility at Pyrenees in March 2010 (BHP
Billiton, 2010b). Produced gas from these fields will be reinjected into the nearby Macedon gas
reservoir. The latter will be developed through the BHP Billiton-operated Macedon Development
Project, which will supply domestic gas via a processing plant, to be constructed at Ashburton
North, to the Dampier to Bunbury Natural Gas Pipeline, with first production expected in 2013
(BHP Billiton, 2010a).
The Enfield oil field is operated by Woodside, with partner Mitsui, and commenced production
through the Nganhurra FPSO facility commenced in July 2006 (Woodside, 2011a). Enfield was
discovered in 1999 along with the nearby Vincent/Van Gogh and Laverda oil fields.
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).
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The Vincent oil field is operated by Woodside, with partner Mitsui E&P Australia Pty Ltd, and
commenced production in August 2008 (Woodside, 2011c). The Van Gogh extension of the Vincent
oil discovery commenced production in February 2010 using the Ningaloo Vision FPSO facility
operated by Apache Corporation and is projected to receive oil from the Coniston/Novara field
during 2013. The project is expected to produce 40,000 bopd (Department of Mines and Petroleum,
Petroleum Division, 2010).
Development Status
Currently there are five LNG development projects in progress in the Northern Carnarvon Basin;
Gorgon, North West Shelf Venture, Pluto, Scarborough and Wheatstone.
The Gorgon LNG project is currently the largest single resource natural gas project in Australia and
will produced gas initially from the Greater Gorgon field, followed by the Io/Jansz field. This project
is operated by Chevron Australia Pty Ltd, with joint venture partners ExxonMobil, Shell, Osaka
Gas, Tokyo Gas and Chubu Electric Power Co (Chevron Australia, 2011c). Production facilities
incorporate a three-train export LNG plant on Barrow Island with a combined capacity of 15 Mtpa,
a domestic gas plant to supply the Western Australian markets, and a large-scale carbon dioxide
reinjection project. First LNG production is planned for 2014.
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 and Xena discoveries (Woodside Petroleum Ltd, 2011c). The plant is
expected to commence export in March 2012. Exploration to underpin an expansion of this project
is underway. The initial phase of the project comprises an offshore platform in 85 m of water,
connected to the five subsea wells at Pluto. Gas will be piped in a 180 km trunkline to an onshore
facility, located between the North West Shelf 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.
The Scarborough gas field is being developed jointly by Esso Australia Resources Pty Ltd
(operator; an affiliate of ExxonMobil) and BHP Billiton, with plans to include the nearby Thebe gas
field (ExxonMobil, 2011).
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20
In September 2011, Chevron Australia delivered the FID on the Wheatstone LNG Project, with
Apache, Kuwait Foreign Petroleum Exploration Co (KUFPEC) and Shell as equity participants
(Chevron Australia, 2011d). 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.
Apache and KUFPEC will supply additional gas from Julimar and Brunello (Julimar Development
Project) to the Wheatstone LNG plant (Apache Corporation, 2011d), which may eventually
produce up to 25 Mtpa of LNG. Moreover, Apache also plans to produce oil from the Balnaves
accumulation underlying Brunello via an FPSO by 2014 (Apache Corporation, 2011c). The Julimar
Development Project (JDP) is expected to produce in excess of 2.1 Tcf of sales gas approximately
140 MMscfd of LNG (1.07 MMtpa), 22 MMscfd of domestic gas and 3,250 bcpd of condensate
(Apache Corporation, 2011c).
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21
FIGURES
Figure 1
Structural elements of the Northern Carnarvon Basin and adjacent basins
showing the 2012 Release Areas and petroleum fields and discoveries.
Figure 2
Petroleum production facilities, hydrocarbon accumulations and current and
proposed pipeline infrastructure in the Northern Carnarvon Basin.
Figure 3
Stratigraphy and hydrocarbon discoveries of the Northern Carnarvon Basin
based on the Northern Carnarvon Basin Biozonation and Stratigraphy Chart
(Nicoll et al, 2010). Geologic Time Scale after Gradstein et al (2004) and Ogg
et al (2008). AGSO regional seismic horizons after AGSO (2001).
Figure 4
Location of regional cross-sections in the Northern Carnarvon Basin.
Figure 5
AGSO seismic line 110/03 across the southwestern Beagle Sub‑basin and
Lambert Shelf. Location of line shown in Figure 1. Regional seismic horizons
shown in Figure 3.
Figure 6
AGSO seismic line 101r/09 across the central Exmouth Plateau and Dampier
Sub‑basin. Location of line shown in Figure 1. Regional seismic horizons shown
in Figure 3.
Figure 7
AGSO seismic line 110/12 across the western Exmouth Plateau and
southwestern Barrow Sub‑basin. Location of line shown in Figure 1.
Regional seismic horizons shown in Figure 3.
Figure 8
Petroleum systems of the Northern Carnarvon Basin (Bishop, 1999), with
the reservoir age of the major oil and gas accumulations shown. Location of
petroleum permits and the 2012 Release Areas in Commonwealth waters are
also shown.
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22
REFERENCES
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documents/25.11.11%20annual%20investor%20update.pdf (last accessed 16 January 2012).
WOODSIDE PETROLEUM LTD, 2011b—[Web page] Gas Discovery at Martin-1. ASX
Announcement 17 March 2011. http://www.woodside.com.au/investors-media/announcements/
documents/17.03.2011%20gas%20discovery%20at%20martin-1.pdf (last accessed
16 January 2012).
WOODSIDE PETROLEUM LTD, 2011c—[Web page] Pluto LNG Project. http://www.woodside.com.
au/Our-Business/Pluto/Pages/default.aspx (last accessed 27 November 2011).
WOODSIDE PETROLEUM LTD, 2011d—[Web page] Production Commences from Okha
FPSO. ASX Announcement 26 September 2011. http://www.woodside.com.au/Investors-Media/
Announcements/Documents/26.09.2011%20%20Production%20Commences%20From%20
Okha%20FPSO.pdf (last accessed 16 January 2012).
www.petroleum-acreage.gov.au
31
Argo Abyssal Plain
16°
NT
QLD
WA
W12-7
SA
NSW
VIC
TAS
ROEBUCK
BASIN
Wombat
Plateau
2012 Offshore Petroleum
Acreage Release Area
Gas field
Rowley
Sub-basin
Oil field
Gas pipeline
Gascoyne Abyssal Plain
Gas pipeline (proposed)
18°
Oil pipeline
Basin outline
Sub-basin outline
NORTHERN CARNARVON BASIN
Fault
Syncline
Petroleum exploration well - Gas show
Beagle
Sub-basin
Exmouth Plateau
W12-10
lin
e
NOR TH
Rankin
Platform
Sy
nc
W12-11
R
ar
o
o
RO S
Sult
an
Nos
e
n
ch
ti o
e
ac
e
.
F.S
Lambert Shelf
er
yT
Petroleum exploration well - Gas discovery and oil show
uc
Br
IN
D
h
W12-9
20°
ce
ra
Dampier
S
Peedamullah
Shelf
D
LA N
FL
ER
.
F.S
22°
WESTERN AUSTRALIA
SOUTHERN CARNARVON BASIN
112°
Bernier
Platform
Gascoyne
Sub-basin
114°
Merlinleigh
Sub-baisn
0
100 km
116°
118°
Petroleum exploration well - Oil show
Petroleum exploration well - Oil discovery
Petroleum exploration well - Oil and gas show
rr
Te
Pilbara Block
.
F.S
Exmouth
Sub-basin
Cuvier Abyssal Plain
Bedout
Sub-basin
.
SH OL L IS
c
Ar
Arch
aloo
Ning
Exmouth
er b
F.S
Barrow
Sub-basin
p
Al
ra
va
No
R
olu
es
W12-8
ch
Ar
W12-14
Ar
Y
AR
Dampier
Sub-basin
Barrow Is
W12-13
De Grey
Nose
.
F.S
EM
En d
ha
Investigator Sub-basin
Ka
ng
W12-12
K IN
AN
TU R
E
TL
Petroleum exploration well - Gas discovery
11-5784-1
Well symbol information is sourced either from "open file" data from titleholders where this is publicly available as at 1 December 2011 or from other public sources. 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 the information used by it are correct before any reliance is placed on them.
Figure 1:Structural elements of the Northern Carnarvon Basin and adjacent basins showing the 2012 Release Areas and petroleum fields and discoveries.
112°
113°
114°
115°
Martell
Larsen Deep
Thebe
Martin
Wheatstone
Yellowglen
Io/Jansz
Urania
Scarborough
Eendracht
Alaric
Eurytion
Briseis
Glencoe
Dionysus
Maenad
Nimblefoot
Xena
Brulimar
Brunello
Orthrus
Julimar
Chrysaor
Acme
Clio
Achilles
Sappho
Zeepaard
Spar
Antiope
100 km
Skiddaw
Laverda
Falcone
Exmouth
22°
0
10 km
Airlie Island Basil
Taunton
Blackthorn
Dillson
Australind
Crest
Thevenard Island
Saladin A, B, C
Saladin
23°
115°15'
W
115°30'
Mulyery
Mardie
Carnie
Monopod/Minipod
11-5784-2
Varanus Island
Zephyrus Rosette
20°40'
Artreus
Agincourt
South Plato
Gobi
Romulus
Remus
2.5 km Pedirka
Albert
Victoria
Double Island
Oil storage tanks
Campbell
Wonnich
Subsea gas well
Orpheus
Bambra East
20°30'
Windsor
Sinbad
Linda
See Inset C
North
Marra
Harriet
Rose
Lee
Monty
Josephine
Gudrun
Baker
Bob
Monet
Ginger
20°45'
Barrow
Island
Tanami
Simpson
Gibson
South Gibson
West Cycad
Barrow Island
Dugong
Pasco
115°30'
Narvik
Hermite
Peck
Hoover
Little Sandy
Denver
Highgrove
Cycad
North Pedirka
Mohave
Mini platform
LNG storage tanks
Kultarr
115°35'
Abandoned field
Floating production storage and
offloading vessel
Tripod
Flag
Topaz
Gas and oil discovery
Onshore oil production
See Inset A
Tubridgi
Gas discovery
Oil discovery
Onshore gas production
Bennet
Jane
WESTERN
AUSTRALIA
Skate
WA
Dampier
Storage
Immortelle
North
Herald
Inset C
Parrot Hill
Conventional oil platform
Errol (Flinders Shoal)
South Pepper
Inset B
0
Onslow
Conventional gas platform
Bambra
Rough Range
21°30'
Roller 115°00'
Gas subsea tieback
Gipsy
Cowle
Coaster
Pepper
Alkimos
Santa Cruz
Yammaderry
Road
Oil subsea tieback
See Inset B
North Alkimos
Chervil
Elder
South
Chervil
Cyrano
Cadell
Oil pipeline
Dampier
Nasutus Thringa
Myanore
Leatherback
Ridley
Rivoli
Gas pipeline (proposed)
Roebourne
Rosily
Blencathra
Cape Range
Inset A
Antler
Chamois
Outtrim
Ravensworth
Crosby
Stickle
Harrison
Wandoo
Gas pipeline
Morrel
Hampton
Stag
Oryx
Coniston/Novara Nimrod
Vincent/Van Gogh
Bleaberry West
Corowa
Pyrenees/
Macedon
Elk
Halyard
East Spar
Boojum
Scafell
Oil field
Cherring
Maitland
Chinook/ Bowers
Scindian
Griffin
0
Gas field
Altostratus
Woollybutt
Enfield
Legendre
Lauda
21°
Zeewulf
TAS
Gungurru
Okapi
NSW
VIC
Karratha
Zola
Sirius
Amulet
QLD
SA
Forestier
Hurricane
Reindeer
Caribou
Tusk
John Brookes
Rosella South
Stybarrow
Venture
Rosella North
Vinck
Resolution
Libris
Corvus
West Tryal Rocks
Gorgon
Satyr
Wilcox
Cossack
Ajax
Sage
Saffron
Rosemary
NT
WA
Talisman
Angel
Montague
Wanaea
Gaea
Tidepole
Pemberton
Keast/Dockrell
Rankin
Lady Nora
Dixon
Haycock
Iago
Saturn
20°
Goodwyn
Sculptor
Pluto
Geryon
Eskdale
Echo/Yodel
North
Rankin
Fletcher
Finucane
Hermes
Lambert
Egret
Perseus
Chandon
Jupiter
Brederode
Eaglehawk
117°
Mutineer
Exeter
Noblige
Remy
Kentish Knock/
Guardian
116°
0
10 km
115°45'
Well symbol information is sourced either from "open file" data from titleholders where this is publicly available as at 1 December 2011 or from other public sources. Field outlines and location of pipelines 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 and location of pipelines by PBS, no warranty is provided
regarding 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.
Figure 2:Petroleum production facilities, hydrocarbon accumulations and current and proposed pipeline infrastructure in the Northern Carnarvon Basin.
Subsea oil well
Subsea oil & gas well
Subsea completion
Lambert Fm
bter
Miria Fm
Maastrichtian
Beedagong
Claystone
Coniacian
tur
Barremian
150
Late
Kimmeridgian
Oxfordian
Jurassic
Callovian
Middle
Miria Fm
Miria Fm
Withnell
Formation
Withnell
Formation
Withnell
Formation
Toolonga
Calcilutite
Toolonga
Calcilutite
Toolonga
Calcilutite
Beedagong
Claystone
Bathonian
Bajocian
Undifferentiated
Barrow
Group
Early
190
Hettangian
bjtt
Dupuy
Fm
Dingo
Claystone
Biggada Fm
Calypso
Formation
Mardie
Greensand
Mbr
Forestier
Claystone
Windalia
Sand Mbr
Cape Range Group
Windalia
Radiolarite
Windalia
Sand Mbr
M. australis
Sandstone Mbr
M. australis
Sandstone Mbr
Muderong
Shale
Muderong
Shale
Mardie
Greensand
Member
Birdrong
Sandstone
Forestier
Claystone
Angel Fm
Dingo
Claystone
Mardie
Greensand
Member
Birdrong
Sandstone
Forestier
Claystone
Angel Fm
Dingo
Claystone
Eliassen Fm
Legendre Fm
Legendre Fm
Legendre
Formation
Athol
Formation
Athol
Formation
Athol
Fm
Murat
Siltstone
Murat
Siltstone
Murat
Siltstone
Murat
Siltstone
Murat
Siltstone
North Rankin
Formation
North
Rankin
Formation
North
Rankin
Formation
North
Rankin
Formation
Brigadier
Formation
Brigadier
Formation
Brigadier
Formation
Brigadier
Formation
Brigadier
Formation
Brigadier
Formation
Mungaroo
Formation
Mungaroo
Formation
Mungaroo
Formation
Athol
Formation
Athol
Formation
Calypso
Formation
Norian
220
Pre-rift
Late
Triassic
Carnian
Ladinian
240
250
Mungaroo
Formation
Cossigny
Member
Cossigny Mbr
Cossigny Mbr
Cossigny Mbr
Mungaroo
Formation
Anisian
Early
Mungaroo
Formation
mtri
Middle
Locker
Shale
Olenekian
Locker
Shale
Locker
Shale
Locker
Shale
Locker
Shale
Chinty
Formation
Chinty
Formation
Induan
Permian
Changhsingian
260
Winning Group
Dingo
Claystone
Undifferentiated
Barrow
Group
Athol
Formation
Murat
Siltstone
Rhaetian
210
230
Undifferentiated
Barrow
Group
Flag Sandstone
Muderong
Shale
Windalia
Radiolarite
Gearle
Siltstone
Calypso
Formation
Sinemurian
200
Birdong
Sandstone/
Zeepaard Fm
Windalia
Radiolarite
Haycock
Marl
Calypso
Formation
Toarcian
Pliensbachian
Muderong
Shale
Birdong
Sandstone/
Zeepaard Fm
(inc. Eskdale Mbr)
Dingo
Claystone
Windalia
Radiolarite
Mardie
Greensand
Member
Jansz
Sandstone
call
Aalenian
180
Cape Range Group
Miria Fm
Mardie
Greensand
Member
Dupuy Fm
Early syn-rift
160
170
bcre
Main syn-rift
Tithonian
Late
syn-rift
val
140
Berriasian
Walcott
Formation
Miria Fm
Windalia Sand Mbr
Muderong
Shale
Muderong
Shale
Hauterivian
Valanginian
Dockrell Fm
Lambert Fm
Mungaroo
Formation
130
Windalia
Radiolarite
Barrow Gp
apt
Early
Wilcox
Formation
Lambert Fm
Gearle
Siltstone
Learmonth Formation
Aptian
Windalia
Radiolarite
Winning Group
Post-rift active
Albian
120
Gearle
Siltstone
Gearle
Siltstone
Barrow Gp
Cretaceous
110
Dockrell Fm
Walcott
Formation
Lambert Fm
Cenomanian
100
Mandu
Limestone
Lambert Fm
Gearle Siltstone
Santonian
Turonian
Dockrell Fm
Wilcox
Formation
Haycock Marl
Toolonga
Calcilutite
Toolonga
Calcilutite
80
90
Mandu
Limestone
Bare
Formation
Trealla Limestone
Korojon Calcarenite
Campanian
Late
Miria Fm
Dockrell
Formation
Wilcox
Formation
Gearle Siltstone
70
Cardabia
Calcarenite
Dockrell Fm
Selandian
Danian
Giralla
Calcarenite
Angel Formation
Paleocene
Walcott
Formation
Wilcox
Formation
beoc
Thanetian
60
Trealla Limestone
Giralia
Calcarenite
Lutetian
Ypresian
Mandu
Limestone
Bare
Formation
Walcott
Formation
Passive margin
Paleogene
50
Bartonian
Eocene
Mandu
Limestone
Delambre
Formation
molig
Priabonian
40
Unnamed
Tulki
Limestone
Bullara
Limestone
Mandu
Limestone
Rankin Platform
Delambre
Formation
Bare
Formation
Trealla Limestone
Giralia
Calcarenite
Rupelian
Trealla Limestone
Delambre
Formation
Haycock Marl
Oligocene
30
Trealla
Limestone
Pilgramunna Fm
Dampier Sub-basin
Cape Range Group
Mandu
Limestone
Chattian
Delambre
Formation
Dingo Claystone
Aquitanian
bmio
Beagle Sub-basin
Cape Range Group
Langhian
Burdigalian
20
Trealla
Limestone
Serravallian
Barrow Sub-basin
Exmouth
Sandstone
Delambre
Formation
lmio
Tortonian
Miocene
Exmouth Sub-basin
Walcott
Formation
Neogene
Messinian
10
Exmouth Plateau
Wilcox
Formation
Pliocene
M. Pleist.
E. Pleist.
Gelasian
Piacenzian
Zanclean
Withnell
Formation
Pleistocene
Seismic horizon Basin
phases
(AGSO, 2001)
Giralia
Calcarenite
Lt. Pleist.
Cardabia
Calcarenite
Stage
Holocene
Toolonga Calcilutite
Quaternary
Epoch
Cape Range Group
Age
Period
(Ma)
Lopingian
Guadalupian
tper
Wuchiapingian
Capitanian
11-5784-3
Figure 3:Stratigraphy and hydrocarbon discoveries of the Northern Carnarvon Basin based on the Northern Carnarvon Basin Biozonation and Stratigraphy Chart (Nicoll et al, 2010).
Geologic Time Scale after Gradstein et al (2004) and Ogg et al (2008). AGSO regional seismic horizons after AGSO (2001).
16°
Argo Abyssal Plain
NT
QLD
WA
SA
W12-7
NSW
VIC
Wombat
Plateau
TAS
ROEBUCK
BASIN
Fig
ur
5
W12-10
Exmouth
Plateau
re
Gascoyne Abyssal Plain
gu
Fi
NORTHERN CARNARVON BASIN
Fi
gu
re
Beagle
Sub-basin
6
Bedout
Sub-basin
Rankin
Platform
W12-11
e7
Dampier
Sub-basin
W12-12
Investigator
Sub-basin
W12-8
W12-13
Dampier
Pilbara Block
W12-9
Exmouth
Peedamullah
Shelf
Exmouth
Sub-basin
Gascoyne
Sub-basin
Bernier
Platform
20°
Barrow
Sub-basin
W12-14
Cuvier Abyssal Plain
Lambert
Shelf
WESTERN
AUSTRALIA
Merlinleigh
Sub-basin
SOUTHERN CARNARVON BASIN
0
100 km
114°
118°
11-5784-7
Well symbol information is sourced either from "open file" data from titleholders where this is publicly available as at 1 December 2011 or from other public sources. 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 the information used by it are correct before any reliance is placed on them.
2012 Offshore Petroleum
Acreage Release Area
Petroleum exploration well - Not classified
Gas field
Petroleum exploration well - Gas show
Petroleum exploration well - Dry hole
Oil field
Petroleum exploration well - Gas discovery
Gas pipeline
Petroleum exploration well - Oil discovery
Petroleum exploration well - Oil show
Gas pipeline (proposed)
Petroleum exploration well - Oil and gas show
Oil pipeline
Petroleum exploration well - Gas discovery and oil show
Seismic section figure location
Petroleum exploration well - Gas and oil discovery
Basin outline
Sub-basin outline
Figure 4:Location of regional cross-sections in the Northern Carnarvon Basin.
Exmouth
Plateau
NW
Lambert Shelf
Beagle Sub-basin
Delambre 1
Ronsard 1
Cossigny 1
SE
0
iocene
Late M
Miocene
Base
ligocene
Mid O
Base Eocene
2
Valanginian
Callo v ian
zoic
o
Base Cen
Base
Cretaceous
n
Turonia
Aptian
Jurassic
Base
4
Two-way time (s)
Intra Triassic
6
Top Permian
iferous
arbon
Late C
8
10
ent
em
Bas
Line 110/03
11-5784-4
0
50 km
Figure 5:AGSO seismic line 110/03 across the southwestern Beagle Sub‑basin and Lambert Shelf. Location of line
shown in Figure 1. Regional seismic horizons shown in Figure 3.
NW
Rankin
Platform
Exmouth Plateau
Lambert
Shelf
Dampier Sub-basin
Goodwyn 7
Rosemary 1
Hampton 1
SE
Strickland 1
0
Aptian
2
Base Cretaceous
ng
Vala
Ba
an
Ju
se
Two-way time (s)
inian
vi
lo
l
Ca
ic
ass
Tri
a
Intr
4
Cenozoic
onian
Tu r
ic
Mid Oligocene
Ba
ss
Base Eocene
se
ne
ioce
Base M
ra
Late Miocene
Top
on
Carb
Late
8
10
n
Permia
us
ifero
Ba
se
m
en
t
6
Line 101r/09
11-5784-5
0
50 km
Figure 6:AGSO seismic line 101r/09 across the central Exmouth Plateau and Dampier Sub‑basin. Location of line
shown in Figure 1. Regional seismic horizons shown in Figure 3.
W12-8
W12-12
Exmouth Plateau
Exmouth Plateau
Investigator Sub-basin
NW
Eendracht 1
Exmouth Sub-basin
W12-9
Barrow Sub-basin
Investigator 1
Ramillies 1
SE
0
Base Cenozoic
Base Eocene
V alanginia
n
Aptian
Turonian
us
eo
Base Cretac
4
tra
In
Vol
6
can
Top
Callovian
ic
ass
Tri
Tr
Two-way time (s)
2
ene
Mid Oligoc
iocene
Late M
ics
ia
ss
ic
Top Permian
8
Late Carboniferou
s
10
Line 110/12
Basement
11-5784-6
0
100 km
Figure 7:AGSO seismic line 110/12 across the western Exmouth Plateau and southwestern Barrow Sub‑basin.
Location of line shown in Figure 1. Regional seismic horizons shown in Figure 3.
112°
18°
114°
116°
NT
WA
QLD
SA
NSW
VIC
TAS
2012 Offshore Petroleum
Acreage Release Area
Existing petroleum title
Mutineer
W12-10
Thebe
W12-11
20°
Martell
Alaric
Noblige
Jupiter
Wheatstone
Kentish Knock
Io/Jansz
Scarborough
Eendracht
Glencoe
Nimblefoot
Goodwyn
Forestier
Ajax
North
Rankin
Iago
Lago
Maenad
Legendre
Saffron
Reindeer
Gungurru
Corvus
Wandoo
Clio
Barremian
Valanginian and Berriasian
Stag
Gorgon
Tithonian, Oxfordian and Middle Jurassic
John Brookes
Late Triassic (Brigadier and Mungaroo
formations)
Maitland
Vinck
W12-13
W12-14
Dampier
East Spar
Barrow Island
W12-8
Sirius
Reservoir age (formation)
Paleocene
Haycock
Venture
Dingo-Mungaroo/Barrow
total petroleum system
Limit of Coastal Waters
Pluto
Saturn
Briseis
W12-12
Angel
Perseus
Chandon
Fletcher
Locker-Mungaroo/Barrow
total petroleum system
Pasco
Pepper
Zeewulf
Immortelle
Bennet
Resolution
Eskdale
Stybarrow
Novara
Enfield
Cyrano
Santa Cruz
W12-9
Skate
Falcone
Topaz
Tubridgi
22°
Exmouth
Rivoli
Cape Range
Parrot Hill
WESTERN AUSTRALIA
Rough Range
0
100 km
11-5784-8
Well symbol information is sourced either from "open file" data from titleholders where this is publicly available as at 1 October 2010 or from other public sources. 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 the information used by it are correct before any reliance is placed on them.
Figure 8:Petroleum systems of the Northern Carnarvon Basin (Bishop, 1999), with the reservoir age of the major oil and gas accumulations shown. Location of petroleum permits and
the 2012 Release Areas in Commonwealth waters are also shown.
Oil fields and
discoveries
Gas fields and
discoveries