REGIONAL GEOLOGY OF THE NORTHERN
CARNARVON BASIN
BASIN OUTLINE
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). It is bounded to the northeast by the Roebuck and
offshore Canning basins, to the southeast by the Pilbara Block, to the south
by the Southern Carnarvon Basin, and to the northwest by the Argo, Cuvier
and Gascoyne abyssal plains. The basin is predominantly offshore, covering
an area of approximately 535,000 km2 in water depths of up to 3,500 m
(Figure 1). The sedimentary fill is up to 15 km thick and dominated by deltaic
to marine siliciclastics and shelfal carbonates of Mesozoic age.
As one of Australia’s most explored and prospective basins, the Northern
Carnarvon Basin has ready access to established oil and gas exploration,
production and support infrastructure (Figure 2). Major oil and gas production
areas are located in the Barrow Island, Varanus and Thevenard areas of the
Barrow Sub-basin, the northern parts of the Rankin Platform and Dampier
Sub-basin, and the northern Exmouth Sub-basin. Large-scale development
projects under way include the Gorgon, Pluto and Wheatstone LNG projects,
Macedon–Pyrenees project (gas and oil) and Reindeer–Devils Creek
Development (gas). The basin is proximal to the major settlements of Port
Hedland, Karratha, Dampier, Onslow, Exmouth and Carnarvon, and the North
West Coastal Highway. A major LNG loading terminal and processing centre
is located at Karratha. The Dampier to Bunbury Natural Gas Pipeline and the
Goldfields Gas Transmission Pipeline provide a direct connection with the
major domestic and industrial markets of southern Western Australia (Perth,
Bunbury and the Goldfields), and the basin is favourably located in relation to
the main export markets in Southeast and East Asia.
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 Exmouth,
Barrow, Dampier and Beagle 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 (Figure 1).
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The geological evolution of the Northern Carnarvon Basin has been discussed
in detail 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) in the Exmouth Sub-basin, Stagg et al (2004) in the Exmouth
Plateau, Hearty et al (2002) in the Barrow Sub-basin, Woodside Offshore
Petroleum Pty Ltd (1988) and Barber (1994) in the Dampier Sub-basin, and
Blevin et al (1994) in the Beagle 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 northnorthwest–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 (Figure 1) are
described briefly below. Representative geologic sections through the basin
are shown in Figure 3, Figure 4, Figure 5, Figure 6 and Figure 7.
The Exmouth, Barrow and Dampier sub-basins are a series of large en
echelon rift depocentres (Figure 1) that contain a dominantly Triassic,
Jurassic and Lower Cretaceous sedimentary succession. Maximum sediment
thickness exceeds 10 km in the Exmouth and Dampier sub-basins and 15 km
in the Barrow Sub-basin (Figure 4 and Figure 5). The Barrow Delta
succession dominates the Lower Cretaceous section 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 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 km, and is dominated
by Triassic to Middle Jurassic sediments (Figure 6 and Figure 7). In contrast
to the other sub-basins, the Upper Jurassic succession is thin or absent.
The sub-basins are separated from each other by Paleozoic–Triassic fault
blocks that have been modified by faulting, uplift and/or rotation: the Alpha
Arch between the Exmouth and Barrow sub-basins, the Sultan Nose between
the Barrow and Dampier sub-basins (Polomka and Lemon, 1996), and the De
Grey Nose between the Dampier and Beagle sub-basins (Figure 1).
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The sub-basins are separated from the structurally high areas of the Rankin
Platform and Exmouth Plateau to the northwest, and the Lambert and
Peedamullah shelves to the east and south, by major extensional fault
systems (Figure 1). The Rankin Fault System separates the Rankin Platform
from the Dampier Sub-basin (Stagg and Colwell, 1994), and the Flinders and
Sholl Island fault systems separate the Peedamullah and Lambert shelves
from the Barrow and Dampier sub-basins (Kopsen and McGann, 1985;
Figure 1). 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
(Figure 1 and Figure 5) and the Bruce and North Turtle terraces in the
Beagle Sub-basin (Figure 1). 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).
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 km (Figure 4, Figure 5 and Figure 7).
Jurassic sediments are generally thin or absent. The major sub-elements of
the plateau include the Rankin Platform, Kangaroo Syncline, Investigator Subbasin 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).
The Lambert and Peedamullah shelves form the rift shoulders 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 km thick (Figure 6). In addition, Silurian–Permian
successions underlie parts of the Peedamullah Shelf.
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BASIN EVOLUTION AND TECTONIC DEVELOPMENT
The key evolutionary stages of the Northern Carnarvon Basin are (Figure 8):

Pre-rift intracontinental basins (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 intracontinental basins (Silurian to Toarcian)
North–south-trending intracontinental basins developed during the Silurian to
Permian in the initial stages of Gondwana breakup. Siliciclastic non-marine to
shallow marine sediments deposited during this phase are preserved only in
the deeper and southern parts of the basin today (Figure 4, Figure 5, Figure
6 and Figure 7).
Northeast–southwest-trending depocentres started to form during the latest
Permian. 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 8). The Locker Shale
grades upwards into the Middle to Upper Triassic Mungaroo Formation
(Figure 8). 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 ‘Top Triassic’
interval in Figure 4, Figure 5, Figure 6 and Figure 7). The upper Mungaroo
Formation consists of shoreline sandstone, shallow marine claystone and
minor limestone. In the Beagle Sub-basin, the Middle Triassic Cossigny
Member of the Mungaroo Formation (paralic and marine siltstone, claystone
and limestone) is a significant regional seismic marker (Figure 8). Fluvial and
shoreline sandstone of the Mungaroo Formation host the giant gas
accumulations on the Rankin Platform (Figure 9). The Mungaroo Formation is
also the main gas-prone source in the Barrow and Dampier 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
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central Australia, Argo Land, West Burma, and/or Greater India (Norvick,
2002; 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 8). On the Wombat Plateau,
uppermost Triassic reef 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 9). Thin, reservoir-quality
sandstones on some horst blocks along the Rankin Platform are known as the
North Rankin Formation (Seggie et al, 2007).
In the Beagle Sub-basin, the Late Triassic Fitzroy Movement (Smith et al,
1999) formed a series of structural highs and lows and led to the isolation of
the sub-basin from the Dampier Sub-basin (Blevin et al, 1994).
Early syn-rift (Toarcian to earliest Callovian)
Rifting from the Pliensbachian onward produced the general structural
framework of the Northern Carnarvon Basin that is apparent today. Major
bounding faults (e.g. the Rosemary, Flinders and Rankin fault systems)
developed, delineating the Barrow, Dampier and Exmouth sub-basins, the
Rankin Platform, and the Lambert and Peedamullah shelves (Figure 1).
An oblique extension vector 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).
The onset of rifting is marked by an unconformity at the JP1 seismic horizon
(previously known as the ‘Pliensbachian unconformity’; Figure 8). The
Toarcian to earliest Callovian syn-rift megasequence comprises restricted
marine claystone and siltstone of the Athol Formation and regressive deltaic
sandstone of the Legendre Formation (Figure 8). 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 oil field), and hosts gas fields such
as Reindeer and Rosemary (Figure 9).
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).
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Uplift and erosion associated with initial extension produced the Callovian
unconformity (JC seismic horizon; Figure 8). 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 (Figure 8). Major rift-related
faults developed along the northern edge of the Exmouth Plateau.
In the late Oxfordian, continental breakup and the onset of seafloor spreading
in the Argo Abyssal Plain (Norvick, 2002) resulted in the basal Oxfordian
unconformity, or the ‘Breakup Unconformity’ (JO seismic horizon; Figure 8).
In places, the basal Oxfordian unconformity corresponds to the so-called
‘Main Unconformity’. However, the latter is a diachronous sequence
boundary, of earliest Jurassic to Aptian age (Newman, 1994; Jablonski,
1997). The Main Unconformity 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 8), which progressively filled, and
overlapped the flanks of, the Barrow, Dampier and Exmouth sub-basins (see
the ‘Callovian’ to ‘Top Jurassic’ interval in Figure 4 and Figure 5; 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 9). These include turbiditic sandstone
of the Biggada, Eliassen, Dupuy and Angel formations, and shallow-marine to
shoreline Jansz and Linda sandstones (Jenkins et al, 2003; Moss et al, 2003;
Figure 8). 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 (Figure 9).
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
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(Figure 8), which attains a thickness of up to 2.5 km (see the ‘Top Jurassic’ to
‘Valanginian’ interval in Figure 4). 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.
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 8). 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 in the outer part of the
Northern Carnarvon Basin. The Scarborough giant gas accumulation is
hosted within a Barrow Group basin-floor fan sandstone (Norvick, 2002;
Figure 9).
Sediment supply to the Barrow Delta system ceased due to the
commencement of continental breakup to the southwest of the Exmouth
Plateau during the Valanginian (Hocking, 1990). The Exmouth Sub-basin and
Exmouth Plateau were tectonically inverted during breakup, but subsidence
and marine sedimentation continued throughout the Barrow and Dampier subbasins.
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 (KV seismic horizon; Figure 8). Rapid subsidence
following breakup resulted in a widespread transgression and deposition of a
fining-upward marine sequence over the Valanginian unconformity surface
(Figure 4, 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 8). The Muderong Shale is a regional seal, but also contains
economically important petroleum-bearing glauconitic sandstones such as the
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M. australis Sandstone (also known as the Stag Sandstone) and Windalia
Sandstone in the Barrow and Dampier sub-basins (Figure 8). The Windalia
Sandstone has historically been a major exploration target in the Barrow Subbasin (Figure 9). It contains 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 4, Figure 5, Figure 6 and Figure 7).
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). Preexisting 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 8).
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
The Carnarvon Basin is currently Australia’s most prolific hydrocarbonproducing basin; 58.2 MMbbl (9.26 GL) of oil, 1198 Bcf (33.9 Bcm) of gas and
46.6 MMbbl (7.42 GL) of condensate were produced in 2009 (Department of
Mines and Petroleum, Western Australia, 2010b). 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;
Department of Mines and Petroleum, Western Australia, 2010b). In 2009, 64
new wells were drilled in the offshore Northern Carnarvon Basin, of which 22
were wildcat wells (Department of Mines and Petroleum, Western Australia,
2010a). There were 28 production areas and fields in 2009 (Australian
Petroleum Production and Exploration Association, 2010).
Reservoirs, Seals and Trap Styles
Reservoir formations in the Northern Carnarvon Basin are dominated by
fluvio-deltaic and marginal marine sandstones, such as those within the
Triassic Mungaroo Formation, the Bajocian–Callovian Legendre Formation in
the Dampier and Beagle sub-basins, and the Berriasian–Valanginian Barrow
Group in the Barrow and Exmouth sub-basins and the Exmouth Plateau
(Figure 9). The stratigraphic level of top-porosity across the basin generally
becomes younger landward.
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 a 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 and the Paleocene Dockerell Formation at the Maitland gas
accumulation.
In addition, intra-formational seals result in stacked hydrocarbon-bearing
reservoirs. Gas accumulations on the Rankin Platform are top-sealed by a
combination of the regional seal and intra-formational claystones. Significant
intra-formational 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 basinfloor and turbidite fans, unconformity pinch-outs and onlaps. Structural
compartmentalisation of the basin has resulted in complex trap evolution and
charge histories. Figure 9 shows the major oil and gas accumulations
discovered in the Northern Carnarvon Basin.
Hydrocarbon Families and Source Rocks
Two broad hydrocarbon families are recognised in the Northern Carnarvon
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deltaic facies; and the other oil prone and sourced from Upper Jurassic
marine sediments.
The main gas source rocks in the Barrow, Dampier and Exmouth sub-basins
are the Triassic fluvio-deltaic sediments of the Mungaroo Formation, Upper
Triassic to Lower Jurassic marine sediments of the Brigadier Formation and
the Middle to Upper Jurassic deltaic Legendre Formation. The giant gas fields
of the Exmouth Plateau (Figure 9) were charged probably 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 sea floor
(Bussell et al, 2001). Geochemical studies indicate that the gas accumulations
of the Rankin Platform (Figure 9) accessed these Triassic sources as well as
Lower–Middle Jurassic sources in the adjacent Barrow and Dampier subbasins (Boreham et al, 2001; Edwards and Zumberge, 2005; Edwards et al,
2007).
The principal oil source in the Northern Carnarvon Basin is the Upper Jurassic
Dingo Claystone. It was deposited under deep, restricted marine conditions in
the Exmouth, Barrow and Dampier sub-basins. However, biomarker and
geochemical studies indicate a significant supplementary contribution from
terrestrial organic matter (Summons et al, 1998). The Oxfordian interval
(W. spectabilis biozone) is particularly organic rich (van Aarssen et al, 1996).
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.
These two broad hydrocarbon families are considered to be the source of
almost all the commercially developed accumulations within the Northern
Carnarvon Basin (Figure 9). However, geochemical studies have identified
some vagrant oils which do not fall into these families (Summons et al, 1998).
Lacustrine sources have been ascribed to the Nebo oil accumulation in the
Beagle Sub-basin and at Rough Range in the onshore Exmouth Sub-basin
(Longley et al, 2002; Edwards and Zumberge, 2005).
Regional Petroleum Systems
On the basis of a USGS analysis (Bishop, 1999), two petroleum systems are
recognised in the Northern Carnarvon Basin: the ‘Locker/Mungaroo–
Mungaroo/Barrow’ Petroleum System, and the ‘Dingo–Mungaroo/Barrow’
Petroleum System.
The gas-prone ‘Locker/Mungaroo–Mungaroo/Barrow’ Petroleum System
covers most of the basin to the margins to the Exmouth Plateau. It is primarily
sourced from the Triassic Mungaroo Formation. However, basin modelling
suggests that the underlying Locker Shale may also have contributed to the
hydrocarbon charge. 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 et al,
2007). This Supersystem includes giant gas accumulations sourced mainly
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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,
2007).
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; Edwards
and Zumberge, 2005; Edwards et al, 2007). Geochemically similar oils are
recognised in the Northern Carnarvon, Bonaparte and Papuan basins, all
derived from Upper Jurassic marine source rocks deposited in incipient rifts
that developed along the northern and northwestern continental margin during
Gondwana breakup.
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EXPLORATION HISTORY
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 the Barrow Sub-basin in 1964, the Legendre 1 oil discovery in
1968 attracted exploration interest to the Dampier Sub-basin, and a series of
multi-Tcf gas discoveries were made in the 1970s on the Rankin Platform
(e.g. North Rankin, Angel, Goodwyn, Perseus). The Gorgon field, discovered
in 1979, is one of the largest gas fields within the North Carnarvon Basin. On
the deepwater Exmouth Plateau, a giant gas accumulation in a Lower
Cretaceous Barrow Group basin floor fan was discovered in Scarborough 1 in
1980. In 1984, the North West Shelf Venture commenced domestic gas
production from the North Rankin field and in 1989 the first LNG cargo was
shipped to Japan. Since then, the project has contributed $70 billion to
Australia’s gross domestic product (Woodside Petroleum Ltd, 2009b).
From the early 1980s to the mid-1990s, a number of significant, mostly
medium-sized oil (and gas) discoveries were made in the Barrow and
Dampier sub-basins, as a result of the application of dense 2D seismic
surveys (Longley et al, 2002). These include South Pepper, Chervil, Harriet
and Saladin in the Barrow Sub-basin and Wanaea, Stag and Wandoo in the
Dampier Sub-basin. The oil discovery at Nebo 1 in 1993 extended exploration
interest into the under-explored Beagle Sub-basin.
3D seismic and AVO technology have contributed to an improvement in the
success rate of recent exploration activities, despite the comparatively high
level of exploration maturity (Longley et al, 2002; Korn et al, 2003; Williamson
and Kroh, 2007). In the Dampier Sub-basin, the productive oil trend has now
been extended northward to the Mutineer and Exeter fields. In the Exmouth
Sub-basin, the 1999 Enfield discovery has been followed by a string of oil
finds including Coniston, Laverda, Stybarrow, Ravensworth and Stickle, and
oil production is under way from the Enfield, Stybarrow and Eskdale fields.
Growing demand for LNG has stimulated exploration along the Rankin
Platform and on the Exmouth Plateau in recent years, mostly targeting
Triassic fault block and intra-Triassic plays. However, the supergiant Io–Jansz
gas field, discovered in 2000 on the Exmouth Plateau is hosted by an
Oxfordian shallow-marine sandstone (Jenkins et al, 2003). Other recent large
gas discoveries over the Rankin Platform and inboard areas of the Exmouth
Plateau have been made at Wheatstone, Pluto, Xena, Achilles, Satyr, Sappho
and Clio. The significant gas discovery at Acme 1, with a net gas pay of
273 m, has the potential to feed into the Wheatstone LNG project (Chevron
2011 Release of Australian Offshore Petroleum Exploration Areas
Regional Geology of the Carnarvon Basin
Page 12 of 22
Australia Pty Ltd, 2010a). Apache Corporation has made several significant
discoveries on the Julimar trend between the Gorgon and Pluto fields,
including the Julimar and Brunello gas fields and the Balnaves oil
accumulation (Apache Corporation, 2010a). Hess Corporation has recorded
over 10 discoveries in a work program comprising 16 wells within WA-390-P,
southwest of the Io–Jansz field (Jonasson and Mack, 2010).
The multi-Tcf gas fields discovered at Thebe 1, which intersected a gross gas
column of 73 m (BHP Billiton Ltd, 2007), Martell 1, with a gross gas column of
110 m (Woodside Petroleum Ltd, 2009a, and at Noblige 1, with gas
indications over a 300 m gross interval (Woodside Petroleum Ltd, 2010b),
have extended the northerly limit of known gas accumulations on the Exmouth
Plateau. The 185 m gas column discovered at Alaric 1 (Woodside Petroleum
Ltd, 2010a) has proven that the prospective zone extends to the deepwater
western margins of the Exmouth Plateau. Other major recent gas discoveries
in outer areas of the Exmouth Plateau include Chandon, Yellowglen,
Brederode, Kentish Knock, Larsen Deep and Remy.
Accompanying the recent discoveries have been a series of new, large-scale
development projects and associated investment in infrastructure. The Pluto
LNG project, operated by Woodside Petroleum Ltd, consists of a processing
plant on the Burrup Peninsula for gas from the Pluto and Xena fields with an
expansion plan for three or more LNG trains and a pipeline gas facility
(Woodside Petroleum Ltd, 2010c). The plant is expected to commence
production in 2011. The Gorgon LNG project, the largest resource
development project in Australia, incorporates a 15 Mtpa LNG plant on
Barrow Island and a large-scale carbon dioxide reinjection project. This
project is operated by Chevron, ExxonMobil and Shell and the first LNG
production is planned for 2014 (Chevron Australia Pty Ltd, 2010b). The
Wheatstone LNG project, operated by Chevron, will process gas from the
Wheatstone and Iago fields via a two-train plant at Ashburton North (Chevron
Australia Pty Ltd, 2010c). Apache and Kuwait Foreign Petroleum Exploration
Co. (KUFPEC) plan to supply additional gas from the Julimar–Brunello project
to the Wheatstone LNG plant (Apache Corporation, 2010a), which may
eventually produce up to 25 Mtpa of LNG (Chevron Australia Pty Ltd, 2010c).
Extension of the North West Shelf Venture is in progress, including the
conversion of the Cossack–Wanaea–Lambert–Hermes FPSO and the North
Rankin B Gas Compression project (BHP BiIliton Ltd, 2010b). Planning for the
development of the Scarborough and Thebe fields is underway.
Some of the fields in the inboard areas of the Northern Carnarvon Basin are
also being developed. The Pyrenees project commenced production from the
Crosby, Ravensworth and Stickle oil fields in the Exmouth Sub-basin in 2010.
The project, operated by BHP Billiton, involves 13 subsea wells tied back to
an FPSO (BHP Billiton Ltd, 2010c). Gas produced will be reinjected into the
neaby Macedon gas field. The latter field will be developed through the BHP
Billiton-operated Macedon project, which will supply domestic gas via a
processing plant to be constructed at Ashburton North, to the Dampier to
Bunbury Natural Gas Pipeline (BHP Billiton Ltd, 2010a). Production is
expected to commence in 2013 (BHP Billiton Ltd, 2010a). The Van Gogh oil
2011 Release of Australian Offshore Petroleum Exploration Areas
Regional Geology of the Carnarvon Basin
Page 13 of 22
field, also in the Exmouth Sub-basin, commenced production in early 2010
using an FPSO operated by Apache Energy (Apache Corporation, 2010b).
Apache Energy’s Devil’s Creek Development project will commence supply of
domestic gas from the Reindeer field in the Dampier Sub-basin to the
Dampier–Bunbury Natural Gas Pipeline via a new offshore pipeline and an
onshore processing plant by 2011 (Apache Corporation, 2009).
2011 Release of Australian Offshore Petroleum Exploration Areas
Regional Geology of the Carnarvon Basin
Page 14 of 22
FIGURES
Figure 1:
Structural elements of the Northern Carnarvon Basin and
adjacent basins showing the 2011 Release Areas, oil and gas
accumulations and selected wells.
Figure 2:
Petroleum production facilities, hydrocarbon accumulations and
pipeline infrastructure in the Northern Carnarvon Basin.
Figure 3:
Map of the Northern Carnarvon Basin with the location of
regional geological cross-sections shown in Figure 4, Figure 5,
Figure 6 and Figure 7.
Figure 4:
Geological cross-section along AGSO seismic line 110/12 from
the western Exmouth Plateau to the southwestern Barrow Subbasin (see Figure 3 for location)
Figure 5:
Geological cross-section along reprocessed AGSO seismic line
101r/09 from the central Exmouth Plateau across the Dampier
Sub-basin (see Figure 3 for location)
Figure 6:
Geological cross-section along AGSO seismic line 110/03
across the southwestern Beagle Sub-basin and the Lambert
Shelf (see Figure 3 for location).
Figure 7:
Geological cross-section along AGSO seismic line 120/14
across the northeastern Exmouth Plateau, the northern Beagle
Sub-basin and the Roebuck Basin (see Figure 3 for location).
Figure 8:
Generalised stratigraphy 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).
Figure 9:
Major oil and gas fields and discoveries in the Northern
Carnarvon Basin indicating age of the main reservoir.
2011 Release of Australian Offshore Petroleum Exploration Areas
Regional Geology of the Carnarvon Basin
Page 15 of 22
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Front page image courtesy of Petroleum Geo-Services.
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