PETROLEUM GEOLOGICAL SUMMARY
RELEASE AREAS W11-10 AND W11-11,
BEAGLE SUB-BASIN, LAMBERT SHELF AND
DAMPIER SUB-BASIN, NORTHERN CARNARVON
BASIN
WESTERN AUSTRALIA
Bids Close – 13 October 2011

Immediately to the east of producing oil and gas fields within one of
Australia’s premier offshore petroleum basins.

Under-explored area with indications of active petroleum system at
Bruce 1.

Proximal to established offshore and onshore production infrastructure
and major new development projects.

A range of possible structural and stratigraphic plays.

Water depths mostly less than 100 m.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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LOCATION
The Release Areas W11-10 and W11-11 straddle the southern Beagle Subbasin, northeastern Dampier Sub-basin and Lambert Shelf of the Northern
Carnarvon Basin. The northeastern corner of Release Area W11-11 extends
into the Bedout Sub-basin of the Roebuck Basin.
Although the Release Areas are in an under-explored part of the Northern
Carnarvon Basin, they are located close to major hydrocarbon accumulations
within the Dampier Sub-basin, established petroleum production
infrastructure, as well as commercial centres and transport networks along the
Western Australian coast (Figure 1). Release Area W11-10 is located
immediately to the east of the Legendre, Amulet and Talisman oil
accumulations in the Dampier Sub-basin, and is proximal to the gas pipelines
connecting the Rankin Platform gas fields to the LNG processing plant at
Karratha (Figure 1). Minor oil and gas occurrences have previously been
recorded at Bruce 1 (Stirling Petroleum NL, 1979) within Release Area W1111, indicating that an active petroleum system is present in this part of the
southern Beagle Sub-basin and the Lambert Shelf.
The Release Areas are between 30 and 100 km off the Western Australian
coast, near the major regional centres of Dampier, Karratha and Port Hedland
(Figure 1), and in 20–130 m of water.
Release Area W11-10 comprises 79 graticular blocks with a total area of
approximately 6375 km2 and Release Area W11-11 comprises 77 graticular
blocks with a total area of approximately 6215 km2 (Figure 2).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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RELEASE AREA GEOLOGY
Local Tectonic Setting
The Beagle Sub-basin is located in the northeastern part of the Northern
Carnarvon Basin. It is bounded to the east by the Bedout and Rowley subbasins of the Roebuck Basin, and to the north and northwest by the Exmouth
Plateau. The greater part of the sub-basin consists of a broad transtensional
depocentre containing a series of en echelon troughs, fault blocks and
anticlines with a general north–south trend (Figure 3). The east-northeasttrending Beagle and Cossigny troughs mark the southern margin of the main
depocentre. The North Turtle and Bruce terraces, an east-northeast-trending
zone of shallow basement, occur to the south of the Beagle and Cossigny
troughs across the North Turtle Fault Zone (Figure 3).
The Dampier Sub-basin, to the southwest of the Beagle Sub-basin, comprises
subparallel northeast-trending fault-bounded highs and troughs that deepen
toward the axial depocentre of the Lewis Trough (Figure 3). The De Grey
Nose, a Paleozoic (?Permian) basement fault block cut by north-northwesttrending faults (Blevin et al, 1993), marks the boundary between the Dampier
and Beagle sub-basins (Figure 3). The Legendre Trend, a faulted anticline,
and the Rosemary Fault System separate the Lewis Trough from the shallowbasement area of the Enderby Terrace to the southeast (Figure 3). The
Dampier Sub-basin is bounded to the northwest by the Rankin Platform and to
the southwest by the Barrow Sub-basin.
The Beagle and Dampier sub-basins are bounded to the southeast by the
Lambert Shelf, an offshore extension of the Precambrian Pilbara Block
(Figure 3). The shelf consists of a planated basement surface thinly mantled
by dominantly Cretaceous–Cenozoic sediments (Figure 4). Extensional
faulting has created fault blocks and small half-graben in places, especially in
the outboard areas.
The Beagle and Dampier sub-basins contain a Paleozoic to Cenozoic
sedimentary succession with a maximum thickness of 10–12 km. The
sediments are dominantly Triassic to Middle Jurassic in the Beagle Sub-basin
(Figure 4), and Triassic to Lower Cretaceous in the Dampier Sub-basin. The
deeper depocentres of the Dampier Sub-basin contain thick successions of
Jurassic oil-prone sediments that are underlain by faulted gas-prone Triassic
sediments. Most of the succession underlying the North Turtle, Bruce and
Enderby terraces comprises faulted, landward-thinning Triassic sediments
(Figure 4). These sediments are thinly covered by Lower to Middle Jurassic
sediments that are unconformably overlain by Cretaceous sediments
(Figure 4). Over the Lambert Shelf, Triassic to Jurassic sediments are
preserved only in the outboard areas, and the Cretaceous–Cenozoic
succession onlaps the Precambrian basement in the inshore areas
(Figure 4).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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Structural Evolution and Depositional History of the Sub-basin
During the Silurian to Permian, the Northern Carnarvon Basin experienced
continental to shallow marine deposition, as intracratonic rift and sag basins
developed in the initial stages of the Gondwana breakup (Hocking, 1990). By
the late Permian, narrow northeast-trending depocentres were starting to form
(Hill, 1994), accompanied by shallow marine deposition (Hocking, 1990).
Permian and older sediments are missing, however, from most of the inshore
parts of the Dampier and Beagle sub-basins and the Lambert Shelf. In these
areas, which include Release Areas W11-10 and W11-11, the Triassic
succession directly overlies the Precambrian basement.
During the Early Triassic, a regional marine transgression deposited marine
claystone and siltstone of the Locker Shale (Figure 5). On the Lambert Shelf
and Enderby Terrace, the Locker Shale commonly overlies a transgressive
basal sandstone and grades upwards into the thick Middle to Upper Triassic
fluvio-deltaic sandstone, siltstone, claystone and coal of the Mungaroo
Formation (Figure 5). The Middle Triassic Cossigny Member of the Mungaroo
Formation in the Beagle Sub-basin (Figure 5) comprises paralic to marine
siltstone, claystone, limestone and dolomite, and forms an important regional
seismic marker within the sub-basin. Thickness of the Triassic succession
ranges from less than 200 m over parts of the Enderby Terrace, to an
estimated 5–6 km in the deeper parts of the Dampier Sub-basin (Stagg and
Colwell, 1994).
Rapid subsidence and transgression from the end of Triassic to Sinemurian
resulted in deposition of the fluvio-deltaic to shallow marine Brigadier
Formation and Murat Siltstone (Figure 5), which comprise thinly bedded
sandstone, siltstone, claystone and marl. Reservoir-quality shallow marine
sandstone overlying the Brigadier Formation is known as the North Rankin
Formation (Figure 5; Seggie et al, 2007). In the Beagle Sub-basin and over
the Lambert Shelf, a major Late Triassic transpressional event (Fitzroy
Movement II; Smith et al, 1999) formed a series of topographic highs, leading
to the isolation of the Beagle Sub-basin from the Dampier Sub-basin and
exposure of the Lambert Shelf (Blevin et al, 1994; Stephenson et al, 1998). As
a result, the Brigadier and North Rankin formations are thin or absent over
structural highs in these areas.
A major rifting phase during the Toarcian–Bathonian resulted in further
structural compartmentalisation of the Northern Carnarvon Basin, forming the
en echelon depocentres of the Beagle, Dampier, Barrow and Exmouth subbasins (Kopsen and McGann, 1985; Boote and Kirk, 1989; Hocking, 1990;
Hill, 1994; Romine et al, 1997). Marine siltstone and claystone of the Athol
Formation were extensively deposited over the JP1 rift-onset unconformity
(Figure 5; previously known as the ‘Pliensbachian unconformity’). Fluviodeltaic and shallow marine sandstone, siltstone and shale of the Legendre
Formation prograded northwestward over the Athol Formation (Figure 5).
Although the Athol and Legendre formations attain a combined thickness of
up to 5 km in the Lewis Trough of the Dampier Sub-basin (Miller and Smith,
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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1996), they are thin or missing from much of Release Areas W11-10 and
W11-11, except at Bugle 1 where they are over 400 m thick (Apache Energy
Ltd, 1999b).
From the end of the Bathonian to the Callovian, major syn-rift faulting
occurred in the lead up to continental breakup and formation of the Argo
Abyssal Plain. A marine transgression from the north and west (Stephenson
et al, 1998) deposited shallow marine claystone and sandstone of the Calypso
Formation over the Callovian (JC) unconformity (Figure 5) in the Dampier
Sub-basin. The formation is largely absent from the Beagle Sub-basin, where
transcurrent fault movements resulted in a major phase of structuring (Blevin
et al, 1994). Continental breakup, marked by the basal Oxfordian (JO)
unconformity (Figure 5), was followed by rapid thermal subsidence and the
Oxfordian–Tithonian deposition of thick (up to 1–2 km), organic-rich, deep
marine Dingo Claystone (Figure 5) in the major depocentres of the Dampier
Sub-basin. Reservoir-quality turbidite, submarine fan, shoreline and fluvial
sandstone of the Angel Formation (Figure 5) were deposited around the
basin margins, fed by erosion of the structural highs (Hocking, 1990). In the
Beagle Sub-basin and over the Lambert Shelf, the Upper Jurassic succession
is thin or absent (Figure 4; Blevin et al, 1994).
Renewed extension occurred during the Berriasian to early Valanginian in the
lead up to the opening of the Cuvier and Gascoyne Abyssal Plains. Initial
uplift and erosion (marked by the K unconformity; Figure 5) was followed by
deposition of the marine Forestier Claystone (Figure 5), the prodelta
equivalent of the Barrow Group sandstone in the Barrow and Exmouth subbasins. The claystone is generally thin (<100 m) but forms a regional seal
across the deeper depocentres of the Dampier and Beagle sub-basins. In the
inboard areas of the Beagle and Dampier sub-basins and over the Lambert
Shelf, localised submarine fan and shelf sandstone deposition occurred
(Figure 5). This Berriasian sandstone is an important reservoir in the
Legendre oil field of the Dampier Basin (B.O.C. of Australia Ltd, 1969),
immediately west of Release Area W11-10.
Continental breakup during the Valanginian triggered widespread erosion in
the Northern Carnarvon Basin (marked by the Valanginian KV unconformity;
Figure 5), followed by a marine transgression that eventually submerged the
Beagle and Dampier sub-basins and the Lambert Shelf. Localised deposition
of the paralic to shallow marine Birdrong Sandstone and the glauconitic
Mardie Greensand was followed by a basinwide deposition of the marine
Muderong Shale during the Valanginian to Aptian (Figure 5). The Muderong
Shale is a regional seal across much of the Northern Carnarvon Basin, but is
generally less than 100 m thick within the Release Areas. The M. australis
Sandstone, a well sorted, glauconitic sandstone with a typical thickness of
10–20 m, was deposited locally in submarine fan, shelf and paralic
environments within this interval (Figure 5; Dyson, 1998; Crowley, 1999). This
sandstone is a significant reservoir in a number of fields on the Enderby
Terrace of the Dampier Sub-basin, e.g. Stag and Wandoo.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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A marine regression during the Aptian, marked by the KA unconformity
(Figure 5), was followed by fine-grained shelf deposition as the Northern
Carnarvon Basin became part of a subsiding passive continental margin.
Initial deposition of the Aptian–Albian Windalia Radiolarite was followed by the
widespread deposition of the Gearle Siltstone and its open-ocean equivalent,
the Haycock Marl, during the Albian to Turonian (Figure 5). The Albian–
Turonian succession is 100–200 m thick in parts of the Release Areas. A
major transpressional event produced the regional KS/KC unconformity at the
Santonian–Coniacian boundary (Figure 5), resulting in fault reactivation and
inversion (Romine et al, 1997; Cathro and Karner, 2006).
A basin-wide transition to carbonate-dominated deposition occurred during
the Santonian (Hocking, 1990). The Toolonga Calcilutite was deposited during
the Santonian to Campanian, followed by the calcareous claystones of the
Withnell Formation and the Miria Marl during the Campanian to Maastrichtian
(Figure 5). By the Paleocene, the northwest Australian margin had become a
prograding carbonate shelf, punctuated by episodes of siliciclastic deposition
during lowstands (Romine et al, 1997). These lowstand–transgressive cycles
also formed backfilled incised-valley systems, which may potentially provide
stratigraphic traps (Romine et al, 1997). The Cenozoic carbonate-dominated
succession typically attains 100 m to 600 m thickness within the Release
Areas.
In the Miocene, a major compressional event associated with the collision of
the Australia–India and Eurasia plates affected the entire northwestern
Australian margin (Longley et al, 2002). This event caused tilting, inversion
and renewed fault movement (Malcolm et al, 1991; Cathro and Karner, 2006).
Episodic deformation appears to have continued to at least the Pliocene–
Pleistocene (Cathro and Karner, 2006).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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EXPLORATION HISTORY
Since the Legendre 1 oil discovery in 1968, the Dampier Sub-basin has
experienced intensive petroleum exploration activity. Over 55 field discoveries
had been made by the early 2000s with an historical drilling success rate of
over 40% (Longley et al, 2002). Exploration from the 1970s to the 2000s
resulted in a string of oil and gas discoveries concentrated along the
Legendre Trend (Figure 1 and Figure 3), e.g. Rosemary 1 (1973), Talisman 1
(1984), Saffron 1 (1994), Reindeer 1 (1997), Caribou 1 (1998), Sage 1 (1999)
and Corvus 1 (2000), and along the Madeleine Trend, e.g. Angel 1A (1972),
Lambert 1 (1974), Wanaea (1989) and Cossack (1990). Over the Enderby
Terrace (Figure 1 and Figure 3), gas was initially discovered at Hampton 1
(1974), but discoveries since the 1990s have revealed the area’s potential for
both oil and gas, e.g. Wandoo 1 (1991), Stag 1 (1993) and Antler 1 (1996).
Recent discoveries in the northeastern Dampier Basin, such as Amulet 1
(2006; Tap Oil Ltd, 2006) have extended the known oil province along the
Legendre Trend to the boundary with the Beagle Sub-basin (Figure 1 and
Figure 3).
The Beagle Sub-basin is a frontier area within the Northern Carnarvon Basin,
where only 25 wells have been drilled. Initial exploration drilling during 1971–
1992 tested a variety of play types, but no hydrocarbon shows were recorded
except at Bruce 1 (1979; minor oil and gas) on the boundary between the
Beagle Sub-basin and the Lambert Shelf. In 1993, Nebo 1 encountered oil in
the Callovian Calypso Formation, confirming the presence of an active
petroleum system in the central Beagle Sub-basin (Osborne, 1994). However,
other wells subsequently drilled in the same area were dry. From the late
1990s onward, the discovery of Mutineer, Pitcairn and Bounty oil fields in the
far northern Dampier Sub-basin has stimulated new exploration in the
boundary zone between the Beagle and Dampier sub-basins (Figure 1 and
Figure 3). Oil has been discovered at Fletcher 1 (Tap Oil Ltd, 2008), located
on a continuation of the highly prospective Madeleine Trend (Figure 3) in the
Dampier Sub-basin.
Release Areas W11-10 and W11-11 (Figure 1) overlap the former exploration
permit WA-1-P in the southeastern Dampier Sub-basin and the Beagle Subbasin. The earliest oil and gas discoveries in the Dampier Sub-basin,
including Legendre, Angel and Rosemary, were made within this permit.
Exploration during the 1970s to 1990s by successive permit holders has
resulted in the drilling of eight wells within the Release Areas. Release Area
W11-10 overlaps the former permit WA-352-P surrendered by Drillsearch
Energy Ltd in early 2010, and includes portions of Release Area W09-19
previously offered during 2009. Release Area W11-11 overlaps the former
permit WA-291-P relinquished by Rialto Energy Ltd in 2010.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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Well Control
There are six wells within the southwestern part of Release Area W11-10 and
two wells within the western part of Release Area W11-11 (Figure 1).
Release Area W11-10 adjoins the intensively explored Legendre Trend and
outer Enderby Terrace of the Dampier Sub-basin (Figure 3) and over 40 wells
have been drilled within 20 km of the western boundary of this Release Area
(Figure 1). Eight additional wells occur within 40 km of the northwestern and
northern limits of Release Areas W11-10 and W11-11 (Figure 1). There are
no nearby wells to the east and south of the Release Areas, in the adjacent
Roebuck Basin, or over the Lambert Shelf.
De Grey 1 (1971)
De Grey 1 was drilled by B.O.C. of Australia Ltd (1972) in the southern Beagle
Sub-basin, near the boundary with the Dampier Sub-basin. It is located 1 km
north of the Release Area W11-10 (Figure 1) in water 95 m deep. It was
designed to test stacked Triassic stratigraphic pinch-outs over a deeper,
rotated fault block on the De Grey Nose (Figure 3). The well reached a total
depth of 2088 mRT in Triassic limestone underlying a thick sandstonedominated Lower–Middle Jurassic succession. The Triassic–Jurassic
boundary could not be determined due to lost circulation. The limestone at
total depth is likely to be the Cossigny Member of the Mungaroo Formation,
given its revised age of Early–Middle Triassic (Ingram, 1990). No significant
hydrocarbons were encountered in the well. However, very minor gas
readings were registered in the Jurassic, Cretaceous and Cenozoic sections,
where potential reservoir-quality sandstones were encountered. Subsequent
remapping showed that there is no closure near the well (Blevin et al, 1993).
Hauy 1 (1972)
Hauy 1 was drilled by B.O.C. of Australia Ltd at the boundary between the
Enderby Terrace of the Dampier Sub-basin and the Lambert Shelf. It is
located within Release Area W11-10 (Figure 1) in 66 m of water.The well
tested for potential hydrocarbons trapped in Lower Triassic to Albian
sediments on the southwestern flank of the De Grey Nose (Figure 3).
Cenozoic sediments were not conclusively identified at the well due to poor
recovery and lack of fauna in sediments that were recovered. The Mesozoic
succession consisted of Albian–Aptian claystone and siltstone and
?Hauterivian–Barremian sandstone, directly overlying a Middle Triassic
claystone. A thin Lower Triassic sandstone separated the Middle Triassic
section from the altered dolerite basement of indeterminate age. The well
reached a TD of 825 mRT. No hydrocarbon shows were recorded in the well
and wireline logs indicated that all porous sandstones were 100% water
saturated.
Picard 1 (1972)
Picard 1 was drilled by B.O.C. of Australia Ltd in the Beagle Sub-basin, 13 km
north of Release Area W11-10 (Figure 1) in water 141 m deep. It was
designed to test the crest of a large, north-trending Jurassic horst, draped by
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
Page 8 of 24
a Lower Cretaceous seal (Figure 4). The well reached a total depth of
4216 mRT within a thick section of Lower Jurassic sandstone with
interbedded claystone, siltstone and minor coal. No significant hydrocarbons
were encountered. Only minor fluorescence and very minor gas readings
were recorded in the Cretaceous–Jurassic section, with wireline logs
indicating that the Jurassic section is water saturated. Reactivation of northtrending bounding faults during the Late Cretaceous to Paleogene may have
breached the structure (Blevin et al, 1993) and, therefore, compromised trap
integrity. Analysis by Surdam and Warme (1984) and Robertson Research
(1986) concluded that the Lower–Middle Jurassic Athol and Legendre
formation claystones have good to very good oil source potential.
Cossigny 1 (1972)
Cossigny 1 was drilled by B.O.C. of Australia Ltd (1973) to test the faulted
north-eastern flank of the De Grey Nose (Figure 3) in the southern Beagle
Sub-basin. It is located 16 km northwest of Release Area W11-10 (Figure 1)
in water 113 m deep. It encountered Upper Cretaceous marl, claystone and
calcilutite and Toarcian–Middle Jurassic siliciclastics, overlying a thick section
of Middle to Upper Triassic Mungaroo Formation. The Mungaroo Formation
consisted of sandstone with claystone, siltstone and minor coal, and included
limestone and dolomite of the Cossigny Member. The well reached a total
depth of 3203 mRT in the Middle Triassic Mungaroo Formation. No significant
hydrocarbons were encountered. Very minor gas readings were recorded in
the Triassic–Jurassic section. The well is considered to be a valid test of
structure at the Upper Cretaceous and Cenozoic levels, but it is unclear
whether closure was present at the Jurassic or Triassic levels (Battrick, 1987).
The presence of a thick Lower Cretaceous sandstone unit, as opposed to the
predicted sealing shale, suggests the absence of an adequate seal.
Poissonnier 1 (1974)
Poissonnier 1 was drilled by B.O.C. of Australia Ltd. within Release Area
W11-11 (Figure 1) in 83 m of water. It was designed to test the Lower
Triassic sandstone within a down-faulted compartment at the boundary
between the Bruce Terrace of the Beagle Sub-basin and the Lambert Shelf
(Figure 3). The well intersected comparatively thin Lower Cretaceous and
Upper Jurassic successions dominated by glauconitic sandstone and
claystone, and ?Toarcian and Triassic successions of interbedded sandstone,
claystone and siltstone with minor coal. It reached a total depth of 1962 mRT
in a basement of intermediate to basic igneous rock. No significant
hydrocarbons were encountered. However, minor gas readings were recorded
throughout the Lower Jurassic and Triassic section with various sidewall
cores and Triassic sandstone ditch cuttings exhibiting minor fluorescence. A
sandstone sidewall core at 1170 mRT had a brown stain associated with
fluorescence. Subsequent remapping indicated that there is little closure at
the Callovian and base-Cretaceous unconformity levels, and that the Triassic
sandstone target was not intersected at the optimal crestal location (Battrick,
1987).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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Jarman 1 (1978)
Jarman 1 was drilled by Woodside Petroleum Development Pty Ltd to test a
large northeast-trending, unfaulted anticline within the Cossigny Trough, to
the north of the main depocentre of the Beagle Sub-basin (Figure 3). The well
is located 7 km west of Release Area W11-10 (Figure 1) in 134 m of water.
The encountered stratigraphy was dominated by Tithonian to Upper
Cretaceous claystone and marl overlying Middle Jurassic to Kimmeridgian
fluvio-deltaic to marine sandstone, siltstone and claystone. The well reached a
total depth of 2906 mRT in Middle Jurassic sandstone and siltstone. No
significant hydrocarbons were encountered. However, four sidewall cores
within the Jurassic section exhibited weak to moderate fluorescence.
Subsequent remapping indicates that the well was positioned off the crest of
the anticline (Battrick, 1987). Furthermore, continued fault movement into the
Cenozoic suggests that the structure would only be able to trap hydrocarbons
migrating vertically since about the Middle Miocene.
Bruce 1 (1979)
Bruce 1 was drilled by Stirling Petroleum N.L. in the inboard part of the Bruce
Terrace in the southern Beagle Sub-basin (Figure 3). It is located within
Release Area W11-11 (Figure 1) in water 78 m deep. It was designed to test
the sediments within a wrench-controlled anticline down-dip of a northeasttrending fault (Figure 4). The well reached a total depth of 2168 mKB within
the Lower Triassic Locker Shale after intersecting a section of Mungaroo
Formation claystone, siltstone and sandstone below the Cossigny Member.
Strong, bright fluorescence was noted in sidewall cores and cuttings from the
Middle Triassic sediments. A sidewall core at about 1700 mKB had visible
brown oil staining, however, geochemical studies indicated the hydrocarbons
to be immature. Subsequent remapping indicates that, although the well was
drilled inside structural closure at the Middle Triassic level, it was outside
closure at the level of the Lower Cretaceous seal (Blevin et al, 1993).
Leakage via the basin-bounding fault immediately to the southeast is also
probable (Battrick, 1987). In the adjacent Roebuck Basin, the Phoenix gas
discovery is hosted at the same stratigraphic level as the hydrocarbon
occurrences at Bruce 1.
Lawley 1 (1981)
Lawley 1 was drilled by Hudbay Oil (Australia) Ltd to test a horst block in an
inboard area of the Enderby Terrace, near the flank of the Lambert Shelf
(Figure 3). It is located in Release Area W11-10 (Figure 1) in 61 m of water.
The encountered stratigraphy deviated significantly from that predicted, in the
absence of Upper Cretaceous and Jurassic successions, replaced by thick
Lower Cretaceous and Lower–Middle Triassic interbedded sandstone,
claystone, siltstone and minor limestone. The well reached a TD of 1120 mRT
in an altered granite gneiss basement, without encountering any significant
hydrocarbon indications. Traces of patchy, dull yellow fluorescence were
noted on some quartz grains below 690 mRT. Interpretation of wireline logs
indicates that no free or residual hydrocarbons were present in the well. The
well contains a large proportion of unconsolidated, porous sands that are
water wet (Hudbay Oil (Australia) Ltd, 1982).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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Talisman 1 ST2 (1984)
Talisman 1 ST2 was drilled by Marathon Petroleum Australia Ltd in the
northeastern Dampier Sub-basin, approximately 6 km northwest of Release
Area W11-10 (Figure 1). It was designed to test the hydrocarbon potential of
the Upper Jurassic (Tithonian) sandstone draping over a fault block.
Additional objectives were Kimmeridgian–Oxfordian and Middle–Lower
Jurassic sandstones within the underlying fault block. The well, drilled in 78 m
of water, reached a TD of 2925 mKB in Middle Jurassic sediments. The
stratigraphy was essentially as predicted. Oil shows and relatively high gas
readings were recorded from 1865 mKB, in the Lower Cretaceous, to TD. The
gross interval 1917–1971 mKB (Lower Cretaceous to Tithonian) had
significant hydrocarbon shows during drilling and wireline logs indicated that
this interval has good oil potential. This interval was tested and oil was
recovered in four RFTs; the maximum recovery was 9.5 L of 41.4º API oil at
1962 mKB. Drill Stem Testing of three zones in this interval flowed oil, with the
maximum flow of 4778 bopd (759.7 m3/d) of 41.6º API oil recorded over the
interval 1961–1968 mKB. Wireline log interpretation and evaluation indicates
that all potential reservoir sections from 1971m KB to TD have very high water
saturations and are considered to be non-productive. Talisman 1 ST2 was
temporarily suspended as an oil discovery. The Talisman oilfield was
subsequently in production from 1989 to 1992 and represented the first oil
production in the Dampier Sub-basin.
Cygnus 1 (1989)
Cygnus 1 was drilled by Arco Australia Limited on the Enderby Terrace in the
northeasetrn Dampier Sub-basin (Figure 3). It is located within Release Area
W11-10 (Figure 1), 3 km south-southeast of Bugle 1, 13 km west-northwest
of Buck 1, in 73 m of water. It was designed as a test of the Lower Jurassic
North Rankin and the Upper Triassic Mungaroo formations on a northeasttrending faulted anticline. The well encountered thick interbedded shale,
sandstone and siltstone of the Middle Jurassic Legendre Formation and the
Lower Jurassic Athol Formation (referred to as the ‘Lower Dingo Claystone’
by Arco Australia Ltd, 1989) overlying the North Rankin and Brigadier
formations. The underlying Mungaroo Formation consisted of an Upper
Triassic sand-dominated braided stream succession, and a Middle Triassic
shaly fluvio-deltaic succession. The well reached a total depth of 2470 mDF
within Middle Triassic Mungaroo Formation without encountering any
significant hydrocarbons. The lack of hydrocarbons may be due to: the sandy
nature of the Athol Formation providing ineffective seal to the North Rankin
Formation; immature and low-quality source rocks, or lack of a viable
migration pathway from deep kitchen areas to the north (Arco Australia Ltd,
1989).
Kanji 1 (1994)
Kanji 1 was drilled by Ampolex Ltd on the Enderby Terrace in the Dampier
Sub-basin (Figure 3). It is located within Release Area W11-10 (Figure 1) in
57 m of water. The well was drilled to appraise the hydrocarbon potential of
an interpreted four-way dip closure of Lower Cretaceous sediments
unconformably draped over a Triassic tilted fault block. The primary objective
2011 Release of Australian Offshore Petroleum Exploration Areas
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of the well was the M. australis Sandstone. Triassic Mungaroo Formation
sandstone within an underlying horst block constituted a secondary objective.
The well reached a TD of 1288 mRT in Middle Triassic sediments. All unit
tops, except the main unconformity, were shallow to prognosis. The Lower
Cretaceous section was sandier than predicted and the Locker Shale was
homogeneous rather than intercalated as predicted. Sandstones within the
Lower Cretaceous section are of excellent reservoir quality and have a logderived average porosity of 25%. The Triassic section also displays excellent
reservoir qualities. No hydrocarbon shows were encountered during drilling.
The absence of hydrocarbons is attributed to an invalid structure and seal at
the M. australis Sandstone level or a lack of effective migration pathways
(Ampolex Ltd, 1995).
Buck 1 (1997)
Buck 1 was drilled by Apache Northwest Pty Ltd on the Enderby Terrace in
the eastern Dampier Sub-basin (Figure 3). It is located within Release Area
W11-10 (Figure 1) in 71 m of water. It tested an interpreted faulted three-way
anticline in Lower Cretaceous (Berriasian) sandstones, overlying a deepseated Permian to Lower Jurassic tilted fault block. Although the encountered
stratigraphy was close to prediction, the reservoir-quality Berriasian
sandstone in the well was thin. Further reservoir-quality, water-wet
sandstones were encountered within the Middle Jurassic Legendre, Lower
Jurassic North Rankin, and the Triassic Mungaroo formations. The well
reached a TD of 1050 mRT in limestone and siltstone of the Cossigny
Member within the Mungaroo Formation. No hydrocarbon shows were
recorded and the well was plugged and abandoned as a dry well. Reinterpreted mapping places the Buck 1 well location on the edge of the
mapped structure and it may be outside closure due to lateral velocity
variations (Apache Energy Ltd, 1999a).
Bugle 1 (1997)
Bugle 1 was drilled by Apache Northwest Pty Ltd to test the hydrocarbon
potential of the North Rankin Formation on a northeast-trending, tilted fault
block on the Enderby Terrace in the northeastern Dampier Sub-basin
(Figure 3). Secondary targets were sandstones in the Middle Jurassic
Legendre Formation and Lower Cretaceous sandstones. The well is located
within Release Area W11-10 (Figure 1), 3 km north-northwest of Buck 1, in
79 m of water. It reached a TD of 1833 mRT within the Triassic Mungaroo
Formation. The section penetrated was essentially as predicted, although
Lower Jurassic to Triassic formation tops came in slightly high. Potential
reservoir quality sandstones were encountered at all three objective levels but
no hydrocarbon shows were recorded. The lack of hydrocarbons is interpreted
to be due to a lack of cross-fault seal at the North Rankin Formation and base
Cretaceous levels, and the possible lack of structure at the top Lower
Cretaceous (Apache Energy Ltd, 1999b). There is also the possibility that
hydrocarbons failed to migrate into the structure.
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Bloodwood 1 (2002)
Bloodwood 1 was drilled by Mobil (Legendre) Pty Ltd on the Enderby Terrace
in the Dampier Sub-basin (Figure 3). It is located 16 km west of Release Area
W11-10 (Figure 1) in 62 m of water. It tested the Barremian M. australis
Sandstone within the crest of a northeast-trending, tilted fault block.
Cretaceous formation tops were considerably deeper than predicted and the
M. australis Sandstone attained a thickness of 144.7 m. Minor oil shows were
recorded in the upper 20 m of the M. australis Sandstone, with a sidewall core
at 581 mRT recording yellow fluorescence, a slow to moderate milky white
streaming cut and thin film residue. Although gas readings for the upper M.
australis Sandstone are unavailable, two minor gas peaks were recorded in
the lower M. australis Sandstone and the Muderong Shale. The lack of
significant hydrocarbon accumulation is probably due to leakage across the
bounding fault (Apache Northwest Pty Ltd, 2003), but the shows suggest that
Bloodwood 1 lies on a migration pathway. The well terminated in the Middle
Jurassic Athol Formation at a TD of 834 mRT.
For further details regarding wells and available data follow this link:
http://www.ret.gov.au/Documents/par/data/documents/Data%20list/data%20li
st_BeaglesbLambertslfDampiersb_AR11.xls
2011 Release of Australian Offshore Petroleum Exploration Areas
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Data Coverage
The southwestern part of Release Area W11-10 lies at the edge of dense 2D
and 3D seismic data coverage over the Dampier Sub-basin. Seismic data are
generally of good quality, especially for the more recent surveys. Advances in
3D seismic data acquisition and processing technologies since the 1990s
have significantly improved exploration success in the region (Longley et al,
2002). Some of the more significant data sets include the SPA East Dampier
9SL/92-3 (S92DDS) survey (1992) by Australian Seismic Brokers, Vermeer
A92V survey (1992) by Ampol Exploration Ltd, SPA 2SL/94-95 (GPDB95)
Dampier Well Tie survey (1994) by GECO-Prakla, Halina (1995) and Maria
(1996) surveys by Minora Resources, and the Panaeus 99C 3D survey (1999)
and Panaeus East 3D survey (2001) by PGS Exploration Pty Ltd.
Seismic data coverage is less dense in the eastern part of Release Area
W11-10 and the northern part of W11-11 located within the Beagle Sub-basin.
Some of the more significant datasets include the B86A survey (1986) by
BHP Petroleum Ltd, H93B survey (1993) by Hadson Energy Ltd, and Mavis
survey (2000) by Magellan Petroleum Australia Ltd.
The southeastern part of Release Area W11-10 and the southern half of
Release Area W11-11 over the Lambert Shelf have a very sparse coverage of
2D seismic data, including the De Grey Nose survey (1973) by B.O.C. of
Australia Ltd, Lambert Shelf HL80 (1980) and HL81 (1981) surveys by
Hudbay Oil Ltd, Cossigny D95 survey (1995) by Discovery, a tie line for the
Leveque Shelf LS93 survey (1998) by GHD-Gardline Surveys JV, and the
Mavis survey (2000) by Magellan Petroleum Australia Ltd. Large areas of
sparse or no data occur within the southeastern part of Release Area W11-11.
Regional 2D seismic data acquired by Geoscience Australia include the
Barrow/Dampier survey 110 (1990), deep seismic survey 101 (1991–1992)
and high-resolution survey 136 (1994). Several lines from these surveys
traverse the Release Areas, including the data-poor southern parts of both
areas.
In 2007, the long-offset New Dawn 2D multi-client seismic survey was
completed over the Northwest Shelf together with the acquisition of gravity
and magnetic data (Petroleum Geo-Services ASA, 2010). Several of the
survey lines traverse the Release Areas.
Satellite-based synthetic aperture radar (SAR) and airborne laser fluorosensor
(ALF) data are also available within, and in the vicinity of, the Release Areas.
O’Brien et al (2003) present a summary and an assessment of these data
sets.
Open-file seismic data, as well as seismic interpretation, well and destructive
analysis reports, are available from Geoscience Australia.
2011 Release of Australian Offshore Petroleum Exploration Areas
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To view image of seismic coverage follow this link:
http://www.ga.gov.au/energy/projects/acreage-release-andpromotion/2011.html#data-packages
2011 Release of Australian Offshore Petroleum Exploration Areas
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PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL
Table 1: Petroleum Systems Elements Summary
Sources
Reservoirs

Dingo Claystone (Upper Jurassic, marine, oil prone);

Legendre Formation (Lower–Middle Jurassic, fluviodeltaic to marginal marine, gas and oil prone);

Athol Formation (Lower–Middle Jurassic, marine to
marginal marine, gas and oil prone);

Murat Siltstone (Lower Jurassic, marine, gas and oil
prone);

Brigadier Formation (Upper Triassic, fluvio-deltaic to
marine, gas prone);

Mungaroo Formation (Middle–Upper Triassic, fluvial to
marginal marine, gas prone).

M. australis Sand and other sandstone intervals within
Muderong Shale (Lower Cretaceous, marine to
marginal marine);

Berriasian sandstones within Forestier Claystone
(Lower Cretaceous Barrow Group equivalents, marine
to fluvio-deltaic);

Angel Formation (Upper Jurassic, marine to fluvial);

Calypso Formation (Middle–Upper Jurassic, marine to
marginal marine);

Legendre Formation (Lower–Middle Jurassic, fluviodeltaic to marginal marine);

Athol Formation (Lower–Middle Jurassic, marine to
marginal marine);

North Rankin Formation (Lower Jurassic, fluvio-deltaic
to marine);

Brigadier Formation (Upper Triassic, fluvio-deltaic to
marine);

Mungaroo Formation (Middle–Upper Triassic, fluvial to
2011 Release of Australian Offshore Petroleum Exploration Areas
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marginal marine);
Seals

Basal transgressive sand underlying Locker Shale
(Lower Triassic, marginal marine).

Gearle Siltstone (Lower Cretaceous, marine);

Muderong Shale (Lower Cretaceous, marine to
marginal marine, regional seal);

Forestier Claystone (Lower Cretaceous, marine to
fluvio-deltaic);

Dingo Claystone (Upper Jurassic, marine);

Calypso Formation (Middle–Upper Jurassic, marine to
marginal marine);

Athol Formation (Lower–Middle Jurassic, marine to
marginal marine);

Murat Siltstone (Lower Jurassic, marine);

Cossigny Member, Mungaroo Formation (Middle
Triassic, marine, regional seal)

Locker Shale (Lower Triassic, marine).

Cenozoic incised valley and channel stratigraphic traps;

Lower Cretaceous unconformity and basement onlap
stratigraphic traps;

Upper Jurassic–Lower Cretaceous submarine fan,
shoreline and estuarine sandstone stratigraphic traps;

Middle Jurassic to Lower Cretaceous horst, tilted fault
block and low-side rollover traps;

Triassic to Lower Cretaceous anticlines and faulted
anticline traps;

Middle Jurassic to Lower Cretaceous drape and
anticline traps over Triassic to Jurassic fault blocks;

Middle–Upper Triassic Mungaroo Formation pinchout
traps;

Triassic transgressive sandstone stratigraphic traps at
Play Types
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the base of the Locker Shale.
Petroleum Systems
In the Dampier Sub-basin, two proven petroleum systems are recognised. A
gas-prone system is sourced from Triassic to Middle Jurassic fluvio-deltaic
sediments of the Mungaroo and Brigadier formations, Murat Siltstone, Athol
and Legendre formations (Figure 5 and Figure 6). An oil-prone system,
responsible for the accumulations along the Legendre and Madeleine trends
and the Enderby Terrace (Figure 3), is primarily sourced from the Upper
Jurassic Dingo Claystone (Figure 5 and Figure 6; Boreham et al, 2001;
Edwards and Zumberge, 2005; Edwards et al, 2007). The Oxfordian
(W. spectabilis biozone) interval of the claystone in the eastern Dampier Subbasin (Thomas et al, 2004), deposited during a maximum flooding stage in a
restricted marine embayment, is particularly organic-rich (van Aarssen et al,
1996; Norvick, 2002). Mixed sourcing is apparent in some accumulations, e.g.
the Middle and Upper Jurassic sources for the Angel gas field (Longley et al,
2002; Thomas et al, 2004).
The oil discovery at Nebo 1 (1993) demonstrated the presence of an active
petroleum system within the Beagle Sub-basin. Potential source rock intervals
are expected at similar stratigraphic intervals to the Dampier Sub-basin, but
well data indicate that the Dingo Claystone is often thin or absent, and source
quality of the Mungaroo Formation and the underlying Locker Shale
(Figure 5) is poor (Surdam and Warme, 1984). Moreover, the oil at Nebo 1
was derived from a probable Lower–Middle Jurassic lacustrine source
(Stephenson et al.,1998) and is distinct from oils in the Dampier Sub-basin
and other basins of the North West Shelf (Edwards and Zumberge, 2005).
Potential reservoirs over the Legendre Trend and the Enderby Terrace of the
Dampier Sub-basin include Upper Triassic to Middle Jurassic fluvial to shallow
marine sandstones, Upper Jurassic marine to fluvio-deltaic sandstones, and
Lower Cretaceous marine sandstones, including the Berriasian Sandstone
within the Forestier Claystone and the Barremian M. australis Sandstone
(Figure 5 and Figure 6). The M. australis Sandstone is particularly significant
as a reservoir over the Enderby Terrace, where it is often glauconitic. In the
Beagle Sub-basin, the Mungaroo and Legendre formations (Figure 5) are
known to host reservoir-quality sandstones. The Upper Jurassic succession is
commonly missing in the Beagle Sub-basin, but the Callovian Calypso
Formation (Figure 5) is a significant potential reservoir in places. The Triassic
transgressive sandstone at the base of the Locker Shale (Figure 5 and
Figure 6) may provide a potential reservoir in the inboard parts of the Beagle
Sub-basin, Enderby Terrace and the Lambert Shelf.
The Lower Cretaceous Muderong Shale (Figure 5 and Figure 6) is an
effective regional seal across the Dampier Sub-basin. It has encouraged
lateral drainage of hydrocarbons from the deeper parts of the sub-basin into
2011 Release of Australian Offshore Petroleum Exploration Areas
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accumulations in basin margin areas, such as the Enderby Terrace. Finegrained facies within the Jurassic to Lower Cretaceous successions are
significant additional seals in the deeper parts of the sub-basin. The Middle
Triassic Cossigny Member of the Mungaroo Formation (Figure 5 and
Figure 6) is a regional seal in the Beagle Sub-basin and the adjoining Bedout
Sub-basin (Roebuck Basin). In the inboard areas of the Beagle Sub-basin,
Enderby Terrace and Lambert Shelf, the Jurassic to Lower Cretaceous
formations are often sandy or absent due to erosion and the Lower–Upper
Cretaceous formations may provide local seals (Figure 6). The Lower–Middle
Triassic Locker Shale may also act as a seal to the basal Triassic sandstone
(Figure 5 and Figure 6) and older reservoir targets in the inboard areas.
Play Types
The main structural play types in the southeastern Dampier Sub-basin,
southern Beagle Sub-basin and Lambert Shelf are Middle Jurassic to Lower
Cretaceous horsts, tilted fault blocks and low-side rollovers, Triassic to Lower
Cretaceous anticlines and faulted anticlines, and drapes and anticlines over
Triassic to Jurassic fault blocks (Figure 6). Potential stratigraphic plays are
found in Upper Jurassic to Lower Cretaceous submarine fan, shoreline and
estuarine sandstones, pinchouts within the Triassic Mungaroo Formation,
Lower–Middle Triassic transgressive sandstone at the base of Locker Shale,
and unconformity traps (below the Lower Cretaceous) as well as basement
onlaps found generally in the inboard areas (Figure 5 and Figure 6).
Stratigraphic plays are particularly significant in inboard areas such as the
Lambert Shelf where structuring has been comparatively weak.
Critical Risks
The marginal location of Release Areas W11-10 and W11-11 relative to the
main basin depocentres imply that the source rocks may be thin, immature
and/or of low quality, and some of the areas may be outside the range of
lateral hydrocarbon migration from the main source kitchens. Poor seal
development due to erosion or high sand content, leakage via basin-bounding
faults, lack of closure, and biodegradation pose further potential risks to
hydrocarbon accumulation in the area. Late-stage fault reactivation may have
resulted in seal breaching and delayed charge from vertical migration. The
dominance of lateral fault motion within the Beagle Sub-basin has resulted in
a history of trap development, charge and preservation considerably more
complex than that in a typical extension-dominated rift system (Blevin et al,
1994).
2011 Release of Australian Offshore Petroleum Exploration Areas
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FIGURES
Figure 1:
Location map of Release Areas W11-10 and W11-11 in the
Beagle and Dampier sub-basins and the Lambert Shelf,
Northern Carnarvon Basin.
Figure 2:
Graticular block map and graticular block listings for Release
Areas W11-10 and W11-11 in the Beagle and Dampier subbasins and the Lambert Shelf, Northern Carnarvon Basin.
Figure 3:
Structural elements of the southern Beagle and Dampier subbasins and the Lambert Shelf, Northern Carnarvon Basin.
Figure 4:
Cross-section across the Beagle Sub-basin to the northern
Lambert Shelf based on AGSO seismic line 110/02. See
Figure 3 for location of cross-section.
Figure 5:
Generalised stratigraphy of the Dampier and Beagle subbasins, tied to the geological timescale after Gradstein et al
(2004) and Ogg et al (2008). Note that the Phoenix 1 gas
discovery is located in the adjacent Bedout Sub-basin,
Roebuck Basin.
Figure 6:
Possible play types in Release Areas W11-10 and W11-11,
based on AGSO seismic line 110/02. See Figure 3 for location
of cross-section.
2011 Release of Australian Offshore Petroleum Exploration Areas
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REFERENCES
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Dampier Sub-basin, northern Carnarvon Basin Western Australia
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Dampier Sub-basin, northern Carnarvon Basin Western Australia
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2011 Release of Australian Offshore Petroleum Exploration Areas
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Dampier Sub-basin, northern Carnarvon Basin Western Australia
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the Rankin Trend gas reservoirs, North West Shelf, Australia. The APPEA
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Front page image courtesy of Petroleum Geo-Services.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-10 and W11-11,Beagle Sub-basin, Lambert Shelf and
Dampier Sub-basin, northern Carnarvon Basin Western Australia
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