PETROLEUM GEOLOGICAL SUMMARY
RELEASE AREAS W12-8 AND W12-9
BARROW SUB-BASIN AND EXMOUTH SUBBASIN, NORTHERN CARNARVON BASIN,
WESTERN AUSTRALIA
HIGHLIGHTS
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Adjacent to Australia’s major new oil producing province
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Shallow water depths 50–600 m
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Active exploration and production area with established infrastructure in close proximity
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Three proven petroleum systems; Triassic fault block and Barrow Group plays
Release Area W12-8 is located in the Barrow and Exmouth sub-basins, and Release Area W12-9 is
located in the Barrow Sub-basin. These two southernmost sub-basins are part of a series of
Jurassic depocentres that form the Northern Carnarvon Basin.
The petroliferous Barrow Sub-basin is located in shallow water within Australia’s premier
hydrocarbon province. The sub-basin comprises a major Jurassic depocentre bordered to the west
by the Rankin Platform and Alpha Arch and, to the east, by the Barrow Island Anticline. The highly
productive Locker/Mungaroo-Mungaroo/Barrow petroleum system and Dingo-Barrow petroleum
system continue to be successfully tested.
The Exmouth Sub-basin is the southernmost in a series of Jurassic depocentres that form the
Northern Carnarvon Basin. Oil production commenced in the Exmouth Sub-basin in 2006 and since
1993, numerous oil and gas accumulations of the productive Dingo-Barrow petroleum system have
been discovered.
Both sub-basins offer a wide range of play types, including tilted fault blocks, en-echelon and
rollover anticlines, rollover anticlines associated with antithetic faults, stratigraphic traps, pinchouts
and onlap plays. Modern data-sets, including open file seismic, support ongoing exploration activity.
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LOCATION
Release Area W12-8 is located predominantly in the northern Exmouth Sub-basin, approximately
75–110 km offshore from Onslow (Figure 1). The southeastern portion of this Release Area extends
onto the Alpha Arch in the southwestern Barrow Sub-basin. Water depths vary from 100–800 m.
There are 23 graticular blocks within Release Area W12-8, with a total area of approximately
1,837 km2 (Figure 2).
Release Area W12-9 is located within the southwestern part of the Barrow Sub-basin,
approximately 45–60 km offshore from Onslow (Figure 1). The Release Area is in water depths that
range between 50–150 m. There are 13 graticular blocks within Release Area W12-9, with a total
area of approximately 607 km2 (Figure 2).
Both Release Areas are located close to numerous oil and gas fields that include: the Van Gogh
development—part of the greater Vincent oil field (Gascoyne Development Commission, 2010); the
Macedon gas field, planned for domestic gas production from 2013; the Chinook/Scindian oil and
gas field; and the Corowa and Griffin oil fields (Figure 1).
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RELEASE AREA GEOLOGY
The geological evolution of the Northern Carnarvon Basin, and Exmouth and Barrow sub-basins,
has been described in detail by many authors, and the summary presented below is derived from
the work of Veevers (1988), Hocking (1990), Arditto (1993), Jablonski (1997), Tindale et al (1998),
Bussell et al (2001), Norvick (2002), Longley et al (2002), Hearty et al (2002), Smith et al (2003),
Scibiorski et al (2005) and Bailey et al (2006).
Local tectonic setting
The Exmouth Sub-basin is separated from the Barrow Sub-basin by the north–south-trending
Triassic high of the Alpha Arch (Figure 3). The Exmouth Sub-basin is bounded by the Exmouth
Plateau to the north and west. To the east and south, the sub-basin is bounded by the Alpha Arch
and the Southern Carnarvon Basin, respectively. The Barrow Sub-basin is bounded by the Dampier
and Exmouth sub-basins to the east and west, respectively; and the Rankin Platform and
Peedamullah Shelf to the north and south, respectively.
Structural evolution and depositional history of the area
The Exmouth and Barrow sub-basins, along with the Dampier and Beagle sub-basins, formed as a
series of northeast–southwest-trending, en-echelon structural depressions during the Pliensbachian
to Oxfordian (Tindale et al, 1998; Smith et al, 2003; Scibiorski et al, 2005). These Jurassic
depocentres developed during the early syn-rift phase of the Northern Carnarvon Basin and contain
thick successions of oil-prone sediments.
Pre-rift sequences in both the Exmouth and Barrow sub-basins consist of Permian and Lower to
Middle Triassic sediments that are gas-prone. The extensive Locker Shale was deposited during a
widespread Early Triassic marine transgression and is overlain by the thick, prograding, fluviodeltaic Mungaroo Formation (Figure 4, Figure 5 and Figure 6).
Middle Jurassic rifting between Australia and Greater India opened a narrow basin allowing for the
intermittently restricted to open marine Dingo Claystone to be deposited during the Late Jurassic
across the Exmouth, Barrow and Dampier sub-basins (Figure 4 and Figure 5). The Dingo Claystone
is the main oil-prone source rock for the region. Further episodic movement during the Late
Jurassic resulted in reactivation of older extensional faults, block faulting and erosion. Eroded
material provided coarser grained clastics, within the deep-water setting, and formed the reservoir
units of the Biggada and Dupuy formations; primarily seen in the Barrow Sub-basin (Figure 5 and
Figure 6).
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Rift related uplift of the Cape Range Fracture Zone, south of the Exmouth Sub-basin, provided a
sediment source for the progradational Barrow Group delta. Progradation of this delta continued
northward over the Exmouth Sub-basin and Exmouth Plateau. By the mid-Berriasian the Barrow
Group delta had covered the Alpha Arch and by the Valanginian it had prograded across the
Barrow Sub-basin as far south as the southern edge of the Gorgon field. Within the Northern
Carnarvon Basin, the Barrow Group is a coarsening upward sequence, comprising two seismic
stratigraphic units: the Malouet Formation (delta bottomsets) and the Flacourt Formation (delta
topsets and foresets). Barrow Group sediments have excellent reservoir properties, with northeast–
southwest-trending syn-sedimentary faults providing localised stratigraphic and structural traps.
Continued separation of Greater India and Australia in the Valanginian (Veevers, 1988) is
correlated with major structural inversion of the Ningaloo Arch, with associated erosion of the
Barrow Group and older Jurassic sediments across much of the Exmouth and Barrow sub-basins
(Figure 3 and Figure 7; Tindale et al, 1998). The delta sediments were reworked and redeposited in
the parasitic deltaic wedges of the Birdrong Sandstone in the Exmouth and Barrow sub-basins, and
the Zeepaard Formation in the Exmouth Sub-basin (Figure 4 and Figure 5: Arditto, 1993; Tindale et
al, 1998). This event is associated with the development of structural dip to the north by tilting of the
east–west-trending Ningaloo Arch to the south. This resulted in the formation of complex trapping
architecture within the late Berriasian arch that extends in a north-northeast direction across the
western edge of the sub-basin (e.g., Eskdale structure).
A marine transgression during the Hauterivian marked the beginning of thermal relaxation during
the post-rift stage, and resulted in the deposition of the Muderong Shale; the regional top seal for
most fields of the Northern Carnarvon Basin (Figure 4 and Figure 5). South of Release Area W12-8
this formation thins as it onlaps the Ningaloo Arch, which was a positive feature at the time of
deposition (Tindale et al, 1998).
In the Barrow Sub-basin, the porous Windalia Sand Member overlies the Muderong Shale (Figure 5
and Figure 6) and is the main reservoir of the Barrow Island oil field. However, its low permeability
elsewhere in the sub-basin makes it unsuitable as a reservoir. Both in the Exmouth and Barrow
sub-basins the Muderong Shale is overlain by the Windalia Radiolarite, a porous but low
permeability thief zone. Above the radiolarite, the lower Gearle Siltstone, consisting of a thick
sequence of Albian to mid-Cenomanian claystones and siltstones, was deposited in an outer-shelf
environment and is considered to be an effective top seal for accumulations in the both the Barrow
and Exmouth sub-basins, such as in the Pyrenees/Macedon field (Figure 1 and Figure 7: Bailey et
al, 2006).
Basin inversion and uplift of the Exmouth Sub-basin in the Late Cretaceous formed the Novara
Arch and the Resolution Arch (Figure 3) and effectively shut off the Jurassic source kitchen. Uplift
began in the early Santonian which overprinted and reactivated previously formed structures
(Tindale et al, 1998). In the Barrow Sub-basin, this inversion resulted in numerous structural
closures; including the Rankin Trend, John Brookes, Spar, Alpha Arch, Woollybutt South Lobe, and
Barrow Island, which were ideally placed for oil charge after the Barrow Group deposition.
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From the Late Cretaceous to the Holocene, fine grain siliciclastic deposition gave way to marls and
calcilutites (Figure 4 and Figure 5). This change was largely governed by the marine, passive
margin environment, as well as climatic change and peneplanation of the clastic source area. The
Cenozoic succession comprises a thick wedge of prograding marine carbonates deposited during
various transgressive and regressive stages.
The final stage of tectonism is recorded in the middle to late Miocene, when the Australian-Indian
plate collided with the Eurasian plate. In the Exmouth Sub-basin this last event saw gross tilting of
the margin to the west due to progradation of a thick Paleogene–Neogene carbonate wedge and
fault reactivation. At this time, a new phase of compression enhanced the Pyrenees/Macedon
structure and it is interpreted to have tilted many structures to the south and west, as well as
modifying existing hydrocarbon accumulations (Tindale et al, 1998). In the Barrow Sub-basin, this
collision event enhanced pre-existing structures, such as the Woollybutt South Lobe, Spar, John
Brookes and the Barrow Island Trend, and created new structures, including the Woollybutt North
Lobe and East Spar (Hearty et al, 2002).
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EXPLORATION HISTORY
Exploration in the region around the Release Areas has been episodic over the last 35 years. The
Exmouth Sub-basin, along with the Barrow Sub-basin, received some interest during the first phase
of West Australian Petroleum Pty Ltd’s (WAPET) ‘island and shallow water drilling program’ in the
1960s and early 1970s (Mitchelmore and Smith, 1994). In 1972, the first gas shows were recorded
in the Exmouth Sub-basin when West Muiron 1 was drilled on the feature which was later to be
recognised as hosting the Pyrenees/Macedon gas and oil accumulations. This was the first
indication that the Exmouth Sub-basin was petroliferous. Exploration, however, was largely focused
on other regions of the Northern Carnarvon Basin, namely the Barrow and Dampier sub-basins,
where giant discoveries like the billion barrels (1.59 × 10 8 kL) of oil-in-place at Barrow Island in
1964 and multi-Tcf (>5 × 1010 m3) gas fields on the Rankin Platform in 1972. Also in 1972, gas
discoveries were made in Triassic sandstones at West Tryal Rocks 1 and later in Lower Cretaceous
sandstones in Spar 1 (1976) in the Barrow Sub-basin. It was not until 1983 that the first commercial
discovery of oil was made in the offshore part of the Barrow Sub-basin in the South Pepper 1 well
(Baillie and Jacobson, 1997).
During the late 1970s and early 1980s exploration concentrated on deep-water drilling of the
Exmouth Plateau. Initially these drilling programs were conducted by Esso and Phillips (Barber,
1988) and led to the giant gas discovery at Scarborough (Walker, 2007).
With the permit sizes and prospect volumes within the permits decreasing, the 1980s saw the
general offshore exploration focus in Australia shift inboard. In the shallower water sections of the
Exmouth Sub-basin, Jurabi 1 was drilled by Esso Australia Ltd in 1982 as another test of the West
Muiron structure. However, the test failed and it was not until the 1990s that a significant
hydrocarbon column was intersected on this structure (Mitchelmore and Smith, 1994). The early
1990s also saw a significant Cenozoic gas discovery in the Barrow Sub-basin in Maitland 1 (1992),
near the base Paleocene sand play previously recognised on 1985 2D seismic data as an
amplitude anomaly (Sit et al, 1994).
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Following the oil discovery at Vincent 1 in 1998, eight deep-water wells were drilled in the southern
Exmouth Sub-basin between 1999 and 2004. The discovery of the Enfield oil field in 1999 was
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, that increased interest in the Exmouth Sub-basin. These
discoveries formed a new oil province. The drilling program was successful, due to the extensive
quantitative interpretation of 3D seismic data (Walker, 2007). Combined initial production of major
fields, including Enfield, Vincent, Pyrenees, Stybarrow and Laverda, indicates the province contains
more than 300 MMbbl (48 GL) of heavy crude reserves (Department of Mines and Petroleum,
Petroleum and Royalties Division, 2008). Production is estimated to reach 250,000 bbl/d
(40,000 kL/d) (Department of Mines and Petroleum, Petroleum and Royalties Division, 2008). Other
projects that commenced in 2010 include the Van Gogh oil field, which started production in
February, and the Pyrenees project (comprising Crosby, Harrison, Ravensworth and Stickle oil
fields) which started production in March (Department of Mines and Petroleum, Petroleum Division,
2010). The last two years has seen a continued interest in and around the Exmouth Sub-basin with
Sappho 1 (2010) encountering gas with 75 m of pay interpreted from logs; Zola 1 ST1 (2010–2011)
discovering approximately 125 m of net gas pay in several sandstones and confirmed as a
significant discovery in the Mungaroo Formation; and Cimatti 1 and 2 intersecting a gross oil
column of 15 m, and a 7 m thick oil bearing sandstone in close tie-back distance to Enfield
(Department of Mines and Petroleum, Petroleum Division, 2010, 2011a, 2011b).
The Barrow Sub-basin has been one of the most actively and continuously explored offshore area
in Australia for the better part of the last 25 years. The Harriet Joint Venture made several small oil
and gas discoveries in the Flag Sandstone, including the Wonnich (1995), Montgomery (2003) and
Kultarr (2005) accumulations. Producing fields closer to the W12-9 Release Area include Griffin
(1990), Chinook/Scindian (1989/1990) and Woollybutt (1997) to the north; Saladin (1985) to the
east; and Corowa (2001) and Pyrenees/Macedon (1994) to the west.
Well control
ANCHOR 1 (1969)
Anchor 1 is located approximately 43 km west-northwest of Onslow in the Barrow Sub-basin. The
well was drilled by WAPET to a total depth (TD) of 3,048.6 m in a water depth of 18 m. The primary
objective was to investigate the reservoir potential of the Lower Cretaceous Barrow Group and
Upper Jurassic Dupuy Formation sandstones. Structurally, the prospect area was a fault trap lying
on the north (downthrown) side of the Long Island Fault System (the east–west-trending fault
system south of the Blencathra, Corowa and Saladin fields). The system provides a southern
closure, while the critical dip is to the east and the regional dip to the north and west.
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Geophysical interpretations suggested that the Anchor prospect area provided excellent
possibilities for stratigraphic traps, both sand pinch-outs and overlapped basal sand units. Cores in
the top of the Barrow Group indicated the presence of sandstone units with excellent reservoir
qualities with porosities ranging between 20% and 30% and permeabilities of 1–9 D. Sonic and
density logs from the Dupuy Formation indicated porosities of about 25%, while permeabilities were
expected to have been very low (West Australian Petroleum Pty Ltd, 1969). Although excellent
reservoir sandstones were encountered, no hydrocarbon accumulations were identified. The well
was subsequently plugged and abandoned.
ZEEPAARD 1 (1980)
Zeepaard 1 was drilled by Esso Australia Ltd, with a primary objective to test a narrow Upper
Triassic northeast-trending faulted horst in the northern edge of the Exmouth Sub-basin. Closure is
provided to the west and north by a bounding fault which curves round to strike east–west. Closure
to the southeast is provided by dip of the beds towards the Exmouth Sub-basin depocentre.
Possible erosion along the northern flank of the horst may have provided independent closure. The
second objective was to evaluate the hydrocarbon potential of a Lower Cretaceous turbiditic
sandstone stratigraphic trap, with up-dip pinchout of the sand units. The well reached a TD of
4,214.8 mKB. Good reservoirs were encountered in the Barrow Group and Mungaroo Formation
equivalent. Two gas-bearing sandstones were interpreted in the Mungaroo Formation equivalent
from electric logs, with average porosities of 14.5% and 10.6%, respectively. A possible third gasbearing sandstone unit is interpreted between these. Residual hydrocarbons were found in the
Barrow Group. The lower Barrow Group and Dingo Claystone have good oil source potential, while
the Mungaroo Formation equivalent could source both gas and oil. Reworked Triassic coals in the
Dingo Claystone are also identified as a potential source. The Dingo Claystone and delta front
siltstones of the Barrow Group and the Muderong Shale provide good seals. The lack of fluid
movement into the horst trap, resulting from over-pressuring in the Dingo Claystone, may have
preserved initial porosities (Esso Australia Ltd, 1981).
VLAMING HEAD 1 (1982)
Vlaming Head 1 was drilled by CNW Oil (Australia) Pty Ltd to test a large stratigraphic pinchout
structure in the Barrow Group on a northeast–southwest-trending structural nose. Top and bottom
seals were predicted in the Muderong Shale and interbedded shales within the Barrow Group,
respectively. The objective was encountered lower than predicted, as the unexpected Birdrong
Sandstone was intersected beneath the Muderong Shale. The basal seal, predicted to be shales
within the Barrow Group were instead at the top of the Barrow Group and no other interbedded
shales were intersected. With a lack of a basal seal, the well was deepened but no significant
shales were intersected below the lower Barrow Group sandstones (CNW Oil (Australia) Pty. Ltd.,
1983). The primary objective lacks a basal seal and the secondary objective an upper seal. The
absence of seals resulted in the Barrow Group reservoirs being 100% water wet. The well was
plugged and abandoned.
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ROSILY 1A ST1 (1982)
Rosily 1A ST1 was drilled by West Australian Petroleum Pty Ltd (WAPET) to test the hydrocarbon
potential of the Barrow Group in a gentle anticlinal feature developed in Lower Cretaceous
sediments approximately 5 km north of Release Area W12-9. The well, drilled in 125 m of water,
reached a TD of 3,066 mRT in Lower Cretaceous Malouet Formation sediments. Following
operational problems associated with drilling of Rosily 1A to 1,968 m, Rosily 1A was spudded and
sidetracked as Rosily 1A ST 1 from 1,819.5 mRT.
Although the stratigraphy encountered was as predicted, all sandstones within the Flacourt and
Malouet formations, except one, were found to be fully water saturated. A four metre sandstone in
the lower Malouet Formation (2,947–2,951 mRT) is gas saturated with a log derived average
porosity of 19% and an average water saturation of 12%. An RFT sample collected at 2,948.5 mRT
confirmed the log analysis results by recovering 0.9 cf (2.549 cm3) of gas (West Australian
Petroleum Pty Ltd, 1983). The onset of a supernormal pressure zone was detected at 2,929 mRT.
Log analysis concluded that there were no commercially exploitable hydrocarbons and the well was
plugged and abandoned.
SOMERVILLE 1 (1987)
Somerville 1 was drilled by BHP Petroleum Pty Ltd to test a rollover in a faulted graben with faultdependent closure at the top Mardie Greensand Member, as well as top Barrow Group sandstone.
The well reached a TD of 1,749 mRT in 58.6 m water depth. The primary objective was to test the
hydrocarbon potential of the sandstone unit at the top of the top Barrow Group and the overlying
Mardie Greensand Member. Only two metres of poor quality sandstone with residual oil saturation
was intersected within the Mardie Greensand Member. This is largely due to the high clay content
of the matrix. Quantitative assessments of permeability suggested that the Mardie Greensand
Member was of low permeability (<1.0 mD). Although having a high glauconite content, extensive
carbonate cementation and pyritisation, the Mardie Greensand Member did not act as an effective
seal to the underlying primary reservoir sandstones of the upper Barrow Group. The Greensand is
therefore considered a non-net reservoir section, and being 30 m thick, takes up most of the
structural closure at Somerville 1.
The secondary objective was to intersect the top of the Dupuy Sandstone Member. Due to a
combination of cyclone risk and the actual TD being 300 m above that proposed, the secondary
objective was not intersected (BHP Petroleum Pty Ltd, 1987).
Interpretation of logs indicated the upper Barrow Group and potentially the sandstone units of the
Dupuy Sandstone Member were water saturated. The Dingo Claystone source was not intersected
in the well. It was suspected however, that the base of Somerville 1 approached sub-mature to
mature levels of organic maturation, suggesting the underlying Dingo Claystone lies within the oil
window. Therefore, it may have been mature enough for the generation of the hydrocarbons
encountered in the Mardie Greensand Member and which have since migrated through the section.
After the completion of wireline log evaluation, Somerville 1 was plugged and abandoned.
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CHINOOK 1 (1989)
Chinook 1 was the first well operated by BHP Petroleum Pty Ltd in permit WA-210-P (now WA-10L) in the Griffin block. The well reached a TD of 3,400 mKB and had open hole wireline logs run
and a drillstem test performed. The well is located on a terrace, downthrown to the east of the
Alpha Arch horst block, in the Barrow Sub-basin. The primary reservoir objective was the Barrow
Group sandstones underlying the Mardie Greensand Member. A new field wildcat, Chinook 1 was
drilled to evaluate the four-way dip closure at the top of the Barrow Group. It was expected that the
Muderong Shale would be the top seal. The Mardie Greensand Member was not expected to be an
effective seal, but rather the Muderong Shale would provide the top seal.
The Mardie Greensand Member had moderate hydrocarbon shows with 43 m of gas being
interpreted, however reservoir quality was variable, as a result of the thinly bedded sandstones.
The targeted top Barrow Group was intersected at 2,560 mKB and had a 21 m oil show identified.
The Barrow Group sandstones showed good reservoir properties; average porosity was 17.8%,
average permeability around 2,000 mD, and a net-to-gross thickness ratio of 88% (BHP Petroleum
Pty Ltd, 1991). Chinook 1 was suspended as a gas and oil discovery in August 1989.
GRIFFIN 1 (1990)
Following the oil and gas discovery of Chinook 1, BHP Petroleum Pty Ltd drilled their second well
within the same WA-10-L permit. The well is located approximately 10.8 km southwest of Chinook 1
in the Barrow Sub-basin. Griffin 1 reached a TD of 3,400 mKB; open hole wireline logs were run
and a drillstem test performed. The primary objective for Griffin 1 was to evaluate a fault bounded
Neocomian (Valanginian) top Barrow Group closure, with potential for a secondary target in the
Triassic Mungaroo Formation. As in Chinook 1, it was expected that the Muderong Shale would be
the top seal.
The Mardie Greensand Member was intersected and had moderate to excellent hydrocarbon
shows at 2,607 mKB, containing 10.6 m of net pay sandstone with an average porosity of 15% and
an average oil saturation of 44.5%. The Barrow Group sandstones contained 60.2 m of net pay
sandstone with an average porosity of 17.5% and an average oil saturation of 81.5%. The
secondary target, the Mungaroo Formation, had no hydrocarbon indications (BHP Petroleum Pty
Ltd, 1992).
The Griffin and Scindian/Chinook oil fields are tied into the Griffin Venture Floating Production
Storage and Offloading (FPSO) facility, which commenced production in January 1994 (Curtis et al,
1994). By the end of 2009 the combined Griffin/Chinook/Scindian fields had produced
3,634,226 × 103 m3 of gas and 26,514,915 kL of oil (Department of Mines and Petroleum,
Petroleum Division, 2010).
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WEST MUIRON 3 (1992)
The West Muiron structure (Pyrenees/Macedon fields) is a large antiform, dissected into a series of
tilted fault blocks by several northeast–southwest-trending faults. The prospect is in the Lower
Cretaceous at the base of the Muderong Shale, overlying the deep Triassic high trend which is the
southerly extension of the Alpha Arch. West Muiron 1 and 2 were drilled by WAPET in 1972 and
1975 respectively, targeting the Lower Cretaceous sequence that was hydrocarbon-bearing at
Barrow Island. West Muiron 1 was abandoned due to mechanical difficulties, while West Muiron 2
encountered no shows within the thin Barrow Group sediments. West Muiron 3 was drilled by BHP
Petroleum in 1992, 3 km to the northwest of West Muiron 2, testing the Birdrong Formation and
Barrow Group sandstones within the West Muiron structure. West Muiron 3 reached a TD of
1,200 mRT. The Birdrong Formation was absent, but the well intersected a 40 m dry gas column in
highly porous and permeable unconsolidated sands of the Berriasian Barrow Group (Mitchelmore
and Smith, 1994). An average porosity of 31% and gas saturation of 88% were calculated (BHP
Petroleum Pty Ltd, 1994a). The Muderong Shale and lower Gearle Formation act as the seal for
these units. A gas-bottom seal contact prevented an accurate assessment of the potential
hydrocarbon column. The presence of gas is also reported in the Windalia Radiolarite but
permeabilities are very low. The West Muiron 4 step-out well, drilled by BHP Petroleum in 1993,
established a total gas column in the Barrow Group in excess of 91 m. The gas field discovered in
West Muiron 3 was later named the Macedon gas field.
YORK 1 (1993)
York 1 was drilled by BHP Petroleum Pty Ltd to test the Birdrong Sandstone on an unfaulted
depositional drape anticline with four-way dip closure overlying an older Triassic–Jurassic horst
block. The time closure is lacking due to lateral velocity variations in the Paleogene–Neogene
carbonates ‘pulling-up’ the eastern flank of the structure; however, depth conversion indicated a
closure at the York location. York 1 reached a TD of 3,372 mRT in a water depth of 365 m. Good
reservoir quality sandstones, with high net-to-gross ratios were intersected in the Birdrong
Sandstone and underlying Zeepaard Formation of the Barrow Group. The Birdrong Sandstone has
core plug porosities of 15–20% and permeabilities of up to 3,000 mD. The well intersected the
entire Zeepaard Formation and bottomed in the upper Barrow Group without encountering
significant hydrocarbon shows (BHP Petroleum Pty Ltd, 1994b). There was no attempt to drill this
well any deeper to target possible slope fan sandstones that may form stratigraphic traps in the
intra-Barrow Group units on the York structure.
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WEST MUIRON 5 (1993)
West Muiron 5 was drilled by BHP Petroleum Pty Ltd to test the extent of the gas accumulation
discovered in West Muiron 3 and whether oil could be trapped in a large down-thrown fault block to
the west of West Muiron 4 (5.7 km east of West Muiron 5). The well reached at TD of 1,526 mRT in
187.5 m of water and intersected a 20 m gas and a 32 m oil column. Gas was encountered in the
high quality reservoir sandstones of the Pyrenees Member, while the oil was encountered in the
poorer reservoir sandstones below the Intra-Hauterivian Unconformity. In the gas column,
maximum flow rate testing reached 16.8 MMscf/d through a 64/64” choke; this rate may have been
restricted and hence, not reflect the true quality of the reservoir. A maximum rate of only 550 bbl/d
was achieved when testing the oil column, a reflection of the poorer reservoir quality and
biodegraded nature (18° API gravity) of the oil (BHP Petroleum Pty Ltd, 1994c). West Muiron 5 was
the first well to intersect an oil column in the West Muiron field.
A combination of various gas compositions, separate hydrocarbon contacts and minor pressure
differences between West Muiron 5, and West Muiron 3 and 4 suggest that there are two distinct
fields. The oil and gas field discovered in West Muiron 5 was later named the Pyrenees oil and gas
field. Both the oil and gas of this field were biodegraded but producible, especially in the high
quality reservoirs (Smith et al, 2003).
ALTAIR 1 (1995)
Altair 1 was drilled by WAPET testing a stratigraphic trap in a basinal turbidite sandstone reservoir
in the Malouet Formation of the Barrow Group. Trap closure is defined by up-dip pinchout of sands
onto prodelta foreset shales of the Barrow Group delta. Northern closure is provided by lateral
pinchout of sands within condensed pelagic shales. Eastern and southern limits of the reservoir are
a result of regional dip. The top seal is provided by progradational prodeltaic shales over the
turbidite reservoir, while the bottom seal is provided by transgressive, highstand condensed pelagic
shales. Sands were determined to be of good reservoir quality, with a porosity of approximately
25%. It was concluded that the reservoir unit once contained gas but, due to the high porosity and
inversion folding during the Paleogene, the hydrocarbons were lost (West Australian Petroleum Pty
Ltd, 1995). Wireline log and MDT tool determined the reservoir sandstones were water wet. The
well was plugged and abandoned as dry.
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NIMROD 1 ST1, ST2, ST3 (1996)
The Nimrod 1 well was drilled by BHP Petroleum Pty Ltd as a wildcat well in the southwest Barrow
Sub-basin; testing the hydrocarbon potential of a series of large rotated Triassic fault blocks.
Nimrod 1 was sidetracked as Nimrod 1 ST1, at 1,545 m, after the bottom hole assembly (BHA) was
severed, recovered and hung up at 1,633 m. Following operational problems that left a 190 m fish
at the bottom of the 3,355 m Nimrod 1 ST1 well, Nimrod 1 ST1 was sidetracked as Nimrod 1 ST2
from 3,089 m. Further operational problems, resulting in loss of equipment, required Nimrod 1 ST2
being cemented and sidetracked as Nimrod 1 ST3 3,415 m. After the drilling of the three sidetracks
(ST1, ST2 and ST3) the well reached at TD of 4,130 mRT within the Triassic Mungaroo Formation.
The Nimrod structure consists of a large north-northwest to south-southeast-trending Triassic horst
which dips to the east-southeast. It formed during the early phase of basin rifting in the Sinemurian,
and resulted in the development of the Alpha Arch which separates the Barrow and Exmouth subbasins.
The primary target for the well were sandstones in the Triassic Mungaroo Formation, which were
expected to be sealed both vertically and laterally by shales of the Murat Siltstone. The Murat
Siltstone was not intersected; however, the dominantly shale Jurassic Brigadier Formation was
intersected. No closure was mapped in the overlying Barrow Group sandstones.
Although not specifically targeted, gas encountered (log interpreted total of 11.4 m of net gas over a
205 m depth range) in the Barrow Group suggests that there is potential for stratigraphic traps.
However, the thickness of these sandstones and the poor reservoir quality suggests that any
stratigraphic play development within the basal Barrow Group would be high risk.
In Nimrod 1 ST2 and ST3, gas was encountered in the thin sandstones of the Brigadier Formation,
with a total of 9.6 m of net gas sandstone, average porosity of 13.8% and average water saturation
of 57.8%.
The primary objective, the Mungaroo Formation, also encountered gas in thin sandstones (3,426–
3,625 mRT) with a total of 11.6 m of net gas, average porosity of 11.4% and water saturation of
77.7%. Thicker sandstones of the Mungaroo Formation (3,646–3,667 mRT) were also encountered.
Here a total of 23.0 m of net gas is interpreted with an average porosity of 13.6% and water
saturation of 27.8% (BHP Petroleum Pty Ltd, 1997). Hydrocarbon charge is thought to be through
direct face-loading across the large bounding faults of the Nimrod structure, where mature
claystones of Late Jurassic age are potentially juxtaposed against the Mungaroo Formation.
Alternatively, mature shale source units within the Mungaroo Formation itself may have provided
direct charging within and downdip of the structure. The presence of thin sandstones overlying the
thicker sandstones of the Mungaroo Formation appear to have provided cross-fault thief zones, and
thus significantly reduced the trap capacity of the Nimrod structure. Nimrod 1 was subsequently
plugged and abandoned.
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VINCENT OIL FIELD (1998)
Vincent 1 was drilled by Woodside in 1998 to a TD of 1,560 mRT on the flank of the Novara Arch,
to test a three-way dip/fault closure at the base of the Muderong Shale. Hydrocarbon-bearing
sandstones were encountered in the lower Barrow Group objective, with a 7.75 m gross gas
column and a 19.35 m gross oil column identified. Production testing of the well, yielded maximum
flow rates of 4,301 bopd (683.8 kL/d), with 1.9 MMscf/d (53,808 m3/d) gas through a 2” choke
despite its heavy level of biodegradation (17° API gravity). Hydrogen sulphide (H2S) gas was
detected during the test, reaching a maximum of 80 ppm. The excellent quality of the reservoir
encountered in Vincent 1 is the primary reason for the good test result and it is clear that reservoir
quality is a key factor for prospects with a similar hydrocarbon charge. Vincent 1 was plugged and
abandoned as an oil and gas discovery.
The Vincent oil discovery at the top of the Barrow Group is significant in that it proved producible oil
in an area where oil was previously considered to be too biodegraded and heavy to bring into
production (Polomka et al, 1999). The Vincent 1 well became the harbinger of successful
exploration drilling campaigns in this area. Van Gogh is the name given to the northern part of
Vincent field where production commenced in February 2010. Van Gogh is Apache’s first oil
development using a floating production, storage and offloading (FPSO) system, the Ningaloo
Vision. The project is expected to produce 40,000 bbl/d (6,360 kL/d) of oil (Department of Mines
and Petroleum, Petroleum Division, 2010).
HARPY 1 (2001)
Harpy 1 was drilled by Santos Ltd to a TD of 1,665 mRT, with the primary objective being the upper
Barrow Group – S. areolata sandstones. The well was drilled to test a proven play type, such as
that drilled at South Pepper and North Herald. These oil and gas fields occur at the crest of
anticlines, trapped to the north by east–west-trending normal faults. Reservoir qualities in these
fields are good and are predominantly sand-prone with discontinuous shale units. The Muderong
Shale is the regional seal, sealing the Barrow Group. The presence of nearby oil accumulations at
Griffin, Novara, Pyrenees/Macedon, Caretta, Saladin, Enfield and Vincent suggested oil charge into
Harpy 1 was low risk.
Based on good quality reservoirs intersected at Somerville 1, a thickness range of 80–100 m was
expected. Other wells that intersected these Barrow Group sandstones include Vlaming Head 1,
Anchor 1 and Nimrod 1, among others. Although porosities and permeabilities were expected to be
high in Harpy 1, there was no indication of hydrocarbons (Santos Ltd, 2002). Wireline logs were
attempted, however due to formation instability no logs were obtained below 1,548 mRT. After the
failure to run logs, the well was abandoned.
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CROSBY 1 (2003)
Crosby 1 was drilled to a TD of 1,226 mRT by BHP Billiton to test the validity of an elongate, northnortheast to south-southwest-trending structural-stratigraphic trap located on a northeast-trending
fault terrace between the Ravensworth and West Muiron 5 oil and gas discoveries. The primary
objective was the shallow marine siliciclastics of the upper Tithonian to lower Berriasian Pyrenees
Member of the Barrow Group. Wireline logs indicate that the primary objective reservoir was oilbearing, and a total of 34 m of net oil pay was interpreted. This was confirmed by RCI pressure
testing and fluid recovery, with a good quality sample of 18.6° API oil obtained.
The marine claystones and siltstones of the Oxfordian to Kimmeridgian Dingo Claystone are mature
in the Exmouth Sub-basin and are expected to be the principal source rock for oil and gas
discoveries within the primary objective Pyrenees Member. Geochemical analysis of the Crosby 1
oil and gas suggests multiple hydrocarbon charges; an early charge of oil and associated gas; a
later charge of mature wet-gas/condensate (including gasoline-range hydrocarbons), now
biodegraded; and a late charge of very mature dry gas that was subsequently biodegraded (BHP
Billiton, 2004). Crosby 1 was plugged and abandoned as an oil discovery.
Early 2010 saw the BHP Billiton-operated Pyrenees project come online, with first oil production
commencing ahead of schedule. The project consists of the Crosby, Harrison, Ravensworth and
Stickle oil and gas fields that are operated in production license WA-42-L. The full project involves
an extensive subsea gathering system, and an FPSO facility with production capacity of
approximately 96,000 bbl (15,261 kL) of oil and gas reinjection capacity of 60 MMscf (1.7 Mm3) of
gas per day (Department of Mines and Petroleum, Petroleum Division, 2010, 2011a). Gas produced
by the development will be reinjected into the reservoir of the nearby Macedon gas field for future
recovery.
COROWA EAST 1 (2005)
Corowa East 1 was drilled by Santos Ltd to test the eastern side of the Corowa Horst. The well was
located to obtain structural information on the Corowa Horst and to target the Birdrong Sandstone,
which had been intersected in Corowa 1 (oil discovery) and Corowa Flank 1 (dry hole).
Corowa East 1 was drilled to a total depth of 1,670 mRT.
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An objective of Corowa East 1 was to determine the oil-water contact within the horst (Corowa 1
intersected ‘oil on rock’) and there was considerable ambiguity because of the pressure differences
between Corowa 1 and Corowa Flank 1. These discrepancies are interpreted to be because of
regional pressure depletion due to historical production. The well also aimed to provide detail on
local sand thickness variations within the reservoir (Santos Ltd, 2005). The primary target, the
Birdrong Sandstone, was intersected 7.9 m below prediction. No hydrocarbon fluorescence was
observed while drilling. There was a total gross reservoir unit of 20 m, with net sandstone of 19 m.
The trap was wet due to trap failure and it was interpreted that the Corowa 1 oil is restricted to a
small three-way dip fault closure. Results from Corowa East 1 also indicated the Corowa
accumulation is a small and structurally constrained oil resource. Corowa East 1 was plugged and
abandoned.
BEG 1 (2007)
Beg 1 was drilled by Apache Northwest Pty Ltd approximately 22 km west of Release Area W12-8
in the Exmouth Su-basin. Gas (Department of Mines and Petroleum, Petroleum and Royalties
Division, 2008) and minor oil shows were identified in the well (Apache Energy, 2008b). Beg 1
reached a TD of 3,936 mRT, in 345 m of water. No further data is available.
BLEABERRY WEST 1 (2007)
Bleaberry West 1 was drilled by Apache Northwest Pty Ltd, approximately 15 km to the southwest
of Release Area W12-8, to a TD of 1,592 m (Apache Energy, 2008a). Both oil and gas shows were
identified in Bleaberry West 1 (Department of Mines and Petroleum, Petroleum and Royalties
Division, 2008). No further data is available.
Further details regarding wells and available data follow this link:
http://www.ret.gov.au/Documents/par/data/documents/Data%20list/data%20list_barrow_AR12.xls
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Data coverage
Release Areas W12-8 and W12-9 have good 2D seismic coverage of various vintages from the
1970s to the early 2000s. Coverage includes: Barrow 4 (DW) (1971), HH90A (1990), Vlaming 2D
(1992), GPCT93 (NEPS 2D) (1993), the Tea Tree survey (1998) and the Klammer survey (2008),
plus many others.
Regional seismic lines that were acquired by Geoscience Australia also intersect both Release
Areas; AGSO 101–Southern Carnarvon (1991) and AGSO 110–Barrow/Dampier (1992), examples
of which are shown in Figure 7 and Figure 8, and AGSO 136–Carnarvon Tertiary Tie (1994).
Most of Release Area W12-8 is covered by 3D seismic surveys, and Release Area W12-9 is nearly
fully covered. Coverage is of different vintages, mostly ranging between 1993 and 1997, with the
most recent being the high quality 3D seismic of the Carnarvon HCA04A survey acquired in 2005
by BHP Billiton Petroleum Pty Ltd with the PGS Ramford Vanguard vessel.
In 2007, Petroleum Geo-Services Asia Pacific (PGS) acquired the New Dawn Survey, a multi-client
2D seismic survey (Petroleum Geo-Services Asia Pacific, 2011) that provides long offset 2D data in
deep-water along the North West Shelf of Australia, close to the Release Areas. Gravity and
magnetic data were acquired in conjunction with the 2D seismic. A good accompaniment to the
New Dawn Survey is the North West Shelf Digital Atlas (NWSDA) also provided by PGS (Petroleum
Geo-Services Asia Pacific, 2011). This data package also covers the Release Areas and provides
continental scale regional understanding with supporting grids for bathymetry, gravity, magnetic,
TOC, HI and VR data; thus providing insights into the NWS petroleum provinces.
To view image of seismic coverage follow this link:
http://www.ga.gov.au/energy/projects/acreage-release-and-promotion/2012.html#data-packages
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PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL
Sources
Reservoirs
Seals
•
Jurassic Dingo Claystone – source of oil fields in the sub-basin
•
Triassic Mungaroo Formation – deltaic sediments are a source of gas
•
Mardie Greensand Member
•
Cretaceous Barrow Group, Zeepaard Formation and Birdrong Sandstone
•
Jurassic Dupuy Formation
•
Triassic sandstones
•
Cretaceous Muderong Shale (regional seal)
•
Intraformational seals within the Upper Triassic and Lower Cretaceous deltaic
sequences
Play Types
•
Cretaceous inversion anticlines and structural/stratigraphic traps
•
Triassic fault blocks and associated drapes
Source Rocks
The Triassic sedimentary succession has the potential for mature source facies, including possible
organic-rich units of both the Lower and Upper Triassic; the marine Locker Shale and equivalents
and the deltaic Mungaroo Formation and equivalents.
The Upper Jurassic Dingo Claystone and lower Barrow Group also have good oil source potential.
The marine shales of the Dingo Claystone are the principal effective source for oil in the Exmouth,
Barrow and Dampier sub-basins (Tindale et al, 1998; Longley et al, 2002). Geochemical studies
indicate that although oils from the Dingo Claystone are derived from marine source rocks there
was also a significant contribution from terrestrial matter (Summons et al, 1998). In general, oils in
the southern and southeastern Barrow Sub-basin show a greater terrestrial component.
Hydrocarbon generation commenced in the Exmouth Sub-basin and southern Barrow Sub-basin in
the Early Cretaceous with the loading of the Barrow Delta (Tindale et al, 1998; Smith et al, 2003).
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Reservoirs
Good reservoirs were encountered in the Late Triassic Mungaroo Formation equivalent at
Zeepaard 1, with two sandstones having average porosities of 14.5% and 10.6%, respectively
(Esso Australia Ltd, 1981). Here the Mungaroo Formation is interpreted to consist of low-sinuosity
river, levee bank and overbank deposits (Esso Australia Ltd, 1981). The Mungaroo Formation has
also been proven as a potential reservoir in the Barrow Sub-basin where gas encountered in thin
sandstones from Nimrod 1 ST1, ST2 and ST3 (3,426–3,625 mRT) indicated a total of 11.6 m of net
gas with an average porosity of 11.4% and water saturation of 77.7%. Thicker sandstones of the
Mungaroo Formation (3,646–3,667 mRT) were also encountered with a total of 23.0 m of net gas
interpreted and an average porosity of 13.6% and water saturation of 27.8% (BHP Petroleum Pty
Ltd, 1997). In addition, there have been indications that the Upper Jurassic Dupuy Formation may
also be a potential reservoir in the Exmouth and Barrow sub-basins (Department of Resources,
Energy and Tourism, 2010, 2011).
The Cretaceous Barrow Group sandstones have good reservoir characteristics, and are composed
predominantly of quartz grains, weakly cemented by siderite and pyrite, with a small amount of clay
matrix. Log derived porosities range from 20% to 26% (Esso Australia Ltd, 1980). In Coniston 1
(BHP Petroleum Pty Ltd, 2001) the Barrow Group is a massive quartz sandstone 88.4 m thick with
excellent reservoir quality in multiple units. The average porosity of the oil-bearing sandstone unit
(1,271.5–,1285.5 mRT) was 27%, with an average permeability at 4.97 D (from logs) and measured
in core at 3.5 D. The gas-bearing unit (1,261.6–1,272.5 mRT) had an average porosity of 26% and
permeability of 1.65 D.
The Zeepaard Formation and Birdrong Sandstone, overlying the Barrow Group sandstones, have
also been shown to have good reservoirs qualities. The sandstones encountered in York 1 had a
high net-to-gross ratio, but were 100% water saturated (BHP Petroleum Pty Ltd, 1994b).
The Mardie Greensand Member is a variable lithological unit. Somerville 1 penetrated it and
recorded poor reservoir characteristics including high amounts of clay, glauconite, carbonate
cement and pyritisation. The Chinook 1 and Griffin 1 wells, however, demonstrated that the Mardie
Greensand Member could be a potential reservoir. The Chinook 1 well recorded a 43 m gas
column, but the reservoir quality was considered to be variable due to the thinly bedded
sandstones. Griffin 1 well yielded moderate to excellent hydrocarbon shows, where it intersected
10 m net pay sandstones with an average porosity of 15% and average oil saturation of 44.5%.
Seals
There are both regional and intraformational seals present in the Release Areas. The Lower
Cretaceous Muderong Shale is the regional seal across the Exmouth and Barrow sub-basins.
Interbedded claystones within deltaic sequences of the Triassic Mungaroo Formation, the Dingo
Formation and Lower Cretaceous Barrow Group also are potential intraformational seals.
Throughout the Northern Carnarvon Basin the sealing unit is dependant on the trap geometry and
stratigraphy within fault blocks. Potential seals for the Mungaroo Formation include: Brigadier
Formation, Murat Siltstone, Dingo Claystone, Barrow Group and Muderong Shale (Korn et al,
2003). The Lower Gearle Formation can also provide a seal (e.g., West Muiron 3).
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Play types
The proven traditional Triassic fault block play hosts some of the hydrocarbon reserves in the
Exmouth Sub-basin. Plays within the Mungaroo Formation in fault block traps are sealed either by
the Dingo Claystone or intraformational seals. As an example, gas-bearing sandstones have been
interpreted in the Mungaroo Formation equivalents from electric logs at Zeepaard 1.
Targets in Release Areas W12-8 and W12-9 can be found in the Barrow Group sandstones and
represent the major producing traps for the oil province in the Exmouth Sub-basin. Here reservoirs
are sourced from the Dingo Claystone, sealed by the Muderong Shale or interbedded claystone
units. The Exmouth Sub-basin has numerous oil and gas fields as examples of these play types.
Other potential reservoirs include the Lower Cretaceous Mardie Greensand Member and Jurassic
sandstones reworked from Triassic highs. These Jurassic sediments are an unproven stratigraphic
play in the western Barrow Sub-basin. The Upper Jurassic Dupuy Formation has been successfully
explored along east–west wrenched fault anticlines.
Play types in the Paleogene sands have proven to be viable around the Barrow Sub-basin
(Maitland gas field) and may also be so in the Release Areas. Oligocene channels have been
defined by 2D and 3D seismic profiles and isochrons within middle Cenozoic carbonates. Drilling of
these channels suggests that coarse-grained clastics were transported basinward. A charge
mechanism has yet to be proven, but if viable petroleum traps are present in these Oligocene
channels, they can be expected to be below sealing marls and fine-grained carbonate of the
overlying progradational facies of the Mandu Formation (Romine et al, 1997; Gorter et al, 2002).
Critical risks
For the Mungaroo Formation play, hydrocarbon charge and reduced reservoir quality due to
diagenetic overprinting are the main risks. Gas charge is considered to be locally derived from the
underlying Triassic Locker Shale and/or interbedded claystone units within the Mungaroo
Formation. The depth to the Triassic in much of the Release Areas may limit this play type,
especially in the northern blocks of W12-8. There may be an improved success rate with the
application of amplitude analysis of 3D seismic coverage to image gas within the reservoirs.
Seal lithologies within the lower Barrow Group and Dupuy Formation are very variable and can be
unexpectedly thin providing an inadequate seal for commercial quantities of hydrocarbons. Gas
charge appears to be pervasive through the Barrow Sub-basin, suggesting that the trap geometries,
reservoir occurrence and quality will be the main risks. Gas flushing is a major risk to the
preservation of any early oil charge. There is also evidence of overpressured zones between
2,650–4,650 m, within the Jurassic section and part of the Cretaceous Barrow Group. This
overpressured zone is associated with vitrinite reflectance values of 0.8–2.2% and an increased
volume of gas-generating organic matter, suggesting that hydrocarbon generation, especially gas,
within sealed conditions is the cause of a sustained deep overpressure since the Cenozoic (He and
Middleton, 2002). Therefore this overpressure poses both a petroleum system risk as well as a
drilling hazard.
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20
Although plays within the Barrow Group are largely favourable in the Exmouth Sub-basin, there are
a number of factors to consider. These include hydrocarbon charge of traps usually requiring
migration from the north of the Release Areas, and biodegradation of early oil charge. Smith et al
(2003) noted that these risks can be mitigated by high quality reservoirs that allow viscous oil to
flow, and that less biodegraded oil will be hosted in the deeper and hotter reservoirs, beneath seals
other than those of the Muderong Shale.
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21
FIGURES
Figure 1
Location map of Release Areas W12-8 and W12-9 in the Exmouth and Barrow
sub-basins, Northern Carnarvon Basin. Exploration wells relevant to the Release
Areas are also shown.
Figure 2
Graticular block map and graticular block listings for Release Areas W12-8 and
W12-9 in the Exmouth and Barrow sub-basins, Northern Carnarvon Basin.
Figure 3
Structural elements of the Exmouth and Barrow sub-basins showing the 2012
Release Areas, hydrocarbon accumulations and discoveries. The location of
seismic lines in Figure 7 and Figure 8 are shown.
Figure 4
Stratigraphy and hydrocarbon discoveries of the Exmouth Sub-basin, based on
the Northern Carnarvon Basin Biozonation and Stratigraphy Chart (Nicoll et al,
2010). Geological Time Scale after Gradstein et al (2004) and Ogg et al (2008).
Regional seismic horizons after AGSO (2001)
Figure 5
Stratigraphy and hydrocarbon discoveries of the Barrow Sub-basin, based on the
Northern Carnarvon Basin Biozonation and Stratigraphy Chart (Nicoll et al,
2010). Geological Time Scale after Gradstein et al (2004) and Ogg et al (2008).
Regional seismic horizons after AGSO (2001).
Figure 6
Detailed stratigraphy and hydrocarbon discoveries of the Late Jurassic to Early
Cretaceous reservoirs of the Barrow Sub-basin, based on the Northern
Carnarvon Basin Biozonation and Stratigraphy Chart (Nicoll et al, 2010).
Geological Time Scale after Gradstein et al (2004) and Ogg et al (2008).
Regional seismic horizons after AGSO (2001).
Figure 7
AGSO seismic line 110/12 across Release Areas W12-8 and W12-9 in the
Barrow and Exmouth sub-basins. The location of the seismic line is shown in
Figure 3. Regional seismic horizons are shown in Figure 4, Figure 5 and
Figure 6.
Figure 8
AGSO seismic line 101/04 across Release Area W12-8 in the Barrow and
Exmouth sub-basins. The location of the seismic line is shown in Figure 3.
Regional seismic horizons are shown in Figure 4, Figure 5 and Figure 6.
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22
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