GEOLOGICAL INFORMATION
RELEASE AREAS W11-7, W11-8 AND W11-9,
NORTHEASTERN EXMOUTH PLATEAU, NORTHERN
CARNARVON BASIN
WESTERN AUSTRALIA
Bids Close – 12 April 2012

Deepwater frontier of Australia’s premier Northern Carnarvon Basin
hydrocarbon province.

Large untested structures on trend with large gas fields to the south.

Water depths range from 500 m to 4500 m.

Play types include horsts, reefs and basin-floor fan sands.

Infrastructure in place over 100 km to the south.

Active petroleum system present at Nebo 1 to the south, but may
indicate a local, rather than a regional, origin.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 1 of 24
LOCATION
Release Areas W11-7, W11-8 and W11-9 lie 250-450 km north of Dampier,
Western Australia, across the northeastern Exmouth Plateau and Beagle Subbasin of the Northern Carnarvon Basin (Figure 1). Water depth across the
Release Areas deepens from the south to the north over the range 5004500 m. The northern half of the Release Areas includes several large
canyons that dissect the margin down to the Argo Abyssal Plain.
The graticular block map and listings defining the Release Areas are shown in
Figure 2. A total of 488 blocks is divided across the Release Areas: 167
blocks (approximately 13655 km2) in W11-7, 154 blocks (approximately
12585 km2) in W11-8 and 167 blocks (13555 km2) in W11-9.
The Northern Carnarvon Basin is Australia’s premier hydrocarbon province,
with the Exmouth Plateau component hosting world-class giant gas fields (e.g.
Io-Jansz, Gorgon and Scarborough), while the Barrow and Dampier subbasins host more moderately sized oil/gas accumulations (e.g.
Perseus/Goodwyn, Angel and Stag). The northeastern Exmouth Plateau and
Beagle Sub-basin components, however, are relatively under-explored. Only
Wigmore 1 well has been drilled in the Release Areas, and it was
unsuccessful. In the immediate vicinity, however, Nebo 1 discovered a subcommercial oil accumulation and this suggests, at least, a localised active
petroleum system. In addition, Phoenix 1, further to the southeast, discovered
gas.
The nearest production facilities, within the northern Dampier Sub-basin, are
the Santos Ltd-operated Mutineer-Pitcairn and Exeter oil fields, about 100 km
to the south, and the large Woodside Energy Ltd-operated Angel gas field, a
further 25 km to the south. Production commenced at Mutineer-Pitcairn and
Exeter in 2005 as a floating production, storage and offload facility (FPSO).
Production at Angel began in 2008, and is carried out via a subsea pipeline
link to a trunkline connecting the North Rankin A platform to an onshore
facility.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 2 of 24
RELEASE AREA GEOLOGY
Local Tectonic Setting
The Release Areas are located on the North West Shelf, over the
northeastern Exmouth Plateau – an area sometimes termed the Dixon Subbasin (Hocking et al, 1994) – where the Northern Carnarvon Basin abuts the
Roebuck Basin at the southeastern end of the Argo Abyssal Plain. In terms of
the broad structural elements, the Release Areas overlie the Exmouth Plateau
and Beagle Sub-basin (Northern Carnarvon Basin), to the west and south,
and the western flank of the Rowley Sub-basin (Roebuck Basin), to the east
(Figure 3). To the north lies the oceanic crust of the Argo Abyssal Plain. The
general distinction between these elements reflects the partitioning of a broad
intracratonic downwarp, during the Triassic, into various structural grains
related to - and modified later by - Mid-Late Jurassic and Early Cretaceous
oblique rifting episodes which led, respectively, to Oxfordian and Valanginian
breakups.
The Exmouth Plateau is a broad, sunken continental block, which is underlain
by 10-15 km of a generally flat-lying, or block-faulted and tilted, Lower
Cretaceous, Jurassic, Triassic and Paleozoic section. These sediments were
deposited during periods of extension that preceded the breakup of Australia
and Argo Land in the Middle Jurassic and then Greater India in the Early
Cretaceous. The plateau’s northern margin is defined by a series of broad
northeast- to north-trending canyons and a large, high-standing detached
continental block (i.e. Wombat Plateau). Exon et al (1982) considered this
margin’s underlying Mesozoic geology as distinct from the Exmouth Plateau
proper to the south, with its complex morphology being related to a more
dominant component of shearing leading to breakup.
The Beagle Sub-basin is dominated by a horst-and-graben morphology
modified by transcurrent motion which reflected oblique extension prior to the
separation of Argo Land. It contains over 10 km of Upper Paleozoic to
Cenozoic sediments. Tectonically, it is defined by two regions: one dominated
by fault-controlled basement flanks to the south and the other a broad, heavily
faulted depocentre in the north (Figure 3; Blevin et al, 1993a, 1993b, 1994).
The Rowley Sub-basin represents a major westward-thickening upper
Paleozoic-Cenozoic depocentre containing about 9 km of PermoCarboniferous, or older, strata overlain by up to 6 km of Mesozoic-Cenozoic
sediments (Smith et al, 1999). It is structurally separated from the Beagle
Sub-basin and northeastern Exmouth Plateau, to its west, by a long, sinuous
zone of uplift and faulting termed the North Turtle Hinge Zone. Unlike the
dissected form of the northern margin to the Exmouth Plateau, the outer
margin of the Rowley Sub-basin is characterised by margin-parallel largethrow rift faults descending to the Argo Abyssal Plain.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 3 of 24
Although direct lithostratigraphic information from wells is limited, the general
chronostratigraphic setting within the Release Areas is expected to reflect
Northern Carnarvon Basin (i.e. Dampier and Beagle sub-basins) depositional
cycles. However, the large distances from siliciclastic sediment sources to the
south and east, as well as the effects of widespread structuring and igneous
activity closer to the locus of breakup to the north, is likely to have
substantially affected the sedimentary facies.
Structural Evolution and Depositional History of the area
The dominant fault trend across the Exmouth Plateau is north-south to
northeast-southwest, reflecting an early widespread extensional structural
grain recognised in the Paleozoic of the onshore Carnarvon Basin (Stagg and
Colwell, 1994; Stagg et al, 2004) and offshore, over a ductile lithosphere
(Gartrell, 2000). These trends are broadly reflected inboard by the later
development of thick Mesozoic sequences across a series of broad troughs
and highs (e.g. Exmouth, Barrow and Dampier sub-basins and Rankin
Platform).
The late Paleozoic rift cycle was succeeded across the Northern Carnarvon
Basin by an Early Triassic sag phase resulting in an initial regional marine
transgression. This transgression is marked by the marine Locker Shale,
which unconformably overlies the Permian section and grades upwards into
the thick fluvio-deltaic Mungaroo Formation (Figure 4; i.e. equivalent to the
Keraudren Formation in the Roebuck Basin). The Locker Shale was deposited
in shallow shelf and shoreline environments, while the Mungaroo Formation
was deposited on a broad, low-relief, rapidly subsiding coastal plain as
northward-prograding deltaic sequences that extended across the Exmouth
Plateau. The Mungaroo Formation consists of numerous fining-upward cycles
of thick fluvio-deltaic sandstone with minor interbeds of siltstone, claystone
and coal (e.g. Delambre 1). Along the northern parts of the plateau it is
expected to be influenced by more marine sedimentation pulses. For
example, the Middle Triassic Cossigny Member comprises paralic to marine
siltstone, claystone and limestone/dolomite, and where the limestone/dolomite
is well developed it forms an important transgressive seismic marker horizon
(Figure 5 and Figure 6).
The Late Triassic was marked by an episode of faulting across the Northern
Carnarvon Basin prior to a limited marine transgression from the north. This
tectonic pulse was manifest along the northern margin of the Exmouth
Plateau by faulting within the Swan Graben and Kangaroo Syncline,
concomitant with the development of volcanics on the northwestern margin of
the Wombat Plateau (Exon et al, 1982). The Wombat Plateau ODP wells
show that this period was characterised along the northern part of the plateau
by Carnian prodelta mudstones and carbonate banks grading into Norian
shallow marine to paralic sedimentation of siliciclastics, shelfal carbonates
and coal (von Rad et al, 1992a). This was followed in the Rhaetian by a
marine transgression marked by marls (Brigadier Formation equivalent;
Figure 4) and shelf and reefal limestones (Williamson et al, 1989; Haq et al,
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 4 of 24
1990; Exon and von Rad, 1994). Further inboard, where intersected
(Delambre 1), the Brigadier Formation comprises numerous fining- and
coarsening-upward cycles of thinly bedded sandstone, siltstone and claystone
deposited in a shallow to marginal marine setting.
The Jurassic is characterised by continued structuring across the region, as
rifting between Australia and Greater India proceeded to eventual breakup.
Jurassic sedimentation is absent on the Wombat Plateau (von Rad et al,
1992a, 1992b) where the full effects of post-breakup erosion are expected to
have occurred.
The Early Jurassic was marked by deposition of the North Rankin Formation
and Murat Siltstone (“Picard Formation” in Wigmore 1). For the Release
Areas, information on these units is limited to that obtained from Wigmore 1.
The North Rankin Formation comprises thick, clean sandstone units,
interbedded with siltstone and claystone, deposited in a high-energy shallow
marine environment. It is directly overlain by the “Pliensbachian Limestone”
unit/member of the Murat Siltstone, which is widespread across the northern
part of the Exmouth Plateau. In the Pliensbachian, rifting began to be focused
more inboard in the Exmouth, Barrow, Dampier and Beagle sub-basin
depocentres. In these troughs, several kilometres of marine Jurassic
sediments were deposited; these are the equivalent of condensed sections a
few metres thick preserved in some locations of the central Exmouth Plateau.
After a minor hiatus in the Toarcian, the widespread Athol and Legendre
formations were deposited in the Middle Jurassic. Athol Formation claystones
were deposited in a restricted marine environment and represent the marine
facies distal to the widespread, major prograding sandstones of the Legendre
Formation, which reached its maximum extent in the Bathonian, just prior to
Argo breakup. The Legendre Formation is characterised by a series of
stacked coarsening-upward fluvio-deltaic cycles of sandstone, siltstone, shale
and minor coal (e.g. Wigmore 1 and Nebo 1).
Rift-related faulting across the northern Exmouth Plateau reached its peak
with Argo breakup in the Callovian. The Callovian marks the major movement
on the rift faults along the northern Exmouth Plateau, while oceanic crust did
not develop in the Argo Abyssal Plain until the Oxfordian (Norvick, 2002). The
Wombat Plateau, and emergent syncline flanks in the adjoining Exmouth
Plateau, were uplifted and eroded . The resulting erosion is particularly
marked on the Wombat Plateau as the Triassic section is directly overlain by
the Cretaceous, with thin Berriasian shallow marine sands/silts deposited
directly on Rhaetian reefal systems (von Rad et al, 1992a). Further inboard,
this period is marked by deposition of the transgressive Callovian-Oxfordian
Calypso Formation (e.g. Manaslu 1 and Nebo 1), which consists of glauconitic
claystone and thinly interbedded sandstone and siltstone.
Wells across the region indicate that the Upper Jurassic succession is very
thin or absent (Figure 4; ODP Leg 122, Wigmore 1, Nebo 1, Whitetail 1 and
Manaslu 1). This interval is largely represented in the inboard sub-basins, to
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 5 of 24
the south, by the extensive Dingo Claystone. Given that the wells in the
Exmouth Plateau are generally located on structural highs, where Callovian
and Valanginian erosional events are expected to be pronounced, this unit or
its equivalent, may be present within intervening lows. A very thin interval of
Dingo Claystone/Angel Formation is interpreted in Darwin 1, and this most
likely represents a more condensed development of the much thicker unit
found in the Barrow/Dampier/Exmouth sub-basins to the south.
The Early Cretaceous in the Northern Carnarvon Basin was a more quiescent
phase of structuring. The Berriasian-Valanginian is characterised by some
late syn-rift style sedimentation, as breakup proceeded far to the west and
south in the Gascoyne and Cuvier abyssal plains respectively. Breakup was
followed by the establishment of an early passive margin setting with the
onset of rifted margin thermal relaxation. This continued until the Aptian when
deposition of the Windalia Radiolarite marked the onset of largely carbonate
deposition in an open marine setting.
The Berriasian to Valanginian Forestier Claystone is a marine claystone
widespread across the northeastern Exmouth Plateau, and is the late syn-rift
equivalent of the massive Barrow Delta developed elsewhere. The unit
probably thickens into the troughs and forms a regional seal (e.g. Nebo 1), but
it is absent (Wigmore 1) or thin (Whitetail 1 and Manaslu 1) further north.
The Valanginian to Barremian Muderong Shale is a thick marine claystone
that is widespread across the Northern Carnarvon Basin, and acts as a
secondary seal to the Forestier Claystone. A basal sandstone unit may be
considered equivalent to the Mardie Greensand Member, present in the
southern sub-basins.
The upper Lower Cretaceous to Holocene section comprises claystone, marl
and calcilutite deposited on a prograding, increasingly carbonate-dominated,
open marine, passive ramp margin.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 6 of 24
EXPLORATION HISTORY
Exploration of the Beagle Sub-basin area began in 1965 with regional
seismic, gravity and magnetic surveys. Subsequent exploration led to the
drilling of 13 wildcat wells between 1971 and 1983. The wells tested a range
of plays, including uplifted Triassic–Jurassic fault blocks, anticlines and faultcontrolled structures down-dip of the main basin-margin fault. Drilling
confirmed the presence of a thick Upper Paleozoic–Cenozoic sedimentary
succession which contained prospective reservoir, source and seal units.
Despite several minor shows, no significant hydrocarbon discoveries resulted.
Only two wells were drilled in the sub-basin between 1983 and 1992
(Trafalgar 1 in 1988 and Aurora 1 in 1990), together with two wells along the
northern margin of the adjacent Dampier Sub-basin (Bounty 1 in 1983 and
Calypso 1 in 1985). However, no hydrocarbon shows were recorded in these
wells.
In the early 1990s, a third wave of exploration activity was initiated in the subbasin. Nebo 1 (1993) encountered thin oil-bearing sands in the Callovian
Calypso Formation (Figure 4), and was the first well to confirm the presence
of an active petroleum system in the Beagle Sub-basin (Osborne, 1994). In
1994–1995 the same joint-venture consortium drilled three unsuccessful wells
(Cimba 1, Darwin 1 and Halo 1).
To the south, within the northernmost Dampier Basin, Mutineer 1B discovered
oil in the Upper Jurassic Angel Formation, which encouraged further
exploration in the adjacent Beagle Sub-basin. Woodside subsequently drilled
four unsuccessful wells (Serval 1, Ermine 1, Grey Rabbit 1 and Tayra 1) in the
western-central sub-basin in 1999–2001, and IB Resources drilled two
unsuccessful wells (Manaslu 1 and Huascaran 1) in the central sub-basin in
2001–2002. Wigmore 1 (2002) was drilled by Kerr-McGee in the outer, deepwater, northwest portion of the sub-basin, and was also unsuccessful.
To the east of the Release Areas, within the Roebuck Basin, Whitetail 1
(2003) and Huntsman 1 (2006) (Figure 1) were drilled by Woodside Energy
Ltd to test Jurassic targets within structural highs. The wells were
unsuccessful and, at the time of writing, interpretive results for Huntsman 1
had not been released.
For the deepwater Exmouth Plateau, there have been two major exploration
campaigns: the first in 1979–1980 for oil targets; and the second, currently
underway, for gas. The initial exploration programs undertaken by Esso and
Phillips (Barber, 1988) began when no proven technology existed to develop
a deepwater oil field. Eleven deepwater (740–1375 m) wells were drilled by
the early 1980s (Walker, 2007) with the anticipation of oil charge from the
Upper Jurassic Dingo Claystone. A result of this campaign was the discovery
of a giant gas accumulation in a Lower Cretaceous Barrow Group basin floor
fan by the Scarborough 1 well. The Scarborough domal anticline, which was
generated by structural inversion in the Campanian, is approximately 350 km2
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 7 of 24
in area and contains reserves of about 8 Tcf of gas (BHP Billiton, 2008). At
the time of this discovery (i.e. 1979), the available technology and the
undeveloped LNG market made the remote, deepwater gas accumulation
uneconomic to develop. In this initial phase of exploration on the Exmouth
Plateau, gas was also discovered in Upper Triassic Mungaroo Formation
sandstones by the Jupiter 1 well, in a tilted fault block trap (approximately
0.15 Tcf; Walker, 2007).
After the 1979-1980 drilling campaign no further exploration on the deepwater
Exmouth Plateau was undertaken for over a decade. The second phase of
activity commenced in the mid-1990s with a focus on the established Triassic
fault block play along the eastern margin of the Exmouth Plateau, outboard of
the Rankin Trend. Activity returned to the central Exmouth Plateau in 1996
with the appraisal drilling of Scarborough 2 in Retention Lease WA-1-R, jointly
held by ExxonMobil and BHP Billiton. The largest discovery yet made on the
Exmouth Plateau is Io-Jansz, a super-giant gas field in a new play type drilled
in 2000 (Jenkins et al, 2003).
In 2003, BHP Billiton was awarded petroleum exploration permit WA-346-P,
adjoining the Scarborough retention lease to the north, and in 2004 it
undertook a 3D seismic survey over both areas. Thebe 1 (2007) was drilled
and is interpreted as a successful test of a Triassic fault block that may
contain 2-3 Tcf of gas (Journal of Petroleum Technology, 2007).
Market conditions have changed markedly since the first phase of exploration
on the Exmouth Plateau in the 1970s, with major gas contracts secured to
supply LNG to China, in addition to the established trade with Japan. An
indication of the viability of the deepwater frontier plays on the Exmouth
Plateau was the competitive bidding for the 2006 Release Areas, and the
entry of a number of new explorers, including Hess Corporation and OMV
Australia. For example, in 2007, Hess Corporation was awarded the
deepwater petroleum exploration permit WA-390-P, located southwest of the
super-giant Io-Jansz field, with an aggressive bid, including a 16 well drilling
commitment. Three of the four wells drilled in 2008 were gas discoveries in
the post-Callovian interval: Glencoe 1 intersected 28 m of net gas pay,
Briseis 1, 46 m and Nimblefoot 1, 28 m (Hess Corporation, 2008a, 2008b,
2008c). Briseis 1 had an additional pay zone in the Triassic Mungaroo
Formation (Smallwood et al, 2010). This initial success was followed by the
drilling of seven wells (Toporoa 1, Dunlop 1, Lightfinger 1, Bravo 1, Rimfire 1,
Mentorc 1 and Hijinx 1), in 2009, of which six were gas discoveries
(Jonasson, 2010). A twelfth well, Glenloth 1, was completed in 2010, and was
also a gas discovery (Jonasson and Mack, 2010).
Other recent giant gas finds have been made at Wheatstone and Pluto to the
east, Chandon to the northwest, and Martell 1 and Larsen Deep 1 (Woodside
Petroleum Ltd, 2009, 2010a) to the north, of the Io-Jansz field. Of further
significance is the discovery of a 185 m gross gas column within the Triassic
at Alaric 1 (Woodside Petroleum Ltd, 2010b), in the outermost southwestern
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 8 of 24
part of the Exmouth Plateau and, further inboard, a 273 m net gas column at
Acme 1 (Chevron Australia, 2010).
Well Control
Only Wigmore 1 has been drilled within the Release Areas (Figure 1), and no
accumulation of hydrocarbons was encountered. In the vicinity, however,
Nebo 1 is the only significant oil discovery within about 50 km with Phoenix 1,
a significant gas discovery, lying further to the southeast.
Other wells have been drilled near the Release Areas and provide significant
stratigraphic control. Along with Wigmore 1 and Nebo 1, Delambre 1,
Ermine 1, Manaslu 1, Grey Rabbit 1 and Darwin 1, all located to the south,
indicate a strong correlation to the stratigraphy of the remainder of the
Northern Carnarvon Basin. Whitetail 1, just to the east, also indicates the
presence of Northern Carnarvon Basin type Upper Jurassic (i.e. Legendre
Formation) to Holocene sedimentary sequences. ODP Leg 122 wells (Haq et
al, 1990; von Rad et al, 1992a), on the Wombat Plateau to the west, confirm
the northernmost extent of the Triassic Mungaroo Formation and Brigadier
Formation type sediments.
Delambre 1 (1980)
Delambre 1 was drilled by Woodside Petroleum Development Pty Ltd in water
depths of 884 m in permit WA-90-P. It was designed to test both Middle
Jurassic sandstones, sealed by Middle Jurassic and Lower Cretaceous
claystones, and Lower Jurassic to Triassic sandstones, sealed by Lower
Jurassic claystones, over a large north-trending horst (i.e. the northeasttrending “Brigadier Trend”). The well reached a total depth of 5495 mRT
within a thick Upper Triassic section of claystones, sandstones and siltstones.
The well was a valid test of structure with both reservoir and sealing
objectives confirmed, but no significant hydrocarbons were encountered.
However, solvent fluorescence was widespread in ditch cuttings and sidewall
cores taken throughout the Lower Jurassic to Triassic section.
Nebo 1 (1993)
Nebo 1 was drilled by Kufpec Australia Pty Ltd in water depths of 171 m in
permit WA-225-P. The well was designed to test sandstones of the Upper
Jurassic Angel and Middle Jurassic Legendre formations on the “Nebo High”,
a northwest-trending faulted anticline traversing the north- to northeasttrending Thouin Graben. The well reached a total depth of 3132 mRT within
Legendre Formation massive sandstones characterised by interbedded
claystones and thin coal seams.
The well was a valid test of structural closure. The trap structure was
developed through a combination of faulting during the Callovian breakup
event and arching associated with transcurrent motion during the Early
Cretaceous (Osborne, 1994). Intersected sandstones of the Legendre
Formation were permeable and porous, but the lack of shows was attributed
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 9 of 24
to the poor sealing qualities of the overlying Calypso Formation. The predicted
Angel Formation sandstones were not intersected.
The well is an oil discovery. Oil was recovered from thin sands within the
Callovian Calypso Formation. A total of 5.9 m of potential net oil pay was
interpreted in six discrete thin sands (17–26% average log porosity) over a
gross section of 33 m, below 2663 mRT. A drill stem test, perforated over the
best reservoir zone in the depth range 2664.5–2668 mRT, was carried out,
and the well flowed 42° API oil at a maximum flow rate of 1840 bopd
(293 m3/d) on a ½ inch (12 mm) choke.
Wigmore 1 (2002)
Wigmore 1 was drilled by Kerr-McGee NW Shelf Energy Australia Pty Ltd in
water depths of 1247 m in permit WA-295-P, in the northern Beagle Subbasin. The well was designed to test a fault-bounded structural closure for
sands within the primary objective, the Lower Jurassic North Rankin
Formation and the secondary objective, the Middle Jurassic Legendre
Formation. Structural closure was offset at both target levels necessitating a
deviated well trajectory. The well reached a total depth of 5395 mRT within
North Rankin Formation sandstones with minor interbedded claystone.
The well was a valid test of structural closure at both objective formations.
However, the Muderong Shale was found to be thinner than predicted,
suggesting a less than effective seal for the Legendre Formation target. In
addition, widespread porous sandy facies in the lower part of the Athol
Formation may have provided cross-fault seal failure for the North Rankin
Formation target sands within the drilled structure.
No significant hydrocarbons were encountered, nor was there any
fluorescence. No hydrocarbon charge into the structure was confirmed and
the absence of an effective petroleum system for the area was concluded.
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_ne exmouth plateau_AR11.xls
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 10 of 24
Data Coverage
The Release Areas are well covered by grids of regional 2D and more
focused 3D seismic surveys of varying orientations and vintages. Amongst the
earliest surveys in the broader region is the more inboard Montebello–
Mermaid Shoals M.S.S regional 2D grid acquired by B.O.C. Australia in 1965.
In contrast, the most recent seismic coverage is provided by PGS’s longoffset, widely spaced 2007 MC2D New Dawn survey (includes gravity and
magnetics; Petroleum Geo-Services Data Library, 2007), which covers a
broad swathe of the North West Shelf, including the Release Areas.
To highlight good quality 2D seismic coverage across the Release Areas, the
following major seismic surveys are noted: the Deep Water North West Shelf
Spec M.S.S. (acquired in 1998 by GHD-Gardline Surveys Pty Ltd) grid with
approximately 20 km line spacing; the Beagle Deep M.S.S (acquired in 1997
by Nopec International Pty Ltd) grid with approximately 10 km line spacing
across Release Area W11-9 and the southern halves of W11-7 and -8; and
the Tarantula 2D M.S.S. (acquired in 1999 by Woodside Energy Ltd) grid with
a variable 1-10 km line spacing across the eastern half of Release Areas
W11-8 and -9.
Apart from the PGS MC2D New Dawn survey, deep 2D seismic coverage
across the broader region is also provided by Geoscience Australia surveys
95, 110, 120, 128 and 136.
Two major 3D surveys were acquired across two of the Release Areas
(Figure 3): the Canning TQ3D M.S.S. (WesternGeco Multiclient Services,
1999) covers 4365 km2 over a large portion of the western half of Release
Area W11-9; and Woodside Energy’s 2001 Whitetail 3D M.S.S. covers
555 km2 along a portion of the eastern boundary of Release Areas W11-8 and
W11-9. These data sets are available through Geoscience Australia’s
Acreage Release Seismic Workstation Packages.
Various company open file seismic interpretation, well and destructive
analysis reports are available from Geoscience Australia or from Exploration
Data & Scanning Services.
In addition to commercial petroleum exploration efforts on the Exmouth
Plateau, there have also been scientific investigations by the Ocean Drilling
Program (ODP). In 1988, ODP Leg 122 (Haq et al, 1990) drilled four locations
on the Wombat Plateau (i.e. sites 759, 760, 761 and 764). Detailed
descriptions of the fully cored holes and the interpretation of the results are
given by von Rad et al (1992a). Related investigations include Williamson et
al (1989) and Exon and von Rad (1994).
A large amount of satellite-based Synthetic Aperture Radar (SAR) and
Airborne Laser Fluorosensor (ALF) data have been acquired across the
broader region. This data has been interpreted by O’Brien et al (2003).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 11 of 24
Interpretations constructed from earlier vintages of sparse deep seismic data,
are available as part of the North West Shelf Digital Atlas (2008).
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
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 12 of 24
PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL
Given the scarcity of well information within the wider area, Table 2 provides
a list of possible elements of petroleum systems within the Release Areas
(see lithostratigraphy in Figure 4).
Table 2: Petroleum Systems Elements Summary
Sources
Reservoirs
Seals
Play Types

Lower Cretaceous Muderong Shale (gas-prone).

Upper Jurassic to Lower Cretaceous post-breakup Dingo
and Forestier claystones (limited analysis – highly
condensed to absent).

Lower-Middle Jurassic Athol Formation (oil-prone).

Triassic Mungaroo Formation (gas-prone).

Lower Triassic Locker Shale (gas-prone).

Upper Jurassic Calypso Formation (marginal marine to
marine).

Middle Jurassic Legendre Formation (fluvio-deltaic to more
marginal marine in the north).

Triassic Mungaroo Formation (fluvio-deltaic).

Lower Cretaceous Muderong Shale/Forestier Claystone
(regional).

Middle Jurassic Calypso Formation (intra-formational).

Lower–Middle Jurassic Athol Formation (regional).

Triassic Cosssigny member of the Mungaroo Formation
(regional).

Tilted fault blocks, and associated strike-slip related
anticlines.

Upper Jurassic (post-breakup) basin-floor fan sands
downdip of horst flanks.
The giant Scarborough and Io-Jansz gas fields, along with the gas discoveries
at Jupiter 1, Chandon 1, Thebe 1 and 2, Martell 1, Larsen Deep 1 and
Alaric 1, demonstrate that the deepwater Exmouth Plateau is prospective for
large gas discoveries. The extension of this prospectivity further north, to the
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northern margin of the plateau, is yet to be demonstrated. However, several of
the key elements that combine to produce successful petroleum systems
further south also occur in the region of the Release Areas. For example,
ODP drilling on the Wombat Plateau has intersected a similar sedimentary
section to the petroliferous central Exmouth Plateau, such as Upper Triassic
fluvio-deltaic sandstones and coals (?Mungaroo Formation), which are
stratigraphic equivalents of the reservoir and source facies of the proven
deepwater giant gas plays further south. In addition, the wells to the south and
east (i.e. Wigmore 1, Delambre 1, Manaslu 1, Nebo 1, Darwin 1, Phoenix 1
and Whitetail 1) of the Release Areas indicate that similar Jurassic
sedimentation extends into this region, with the caveat that the region was
closer to the locus of structuring associated with Late Jurassic breakup.
For the Beagle Sub-basin, the discovery of oil in Calypso Formation sands at
Nebo 1 (Figure 4) demonstrated the presence of an active petroleum system
within the southern Thouin Graben. The well also confirmed adequate top
seal at the Breakup Unconformity, and suggested that down-dip potential
exists within the drilled structure. However, the subsequent failure of the two
nearby wells (i.e. Huascaran 1 and Halo 1) to encounter hydrocarbons
indicates risks associated with vertical and lateral migration, intraformational
seals within the Legendre and Calypso formations, reservoir sands, fault seal
and fault movement/reactivation timing, or adequate source rock quality and
distribution for effective regional charge. Furthermore, a palaeogeographic
study of the wider region (Stephenson et al, 1998) highlights the spatial and
temporal diversity of potential hydrocarbon targets, and suggests that oil at
Nebo 1 is possibly related more to a localised lacustrine source pod than to a
regional shale unit.
Source Rocks
In the wider region, the Lower Triassic Locker Shale was intersected at
Poissonnier 1 and Bruce 1, both at shallow depths along the Beagle Subbasin’s southern margin to the south of the Release Areas. Poor source
quality at Poissonnier 1 (Surdam and Warme, 1984) may, however, improve
in more outboard, more deeply buried areas, with the risk that the unit may be
overmature in the more deeply buried depocentres. Nevertheless, the region’s
troughs remain an important potential source kitchen. For example,
palaeogeographically-inferred lacustrine, fluvial and estuarine source rocks for
the Beagle Sub-basin, deposited in the Triassic to Middle Jurassic, are likely
to be oil-prone and, for example, to have sourced the oil at Nebo 1
(Stephenson et al, 1998).
Upper Triassic Mungaroo Formation claystones, intersected at Poissonnier 1
and Cossigny 1 to the south, have little or no source potential. However,
source quality for the formation is expected to improve in more outboard
areas. This may be analogous to the plateau setting further south where coaly
facies of the Mungaroo Formation are thought to have sourced significant gas
accumulations. Recent exploration activity there is based on models of gas
charge from deeply buried Mungaroo Formation coals and carbonaceous
claystones with peak generation interpreted to occur at depths greater than
2011 Release of Australian Offshore Petroleum Exploration Areas
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5 km (Bussell et al, 2001). Equivalent Carnian prodelta sediments intersected
on the Wombat Plateau had TOC values up to 2.5%, although they were
thermally immature (von Rad et al, 1992b).
Lower–Middle Jurassic Murat Siltstone and Athol Formation claystones at
Depuch 1, North Turtle 1 and Picard 1, all to the south, have good source
potential, and along with their thickness, distribution and inferred maturity
level, make these the prime potential source units for the Beagle Sub-basin
(Blevin et al, 1994). Wigmore 1 (Kerr-McGee NW Shelf Australia Energy Pty
Ltd, 2003) identified these units as gas prone and as being early to midmature. Expulsion and migration is likely to have occurred during the Late
Cretaceous and Cenozoic, although in more deeply buried depocentres
potential charge could predate emplacement of the sealing Lower Cretaceous
Muderong Shale/Forestier Claystone.
Oil recovered at Nebo 1 was sourced from either oil-prone deltaic coals or
lacustrine mudstones of presumed Early–Middle Jurassic age, and does not
show a generic affinity with any oil from the nearby Dampier Sub-basin or
greater North West Shelf (Edwards and Zumberge, 2005). A source rock
extract of Pliensbachian shale (TOC = 4.6%) from 3840–3850 m in Picard 1
(“Picard Shale”; Murat Siltstone equivalent) is reported to have a similar
biomarker character to that of the Nebo 1 oil (Geotech, 1994; Scott and
Hartung-Kagi, 1998). Partridge (1988) argued, however, that this shale unit
was deposited in a restricted marine environment.
The post-breakup Upper Jurassic to Lower Cretaceous marine organic-rich
sediments (Dingo/Forestier claystones) are a major source within the Dampier
Sub-basin to the south. Seismic mapping suggests a wide distribution but of
thinner development northwards (Figure 5 and Figure 6). The organic-rich
Dingo Claystone has not been sampled by wells (see Darwin 1 WCR (Apache
Oil Australia Pty Ltd, 1995) where a possible very thin unit is inferred) and,
therefore, may be absent. Also, geochemical analyses are limited across the
region’s wells (Blevin et al, 1994). However, a condensed section of the Dingo
Claystone and thicker Forestier Claystone my be present in the deeper
adjoining depocentres and, if buried deeply enough, may have generative
potential.
The Lower Cretaceous Muderong Shale has fair to good TOC and is generally
immature, but may be more mature within the Beagle Sub-basin depocentres
(Blevin et al, 1993b).
Reservoirs
Good to excellent quality potential reservoirs occur at several levels, including
the Triassic Mungaroo Formation (e.g. 10-20% porosity in Norian-Carnian
ditch cuttings in Delambre 1) and Middle Jurassic Legendre Formation sands
(e.g. Darwin 1, Ermine 1, Grey Rabbit 1 and Wigmore 1). Upper Jurassic
reservoirs are at risk of having been eroded, or not deposited, on the
structural highs (e.g. Dampier Sub-basin reservoir Angel Formation absent at
Nebo 1 and very thin at Bligh 1 further to the south). A secondary potential
2011 Release of Australian Offshore Petroleum Exploration Areas
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reservoir is the post-breakup Callovian Calypso Formation (e.g. Nebo 1 and
Darwin 1), although it too may be absent on structural highs due to erosion at
the Valanginian Breakup Unconformity. Both the Lower Jurassic-Upper
Triassic North Rankin and Brigadier formations are inferred to be of good
reservoir quality, although the former was found to be silt-prone at Wigmore 1.
Seals
Regional seals are provided by the Lower Triassic Locker Shale, Middle
Triassic Cossigny Member of the Mungaroo Formation (e.g. Phoenix 1),
Lower–Middle Jurassic Athol Formation (e.g. Wigmore 1) and the Lower
Cretaceous Forestier Claystone and Muderong Shale (e.g. Delambre 1). Intraformational seals occur within the Middle Jurassic Legendre Formation and
the Callovian Calypso Formation (e.g. Nebo 1).
Play Types
Dominant play types for the northeast Exmouth Plateau area are tilted faultbounded sequences within, and along, Triassic-Jurassic horsts, as well as the
possibility of post-breakup Upper Jurassic basin-floor fan sands (e.g. Dampier
Sub-basin Angel Formation equivalent), along their flanks. Structural highs
hosting Upper Jurassic reservoir sands are also a proven play type developed
within the intervening troughs (e.g. Nebo 1 within the Thouin Graben). The
regionally extensive Lower Cretaceous Muderong Shale/Forestier Claystone
could act as the main sealing facies if of sufficient thickness.
For the Beagle Sub-basin, company seismic interpretation reports have
identified various leads and prospects. These reports include: Marathon
Petroleum’s Angel and Boronia surveys (1982 and 1983 respectively); Lasmo
Energy’s Erica and Honorine surveys (1985 and 1986 respectively); Ampol
Exploration’s Katrina survey (1989); Premier Oil’s Cocker survey (1998);
Kufpec Australia’s Mahakan and Mohaku surveys (1992 and 1993
respectively); and Woodside Petroleum’s Reynard and Remus surveys
(1999). The structure contour maps highlight the complex nature of faulting
and associated structural closures at various levels, although the fidelity of the
contouring has been flagged as an issue given the likely strike-slip component
of the faulting.
Reefal stratigraphic traps, such as porous patch reefs laterally sealed by finegrained lagoonal facies, provide another play type, as described by
Williamson et al (1989) for the Wombat Plateau.
An assessment of play types in basins with a strong strike-slip component to
faulting should consider Riedel-shear related faulting and folding, resulting
from differential movements within and around fault complexes, and the
possibility of secondary shallow hydrocarbon entrapment from primary, more
deeply breached traps (Chen et al, 2010).
Critical Risks
The discovery of a small oil accumulation at Nebo 1 proves the existence of
an active petroleum system within the region, though it may be locally
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 16 of 24
restricted. The general absence of significant hydrocarbon shows across the
region’s wells, within the Middle to Upper Jurassic, is possibly a consequence
of the lack, or thin development, of adequate regional-scale source rocks,
particularly of the post-breakup shales (i.e. Dingo and Forestier claystones),
which results in a high charge risk. However, this is unlikely to be the case
with the deeper, extensive Triassic source units.
Fault-trap breaching of seals by late-stage faulting and inadequate migration
pathways have been suggested to explain several well failures (Blevin et al,
1993b, 1994). The likely effects of oblique extension leading to Callovian
breakup, and later re-activation due to Valanginian breakup, in terms of the
horst-graben architecture and bounding fault style, raises complexities in trap
development and preservation as a significant risk. Typical extensional horstand-graben rift-related play concepts developed for the Dampier Sub-basin
are unlikely to extend northwards without considerable modification.
Furthermore, regional reactivation of faulting during the Miocene might have
also affected trap integrity, as well as the shape of existing structures. The
nature of fault movement and fault orientations suggests that migration
pathways that use fault conduits would be complex (Blevin et al, 1994).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
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Release Area Geology
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FIGURES
Figure 1:
Location map of Release Areas W11-7, W11-8 and W11-9,
showing existing petroleum permits, oil and gas fields, wells
and pipelines.
Figure 2:
Graticular block map and graticular block listings for Release
Areas W11-7, W11-8 and W11-9.
Figure 3:
Structural elements of the northeastern Exmouth Plateau
region, also showing Release Areas, AGSO regional deepseismic lines (see Figure 5 and Figure 6), oil and gas fields
and the outline of relevant 3D seismic grids. The more detailed
mapping within the Beagle Sub-basin (i.e. yellow horsts) is
based on the work of Blevin et al (1994).
Figure 4:
Generalised stratigraphy of the northeastern Exmouth Plateau,
based on the Northern Carnarvon Basin Biozonation and
Stratigraphy Chart (Nicole et al , 2010. Geoloci Time Scale
after Gradstein et al (2004) and Ogg et al (2008).
Figure 5:
AGSO regional deep-seismic line 120/14 across the outer
Beagle Sub-basin into the northeastern Exmouth Plateau (see
Figure 3 for location).
Figure 6:
AGSO regional deep-seismic line 128/10 across the Swan
Canyon of the northeastern Exmouth Plateau (see Figure 3 for
location).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 18 of 24
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WOODSIDE PETROLEUM LTD., 2010b——[Web page] ASX Announcement
Gas Discovery at Alaric http://www.woodside.com.au/NR/rdonlyres/790138434776-41C0-B31B-920630672289/0/ASX036GasDiscoveryatAlaric.pdf (last
accessed 1 December 2010).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 23 of 24
Front page image courtesy of Petroleum Geo-Services.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas W11-7, W11-8 and W11-9, Northeastern Exmouth Plateau,
Northern Carnarvon Basin, Western Australia
Release Area Geology
Page 24 of 24