PETROLEUM GEOLOGICAL SUMMARY
RELEASE AREA T12-2
SANDY CAPE AND STRAHAN SUB-BASINS,
SORELL BASIN, TASMANIA
HIGHLIGHTS

Under-explored frontier Cretaceous–Cenozoic basin

Shallow to ultra deep water depths 50–3,000 m

Sub-basins contain up to 6.5 km of sediment with a variety of untested Cretaceous plays

Traces of free oil and minor gas indications encountered in Cape Sorell 1
Release Area T12-2 is located over the Sandy Cape and Strahan sub-basins of the Sorell Basin, in
water depths ranging from 50 to 3000 m. The Sorell Basin is contiguous with the Otway Basin to
the north and the basins have a similar geologic history and stratigraphy. The complex structural
and depositional history of the Sorell Basin reflects its location at the transition from a divergent
rifted margin to a transform continental margin. Release Area T12-2 is covered by extensive open
file 2D seismic and magnetic data.
LOCATION
Release Area T12-2 (Figure 1) is situated over the Sandy Cape and Strahan sub-basins of the
Sorell Basin, offshore western Tasmania. The Release Area covers an area of approximately
15,130 km2 and comprises 245 graticular blocks (Figure 2). It is located along the continental shelf
and slope in water depths ranging from approximately 50 m to 3,000 m on the western margin of
the Release Area. The Release Area is approximately 185 km from north to south, its northern
margin is approximately 350 km from Melbourne and its southern margin is approximately 350 km
from Hobart. Petroleum exploration permit T/32P adjoins T12-2 on the western half of its northern
boundary.
The graticular block map and graticular block listing for the Release Area are shown in Figure 2.
RELEASE AREA GEOLOGY
Release Area T12-2 overlies the Sandy Cape and Strahan sub-basins of the Sorell Basin which are
located along the continental margin, offshore western Tasmania (Figure 1). The Sorell Basin is
one of the easternmost elements of the Southern Rift System (Stagg et al, 1990; Willcox and Stagg,
1990), a major Jurassic-Early Cretaceous rift system that extends along the Australia’s southern
margin. While the Sorell Basin shares a similar stratigraphy with the adjacent Otway Basin, a key
difference from the latter is its dominantly transtensional tectonic setting. The basin has an elongate
geometry, its north-northwest orientation controlled by the direction of Australian–Antarctic rifting
and a strong N–S oriented pre-existing basement fabric (Gibson et al, 2011, in press).
Local tectonic setting
The tectonostratigraphic development of the Sorell Basin has been discussed in detail by many
authors (Moore, 1991, Moore et al, 1992; Conolly and Galloway, 1995; Hill et al, 1997, 2000;
Boreham et al, 2002; O’Brien et al, 2004, Gibson et al, 2011, in press). It is an elongate NW–SE to
N–S oriented transtensional basin that consists of several distinct sub-basins (Figure 3). Release
Area T12-2 is located over the Sandy Cape and Strahan sub-basins. Differences in the architecture
and depositional history of these sub-basins can be attributed to the response of the pre-existing
basement fabric to the evolution of rifting (Gibson et al, 2011, in press).
The Sandy Cape Sub-basin is located offshore southwest of King Island and west of northern
Tasmania. It is separated from the King Island Sub-basin to the east by the Clam High, which is
oriented parallel to the northwest Tasmanian coast. The sub-basin extends for approximately
120 km along the margin. In the northwest part of Release Area T12-2, where it abuts exploration
area T/32P, the main depocentre is developed west of the north-south oriented Avoca-Sorell Fault
system and contains up to 4.0 s (TWT) of fill (Gibson et. al, 2011). To the south, the basin steps to
the east-southeast up across a series of faults. Here, a second depocentre, containing a
sedimentary succession greater than 3.0 s (TWT) thick, is present in the vicinity and to the south of
Jarver 1 well (Figure 1).
Structurally, the Sandy Cape Sub-basin is a north-northwest trending depocentre. Deposition was
constrained by half-graben bounding faults and locally, antithetic faults. Cretaceous sedimentation
(Figure 4) was generally focused outboard (west) of the Avoca-Sorell Fault System, or inboard in
smaller perched half-graben. Cenozoic post-rift fill (Figure 4) is relatively undeformed (Figure 5) and
commonly overlies and onlaps pre-rift basement, which consists of metamorphosed sediments.
The Strahan Sub-basin contains up to 4.5 s (TWT) (Figure 3) of sediments and is located west of
Strahan in shelfal to lower slope depths. Cretaceous to early Cenozoic sedimentation (Figure 4)
was largely constrained by a large (40-50 km) arcuate fault system that forms the northern and
eastern boundaries of the sub-basin (Figure 3). Growth wedges have been imaged seismically on
the south-dipping and west-dipping faults (Figure 6). This fault system and the half-graben fill are
interpreted to have formed in a N–S oriented transtensional or strike-slip stress regime. The
northern, east–west striking fault segment has a releasing bend, pull-apart geometry, whereas the
north-northwest–south-southeast oriented eastern fault segment appears to have formed in
response to the extensional component of the stress regime. The half-graben fill controlled by these
structures comprises a thick ?Lower Cretaceous to Paleocene succession. The overlying post-rift
Cenozoic section is relatively undeformed, commonly overlying or onlapping pre-rift basement,
which comprises metamorphosed sediments.
Interpreted chronostratigraphic horizons for industry seismic lines which intersect key wells in
Release Area T12-2 are shown in Figure 5 and Figure 6.
Structural evolution and depositional history of the area
The Otway sequence stratigraphy has been adopted for the Sorell Basin as it is contiguous with the
Otway Basin (Conolly and Galloway, 1995; Hill et al, 1997); however, initial rifting in the Sorell
Basin is interpreted to have commenced no earlier than the Early Cretaceous. Lower Cretaceous
rocks of the Otway Group equivalent (Crayfish and Eumeralla supersequences; Figure 4) have not
been intersected by drilling but are interpreted on seismic data. In the Sandy Cape Sub-basin, the
Lower Cretaceous succession unconformably overlies basement and commonly displays a halfgraben wedge geometry overlain by post-rift fill. The half graben are mostly located basinward of
the Avoca-Sorell Fault. By analogy with the Otway Basin, deposition is interpreted to have taken
place in fluvial and lacusturine environments. In the Strahan Sub-basin, the basal part of the rift
section is assigned to the Lower Cretaceous Crayfish and Eumeralla supersequences (Figure 4).
Initial deposition appears to have been controlled by the northern bounding fault, with subsequent
strata showing growth into both the east–west and north-northwest–south-southeast oriented
bounding faults. The sub-basin exhibits the characteristic structural style of a strike-slip stepover
basin caused by sinistral strike-slip rifting of Australia and Antarctica.
Regional Cenomanian inversion affected most of the Otway Basin (Norvick and Smith, 2001;
Krassay et al, 2004). In the Sandy Cape Sub-basin, this event gave rise to small rollover anticlines
caused by reverse movement on half-graben bounding faults west of the Avoca-Sorell Fault.
However, in the Strahan Sub-basin, no inversion event can be seen in the seismic record and rifting
was continuous (Figure 6).
Resumption of rifting in the Sandy Cape Sub-basin during the Cenomanian to Maastrichtian (Hill et
al, 1997) saw continued deposition of the Shipwreck and Sherbrook supersequences. Fluvio-deltaic
lowstand sediments of the Shipwreck Supersequence occur at the base of Jarver 1, where they
unconformably overlie basement (Figure 5). Outboard of the Avoca Sorell Fault, in the Sandy Cape
Sub-basin, and below Cape Sorell 1 in the Strahan Sub-basin, Shipwreck Supersequence
sediments unconformably overlie the Lower Cretaceous succession. To the east of the Release
Area, in the King Island Sub-basin, Clam 1 intersected fluvial to shallow marine sediments of this
age.
Sherbrook Supersequence have been intersected by drilling in both sub-basins. Shallow to
marginal marine conglomerates and sandy shales occur at the base of Cape Sorell 1 and fluviodeltaic, coarse grained sandstones in Jarver 1. In the Sandy Cape Sub-basin, the succession
exhibits a sag geometry (Figure 5), whereas in the Strahan Sub-basin seismically imaged growth
wedges indicate extension continues into the Cenozoic (Figure 6).
Regionally, the base of the Cenozoic is marked by uplift and erosion. It is expressed as a significant
unconformity in the Otway and northern Sorell basins, which was followed by a prolonged period of
subsidence. This geometry can be seen in the Sandy Cape Sub-basin (Figure 5), but in the Strahan
Sub-basin, half-graben growth wedges indicate that extension continued up until the beginning of
the Eocene, at which time a local inversion event occurred (Figure 6). The structural history seen in
the Strahan Sub-basin is consistent with continuation of a transtensional regime inboard of the
developing transform margin. The Eocene inversion event may be related to the proximity, and
passing, of the spreading ridge at this time.
There is some debate about the timing of Australian–Antarctic clearance and establishment of an
open seaway between the continents, ranging from 43 Ma (Holford et. al, 2011, Norvick and Smith
2001) or 41-42 Ma (Wei, 2004), to 33.7 Ma (Exon et al, 2001). The Eocene to Holocene section in
this area consists of an aggradational to progradational marine succession. Shallow-marine
sandstones, marls and limestones of Nirranda Group are truncated by a major mid-Oligocene
unconformity and overlain by upper Oligocene and younger shelfal marls and limestones of the
Heytesbury Group.
From the late Oligocene to Pleistocene, open marine conditions prevailed in the Southern Ocean
and Tasman Sea, with sedimentation on the continental margins largely controlled by global sealevel fluctuations, sediment supply, waning rates of post-rift subsistence, and far-field tectonic
events such as Miocene inversion (Boreham et al, 2002).
EXPLORATION HISTORY
The exploration history of the Sorell Basin has been reported by numerous authors (e.g. Hill et al,
1997; Lodwick et al, 1999) and succinctly summarised by O’Brien et al (2004).
The Sorell Basin is one of the least explored of the major southeast Australian offshore sedimentary
basins. The focus of exploration has been on the northern sub-basins, where three petroleum
exploration wells have been drilled.
Petroleum exploration began in the late 1960s, when Esso Exploration and Production Australia
(Esso) and Magellan Petroleum Australia (Magellan) obtained reconnaissance seismic data on the
west Tasmanian margin. During this time, Esso drilled three wells: Clam 1 (1969) was drilled in the
King Island Sub-basin while Prawn A1 (1967) and Whelk 1 (1970) were drilled in the adjacent and
contiguous Otway Basin to the northwest. All wells were dry and were plugged and abandoned.
Clam 1 tested structural closure at the basal Cenozoic level and the up-dip pinchout of Cretaceous
sediments against a large basement high at the western flank of the King Island Sub-basin.
Although good reservoir sands were intersected, no hydrocarbons were encountered
The Bureau of Mineral Resources, Geology and Geophysics (BMR) and Shell International
conducted regional reconnaissance seismic surveys along the western margin of Tasmania during
1972 and 1973, respectively. Together with the existing Esso data, these seismic surveys provided
the broad framework for mapping the geology and structure of the northern Sorell Basin.
In 1981, Amoco Australia Petroleum Company (Amoco) carried out a seismic survey in the Strahan
Sub-basin, followed by the drilling of Cape Sorell 1 in 1982. This well tested a rollover structure and
recorded minor amounts of free oil and residual oil traces, despite being drilled off structure (Amoco
Australia Petroleum Company, 1982).
In the middle to late 1980s, a number of government regional surveys were conducted over the
Sorell Basin (1985/Sonne Survey 36, 1987/Geoscience Australia Survey 48, and 1988/Geoscience
Australia Survey 78). These surveys collected multichannel seismic data, dredge samples and seafloor cores; some of the sea-floor sediment samples were interpreted to contain thermogenic gas
(Exon et al, 1989; Hinz et al, 1986, 1990).
In 1990, Maxus Energy Corporation (Maxus) acquired a dense seismic grid in the Strahan Subbasin. Although Maxus (1993) identified a number of drilling prospects, it failed to attract farm-in
partners and the permit was relinquished. Roma Petroleum NL (Roma) operated this area as T/31P
from 1999 to 2002. Roma reprocessed and re-mapped some existing data, but also failed to attract
farm-in partners.
Multi-beam swath mapping of the seabed was carried out by the Australian Geological Survey
Organisation (AGSO; now Geoscience Australia (GA)) in 1994 (Exon et al, 1994), followed by
regional seismic surveys (Survey 148 and Survey 159) in 1995 and 1996, respectively. In early
2000, AGSO undertook sea floor swath mapping and seismic reflection profiling along the upper
continental slope using the RV Atalante (Austrea 1; Hill et al, 2000).
In 2001 Seismic Australia and Fugro-Geoteam AS acquired 3,612 line-km of non-exclusive seismic
data (ds01 survey) over the deep water Otway and northern Sorell basins. Santos had a major
presence in the basin from 2002 operating permits T/32P, T/33P, T/36P and T/48P all of which
have been relinquished with the exception of T/32P, where the Santos share was taken over by
Perenco (SE Australia) Pty Ltd in 2010. During this phase of exploration, Santos reprocessed the
Maxus seismic and acquired a 2D infill and a 3D survey over the Strahan Sub-basin as well as
acquiring several 2D infill surveys over the Sandy Cape Sub-basin. The only permit currently
operating in the Release Area is T/32P, where Perenco acquired 1,000 km2 of 3D seismic over the
Wolseley prospect in early 2011.
Well control
CAPE SORELL 1 (1982)
Cape Sorell 1 was drilled in 94 m of water in the Strahan Sub-basin by Amoco Australia Petroleum
Company (1982). The well reached a total depth of 3,528 mKB and was drilled to determine the
presence of equivalents to the Upper Cretaceous Waarre Formation and Lower Cretaceous Pretty
Hill Formation, which are prospective in the adjacent Otway Basin. The well targeted a structure
with mapped areal closure of approximately 77 km2 and 120–250 m of vertical closure at the Upper
and Lower Cretaceous levels.
The stratigraphic section encountered was much younger than anticipated with the oldest rocks
found to be of early Paleocene to Late Cretaceous age. No shows were recorded in the well,
however traces of free oil were identified in the Maastrichtian section below 3000 m, and several
minor gas indications were also recorded. Log analyses revealed several clean reservoir intervals
were intersected, however these were water saturated and unproductive. The well was plugged and
abandoned as a dry hole.
JARVER 1 (2008)
Jarver 1 was drilled in 567 m of water in the Sandy Cape Sub-basin by Santos Limited (2008). It
was drilled to test the Upper Cretaceous play that has been proven in the Thylacine and Geographe
fields that lie to the north in the Shipwreck Trough (Otway Basin). The Jarver prospect is a
moderate relief 4-way dip closure defined by elevated amplitude. Thylacine Member equivalent
sandstones sealed by the Belfast Mudstone equivalent were the primary target. The secondary
target was Paaratte Formation equivalent sandstones sealed by intraformational shale. The well
was drilled to a total depth of 3,062 mRT, penetrating the entire Sorell Basin succession and
intersecting approximately 38 m of basement. The well intersected the predicted succession and
was plugged and abandoned. Interpretative data for this well is currently confidential.
Further details regarding wells and available data follow this link:
http://www.ret.gov.au/Documents/par/data/documents/Data%20list/data%20list_sorell_AR12.xls
Data coverage
Seismic coverage in the Sorell Basin is a mixture of government and industry grids. Release Area
T12-2 is well covered by a mixture of regional industry 2D grids, 2D infill grids and a recent 3D
survey in the Strahan Sub-basin (Santos Australia Limited, 2008). In comparison, seismic coverage
south of the Strahan Sub-basin is extremely sparse. Several potential field datasets are available
for the area. Gravity data has mostly been acquired in conjunction with seismic surveys and, as
with the seismic coverage, becomes sparse towards the south of the basin. Over 70,000 line km of
new aeromagnetic data was acquired by Geoscience Australia and Mineral Resources Tasmania
(MRT) over the West Tasmanian Margin in 2008 (Morse et al, 2009). These data were merged with
onshore aeromagnetic datasets to create a near continuous coverage of southeastern Australia
(Morse et al, 2009).
To view image of seismic coverage follow this link:
http://www.ga.gov.au/energy/projects/acreage-release-and-promotion/2012.html#data-packages
PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL
Sources
Lower Maastrichtian fluvio-deltaic to marine mudstone and shale: Austral 3
?Turonian basal coals: Austral 3
Aptian–Albian fluvio–lacusturine shale and coal: Austral 2
Latest Jurassic–Barremian fluvio–lacusturine shale: Austral 1
Reservoirs
Sandy Cape Sub-basin: Waarre Sandstone equivalent, the Thylacine Member
equivalent at the base of the Sherbrook Group and sandstones in the Nirranda
and Wangerrip group
Strahan Sub-basin: Interbedded sandstones in the lower Wangerrip Group.
Sherbrook Group sandstones basinward of major boundary faults
Seals
Sandy Cape Sub-basin: Upper Cretaceous claystones and siltstones (Shipwreck
and Sherbrook supersequences). Marls and fine-grained limestones in the
Oligocene–Holocene Heytesbury Group
Strahan Sub-basin: Intraformational seals formed by shale and mudstone
interbeds in the Wangerrip and Sherbrook Groups. Marls and fine-grained
limestones in the Heytesbury Group
Play Types
Sandy Cape Sub-basin: High-side fault traps and faulted anticlines containing
Waarre and Sherbrook Group reservoirs. Channel-fill in Paleocene-lower Eocene
canyons.
Strahan Sub-basin: High-side fault block traps containing Sherbrook (Waarre
Formation) and Wangerrip group reservoirs and pinch-outs along the western
edge of the sub-basin. Other potential traps include rollover closures in
association with major faults and drape anticlines over canyons and fault blocks in
the Wangerrip Group sand channel-fill in Paleocene-lower Eocene canyons.
Source Rocks
Recent seismic interpretation by GA indicate the depositional sequences hosting active Austral 1,
2 and 3 petroleum systems in the producing areas of the Otway Basin are also likely to be present
in parts of the southern Otway and Sorell basins (Stacey et al, in prep). Potential source rocks of
uppermost Jurassic–Lower Cretaceous Austral 1 petroleum system comprise fluvio–lacustrine
shales of the Crayfish Supersequence. The Austral 2 petroleum system contains potential source
rocks of the Lower Cretaceous Eumeralla Supersequence deposited in fluvio–lacustrine
environments, typically comprising Type III kerogen, while the Austral 3 petroleum system refers to
potential source rocks of the Upper Cretaceous Shipwreck and Sherbrook supersequences
deposited in fluvio-deltaic to marine environments.
In the Strahan Sub-basin, lower Maastrichtian (Austral 3) potential source rocks were intersected in
Cape Sorell 1 in intercalated sandstones and shales of the lower Sherbrook Supersequence over a
depth interval of 3,120-3,250 m. Measured Total Organic Carbon (TOC) ranging from less than 1%
to 18.6% and Hydrogen Index (HI) values indicative of Type II/III and Type III kerogen, suggest
good potential for both oil and gas (Lodwick et al, 1999; Boreham et al, 2002). The maturity of these
lower Maastrichtian potential source rocks has been assessed as marginally mature to the
beginning of the oil window by Boreham et al (2002), and immature to marginally mature by Stacey
et al (in prep) (Figure 7). Cape Sorell 1 was not deep enough to intersect potential source rocks of
the Austral 1 and 2 petroleum systems, however modelling for the Strahan Sub-basin indicates that
if these source rocks are present they are gas to oil mature in the main half-graben (Stacey et al, in
prep). Minor amounts of free oil were recorded in the sandstone and claystone intervals of the
Sherbrook Group in Cape Sorell 1. Whether the oil was generated locally or from deeper
Sherbrook or Otway Groups is uncertain, but its presence is encouraging evidence of an active
Cretaceous petroleum system in the Strahan Sub-basin (Boreham et al, 2002).
Petroleum systems modelling by GA of seismic line ss04-001 in the Strahan Sub-basin (Stacey et
al, in prep) revealed that, if source rocks are present at the predicted levels, generation and
expulsion would have occurred from the Late Cretaceous onwards for Austral 1 and 2 system
sources, and from the Paleocene for Austral 3 sources. All generation and expulsion had probably
ceased by the Eocene. A proportion of accumulated hydrocarbons are likely to have been lost as a
result of the Paleocene/Eocene uplift and erosion. However, migration, remigration and
accumulation may have continued throughout the Cenozoic.
Little is known about potential source rocks in the Sandy Cape Sub-basin. The only well drilled in
the sub-basin (Jarver 1) terminated in basement overlain by the Waarre Formation equivalent.
Recent seismic interpretation by Geoscience Australia show the sequences that would likely host
any Austral 1, 2 and 3 potential source rocks, onlap or drape the basement high extending south
from King Island (King Island High). As a result, the Upper Cretaceous sequences in the east of the
Release Area thin across the high, while the Lower Cretaceous sequences are either poorly
developed or absent. Source rocks are likely to be better developed to the west of the King Island
High in the deep water where the succession thickens.
Reservoirs
In the offshore Otway Basin, the primary reservoirs are the sandstones of the Pretty Hill Formation
in the Otway Group (Crayfish Supersequence), the Waarre Sandstone, the Flaxman Formation and
a sandy facies (Thylacine Member) at the base of the Belfast Mudstone (Shipwreck
Supersequence) and sandstones in the Wangerrip Group (Wangerrip Supersequence) (Lodwick et
al, 1999). The stratigraphic equivalents of these units have been interpreted and mapped into the
Sorell Basin (Stacey et al, in prep).
The only well in the Strahan Sub-basin, Cape Sorell 1, intersected a generally sandy section with
few potential seals. However, due to the well’s proximity to the basin boundary fault, the
stratigraphy is unlikely to be representative of the rest of the sub-basin. Porosity in the Wangerrip
Group from 370–1,230 m are very high (30%+), but the lack of seal limits their reservoir potential
(Conolly and Galloway, 1995). Interbedded sandstones lower in the Wangerrip Group (~1,250–
1,480 m) have excellent reservoir potential with porosity ranging from 20–30%. Porosity decreases
with depth, falling to <15% below 3,050 m in the Sherbrook Group near the base of the well.
Towards the west, away from the boundary faults it has been postulated that the Sherbrook Group
sands become more deltaic to marine and could be winnowed and better sorted, improving their
reservoir potential.
In the Sandy Cape Sub-basin, the Paleogene succession (Wangerrip and Nirranda groups) in
Jarver 1 was also sandy. The Upper Cretaceous succession (Sherbrook Group) below about
1,500 m comprises interbeded sandstone, siltstone and claystone with siltstone and claystone
dominating below 1,760 m (Santos Limited, 2008). Potential reservoirs are the Waarre Sandstone
equivalent, the Thylacine Member at the base of the Sherbrook Group and sandstones in the
Nirranda and Wangerrip groups. Petroleum systems modelling of seismic line ds01-126 (Stacey et
al, in prep) north of the Release Area predicts porosity values for the Waarre Sandstone reservoir
ranging from 20 and 25% on the platform, 10-18% on the terrace, and only 6-11% in the main part
of the basin, while porosity values in the Wangerrip Group are likely to be higher than 15%
throughout.
In summary, the best reservoir targets in the Sorell Basin are likely to be Eocene and Paleocene
sandstones of the Wangerrip Group (Wangerrip Supersequence) and, away from boundary fault,
Upper Cretaceous sandstones and possible conglomeratic sandstones of the Sherbrook Group
(Shipwreck and Sherbrook supersequences). In wells drilled on the flanks of the sub-basins, the
dominantly sandy Sorell Basin succession lacks the mudstones that seal and separate sandstone
reservoirs of the Otway Basin (Lodwick et al, 1999). However, such sequences may be better
developed to the west, away from the flanks of the sub-basins.
Seals
The sedimentary succession in wells drilled proximal to the inner margin of the basin is
predominantly sandy, prompting suggestions that the Sorell Basin lacks the thick, regional top seal
provided by the Belfast Mudstone in the adjacent Otway Basin. The assertion that the basin
becomes more shale-prone seaward, is demonstrated by Jarver 1, which was drilled in 2008. This
well, located further offshore in the Sandy Cape Sub-basin, encountered over 1,300 m of Upper
Cretaceous claystones and siltstones. These rocks belong to the Shipwreck and Sherbrook
supersequences, which can be mapped seismically for a considerable distance seaward of the well.
This thick, laterally continuous interval would provide an excellent regional seal for any hydrocarbon
accumulation within Waarre Sandstone, Flaxman Formation or Thylacine Member reservoirs. The
marls and fine-grained limestone in the Heytesbury Group could also provide seals to Nirranda and
Wangerrip group reservoirs.
In the Strahan Sub-basin, shaly interbeds up to 20 m thick in the Wangerrip Group in Cape Sorell 1
indicate potential intraformational seal development near the sub-basin flanks. Basinward of the
well, a potential sealing facies in the Wangerrip Group may be formed by an Eocene flooding
surface overlain by downlapping progrades (O’Brien et al, 2004). This surface is can be seen in
seismic from the sub-basins flanks to the modern shelf break.
As in the Sandy Cape Sub-basin, facies in the Strahan Sub-basin are expected to become more
shale-prone basinward. The relatively thin marls and fine-grained limestones in the Neogene
Heytesbury Group could also be potential seals. Permeability barriers may also exist in carbonates
and sandstones and at unconformities which could provide stratigraphic traps if laterally continuous
(Lodwick et al, 1999).
Play types
In the Strahan Sub-basin, petroleum systems modelling suggests that migration pathways could
travel updip towards the western edge of the basin, where the most likely trap scenarios are highside fauilt blocks, stratigraphic pinch-outs and, to a lesser extent, small rollover anticlines with updip
closure (Stacey et al, in prep). Fault block traps are predicted in the basal Shipwreck
Supersequence (Waarre Formation) and at the base of the Wangerrip Group, charged by both
Austral 2 and 3 source rocks. A pinch-out play lies along the western edge of the sub-basin where
the sediments thin across the hinge of the half-graben; such stratigraphic traps are likely to be
charged by Austral 2 and 3 sources. Other potential traps in the sub-basin include rollover closures
associated with major bounding faults and drape anticlines over canyons and fault blocks in the
Wangerrip Group, while channel-fill in Paleocene-lower Eocene canyons may form substantial
stratigraphic traps.
The Sandy Cape Sub-basin partly underlies the continental shelf and attains a maximum
sedimentary thickness of over 5,000 m. Similar sediment thicknesses underlie large areas of the
continental slope in the southward deep water continuation of the adjacent Otway Basin (Nelson
Sub-basin). These continental slope depocentres represent a vast, downdip, kitchen area where, if
present, oil-prone Austral 3 source rocks are likely to be in the peak generation window (O’Brien et
al, 2004). Petroleum systems modelling of Austral 1, 2 and 3 source rocks north of the sub-basin
indicates accumulations are most likely developed in structural traps (high-side fault traps and
faulted anticlines) in the Waarre and Sherbrook Groups. The Paleocene-lower Eocene canyons
mapped in the Strahan Sub-basin also occur in the Sandy Cape Sub-basin, where they have the
potential to form substantial stratigraphic traps if suitable seals are present. The canyons may also
act as conduits for migrating hydrocarbons generated in the thick depocentres under the continental
slope.
Critical risks
The critical risks for Release Area T12-2 relate to the presence of source and seal, biodegradation
of shallow reservoirs and potential loss of hydrocarbons in association with Paleocene/Eocene uplift
and erosion. The Sorell Basin contains no proven petroleum systems and interpretation of their
presence is through analogy with the Otway Basin, and the Cape Sorell 1 shows. Potential source
rocks were intersected by Cape Sorell 1 and the presence of trace amounts free oil in the well is
encouraging evidence of an active Cretaceous petroleum system in the Strahan Sub-basin
(Boreham et al, 2002). Wells drilled on the inboard part of the shelf are dominated by sandstone
with no source and poor seal development. However, as Jarver 1 demonstrated, the more
basinward areas are likely to be marine and more shale-prone. Petroleum systems modelling
(Stacey et al, in prep) shows shallow reservoirs in the Wangerrip Group are at risk of
biodegradation when the temperature is below 80ºC.
FIGURES
Figure 1
Location of Release Area T12-2, in the Sandy Cape and Strahan sub-basins,
Sorell Basin.
Figure 2
Graticular block map and graticular block listings for Release Area T12-2.
Figure 3
Structural elements of the northern Sorell Basin and location of seismic sections
illustrated in Figure 5 and Figure 6. Also shown is sediment thickness in two-way
time (ms).
Figure 4
Stratigraphic succession in Sandy Cape and Strahan sub-basins.
Figure 5
Seismic line ds01-142x through Jarver 1, Sandy Cape Sub-basin. Location
shown in Figure 3
Figure 6
Seismic line ss04-001 through Cape Sorell 1, Strahan Sub-basin. Location
shown in Figure 3
Figure 7
Present-day modelled maturity along seismic line ss04-001, Strahan Sub-basin.
REFERENCES
AMOCO AUSTRALIA PETROLEUM COMPANY, 1982—Geological Completion Report, Cape
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