PETROLEUM GEOLOGICAL SUMMARY
RELEASE AREAS V11-3, V11-4, V11-5 AND V11-6,
GIPPSLAND BASIN,
VICTORIA
Bids Close – 13 October 2011

Located in a world-class petroleum province with remaining reserves
estimated at 400 MMstb oil and 6 Tcf gas, with 2-4 Tcf of gas and up to
600 MMstb of liquids yet to be discovered.

Release Areas are in largely under-explored parts of a major
hydrocarbon province.

Proximal to at least two proven petroleum systems.

Multiple sets of updated geoscientific data available, including new
Gippsland Basin Southern Flank Marine Seismic Survey.

Sizeable petroleum infrastructure: both onshore and offshore, including
access to major pipeline networks which distribute processed gas to
Victorian, New South Wales, South Australian and Tasmanian markets.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas V11-3, V11-4, V11-5 and V11-6, Gippsland Basin, Victoria
Release Area Geology
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LOCATION
The Release Areas V11-3 to V11-6 are spread across the basin (Figure 1),
providing potential explorers with the choice of several different tectonic
settings, play types and petroleum systems.
Release Areas V11-3 and V11-4 are adjacent to each other, in close proximity
to the southern Gippsland coast. Water depths across both of these are
typically shallow, with the maximum depth of ~70 m reached in the eastern
edge of V11-4.
Release Area V11-3 spans the Southern Terrace and parts of the Southern
Platform and Central Deep. It comprises 38 full and part graticular blocks and
covers an area of 2,326 km2 (Figure 2). Area V11-4 consists of 14 graticular
blocks and is 937 km2, and is predominantly on the Southern Platform,
covering parts of the Foster Fault system and adjacent Southern Terrace.
Release Area V11-5 lies in the northeastern part of the basin, and covers
parts of the Central Deep, Northern Terrace and Northern Platform, with water
depths increasing from 50-150 m towards the southeast. It encompasses 16
graticular blocks and covers 1,082 km2 (Figure 2). This area also includes the
small Leatherjacket oilfield.
Release Area V11-6 is in the far southeastern part of the Gippsland Basin,
and covers the majority of the Pisces Sub-Basin and parts of the Southern
Platform. This Release Area stretches over the southern margin of the Bass
Canyon, resulting in water depths ranging from 50 m on the shallow shelf to
>1,500 m in the northeastern corner of the Release Area. This Release Area
covers 24 part and full graticular blocks and covers 1,361 km2 (Figure 2).
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas V11-3, V11-4, V11-5 and V11-6, Gippsland Basin, Victoria
Release Area Geology
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RELEASE AREA GEOLOGY
Local Tectonic Setting
The east–west-trending Gippsland Basin was formed as a consequence of
Gondwana break-up (Rahmanian et al, 1990; Willcox et al, 1992, 2001;
Norvick and Smith 2001; Norvick et al, 2001) and the basin evolution is
recorded by several depositional sequences that are Early Cretaceous to
Neogene in age.
The Gippsland Basin’s architecture developed initially during the Early
Cretaceous rifting between Antarctica and Australia and consisted of a
primary depocentre – the Central Deep – which is flanked by structurally
higher platforms and terraces to the north and south. The basin is defined by
a series of major fault systems, namely the Rosedale and Lake Wellington
fault systems on the northern margin and the Darriman and Foster fault
systems on the southern margin (Figure 3). The Rosedale and Darriman fault
systems separate the Northern and Southern platforms from the Central Deep
respectively. The Pisces Sub-basin lies close to the southeastern margin of
the Gippsland Basin, and is a perched Cretaceous half-graben in the hanging
wall of the bounding fault of the Southern Platform.
The Central Deep contains most of the major oil and gas fields; this region is
characterised by rapidly increasing water depths in the east, where depths in
excess of 3000 m occur in the Bass Canyon (Hill et al, 1998). The eastern
limit of the basin is defined by the East Gippsland Rise, a prominent northnortheast-striking ‘basement’ high (Megallaa, 1993; Moore and Wong, 2002).
The western onshore limit of the basin is represented by outcrops of Lower
Cretaceous Strzelecki Group sediments (Hocking, 1988).
Structural Evolution and Depositional History of the Sub-basin
Basin evolution
The initial basin-forming rifting event occurred in the Early Cretaceous
(Berriasian-Albian), creating a series of graben and half-graben of limited
geographic extent that became filled with non-marine arkoses and fluvial
volcaniclastic sediments of the Strzelecki Group. Subsequently, a period of
uplift and erosion occurred between 100 and 95 Ma (Cenomanian). This event
produced a new basin configuration and may have provided the
accommodation space for large volumes of basement-derived sediments
(Emperor Subgroup; Figure 4a and Figure 4b). Renewed crustal extension
during the Late Cretaceous (Turonian), associated with the rapid rifting along
the Southern Margin and extension in the Tasman Sea, established the
Central Deep as the primary depocentre. Terrigenous sedimentation in the
Gippsland Basin continued until the late Santonian, when the first marine
incursion is recorded in the eastern part of the basin (Partridge, 1999).
Rift-related extensional tectonism continued into the early Eocene, with the
formation of a pervasive set of northwest–southeast-trending normal faults. By
the middle Eocene, a period of low-strain compressional tectonism began to
affect the Gippsland Basin and resulted in the formation of a series of
northeast to east-northeast-trending anticlines. This event may have been due
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas V11-3, V11-4, V11-5 and V11-6, Gippsland Basin, Victoria
Release Area Geology
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to intra-plate stress effects, perhaps associated with changes in the sea-floor
spreading rate along the Southern Margin rift system. All the major fold
structures at the top of the Latrobe Group, which became the hosts for the
large oil and gas accumulations such as Barracouta, Tuna, Kingfish, Snapper
and Halibut, formed as a result of this inversional tectonism. Minor inversion
episodes continued well into the Neogene, forming a number of smaller
anticlines and traps.
Post-rift depositional architectures and settings became dominant in the
Gippsland Basin from the early Oligocene, with the deposition of the basal
unit of the Seaspray Group, the Lakes Entrance Formation. These onlapping,
marly sediments provide the principal regional sealing unit across the basin.
Subsequently, the deposition of the thick Gippsland Limestone, also part of
the Seaspray Group, provided the critical loading for the source rocks of the
deeper Latrobe and Strzelecki groups, with the majority of hydrocarbon
generation (or certainly the preserved component of the generated
hydrocarbons) occurring in the Neogene.
The deposition of relatively thick Cenozoic sequences, and the attendant late
loading of the source rocks, means that even traps that have developed
during the Neogene can be charged with economic quantities of
hydrocarbons.
Stratigraphy and depositional history
Three broad stratigraphic successions are recognised in the Gippsland Basin,
based upon lithological variations (Figure 4a and Figure 4b). These
stratigraphic successions comprise: a) the Strzelecki Group, a thick sequence
of non-marine, volcaniclastic-rich sediments; b) the Latrobe Group, a
sequence of marine and non-marine siliciclastics that host all of the known
hydrocarbon occurrences in the offshore; and c) the Seaspray Group, a
carbonate-dominated sequence that provides both the regional top-seal to the
oil and gas accumulations at the top of the Latrobe Group, and the critical
loading for the generation of hydrocarbons.
Strzelecki Group (Lower Cretaceous)
The Hauterivian–Albian Strzelecki Group was deposited during low-strain synrift tectonism and unconformably overlies Paleozoic igneous and folded
sedimentary rocks. The group consists of interbedded lithic, volcaniclastic
sandstones, mudstones and includes several coal-rich horizons. The
sediments accumulated in a non-marine environment dominated by a fluvial
depositional regime. The Strzelecki Group has very strong affinities with the
Eumeralla Formation (Otway Group) in the Otway Basin (Duddy, 1994).
Although often regarded by the industry as ‘economic basement’, it is
considered to have potential for hydrocarbon generation and accumulation, in
particular in the western part of the basin (Mehin and Bock, 1998), and is host
to minor dry gas accumulations in the Seaspray Depression onshore. The
total thickness of the Strzelecki Group is poorly defined, but it is likely to
exceed 3,000 m in parts of the basin.
2011 Release of Australian Offshore Petroleum Exploration Areas
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Latrobe Group
The Latrobe Group is of key relevance to explorers as it hosts all currently
known hydrocarbons in the offshore and was deposited in tectonic settings
which ranged from active syn-rift to early post-rift. Four subgroups have been
defined: the Emperor, Golden Beach, Halibut and Cobia; each of which is
bounded by basin-wide unconformities.
Emperor Subgroup
The Emperor Subgroup is exclusively Turonian in age and has only been
intersected around the basin margins in the vicinity of the bounding faults of
the Northern and Southern terraces. Seismic data suggest that a thick section
of the subgroup exists below depths of 4 to 6 km in the Central Deep
(Bernecker et al, 2001). The Otway Unconformity, which separates the
subgroup from the underlying Strzelecki Group, developed in response to
uplift along the basin margins. Large volumes of erosional material were
delivered to the evolving rift-valley, within which a system of large, deep lakes
developed.
The subgroup comprises marginal coarse-grained alluvial fan/plain as well as
lacustrine facies associations that are characteristic for rift-valley deposition
prior to continental break-up. Within the rift-valley, one or more deep lakes
emerged to form a large lacustrine depocentre (Marshall and Partridge, 1986;
Marshall, 1989; Lowry and Longley, 1991). This palaeo-lake or lakes,
presumably occupied most of the Turonian rift-valley and received detrital
sediments from the basin margins; these lacustrine facies associations form
the Kipper Shale. The Kersop Arkose, a coarse-grained feldspathic
sandstone, represents the earliest erosion of uplifted granites at the southern
basin margin. The unit has been intersected both in Moray 1 (type section) in
the south, and also in Admiral 1, northeast of the Kipper gas field, providing
evidence that the early depocentre was oriented east-west and was relatively
narrow. These intersections provide evidence that the Turonian basin margin
was defined by the Lake Wellington Fault Zone to the north and the Foster
Fault Zone to the south. The Admiral Formation is characterised by quartzdominated lithic arenites that were derived from Paleozoic sedimentary and
metamorphic terrains, as well as from newly uplifted Lower Cretaceous
sediments. The Curlip Formation consists of sandstones and conglomerates
that are interbedded with thin shales and minor coals. This formation overlies
and interfingers with the lacustrine Kipper Shale and the formation top is
represented by the basin-wide Longtom Unconformity that terminates
Emperor Subgroup deposition. This unconformity was recognised by
Partridge (1999), who showed that it had been previously erroneously merged
or confused with the Seahorse Unconformity at the top of the Golden Beach
Subgroup. Accordingly, numerous well sections were incorrectly assigned to
the Golden Beach Subgroup. The hiatus between the Emperor and Golden
Beach subgroups separates freshwater lacustrine sediments from non-marine
and marine sediments and correlates with the opening of the adjacent
Tasman Sea.
2011 Release of Australian Offshore Petroleum Exploration Areas
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Golden Beach Subgroup
Two formations are distinguished in the Golden Beach Subgroup, the marine
Anemone Formation and the fluvial/paralic Chimaera Formation. The
Anemone Formation consists predominantly of mudstones, shales and other
fine-grained siliciclastics that represent shallow to open marine deposition that
prevailed in the eastern part of the basin. The marine Golden Beach
Subgroup has been intersected in Archer 1, Anemone 1, Angler 1 and
Pisces 1. The Chimaera Formation is a non-marine succession that consists
of coarse-grained alluvial/fluvial sediments, as well as fine-grained floodplain
deposits including some coals. The formation has been intersected, and
occasionally fully penetrated, in wells near the Rosedale Fault System but it is
missing on the Northern Platform and Northern Terrace. In the southern part
of the basin, the Chimaera Formation is only known from Omeo 1, 2 and
Perch 1. The Golden Beach Subgroup is essentially confined to the Central
Deep, which reflects tectonic movement along the basin margins where
conglomerates accumulated. Finer material was transported by fluvial
systems that continued to migrate across a gradually widening lower coastal
plain and terminated as deltaic bodies in the shallow sea. This alternation
between marine and non-marine influence persisted throughout the remainder
of the Latrobe Group and had significant control on the distribution of
petroleum system elements. The subgroup also contains several volcanic
horizons that, although undated, are likely to be Campanian in age. These
volcanics, most prominently developed in the Kipper Field and in the
Basker/Manta/Gummy area, terminate the Golden Beach Subgroup and
signal another depositional hiatus represented by the Seahorse Unconformity.
Halibut Subgroup
The hiatus recorded by the Seahorse Unconformity is longest in Golden
Beach West 1, where sediments from the upper F. longus biozone directly
overlies N. senectus sediments. Closer to the Rosedale Fault System, F.
longus sediments overlie the Campanian volcanics (Bernecker and Partridge,
2001). The Halibut Subgroup hosts the bulk of the hydrocarbons in the
Gippsland Basin and comprises five formations that are distinguished by their
dominant depositional facies regimes and document the changes from nonmarine to marine environments in a west–east or onshore–offshore direction.
The Barracouta Formation, which represents upper coastal plain deposition is
characterised by fluvial sediments and contains only minor coal. The Volador
and Kingfish formations comprise the typical lower coastal plain coal-rich
sediments and are separated by the Kate Shale, a marine unit recognised at
the Cretaceous/Paleogene boundary across the basin. The Mackerel
Formation consists of near-shore marine sandstones, commonly typified by
excellent reservoir qualities, with intercalated marine shales.
Sea-level fall in the early Eocene, driven by mild basin inversion, initiated a
period of major canyon cutting during which parts of the lower coastal plain
and the shelf were eroded. The array of submarine channels that developed
has added a considerable complexity to seismic mapping, given that the
major channels cut down hundreds of metres into the underlying strata.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas V11-3, V11-4, V11-5 and V11-6, Gippsland Basin, Victoria
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During subsequent transgression, the channels were filled with marine
sediments (e.g. Flounder Formation), which led to the formation of potential
stratigraphic traps (Johnstone et al, 2001). The Marlin Unconformity
comprises the major erosional event associated with channel incision and
terminated deposition of the Halibut Subgroup.
Cobia Subgroup
The middle Eocene to lower Oligocene Cobia Subgroup comprises the coalbearing Burong Formation (lower coastal plain facies) and the shallow to open
marine Gurnard Formation, a condensed section composed of fine- to
medium-grained glauconitic siliciclastics. The Gurnard Formation is the
reservoir unit in the Patricia/Baleen gas field and consists of fine- to mediumgrained clastics. In most other wells, the formation is mud-dominated and
characterised by low porosity and permeability, although the formation is not
considered an effective seal. Included in the subgroup is the Turrum
Formation that consists of mid-Eocene marine channel-fill sediments.
Deposition of the Cobia Subgroup ceased during the early Oligocene as a
consequence of a marked decline in sediment supply. Large areas of the
central basin were left with starved or condensed sections which led to the
development of what is traditionally known as the ‘Latrobe Unconformity’
(Partridge, in Purcell, 1999). On seismic sections, this surface is commonly
interpreted as a time-line, even though the biostratigraphic data clearly
indicates that the Latrobe Unconformity should be considered a composite of
several, separate erosional events (Partridge, 1999, 2003).
Seaspray Group
The Seaspray Group consists of calcareous sediments that unconformably
overlie the siliciclastics of the Latrobe Group. Subsequent to a change in
ocean circulation along the southern Australian margin, accumulation of marls
and limestones began in the middle Eocene in the Eucla Basin, extended to
the Otway Basin during the late Eocene and reached the Gippsland Basin
during the early Oligocene (Holdgate and Gallagher, 1997). Since then, coolwater carbonate production resulted in progradation of the shelf edge. From
an exploration perspective, the Seaspray Group is both the primary regional
seal (the Lakes Entrance Formation) to the oil and gas accumulations hosted
in the top-Latrobe Group and the key sequence that loads and matures the
source rocks. Only sparse data on its lithological character and physical
properties are available and although the carbonates appear to be
monotonous on wireline logs, the Seaspray Group in the offshore can be
subdivided into four units (Bernecker et al, 1997; Partridge, 1999) according
to lithological composition, depositional facies and log-signature. Recent work
by Goldie Divko et al (2009, 2010) and O’Brien et al (2008) provide details of
the sealing characteristics of the Lakes Entrance Formation. This work shows
that the Lakes Entrance Formation is predominantly a smectitic marl over
much of its distribution, with the ability to contain significant hydrocarbon
columns, particularly over the Central Deep.
In the context of this report, the conventional subdivision into the basal mudrich, marly, slightly fossiliferous Lakes Entrance Formation and the carbonate2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas V11-3, V11-4, V11-5 and V11-6, Gippsland Basin, Victoria
Release Area Geology
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dominated Gippsland Limestone is used. It should be noted that a different
subdivision applies to the onshore Seaspray Group (Holdgate and Gallagher,
1997; Partridge, 1999). The boundary between the two formations in the
offshore is not well defined and is based on a subtle increase in carbonate
content. However, over large parts of the basin, a seismic reflector has been
identified at the top of the Lakes Entrance Formation, known as the ‘MidMiocene Marker’. Above this horizon, an interval of anomalous seismic
velocity, the ‘High Velocity Zone’, produces distinctive two-way time pull-ups,
which, in the past, had enormous effects on the correct mapping of target
zones in the Latrobe Group (Feary and Loutit, 1998).
The seismic velocity anomalies are related to a complex system of midMiocene channels that eroded up to 300 m into a sequence of calcareous
sediments. These interfingering channels, which are very well imaged on
seismic sections, are filled with generally coarser and more porous materials,
are characterised by higher velocities than the underlying carbonates, and
also show considerable lateral velocity gradients (Bernecker et al, 1997;
Holdgate et al, 2000). Diagenetic processes, especially the preferential
cementation of channel bases, also influence the seismic velocities (Wong
and Bernecker, 2001).
The modern shelf edge of the basin is located near a line that connects the
Archer/Anemone discoveries with the Blackback and Basker/Manta/Gummy
areas (Figure 3). The slope gradient is <6º, but increases rapidly along the
Bass Canyon, which is deeply eroded into older sequences; erosion has
reached the sediments of the Golden Beach Subgroup east of the East
Gippsland Rise (Marshall, 1990).
2011 Release of Australian Offshore Petroleum Exploration Areas
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Release Area Geology
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EXPLORATION HISTORY
The Release Areas in the Gippsland Basin are all relatively under-explored,
especially Release Area V11-6. Few wells have been drilled within the
Release Areas (Figure 1), although seismic coverage is reasonable.
Release Area V11-3 covers the southern part of the former VIC/P58, held by
Apache Northwest Pty Ltd (awarded 2004, relinquished 2009). Prior to this,
the permit was held by Amity Oil from 1995 to 1999, as permit VIC/P36. Amity
drilled Broadbill 1, but failed to complete the guaranteed work program and
the permit was cancelled in 1999. Earlier exploration in this area, including
seismic acquisition and the drilling of Kyarra 1A, Wyrallah 1 and Tommyruff 1,
has been covered by Bernecker et al (2003).
Release Area V11-4 is the recently relinquished southern portion of VIC/P42.
This permit has been operated by Bass Strait Oil since the permit was granted
in 1997. Over that time both Inpex Alpha Ltd and Apache Northwest Pty Ltd
have farmed in (Inpex Alpha in 2001 and Apache Northwest in 2006),
although the remainder of the permit is now solely operated by Bass Strait Oil.
There have been no wells drilled in V11-4 over the duration of VIC/P42 (for
details of earlier exploration, see Chiupka et al, 1997). Bass Strait Oil
acquired a 3D seismic survey across the eastern part of VIC/P42 in 2002
which covers Devilfish 1 and Pike 1 and the area to the west of these wells.
Release Areas V11-4 and V11-3, are also covered by the 2010 Gippsland
Basin Southern Flanks Marine 2D Survey.
The northernmost Release Area V11-5 was, until recently, the western part of
VIC/P47, and has several 3D seismic surveys obtained over its southern
portion. The remainder of Permit VIC/P47 is held by Bass Strait Oil, Moby Oil
and Gas Ltd and Strategic Resources, and was initially awarded to Eagle Bay
Resources NL and Bass Strait Oil in 2000. There were no wells drilled in
Release Area V11-5 while it was part of VIC/P47, although some seismic
acquisition was undertaken. The Leatherjacket oil field was discovered by
Esso Exploration and Production Australia in 1986, but was not further
developed. The oil is moderately biodegraded, a feature common to other
discoveries on the northern flank of the basin. Further information is given by
Bernecker et al (2003).
The early exploration of the Pisces Sub-basin (which includes Release Area
V11-6) has been summarised by Thomas et al (2003). There is only one well,
Pisces 1, within the Release Area, and it was drilled as a combined structural
and stratigraphic test of the sub-basin. It encountered weak hydrocarbon
shows in the upper part of the Golden Beach Subgroup. An exploration permit
(VIC/P60) was last operated over this area by Holloman Corporation and was
relinquished in mid-2010, with very little activity undertaken during the life of
this permit. This area has reasonable seismic coverage, including the 2010
Gippsland Basin Southern Flanks Marine survey.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas V11-3, V11-4, V11-5 and V11-6, Gippsland Basin, Victoria
Release Area Geology
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To view image of seismic coverage follow this link:
http://www.ga.gov.au/energy/projects/acreage-release-andpromotion/2011.html#data-packages
Well Control
The Release Areas are relatively under-explored, with few wells drilled in
each area. In the southern part of the basin, most wells in the Release Areas
have been drilled on the Southern Terrace. Broadbill 1, Kyarra 1A, Wyrallah 1
and Tommyruff 1 lie within Release Area V11-3, with the wells in the Perch
field immediately to the north providing important stratigraphical and
lithological control. Pike 1 and Devilfish 1 are the only wells within release
Area V11-4, and there are four wells within Release Area V11-5, with more
information available from the Sole, Moby and Kipper fields that lie just
outside the area. Pisces 1 is the single well drilled in Release Area V11-6.
Perch Field (1968)
The Perch field was discovered by Esso Australia in March 1968 in a water
depth of 42 m, located 24 km offshore and 50 km south of Longford. The field
lies on the Perch-Dolphin-Tarwhine-Barracouta trend and is bounded to the
north by an inverted south dipping normal fault. The field is constrained to the
northeast by an inverted southwest dipping normal fault. The entrapment
mechanism of oil is similar to that seen in the Dolphin Field with plunge of the
anticline to the southwest and by fault-seal of the Cobia Subgroup juxtaposed
against marls of the Lakes Entrance Formation to the northeast. The field has
an aerial extent of 3.1 km2, a field OWC of 1,131 mTVDSS and the net
thickness of the reservoir is 17 mTVD (38 mTVD gross). Average porosity for
the field was calculated to be 27% and permeability 3000 mD.
The Perch Tower was installed in July 1989 and production began in January
1990. Oil is piped to shore via the Dolphin Platform and gas is used to assist
oil recovery. The oil is napthenic with an API of 41° and GOR is calculated as
84 scf/bbl.
The field lies in permit block VIC/L17 and is operated by Esso Australia on
behalf of the BHB Billiton-Esso joint venture.
Wahoo 1 (1969)
Wahoo 1 was drilled by Esso Exploration and Production Australia to test a
large fault-line closure on the downthrown side of the Lake Wellington Fault
System. It was spudded in 74.7 m of water and reached TD at 745.5 mRT in
the Strzelecki Group. The absence of hydrocarbons could be either because
the well was drilled 30-60 m below the crest of the structure, or because the
lateral fault-seal is lacking due to the juxtaposition of permeable MioceneOligocene marls and limestones, allowing updip migration of hydrocarbons
away from the structure. The well was plugged and abandoned as a dry hole.
Pike 1 (1973)
Pike 1 was spudded in 73.8 m of water by Esso Australia 16 km northwest of
Moray 1 and 19 km south-southwest of Gurnard 1 on the southern margin of
the Central Deep. The target was a stratigraphically controlled trap within
2011 Release of Australian Offshore Petroleum Exploration Areas
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upper Latrobe Group sediments. The well reached TD at 2,134 mKB in the
Kingfish Formation (Halibut Subgroup). The lack of hydrocarbons in this well
was interpreted to be due to a lack of lateral and/or up-dip seal. The well was
plugged and abandoned as a dry hole.
Sweep 1 (1978)
Sweep 1 was drilled by Esso Australia Ltd in 69 m of water approximately
10 km north of Admiral 1. It reached TD at 900 mKB in the Strzelecki Group It
was designed to test a small west-southwest-east-northeast-trending anticlinal
culmination.. Both the Latrobe Group sands and the uppermost Strzelecki
Group were targets, as the uppermost Strzelecki Group was hydrocarbonbearing at nearby Flathead 1. No hydrocarbons were encountered, either due
to non-generation, migration prior to trap development, or lack of a valid seal.
The well was plugged and abandoned as a dry hole.
Hammerhead 1 (1982)
Hammerhead 1 was drilled by Shell Development (Australia) Pty Ltd about
10 km northeast of the Basker-Manta-Gummy field. It was spudded in 121 m
water and reached TD at 2,130 mKB in the Emperor Subgroup. It was drilled
to test a potential intra-Latrobe structural trap where Upper Cretaceous to
Paleocene shallow marine to marginal marine sandstones are faulted against
upthrown tight Strzelecki Group sediments. Lack of hydrocarbon indications
was attributed to the absence of adequate seal (intra-Latrobe shales). The
well was plugged and abandoned as a dry hole.
Omeo 1 (1982)
Omeo 1 was drilled by Australian Aquitaine Petroleum Pty Ltd 14 km
southwest of the Bream Field, on the southern margin of the Central Deep. It
was spudded in 62.7 m of water, and reached TD at 3,380 mKB in the Golden
Beach Subgroup.
The well was drilled to test a roll-over within Latrobe Group sediments on the
downthrown side of a normal fault, with lateral seal required by Latrobe Group
reservoirs being juxtaposed against Strzelecki Group sediments in the
upthrown side of the fault. The top-Latrobe sands lacked evidence of
hydrocarbons, with the first gas show at 2,846 mKB in the Barracouta
Formation. Further gas, with a thin film of oil/condensate was encountered at
2,849.8 and 3,125 mKB. 33 m of net gas pay was interpreted in sands within
the interval 2,845-3,137 mKB. The well was plugged and abandoned.
Pisces 1 (1982)
Pisces 1 was drilled by Union Texas in 122 m water in the Pisces Sub-basin
and is one of the more distal wells drilled in the Victorian part of the Gippsland
Basin. It reached a TD of 2,580 mKB in the Golden Beach Subgroup.
The target was a complex stratigraphic/structural trap of Latrobe Group
sediments adjacent to the northern bounding fault of the Southern Platform,
and it was expected to provide stratigraphic information about the deep-water
prospects of VIC/P12. It was drilled to test predicted Paleocene to Eocene
marginal marine reservoir sands, stratigraphically sealed beneath the top2011 Release of Australian Offshore Petroleum Exploration Areas
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Latrobe unconformity and to test a fault-defined structural prospect.
Stratigraphic seal at top-Latrobe level proved to be absent due to the sheet
sands of the Gurnard and basal Lakes Entrance formations acting as thief
zones for any migrating hydrocarbons at this level, allowing continued
migration updip (S and W) across the Southern Platform. The well was
plugged and abandoned.
Kyarra 1A (1983)
Kyarra 1A was drilled by Australian Aquitaine Petroleum Pty Ltd about 16 km
southwest of the Perch field. It was spudded in 43.5 m water depth, reaching
a TD of 1,280 mKB in the Strzelecki Group.
The well targeted a stratigraphically sealed sand (Keera Sand), and structural
closures within fluvial (channel and bar sands) to deltaic intra-Latrobe
interbedded sands. Good reservoir and seal units were intersected, while the
lack of hydrocarbons was attributed to formation of the Kyarra structure in the
Miocene (i.e. after the main phase of hydrocarbon expulsion), in addition to
evidence of freshwater flushing and associated biological degradation of any
hydrocarbons that migrated into the structure. The well was plugged and
abandoned as a dry hole.
Wyrallah 1 (1984)
Wyrallah 1 was drilled in 32 m of water by Australian Aquitaine Petroleum Pty
Ltd and reached TD 1,160 mKB in the Barracouta Formation. It is located
15 km offshore from 90 Mile Beach, 9 km west of Kyarra 1A and 20 km
southwest of the Perch Field.
The well was designed to test a structural culmination of the top-Latrobe
Group, and also to test intra-Latrobe intervals. The structure was mapped at
top-Latrobe level adjacent to a high angle reverse fault, with a roll-over formed
by the upthrown block, creating a structural ridge that extends eastwards to
Kyarra 1A.
The lack of hydrocarbons in the Wyrallah structure was attributed either to a
lack of migration from the Central Deep into the structure or to biodegradation.
The Wyrallah structure is also interpreted to have formed in the Miocene, after
the main phase of hydrocarbon generation and migration. The well was
plugged and abandoned as a dry hole.
Omeo 2A (1985)
Omeo 2A was drilled by Australian Aquitaine Petroleum Pty Ltd 900 m west of
Omeo 1. It was spudded in 62 m of water, and reached TD at 3,400 mKB in
the Golden Beach Subgroup.
This well encountered more complex geology than Omeo 1 as it is located in
the vicinity of a major growth fault, and the anticipated structural play was not
encountered. Omeo 2A failed to encounter significant indications of
hydrocarbons, indicating that the accumulation discovered in Omeo 1 was
likely to be small. It was abandoned due to technical difficulties.
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Kipper gas field (1986)
The Kipper field was discovered in 1986 by the Esso-BHP Petroleum led
consortium, and represented the first significant hydrocarbon discovery in the
Golden Beach Subgroup. The field lies approximately 42 km offshore, on the
northern flank of the Gippsland Basin, close to the Rosedale Fault System
and approximately 15 km east of the Tuna field. Estimates of in-place
reserves are approximately 900 Bcf gas and 30 Mstb oil. Development of this
field began in 2010 with the drilling of four development wells.
The field is a lowside fault-dependent trap with a significant gas column within
fluvial/deltaic sandstones at the top of the Golden Beach Subgroup. Kipper 1
also intersected four minor oil pools within the Cobia and Halibut Subgroups
above the gas column.
Leatherjacket 1 (1986)
Leatherjacket 1 was drilled by Esso Exploration and Production Australia Inc.
in 106 m of water, approximately 10 km northeast of the Kipper Field. It
reached a TD of 951 mKb in the Strzelecki Group, only intersecting ~100 m of
Latrobe Group sediments. It was drilled to test a fault-dependent closure, with
the structure situated on the high-side of a northeast-southwest-trending
inverted normal fault.
Two reservoir intervals were intersected, with the upper accumulation in lower
L. balmei sands (Kingfish Formation, 25.5 m oil-bearing column, from
763.5 mKB to OWC at 789 mKB), with an average porosity of 30% and an
average oil saturation of 54%. The lower accumulation is in Volador
Formation sands with an average porosity of 21% and an average oil
saturation of 55%. These sands contain a 7.7 m oil-bearing column
intersected at 811.3 mKB with OWC at 819 mKB. The well was plugged and
abandoned as a new field oil discovery.
Admiral 1 (1989)
Admiral 1 was drilled in 101 m of water by Esso Australia Resources Ltd and
reached TD of 2,162 mKB in the Emperor Subgroup. The well is located about
5 km northwest of the Kipper gas field.
This well tested a footwall fault-dependent closure against the Rosedale Fault
System. While reasonable reservoir quality sandstone was intersected in the
Curlip Formation (Emperor Subgroup), the predicted top-seal (Campanian
volcanics) was not realised, as the volcanics did not extend to the bounding
fault. Geochemical analysis indicates that the lacustrine P. mawsonii
sediments are rated as fair source rocks for gas only. This well was plugged
and abandoned as a dry hole.
Anemone 1A (1989)
Petrofina Exploration Australia spudded Anemone 1A in 231 m of water. TD
was reached at 4,775 mKB (side track) in the base of the Golden Beach
Subgroup.
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The well was drilled to test a large, fault-dependent closure within the
northern, downthrown block of a major northwest trending listric fault, and to
evaluate the hydrocarbon potential of coastal plain and deltaic intraCampanian (Golden Beach Subgroup) sandstones and the Maastrichtian
Volador Formation. The predicted source rock for this area was Campanian
lower coastal plain coaly sediments.
Poor shows were found in the Maastrichtian, top-Campanian and Campanian
“1” (Anemone Formation) sandstones, moderate shows in Campanian “2”
(Anemone Formation) sandstones, and the well intersected a gas-rich
sandstone sequence at 4,525 mKB (Chimaera Formation). The well was
plugged and abandoned as a noncommercial gas-condensate discovery.
Archer 1 (1990)
This well was drilled at the crest of the Archer structure by Petrofina. It was
spudded in 167 m water depth, reaching TD of 4,050 mKB in the Golden
Beach Subgroup.
The target of this well was the Campanian “1” and “2” sandstones of the
Anemone Formation that had previously been intersected at Anemone 1A.
Enhanced reservoir properties were expected in the Archer prospect, which
was a series of stacked reservoir intervals within the Anemone Formation,
having fault-dependent closure with partial four-way dip closure. Seven main
hydrocarbon zones were intersected in the Golden Beach Subgroup, with
progressively more volatile oil found in four intervals within 3,384.0–
3,655.5 mKB, and very gas rich condensate intersected in three intervals
within 3,655.5–4,050 mKB.
The marine shales within the Anemone Formation are likely to be a regional
barrier to vertical migration within the Archer/Anemone area, possibly
preventing migration of hydrocarbons into the Volador Formation.
.Petrofina Exploration Australia S.A. (1990) estimated recoverable gas
reserves of 53 Bcf, 5.0 Mmbbl of oil and condensate. The well was plugged
and abandoned as a non-commercial oil and gas-condensate discovery.
Devilfish 1 (1990)
Devilfish 1 was drilled by Shell Development (Australia) Pty Ltd in 74 m of
water. It is located about 30 km southwest of the Kingfish oil field, close to the
inferred southern limit of the Strzelecki Group. It reached a TD of 2,058 m in
the Volador Formation.
The target structure was a downthrown fault trap, mapped at top-Latrobe
level, and bounded by the Foster Fault System. The trap was predicted to be
fault-sealed, relying on the juxtaposition of the reservoir sands in the
downthrown block against a thick marine shale, with an additional minor,
independent dip closure also mapped. The lack of hydrocarbons in this well
was attributed to a lack of charge, and insufficient thickness of marine shale to
provide effective lateral fault-seal. The well was plugged and abandoned as a
dry hole.
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Tommyruff 1 (1990)
Tommyruff 1 was drilled by BHP Petroleum in 33 m of water about 17 km to
the east of the Perch field and north of Kyarra 1 and Wyrallah 1. It reached TD
at 1,550 mKB in the Kipper Shale (Emperor Subgroup), without penetrating
any Golden Beach Subgroup.
The target was an anticlinal structure with independent 4-way dip closure
mapped at top-Latrobe, with both structural and stratigraphic traps potentially
present in the Latrobe succession. Good to excellent reservoirs and
competent seal were found, with the lack of hydrocarbon indications attributed
to the structure not being on a migration pathway from the Central Deep. The
well was plugged and abandoned as a dry hole.
Broadbill 1 (1998)
Broadbill 1 was drilled by Amity Oil N.L. in 22 m water depth, reaching TD of
1345 mKB in the Strzelecki Group. The target was the Broadbill structure,
about 6 km offshore and 13 km west of the Perch field. This prospect was a
low relief four-way dip structural closure at top-Latrobe level. Hydrocarbons
were thought to have migrated through this area, due to the presence of
hydrocarbon indications in the nearby Woodside 2 well and Perch field. Gas
readings were high from the top-Latrobe level (850 mKB) down to 966 mKB,
although reservoir saturations were too low to be economic. The well was
plugged and abandoned as a dry hole.
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_gippslandl_AR11.xls
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Data Coverage
The Release Areas all have some seismic coverage, with the best covered
being V11-5 in the northern margin of the basin. This area has several 3D
surveys over its southern portion, and reasonable quality 2D coverage over
most of the remainder. As mentioned previously, GSV (in conjunction with
DRET) acquired the 8,000 line km Gippsland Basin Southern Flanks Marine
Survey in 2010, which covers a large part of the southern flank of the
Gippsland Basin, and ties into wells drilled in the three southern Release
Areas. Otherwise, Release Areas V11-3 and V11-4 have better seismic
coverage over their portions which cover the Southern Terrace rather than
those covering the Southern Platform.
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PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL
Table 1: Petroleum Systems Elements Summary
Cobia and Halibut subgroups (Latrobe Group) – coals and
carbonaceous shales
Anemone Formation (Golden Beach Subgroup) – marine shale
Sources
Kipper Formation (Emperor Subgroup) – lacustrine
carbonaceous shales
Strzelecki Group (proven contributor of dry gas along northern
margin)
Burong and Mackerel formations (Cobia Subgroup), and
Barracouta and Kingfish formations (Halibut Subgroup)
Reservoirs
Volador Formation (Halibut Subgroup), Chimaera Formation
(Golden Beach Subgroup)
Regional top seal – Lakes Entrance Formation
Intra-Latrobe seals – Kate Shale (Halibut Subgroup)
Seals
-
volcanics (several distinct horizons, Campanian to
Paleocene)
-
Anemone Formation (Golden Beach Subgroup)
-
Kipper Shale (Emperor Subgroup)
Structural traps (anticlinal closures)
Play Types
Fault traps along the northern and southern bounding faults of
the Central Deep and terraces
Stratigraphic pinch out plays
Petroleum systems elements
The identification of all the required components of petroleum systems in the
Gippsland Basin is the subject of ongoing work and is not a simple task,
especially given that many of the system’s elements are located at great
depth. There are likely to be several petroleum systems operating in the
Gippsland Basin, with the most prolific being that which generated the
hydrocarbon accumulations now reservoired at the top of the Latrobe Group.
This system has a source in the lower coastal plain and swamp facies of the
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Halibut Subgroup, and is usually reservoired in the shallow marine barrier and
shoreface sandstones close to the top of the Latrobe Group.
There is evidence of a deeper system operating within the Latrobe Group, for
example in the Basker-Manta-Gummy field, where the source is a thick
section of coal-bearing lower coastal plain sediments of the Volador
Formation (Halibut Subgroup). These rich source rocks are believed to have
charged the major hydrocarbon traps in the central part of the offshore basin,
and in the Basker-Manta-Gummy field, the reservoir units are fluvial
sandstone of the Chimaera Formation (Golden Beach Subgroup) and lower
coastal plain channel sandstone of the Voldaor Formation (Halibut Subgroup).
Seal for this intra-Latrobe system in the Basker-Manta-Gummy field is
provided by a series of interbedded claystones and siltstones, in addition to
cross-faulting.
Recent work (O’Brien et al, 2008) indicates that an older petroleum system is
operating in the Lower Cretaceous Strzelecki Group, and is providing
significant quantities of dry gas, especially along the northern margin of the
Gippsland Basin (e.g. the Sole field) and onshore (Wombat, North Seaspray
and Gangell fields).
Source
Only a few wells have penetrated the oil- or gas-mature section of the deeper
Halibut and Golden Beach subgroups and hence the distribution of the main
source rock units and source rock kitchens are not fully understood. It is
generally considered that the source rocks for both the oil and gas in the
basin are represented by organic-rich, non-marine, coastal plain mudstones
and coals (Burns et al, 1984, 1987; Moore et al, 1992). Source rocks of
dominantly terrestrial plant origin (Kerogen Type II/III) are widely distributed
throughout the Latrobe Group and generally exhibit high total organic carbon
(TOC) values (>2.0%), high Rock-Eval pyrolysis yields, and moderate to high
hydrogen indices (>250 mgHC/gTOC), suggesting that they have the potential
to generate both oil and gas. The richest Latrobe Group source rocks (mainly
humic to mixed type) occur within lower coastal plain and coal swamp facies.
Well correlations show that much of the T. lilliei biozone is represented by low
energy, lagoonal/paludal sediments in the east-southeast. This facies extends
beneath the giant Kingfish oil field and across the basin to the north. In the
Central Deep, T. lilliei sediments accumulated in a marine environment with
interbedded sandstones and marine shales (Rahmanian et al, 1990; Moore et
al, 1992; Chiupka et al, 1997). Data from Hermes 1, located in the southern
part of the basin, proves the existence of a thick, rich source rock unit at this
level. The >950 m T. lilliei section within this well has TOC concentrations that
generally exceed 10% (Petrofina Exploration Australia S.A., 1993).
Analysis of condensate recovered from the Archer/Anemone discovery
suggests that source rock potential may also exist within marine sediments
(Gorter, 2001).
The Strzelecki Group sediments within the onshore and offshore Gippsland
Basin have the potential to generate significant quantities of gas (O’Brien et
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al, 2008). Overall, the Strzelecki Group appears to have a broadly similar
source rock quality to its temporal equivalent, the proven working Eumeralla
Formation source in the Otway Basin. This indicates that the gas in the
Gippsland Basin fields, such as the onshore Trifon, Gangel and North
Seaspray and offshore Sole, was probably generated within the Strzelecki
Group. If confirmed, these results mean that traps either remote from the
mature Central Deep source, or located in Latrobe migration shadows, can
still be charged with gas, providing that a local, mature Strzelecki Group
source is present.
Reservoirs
Marine near-shore barrier and shoreface sandstones are traditionally
regarded as the best reservoirs in the basin. The most productive of these
were drilled at or near the top of the Latrobe Group and are commonly
referred to as the ‘top-Latrobe coarse clastics reservoirs’. This is an
unfortunate misnomer, given that similar coarse sandstones are developed
throughout the stratigraphic column. All these sandstones are diachronous
and developed in response to periodic marine regressive cycles associated
with low depositional rates. This provided an ideal environment for high levels
of reworking and winnowing of the deltaic and coastal plain sediments.
Geographically, this reservoir facies is best developed in the Barracouta,
Snapper, Marlin, Bream and Kingfish fields. Reservoir distribution in intraLatrobe sequences can be complex and frequently involves multiple stacked
sandstone/shale alternations characteristic of fluvial/deltaic environments.
Submarine channelling, the presence of numerous, thin, condensed
sequences and the overall lower net-to-gross ratio contribute to lower
reservoir qualities. Nevertheless, there are plenty of examples for good quality
reservoirs in deltaic sandstones, as well as in fluvial and submarine channels.
Latrobe Group reservoir porosities average 15-25% across the basin, with the
best primary porosities preserved in fluvial/deltaic sandstones that are
texturally mature and moderately well sorted.
In contrast to the Latrobe Group, the identification of permeable reservoirs
within the Strzelecki Group has proven elusive, though primary porosities can
be high. Unless an improved model for the prediction of permeability within
the Strzelecki Group sands can be developed, such targets are inherently
high-risk.
Seal
For the top-Latrobe reservoirs, a basin-wide, high quality regional seal is
provided by the marls of the lower Oligocene Lakes Entrance Formation. The
thickness of this seal varies considerably and ranges from approximately
100 m to over 300 m in deeper water parts of the basin (O’Brien et al, 2008).
In addition, many potential intraformational sealing units are present within the
Latrobe Group. These include floodplain sediments deposited in upper and
lower coastal plain environments, as well as lagoonal to offshore marine
shales. These seals are commonly thin and mostly occur within stacked
sandstone/mudstone successions; the low shale volume in such settings
makes the prediction of cross-fault seal problematic. Excellent seals, such as
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bounding faults and other effective seals are formed by several distinct
volcanic horizons of Campanian to Paleocene age (e.g., as in the Kipper
Field). The Kipper Shale exceeds 500 m in thickness, whereas the volcanics
are often less than 50 m thick, though they are known to exceed 100 m in the
Kipper field.
Traps
At the level of the basin-wide Latrobe Unconformity, the basin is dominated by
a series of northeast-trending anticlines and synclines. Along the anticlinal
trends, four-way dip closures form the traps for the major fields within the
basin. These anticlines formed during the inversion of deeper Lower
Cretaceous graben and half-graben that were initially filled with the
volcaniclastic-dominated sediments of the Strzelecki Group. As tectonic
regimes changed, these structural lines of weakness have been variably
reactivated. The same northeast trends of anticlines and underlying graben
are present in the onshore, where Lower Cretaceous rocks are exposed
within both the Strzelecki and Otway ranges.
Maturity and migration
Numerous studies of the hydrocarbon generation and thermal history of the
Gippsland Basin have been undertaken, but the results of these investigations
remain largely unpublished. It has been suggested that the main period of
hydrocarbon generation and expulsion was initiated in the Miocene, as a
result of increased sedimentary loading by the Oligocene and younger
carbonate sequences (Moore et al, 1992). Some workers (Duddy et al, 1997)
have proposed that the source rocks within the basin are currently at their
peak levels of hydrocarbon generation and expulsion. Given that traps in the
top-Latrobe interval were formed as a result of Neogene compressional
events, the relative timing of trap formation and reservoir charging is ideal.
This ‘late charge’ scenario does not apply to the deeper Latrobe Group,
however. The Late Cretaceous depocentres underwent an early phase of
generation and migration – in about the late Paleocene to early Eocene
(Moore et al, 1992). With peak generation from the Golden Beach Subgroup
likely to have occurred during the Eocene due to relatively high heat flows
(Summons et al, 2002). At this time, the regional Lakes Entrance seal had not
been deposited and thus by necessity, any trapping must have involved intraLatrobe Group sealing units and early formed traps. Just how much of this
early generated hydrocarbon inventory was in fact ever trapped remains
problematical.
Recent migration modelling by GeoScience Victoria indicates that there are
two long distance fill-spill pathways in the Gippsland Basin (Figure 5; O’Brien
et al, 2008), with evidence of an early oil charge in many of the giant fields
now filled with gas (e.g., Barracouta, Snapper, Marlin).
Play types
The two principal types of petroleum plays are present on both the basin
terraces and in the Central Deep; these are Top-Latrobe plays, and the intraLatrobe/Golden Beach plays. The elements associated with these plays are
as follows:
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
Top-Latrobe Group plays
Source: Halibut and Golden Beach subgroups; ?Strzelecki Group
Seal: Lakes Entrance Formation
Reservoirs: Burong, Barracouta, Kingfish, Flounder formations and
Gurnard Formation when present
Traps: Erosional remnants as in Tuna, Halibut/Cobia/Fortescue,
Volador or Sunfish (reservoirs are intra-Latrobe); Anticlines as in
Snapper, Moonfish, Marlin and Turrum, Leatherjacket; Possible topLatrobe sediments as in Sweetlips.

Intra- and deep-Latrobe Group plays (Halibut, Golden Beach and
Emperor subgroups)
Source: Halibut, Golden Beach and Emperor subgroups; ?Strzelecki
Group
Seal: Intra-Halibut/Golden Beach mudstones, Kipper Shale or younger
volcanics
Reservoirs: Intra-Latrobe, Golden Beach and Emperor sandstones
Traps: Highside fault closures as seen in Angler or Dolphin; Lowside
fault closures as in Kipper, Basker/Manta/Gummy, Longtom, West
Tuna or Archer/Anemone; Faulted anticlines as in Flounder, Seahorse,
Whiting and Turrum.
Critical Risks
The Release Areas are relatively under-explored, particularly along the
southern margin of the basin.
Distribution and effectiveness of sealing facies is not seen as a major risk
over most of the areas. An effective regional seal – the marls of the lower
Seaspray Group – is likely to be present over the majority of the Release
Areas, although the lithologies in the eastern offshore area and on the
Southern Platform remain unknown. The quality of intraformational seals
depends very much on the overall facies associations and their variations
through time. Well control in the Central Deep and on the Northern Terrace
indicates that the Latrobe Group sediments tend to have more marine
influence in the easternmost part of the basin.
Uncertainties also relate to the behaviour of the main fault systems and
related structures. The transition between the Central Deep and the Northern
Terrace is controlled by a complex fault system (the Rosedale Fault System)
that has juxtaposed reservoir and sealing facies in several locations, but is
also known to act as migration pathway in others, and this is also likely to be
the case in the Foster and Darriman fault systems in the southern part of the
2011 Release of Australian Offshore Petroleum Exploration Areas
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basin. Fault seal integrity is certainly one issue that requires detailed attention
by any explorer. A further issue around the basin margins is the possibility of
freshwater flushing of at least the top portion of the Latrobe Group reservoir.
2011 Release of Australian Offshore Petroleum Exploration Areas
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FIGURES
Figure 1:
Gippsland Basin permit map showing location of Release
Areas V11-3, V11-4, V11-5 and V11-6, major oil and gas fields,
and petroleum infrastructure.
Figure 2:
Graticular block map and graticular block listings for Release
Areas V11-3, V11-4, V11-5 and V11-6, in the Gippsland Basin,
Victoria.
Figure 3:
Digital terrain image of the Gippsland Basin displaying the
major tectonic elements.
Figure 4a:
Gippsland Basin stratigraphy. Geologic Time Scale after
Gradstein et al (2004) and Ogg et al (2008). Hydrocarbon
shows are displayed.
Figure 4b:
Gippsland Basin stratigraphy continued. Geologic Time Scale
after Gradstein et al (2004) and Ogg et al (2008). Hydrocarbon
shows are displayed.
Figure 5:
Petromod model showing predicted a: Neogene and b: present
day hydrocarbon accumulations at top Latrobe horizon,
Gippsland Basin.
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REFERENCES
BERNECKER, T. AND PARTRIDGE, A.D., 2001—Emperor and Golden
Beach Subgroups: The onset of Late Cretaceous Sedimentation in the
Gippsland Basin, SE Australia. In: HILL, K.C. AND BERNECKER, T. (editors),
Eastern Australasian Basins Symposium, A Refocused Energy Perspective
for the Future, Petroleum Exploration Society of Australia, Special Publication,
391–402.
BERNECKER, T., PARTRIDGE, A.D. AND WEBB, J.A., 1997—Mid-Late
Tertiary deep-water temperate carbonate deposition, offshore Gippsland
Basin, southeastern Australia. In: JAMES, N.P. AND CLARKE, J.D.A
(editors), Cool Water Carbonates, SEPM Special Publications 56, 221–236.
BERNECKER, T., THOMAS, H. AND DRISCOLL, J., 2003—Hydrocarbon
prospectivity of Areas V03-1, V03-2, 03-1(v) and 03-2(v) offshore Gippsland
Basin, Victoria, Australia. Victorian Initiative for Minerals and Petroleum
Report 79, Department of Primary Industries.
BERNECKER, T., WOOLLANDS, M.A., WONG, D., MOORE, D.H. AND
SMITH, M.A., 2001—Hydrocarbon prospectivity of the deep-water Gippsland
Basin, Victoria, Australia. The APEA Journal, 41(1), 79–101.
BURNS, B.J., BOSTWICK, T.R. AND EMMETT, J.K., 1987—Gippsland
terrestrial oils – recognition of compositional variations due to maturity and
biodegradation. The APEA Journal, 27, 73–85.
BURNS, B.J., JAMES, A.T. AND EMMETT, J.K., 1984—The use of gas
isotopes in determining the source of some Gippsland Basin oils. The APEA
Journal, 24, 217–221.
CHIUPKA, J.W., MEGALLAA, M., JONASSON, K.E. AND FRANKEL, E.,
1997—Hydrocarbon plays and play fairways of four vacant offshore Gippsland
Basin areas. 1997 acreage release. Victorian Initiative for Minerals and
Petroleum Report 42, Department of Natural Resources and Environment.
DUDDY, I.R., 1994—The Otway Basin: Thermal structural tectonic and
hydrocarbon generation histories. In: FINLAYSON, D.A.I. (editor),
NGMA/PESA Otway Basin Symposium Abstracts, Australian Geological
Survey Organisation Record 1994/14, 35-42.
DUDDY, I.R., GREEN, P.F. AND HEGARTY, K.A., 1997—Impact of thermal
history on hydrocarbon prospectivity in SE Australia. In: COLLINS, G. (editor),
1997 Great Southern Basin Symposium, Abstracts, Australian Petroleum
Exploration Association, Vic./Tas. Branch, 14–17.
FEARY, D.A. AND LOUTIT, T.S., 1998—Cool-water carbonate facies patterns
and diagenesis – the key to the Gippsland Basin ‘velocity problem’. The
APPEA Journal, 38(1), 137–146.
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GOLDIE DIVKO, L.M., O’BRIEN, G.W., TINGATE, P.R. AND HARRISON,
M.L., 2009—Geological Carbon Storage in the Gippsland Basin, Australia:
Containment Potential. VicGCS Report 1, Department of Primary Industries.
GOLDIE DIVKO, L.M., O’BRIEN, G.W., HARRISON, M.L. AND HAMILTON,
P.J., 2010—Evaluation of the regional top seal in the Gippsland Basin:
Implications for geological carbon storage and hydrocarbon prospectivity.
APPEA Journal 2010, 463-486.
GORTER, J.D., 2001—A Marine Source Rock in the Gippsland Basin? In:
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Front page image courtesy of Petroleum Geo-Services.
2011 Release of Australian Offshore Petroleum Exploration Areas
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