PETROLEUM GEOLOGICAL SUMMARY
RELEASE AREA V12-1, V12-2 AND T12-1,
EASTERN OTWAY BASIN, VICTORIA AND
TASMANIA
HIGHLIGHTS

Located within gas producing region, Tasmanian area underexplored

Water depths range from 75–1,000 m

Recent successful exploration and good data coverage

Access to existing infrastructure and growing energy market
The eastern Otway Basin is an established gas producing province that delivers gas to the
southeastern Australian energy market. The Release Areas are partly located in shallow water
within and close to the highly prospective Shipwreck Trough and, further south, offer untested
targets along the eastern basin margin southward into Tasmanian waters.
Recent petroleum geochemical studies suggests that three petroleum systems are accessible
within the Release Areas. Two Late/Early Cretaceous systems are known gas producers and one,
involving potential Turonian source rocks and assessed as being capable of producing liquids,
remains untested.
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LOCATION
The three 2012 eastern Otway Basin Release Areas are located approximately 300 km westsouthwest of Melbourne, the State Capital of Victoria, which has a population of approximately
4 million (Figure 1). The greater Melbourne region currently represents Australia’s largest domestic
gas market and is supported by major petroleum refineries. The City of Portland is the nearest
centre (population approximately 10,000) along the western Victorian coast. Portland is known for
its deep water port, established for the large aluminium smelting operations. The port can be used
for offshore operations and is serviced by an excellent road and rail network.
Release Area V12-1 is located about 20 km southwest of the town of Port Campbell, and lies
between the producing gas fields of Minerva and Casino. This release area lies in shallow water
(50-70 m) and comprises one graticular block only, covering 67 km2 (Figure 2).
Release Area V12-2 is between 50 and 75 km southwest of Port Campbell and is adjacent to the
Geographe, Thylacine and La Bella gas fields. This area has water depths of 80-110 m and
comprises four graticular blocks (two full and two partial), covering an area of 187 km2 (Figure 2).
Release Area T12-1 is located in Tasmanian waters immediately to the south of Victoria-Tasmania
scheduled boundary. It comprises a total of 73 graticular blocks (68 full and 5 partial) and covers
4,690 km2 (Figure 2). Water depths are generally less than 100 m, although the Release Area
extends over the continental shelf break in the southwest (Figure 1).
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RELEASE AREA GEOLOGY
Local tectonic setting
Most of the major structural features of the offshore central Otway Basin were initially developed by
Late Cretaceous rifting and transpressional folding, and later modified by late Paleogene
compression. Seismic mapping clearly shows the development of two main structural provinces in
the area of interest (Figure 3).
Release Area V12-1 lies within the Shipwreck Trough, a region that is a proven commercial gas
province. The Shipwreck Trough is a prominent north-south oriented syncline that separates the
Mussel and Prawn platforms.
Release Area V12-2 lies to the south of Release Area V12-1, and is located in the western part of
the Shipwreck Trough, also crossing the Tartwaup-Mussel Fault Zone and the Voluta Trough to the
south. The Tartwaup-Mussel Fault Zone is a series of northwest striking faults that are laterally
extensive with individual trends able to be traced over 30-80 km and which propagate upwards to
the Late Maastrichtian unconformity where they are either truncated or show only relatively minor
reactivation.
Release Area T12-1 lies on the southern extension of the Prawn Platform to the southeast of the
Shipwreck Trough, and to the west of the King Island High. The Release Area lies at the northern
end of a zone of transition from extension (Otway Basin) through transtension to a dominantly
strike-slip tectonic regime south of Tasmania.
Structural evolution and depositional history of the Release Areas
Structural growth occurred on the faults throughout the Late Cretaceous with the Sherbrook Group
showing variable amounts of offset along the fault zones. Along the Tartwaup-Mussel Fault Zone,
structural closure is associated with rollovers and tilted fault blocks with structures at the top
Waarre Formation level. The Tartwaup-Mussel Fault Zone became the principal basin-margin fault
zone in the late Cenomanian as rifting intensified (~83 Ma; O’Brien et al, 2006), and strongly
controlled the deposition of the Sherbrook Group. South of this fault zone, the Sherbrook Group is
typically very thick with a marine character, whereas to the north of the fault, it is much thinner and
more terrestrial in character. Within the Voluta Trough itself, tilted fault blocks dominate, with a
number of very large features mapped by previous explorers. Closures associated with these
structures were targeted further west by wells such as Bridgewater Bay 1, Voluta 1 (Figure 1),
Discovery Bay 1 and Normanby 1, but are at significant depths (typically deeper than 3,500 m),
unlike the Mussel Platform prospects to the east. The Voluta Trough is predominantly a Late
Cretaceous depocentre.
The Mussel and Crayfish platforms to the north see a dramatic thinning of the Upper Cretaceous
succession over the Tartwaup and Mussel fault zones, respectively. In the area of the Portland
Trough lies a major Paleogene depocentre with around 1,000 m of Wangerrip Group sediments
along its axis. This trough is a relatively unfaulted syncline, rather than a graben.
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The Shipwreck Trough is a structural depression between the Prawn Platform to the east and the
Mussel Platform to the west (Figure 3). This trough and its immediate surrounds contain most of the
significant gas discoveries that have been made in recent years and it may be an important source
kitchen. The north-northwest-trending Shipwreck Fault Zone forms the eastern structural boundary
of the trough.
To the south, the Prawn Platform shows less structural relief and the Shipwreck Fault Zone
becomes less well defined. The Tartwaup-Mussel Fault Zone, formed by a series of west–northwest
oriented, southward-dipping normal fault segments, truncates the southern end of the Shipwreck
Trough (Figure 3) in which the preserved structures and sedimentary sequences provide a record
of both rift phases and the development of the basin margin. The Shipwreck Fault Zone, which
separates the northern section of the Prawn Platform from the Shipwreck Trough is the only major
structural feature to survive the severe overprinting of northeast-southwest early Oligocene to
Holocene compressional folding. This folding obscures the sometimes complex faulting of the
platform. In addition, the development of the smaller scale, north trending Late Cretaceous folds is
also not clearly shown.
Southeast of the Shipwreck Trough, offshore western Tasmania, an abrupt change in basin
geometry from northwest-southeast to dominantly north-south or northeast-southwest-trending
structures is identified (Sorell and eastern Otway basins). A reactivated north–south Paleozoic
shear zone (Avoca-Sorell Fault System) controls the transition from extension through transtension
to a dominantly strike-slip tectonic regime in this part of the southern margin. This shear zone was
optimally oriented for strike-slip reactivation during Late Cretaceous–Cenozoic north–south rifting,
strongly influencing the pattern and geometry of subsequent deposition (Gibson et al, 2011).
The stratigraphy of the Otway Basin has been established by Morton et al (1994, 1995) with
refinements from Perincek et al (1995), the Geological Survey of Victoria (1995), Lavin (1997),
Partridge (1997, 2001) and Geary and Reid (1998). Comprehensive descriptions are also given by
Reid et al (2001) and in the Otway Basin REGIONAL GEOLOGY document. A sequence
stratigraphic framework for the Otway Basin by Krassay et al (2004) recognised seven major basin
phases and eight supersequences. Petroleum systems elements in the basin are hosted by the
Lower Cretaceous Otway Group and the Upper Cretaceous Sherbrook Group (Figure 4).
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EXPLORATION HISTORY
Petroleum exploration in the offshore part of the Otway Basin commenced in 1959, with the first
offshore permits, PEP 22, PEP 40 and PEP 49 awarded to the Frome-Broken Hill consortium.
Extensive offshore aeromagnetic surveys were carried out in 1960 and 1961, providing the first
accurate indication of the basin’s offshore extent. This was followed by the first marine seismic
survey off Warrnambool in 1961. In 1966, Esso and Shell farmed into the offshore Otway Basin
hoping to find an analogue to the Gippsland Basin, which by then had just experienced a raft of
new, large gas and oil discoveries. Their efforts were, however, largely unrewarded. Pecten 1A, the
first offshore well in the Otway Basin, was drilled on the Mussel Platform by Shell in 1967. The well
flowed dry gas at 0.145 MMcfd from a test of a sandstone interval in the Upper Cretaceous Waarre
Formation.
Esso farmed into PEP 40 and PEP 49, and drilled two offshore wells; Nautilus 1 in 1968 and
Mussel 1 in 1969. Both wells were plugged and abandoned with no significant shows encountered.
Between 1970 and 1975, the offshore permits were re-issued, with PEP 22 becoming VIC/P10,
PEP 40 becoming VIC/P6, and PEP 49 becoming VIC/P7. Shell and Interstate Oil Ltd (IOL) jointly
held VIC/P10, while Hematite Petroleum (a BHP subsidiary and a member of the original FromeBroken Hill consortium) held permits VIC/P6 and VIC/P7. Esso Exploration, in joint venture with
Hematite Petroleum, drilled two dry wells in offshore Tasmania: Prawn A1 (1967) and Whelk 1
(1970)
Seismic surveys were undertaken in the offshore petroleum exploration permit areas by Hematite
(between 1972 and 1976) and by Shell and IOL (between 1970 and 1975). By 1976, discouraged
by the lack of commercial oil or gas discoveries, the major companies had begun to withdraw from
the Otway Basin. Little exploration work was carried out between 1975 and 1980 and the petroleum
exploration permits were relinquished progressively. In 1980, three permits VIC/P14, VIC/P15 and
VIC/P16 were awarded covering much of the shelfal portion of the basin. Phillips Petroleum drilled
two wells in VIC/P14; Discovery Bay 1 in 1982 and Bridgewater Bay 1 in 1983. Neither well
encountered significant hydrocarbon shows. In 1982, Esso drilled Triton 1 ST1, located in the
eastern offshore Otway Basin, again without encountering any significant hydrocarbons. Between
1986 and 1988, with the exception of VIC/P14, the permits were relinquished progressively and
very little exploration was undertaken.
In 1990, BHP Petroleum (BHPP) farmed into VIC/P14, and in the same year, was awarded two new
petroleum exploration permits; VIC/P30 and VIC/P31. These permits covered a large proportion of
the Mussel and Prawn platforms in the eastern part of the basin. BHPP recorded in excess of
3,500 line km of regional and semi-regional marine seismic data, including the 3,200 line km
OH91B seismic survey which covers part of the Mussel Platform. In 1993, BHPP made two gas
discoveries on the Mussel Platform (Minerva 1 and La Bella 1), and drilled two dry wells;
Eric The Red 1 and Loch Ard 1, on the eastern flank of the Shipwreck Trough. After drilling an
additional two wells that recorded only scattered gas shows, BHPP relinquished the permits in
1997, though retention permits were taken out over the Minerva and La Bella fields.
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Since 1999, there has been a strong resurgence in exploration activity in the both the Victorian and
Tasmanian parts of the Otway Basin, with increased success rates driven largely by technological
advances such as 3D seismic. A major exploration program by the Woodside Joint Venture in
VIC/P43 and T/30P which recorded over 1,000 km 2 of 3D seismic (Investigator 3D Seismic Survey)
led to the in the discovery of the large Geographe and Thylacine gas fields in 2001. Geographe is
located within Victorian waters and Thylacine in Tasmanian waters. Another commercial gas
discovery, Casino 1, located about 20 km southwest of the Minerva field, on the western flank of the
Shipwreck Trough, was made by Strike Oil in 2002. Discoveries were made in 2004 and 2005 by
Santos Limited at Martha 1 and Henry 1 respectively, and by the Woodside Energy-Origin Energy
Joint Venture at Halladale DW1 and Halladale DW2 in 2005, both of which are nearshore wells.
The Henry and Casino gas developments, originally in VIC/P44, are now operated by Santos
Limited. These developments are the company’s main projects to expand their southern gas
assets; production from the Casino gas field commenced in 2006 and the Henry gas field in early
2010. In the Tasmanian sector the only well since 2001 was Somerset 1 by Woodside in October
2009, which was a dry hole.
Overall, there has been an increase in both the exploration success rates and the size of fields
discovered over the last few years within the Otway Basin. This is probably due to a combination of
factors, which include dramatically improved trap definition (a result of 3D seismic acquisition), an
improved understanding of seal integrity (especially fault seal integrity) and an overall improved
understanding of the critical success factors in the region (O’Brien and Thomas, 2007; O’Brien et al
2009).
Well control
Well control for the 2012 Release Areas is provided by a number of gas discovery wells mainly in
the Shipwreck Trough. Three wells have been drilled on the Prawn Platform (Loch Ard 1,
Eric The Red 1 and Prawn A1), and although all were unsuccessful, they provided valuable
information. In addition, onshore wells can be used to provide a good understanding of the overall
stratigraphic framework in the Otway Basin, especially the Lower Cretaceous succession which has
been penetrated by several exploration wells.
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PORT CAMPBELL 1 (1960)
Port Campbell 1 was drilled in 1959-1960 by Frome-Broken Hill Company Pty Ltd to test a closed
structure within a faulted anticline with a north-south trending axis. The well was the first petroleum
test well to be drilled in the southeastern Otway Basin, and reached a total depth of 1,818 mRT in
the Waarre Formation. The Waarre Formation was found to have excellent reservoir properties in
the interval 1,725.2-1,726.7 mRT with porosity values up to 26.5% and permeabilities as high as
2,985 mD (H) and 1,695 mD (V). Below this interval the formation was predominantly tight. Top and
lateral seal was provided by the Belfast Mudstone, and closure to the north, south and west relied
at least in part by fault seal. A strong but non-commercial gas flow with a small amount of
condensate was produced during a production test from the interval 1,724-1,727.6 mRT. The
pressure and flow rates rapidly dropped and did not recover, and the well began producing
increasing volumes of saline water. It was not known whether the gas-bearing interval was a small
lens or truncated from the main reservoir by faulting. The well was plugged and abandoned.
PORT CAMPBELL 2 (1960)
Following the intersection of gas-bearing sands in Port Campbell 1, the Frome-Broken Hill
Company Pty Ltd drilled a series of wells to test the hydrocarbon potential of the Port Campbell
area. Port Campbell 2 was drilled in 1960, and was located about 2 km north of Port Campbell and
3 km southeast of Port Campbell 1. It was drilled down-dip from the first well with the objective of
testing a thicker section with pinch-out indicated by a seismic survey. The target structure was
bounded to the northwest by a north-south trending fault dowthrown to the east, and the well was
drilled on the downthrown side of the fault within closure. The well reached a total depth of
2,543 mRT in the Eumeralla Formation.
The well was targeted to test a predicted thicker section of the same hydrocarbon bearing sand at
the top of the Waarre and base of the Flaxman formations encountered in Port Campbell 1.
However, the reservoir quality was not as good as at Port Campbell 2, with fair porosity and low to
fair permeability in comparison to the excellent reservoir properties found in the first well. No free
gas or oil was apparent in Port Campbell 2, although a small amount of gas dissolved in formation
water was obtained during drill stem testing. It was concluded that the well was either located too
far down-dip to be within closure, or that the anticipated fault trap was either non-existent or too
small. The well was completed as a water bore for state authorities.
PORT CAMPBELL 3 (1961)
Port Campbell 3 was drilled in 1961 by the Frome Broken Hill Company Pty Ltd approximately 5 km
west-northwest of Port Campbell 1. This well was drilled to test a structure identified through
seismic analysis to have good east-west relief and southerly closure, although closure to the north
was identified as being fault-dependent. Core samples in the Waarre Formation (1,425.9 and
1,426.8 mKB) exhibited very high visual porosity and permeability; however analysis of the samples
indicated permeabilities of 4.84 and 1.00 mD respectively, with an average porosity of 23.7%. They
were found to be water saturated.
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Porosity was also recognised on log analysis of the Eumeralla Formation, although at much lower
percentages than in the Waarre Formation. A small amount of gas was recovered from the interval
1,510.6-1,512.7 mKB in the Eumeralla Formation, which was significant as it was the first record of
gas from this unit. High mud gas readings, encountered within the Paaratte Formation (over the
interval 1,158.2-1,280.2 mKB), were thought to be related to the well penetrating a fault-zone,
although the exact location of the fault within the well is not known. The well was plugged and
abandoned.
PORT CAMPBELL 4 (1964)
Port Campbell 4 was drilled in 1964 into what was thought to be the crest of the anticlinal Port
Campbell structure, to the northeast of Port Campbell 3. It was expected that the well would
encounter a thicker Upper Cretaceous succession. The well was located northeast of the
culmination (at the Otway Group level) of an anticline striking northeast-southwest. The anticlinal
trend is on the south and downthrown side of a west-northwest–east-southeast oriented fault.
Port Campbell 4 was primarily drilled to further evaluate the reservoir potential and formation fluid in
the Waarre Formation, although following the gas shows detected in the Otway Group at
Port Campbell 3, the secondary objective of this well was to penetrate and evaluate the
hydrocarbon prospectivity and reservoir characteristics of the Otway Group. The well reached TD at
2,596.9 mRT, having penetrated 972 m of the Eumeralla Formation.
Reservoir properties of the Eumeralla Formation were evaluated though log analysis, and porosities
ranged from 8.2-19.8% while permeabilities were nil to very low (maximum of 2.5 mD). The poorly
consolidated sands of the Waarre Formation exhibited good visual porosity, and formation testing
revealed good porosity (21-25%) and permeability (34-264 mDvert and 302-426 mDhor) throughout
the Nullawarre Greensand. Small quantities of crude oil and gas were recorded in two intervals in
the Eumeralla Formation (1,811.1-1,822.7 mRT and 1,789.2-1,799.2 mRT); the gas encountered
was largely methane (83.3%) with no CO2 detected. Formation testing also revealed traces of oil in
the intervals 2,205.2-2,232.7 mRT and 2039.4-2,062.0 mRT. The Waarre Formation was found to
be water saturated with saline formation fluids. The well was plugged and abandoned with strong oil
and gas shows.
PECTEN 1° (1967)
Pecten 1A was drilled by Shell Development (Australia) Pty Ltd in 1967 on the Mussel Platform to
evaluate the Waarre Formation, sealed by the Belfast Mudstone, in a seismically mapped anticlinal
closure dissected by northwest-trending normal faults. The well was spudded in 62.5 m of water
and was drilled to a TD of 2,850 mRT. A gross gas column of 17.5 m was intersected in the Waarre
Formation which flowed gas at 0.145 MMcfd on test. The flow was deemed uneconomic and the
well was plugged and abandoned.
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PRAWN A1 (1968)
Prawn 1 was drilled by Esso in 1968. The well was drilled on a mapped anticlinal feature in
southern sector of the Prawn Platform to test reservoir sands below the base of the Cenozoic. It
was spudded in 108 m of water and reached TD at 3,193 mKB in the Eumeralla Formation before
being plugged and abandoned with no significant shows.. The absence of hydrocarbons was
attributed to a lack of seal in the Upper Cretaceous section.
NAUTILUS A1 (1968)
Nautilus A1, drilled by Esso Exploration and Production Inc in 1968, was spudded in 100 m of water
and reached a TD of 2,011 mKB in the Belfast Mudstone (Sherbrook Group). The well targeted a
Paleogene ‘clastic wedge’ stratigraphic play on the northeastern flank of the Voluta Trough.
However, the target section proved to be composed entirely of marl with no reservoir present. No
significant hydrocarbon indications were encountered and the well was plugged and abandoned.
MUSSEL 1 (1969)
Mussel 1 was drilled by Esso Exploration and Production Inc in 1969 to evaluate the Waarre
Formation on a tilted fault block closure on the Mussel Platform. It was spudded in 85 m of water
and reached a TD of 2,450 mRT. No hydrocarbons were encountered and the well was plugged
and abandoned. Based on the current interpretation, the well appears to have been drilled within
closure but significantly downdip from the mapped crest of the structure.
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WHELK 1 (1970)
Whelk 1 was drilled in 103 m of water by Esso Standard Oil (Australia) Limited in 1970, to test for
the presence of the Waarre Formation in an anticline extending over 44 km2 with 91 m of vertical
closure. It was anticipated that the Waarre Formation would be 274 m thick and lie within the
transition from coarse clastics in the north (Prawn A1) to very fine grained clastics in the south
(Clam 1) and therefore was likely to have good reservoir characteristics. The well intersected 94 m
of Waarre Formation which consisted of dominantly coarse to very coarse-grained sandstone.
Lithologic and well-log correlations as well as velocity survey data place the top of the formation
136 m lower than predicted. The silty shales of the Belfast Formation, the regional seal in the
Otway Basin, were not present, although coeval silty sandstones were encountered.
Whelk 1 was drilled to a total depth of 1,446 m, intersecting basement at approximately 1,404 m.
The well was plugged and abandoned as a dry hole. Failure has been attributed to either the lack of
source or adequate seal.
GRUMBY 1 (1981)
Grumby 1 was drilled by Beach Petroleum N.L. in 1981 to test a dip closure on the southeastern
flank of the Port Campbell High, to the south of the North Paaratte gas field. The well reached TD at
1,913 m in the Eumeralla Formation. It encountered a gas-saturated Waarre Formation at
1,664.5 m, with the GWC at 1,686.5 m, giving a total of 17 m net gas bearing sand. The recovered
gas contained 51.7% CO2, and the gas/condensate ratio was greater than 6 bbl/MMscf . Grumby 1
was completed and suspended as a potential gas producing well.
TRITON 1 (1982)
Triton 1 was drilled by Esso Exploration and Production Australia in 1982 targeting the Waarre
Formation within an interpreted fault-controlled closure. The well was spudded in 100 m of water
and reached a TD of 3,545 mKB. The Waarre Formation exhibited poor reservoir development and
was water wet. The well was plugged and abandoned. No closure was mapped over the structure
(Geary and Reid, 1998). However, of significance was the intersection of a thin sandstone interval
at the base of the Paleogene section that produced a C1 to C6 mud gas peak, possibly indicative of
oil.
LA BELLA 1 (1993)
La Bella 1 was drilled by BHP Petroleum Pty Ltd in 1993, on the outer Mussel Platform to test
closure mapped at the Waarre Formation level in a tilted fault block. The well was drilled in 94 m of
water and reached a TD of 2,735 mRT in the Waarre Formation. Hydrocarbons were encountered
in sands of both the Flaxman (15 m gross column) and Waarre (65 m gross column) formations.
RFT pressure data indicate that these are separate accumulations. No DSTs were run, but RFT
samples showed that the gas is predominantly methane with a relatively high CO2 content (12.513.3 mol%) with minor condensate. Gas-in-place is estimated by Luxton et al (1995) at 210 Bcf
(5,946x106 m3). The well was plugged and abandoned as a sub-commercial gas discovery.
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ERIC THE RED 1 9(1993)
Eric The Red 1 was drilled by BHP Petroleum in 1993 and targeted a faulted anticline in the Upper
Cretaceous Sherbrook Group. Extensional faulting formed a series of fault blocks with east-west dip
closure, but the block in which the well was drilled relied upon fault seal to the north and south.
Upper Sherbrook Group sediments were expected to provide adequate cross-fault seal, but this
section was much sandier than predicted, which resulted in inadequate seal integrity and the failure
of the structure. No significant gas shows were observed and the section was water saturated.
Thermal maturity data and vitrinite reflectance measurements indicated that the Sherbrook Group is
thermally immature, whereas the Otway Group is marginally mature at the total depth of 1,875 mRT
(Wong, 1994).
MINERVA 1 (1993)
Minerva 1, drilled by BHP in 1993, was designed to test the hydrocarbon potential of the lower
Waarre Formation within a northern tilted fault block located on the broader Minerva structure.
Secondary targets included mapped anticlinal closures within the Sherbrook Group (Paaratte
Formation, and the Belfast and Skull Creek mudstones) and the Wangerrip and Nirranda groups,
which had only minor fault dependence. Claystones of the Belfast Mudstone were interpreted to
provide both the vertical and cross-fault sealing to the gas-bearing reservoirs. Minor gas shows in
the Skull Creek Mudstone and Flaxman Formation indicate that these units may represent valid
targets elsewhere in the structure, where they may be thicker and of better quality. The main gasbearing sand within the Waarre Formation was intersected in the interval 1,815-1,948 mRT, where
average porosities of 18% and average hydrocarbon saturations of 81% were measured (Locke,
1994a). Production testing resulted in gas flowing at a rate of 28.4 Mcf/d, with a CGR of 2 stb/Mcf.
MINERVA 2° (1993)
Minerva 2A was drilled as an appraisal well by BHP Petroleum in 1993, as a follow-up to the
Minerva 1 discovery. The objective was to confirm the extension of the gas-bearing reservoir within
the southern fault block of the Minerva structure. Secondary targets included gas-bearing sands in
the Flaxman Formation and sand horizons within the Skull Creek Mudstone that had yielded gas
shows in Minerva 1. The Skull Creek Mudstone had only minor gas shows, but a gas-bearing
interval of 20 m (10 m net) was penetrated within the Flaxman Formation. In the Waarre Formation,
a total 98 m of net gas was interpreted over a 111 m interval, with an average porosity of 19% and
average hydrocarbon saturation of 85% (Locke, 1994b). The gas and water gradients intersected in
the Waarre Formation in the Minerva 2A reservoir were within 2% of the corresponding gradients
measured in Minerva 1. Pressure data indicated that the wells either are, or were at some stage, in
hydraulic communication.
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LOCH ARD 1 (1993)
Loch Ard 1 was drilled by BHP Petroleum in 1993 to evaluate the hydrocarbon potential of the
Sherbrook Group, specifically the Waarre and Flaxman formations and the Nullawarre Greensand
equivalent, in a faulted anticlinal structure. Claystone intervals within the Sherbrook Group were
expected to provide lateral seal across the faults. As with Eric The Red 1, the sealing lithologies
encountered in Loch Ard 1 were much sandier than predicted, resulting in incompetent fault seal
and hence the loss of any hydrocarbons that may have migrated into the trap structure. No
significant hydrocarbons were intersected and all sandstones encountered were water-saturated.
The geothermal gradient measured at total depth (1,397 mRT) in the Lower Cretaceous Otway
Group was slightly lower than expected, which may have adversely affected maturation of the
source intervals (Mustica, 1994).
LANGLEY 1 (1993)
The Langley prospect was identified as a result of the 1993 Waarre 3D seismic survey, and
Langley 1 was drilled by GFE Resources in 1994, targeting an elongate tilted fault block with crests
at either end. The western crest (site of Langley 1) was fault bounded to the southeast and
southwest with no fault-independent closure. The well reached TD at 2007 m in the Eumeralla
Formation. The main target was the Waarre Formation, which was interpreted as being juxtaposed
against the Belfast Mudstone in the hanging wall block, and therefore laterally sealed to the south.
A 23 m gas column was encountered at the top of the Waarre Formation Unit C, although this gas
was found to be one-third dry hydrocarbon gas and two-thirds CO2, making it uncommercial to
develop for either commodity. The high proportion of CO2 in the gas encountered in Langley 1
supported previous work indicating that proximity to major north-east trending faults increased the
likelihood of high CO2 content within the structure (Lanigan, 1996). The well was plugged and
abandoned as a non commercial gas (CO2) discovery.
CONAN 1 (1995)
Conan 1 was drilled by BHP Petroleum Pty Ltd in 1995 on the Mussel Platform which borders the
western margin of the Shipwreck Trough. It was drilled to test closure mapped at the Waarre
Formation level associated with a tilted-fault block. The well was drilled in 70 m of water to a TD of
1,985 mRT. Good to excellent reservoir sands were encountered in the Waarre Formation but they
proved to be water wet. A section of the lower Belfast Mudstone, Flaxman Formation and part of
the upper Waarre Formation were absent, most likely through uplift and subsequent erosional
truncation. The well was drilled within closure. A lack of cross-fault seal due to sand development in
the Flaxman Formation or the Belfast Mudstone is thought to be the most plausible explanation for
well failure.
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THYLACINE 1 (1999)
The Thylacine prospect was identified following the 1999 Investigator 3D seismic survey, and
Thylacine 1 targeted a composite horst structure on a north-northeast-trending ridge within the
Shipwreck Trough. It was drilled by Origin Energy Resources Ltd in 2001 in 101 m of water and
reached a TD of 2,710 mRT in the Waarre Formation (Origin Energy, 2003). The well intersected a
277.1 m gross (139.5 m net) gas column over the interval 2,049-2,326 mRT in sands that spanned
the Thylacine Member (Belfast Mudstone), a sequence of alternating fine to medium grained, well
sorted sandstone, siltstone and minor claystone, as well as the Flaxman and Waarre formations.
The Thylacine field is the largest gas discovery made in the Otway Basin, according to Cliff et al
(2004).
GEOGRAPHE 1 (2001)
The Geographe prospect was identified from the Investigator 3D seismic survey on a southwestplunging anticline which extends from the Otway Ranges. Geographe 1 was drilled by Origin
Energy Resources Ltd in 2001 in 85 m of water and reached a TD of 2,430 mRT in the Waarre
Formation. The well intersected a 233 m gross (56.9 m net) gas column in the interval 1,8172,050 mRT in the Thylacine Member of the Belfast Mudstone and the Flaxman Formation (Cliff et
al, 2004). The Thylacine Member comprises the bulk of the reservoir interval in both the Thylacine
and Geographe fields. The Waarre Formation here has excellent reservoir qualities, with
considerable lateral extent. The gas-water contacts for Thylacine 1 and Geographe 1 are within the
upper Waarre and Flaxman Formations respectively. The well was not tested, so a 7 inch (17.8 cm)
liner was run and the well was plugged and suspended as a gas discovery.
THYLACINE 2 (2001)
Thylacine 2 was drilled by Origin Energy Ltd in 2001 to follow up the gas discovery made in
Thylacine 1. It tested the Waarre Sandstone, and was drilled to a TD of 2,525 mRT in about 100 m
of water. Gas was encountered at 2,053.8 mRT, 2165.8 mRT, 2236.8 mRT, 2,279.1 mRT and
2,302.4 mRT, with water recovered at 2,344.5 mRT. Condensate-gas ratios range from 20-33
bbls/MMscf. The well confirmed the gas occurrence in the Thylacine field and was plugged and
abandoned.
GEOGRAPHE NORTH 1 (2001)
Geographe North 1 was drilled by Origin Energy in 2001 to test a faulted anticline about 3 km north
of the Geographe 1 gas discovery. It was spudded in 82 m of water and reached a TD of
2,156 mRT. It encountered thin Flaxman Formation above Waarre Formation and only minor gas
indications. It was concluded that the prospect failed due to either trap failure (fault leakage) or lack
of charge due to migration problems. Geographe North 1 was plugged and abandoned as a gas
show.
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13
MINERVA 3 AND MINERVA 4 (2002)
Minerva 3 and Minerva 4 were both drilled by BHP Billiton in 2002 as development wells to access
gas in structures up-dip from Minerva 1 and Minerva 2A respectively (Ellis 2003a, 2003b). Both
were completed successfully and gas production commenced in 2004.
M ARTHA 1 (2004)
Martha 1 was drilled by Santos Limited in 2004 primarily to test the hydrocarbon potential of the
Waarre Formation, especially the Waarre ‘C’ unit sands, with a secondary target identified as an
intra-Belfast seismic signal indicative of a gas–charged reservoir. The Martha structure was a tilted
fault block with three-way dip closure and up-dip fault closure, and forms the highest point on the
greater Pecten High. The well spudded in 55 m of water, about 7 km NE of Pecten 1A, and reached
TD at 1,800 m within the Eumeralla Formation. The predicted Waarre ‘C’ Unit was identified as the
Waarre ‘A’ Unit, and contained hydrocarbons. The secondary target was determined to be gas pay
within the Paaratte Formation. Log analysis indicated 12.2 m of net gas pay in the Paaratte
Formation with an average porosity of 23.8% and water saturation of 55%. The Waarre ‘A’
sandstone contained 9.2 m of net gas pay with an average porosity of 23.3% and water saturation
of 53%. The well was plugged and abandoned as a non-commercial gas discovery.
HALLADALE 1 DW 1 (2005)
Halladale 1 DW1 (2005) was the first in a three well programme drilled by Origin Energy Resources
Ltd to test two adjacent fault-dependent closures in the Waarre and Nullawarre formations in
VIC/P37(V). The wells were directionally drilled from a common top-well section, then steered to
their respective targets. Halladale 1 DW1 targeted the southern prospect, Black Watch, and was
drilled vertically down to 833.5 mMD, then directionally steered to its primary and secondary
targets, reaching a TD of 1,918 mMD in the Eumeralla Formation. Both targets contained
hydrocarbons, with 21.6 m of net gas pay in the Upper Nullawarre, Lower Nullawarre, Waarre C
and Waarre ‘A’ over a gross vertical interval of 299 mTVD (Constantine et al, 2007) Geochemical
analysis of the gas samples recovered from the Waarre C unit indicates that the gas is relatively dry
(87.8% C1), with a Condensate to gas ratio of 12.6 bbls/MMscf and an inert content of 2.48% (N2
and CO2). The well was plugged at 833.5 mMD as a gas discovery, allowing the drilling of
Halladale 1 DW2 and Halladale 1 DW3. Origin plans to develop the Halladale/Blackwatch field with
production wells directionally drilled from onshore and gas to be processed at either the Iona or
Otway processing facilities.
PECTEN EAST 1 (2008)
Pecten East 1 was the first well drilled in Santos’ 2008 drilling campaign to test Vic/P44. It was
drilled down-dip of the Henry gas field and reached TD at 1,993 mKB. The target was the Waarre
‘A’ sand, and gas shows were seen during drilling in the interval 1,865–1,942 mKB. However,
petrophysical analysis indicated the presence of only residual gas, and the well was plugged and
abandoned as a strong gas show.
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SOMERSET 1 (2009)
Somerset 1 was drilled approximately 15 km southwest of the Thylacine gas field by Woodside
Energy Ltd in 2009. The well was drilled in 503 m of water and reached a total depth of 2,912 mRT,
with the primary target being sandstones within the Upper Cretaceous Sherbrook Group. It was
plugged and abandoned without encountering any significant hydrocarbons.
HENRY GAS FIELD
The Henry gas field was discovered in 2005 by Santos Limited with the drilling of Henry 1 ST1. This
well, located some 8.5 km northwest of the Casino gas field, was drilled in 67.5 m of water to a
TD of 2,100 mRT (Henry 1), with the sidetrack (Henry 1 ST1) reaching a TD of 2,032 mRT. Gas
was discovered in the Waarre Formation. In 2008, Henry 2 and Netherby 1 were drilled as
development wells, and first gas production was achieved from the Netherby 1 well in February
2010.
CASINO GAS FIELD
The Casino gas field was discovered with the drilling of Casino 1 well in 2002. It was drilled by
Santos Limited in 70.5 m water and reached a TD of 2,118 mRT in the Eumeralla Formation.
Casino 1 was drilled to test a prospect mapped by Strike Oil on newly acquired seismic which
imaged a high amplitude zone within a tilted-fault block with three-way dip closure and updip fault
closure. Gas was discovered in the Waarre Formation. Appraisal wells Casino 2 (2002) and
Casino 3 (2003) intersected a younger reservoir within the Waarre Formation, increasing gas
reserves sufficiently to justify economic development of the field (Sharp and Wood, 2004)
Further details regarding wells and available data follow this link:
http://www.ret.gov.au/Documents/par/data/documents/Data%20list/data%20list_easternotway_AR12.xls
Data coverage
Seismic coverage over the Release Areas is generally very good to excellent, with the best
coverage over the Shipwreck Trough. Modern 2D seismic surveys include the Otway-Sorell
Albatross 2D survey (ds01) acquired by Fugro Multiclient Services in 2001 and a subsequent
survey (ds02) acquired in 2002 for Woodside Energy Ltd. These surveys cover the northern section
of Release Area T12-1. This part of the Otway Basin is also well covered by several regional
surveys that were acquired by the Australian Geological Survey Organisation (AGSO – now
Geoscience Australia). 3D seismic coverage is limited to Release Area V12-2, which is covered by
the 1999 Investigator 3D, acquired by Woodside Energy Ltd.
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Several potential field datasets are available over the Release Areas. 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 in 2008. These data were merged with
onshore aeromagnetic datasets to create a nearly 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
Other data
In 2002, the Victoria Department of Primary Industries (DPI) published a report on the basementbasin relationships in the onshore and offshore Otway Basin (Moore, 2002) This report gives the
results of an integrated study of potential field, bathymetric and seismic data that examined the
relationship between the Otway Basin and its basement. It suggests possible correlations between
the hydrocarbon accumulations and the basement. In order to test the validity of the potential field
method, the report also compares the interpretation of the potential field data with a pre-existing
seismic interpretation over the Torquay Sub-basin.
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PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL
Sources
•
Upper Cretaceous-lowest Paleocene (Austral 3 – Sherbrook Group,
unproven)
•
Aptian-Albian (Austral 2, 99% of discovered hydrocarbons – Eumeralla
Formation)
•
Upper Jurassic-lowest Cretaceous (Austral 1 – Crayfish Subgroup, Casterton
Formation)
Reservoirs
Seals
•
Pretty Hill Formation (Lower Cretaceous)
•
Waarre and Flaxman formations (Upper Cretaceous)
•
Belfast Mudstone (Thylacine Member; Upper Cretaceous)
•
Paaratte Formation (Upper Cretaceous)
•
Pebble Point Formation (Paleocene)
•
Belfast Mudstone (Upper Cretaceous)
•
Massacre Shale (uppermost Cretaceous/Paleocene)
•
Pember Mudstone and Dilwyn Formation (Paleocene-Eocene) and Mepunga
Formation (Eocene).
Play Types
•
Waarre/Flaxmans formations sealed by Belfast Mudstone; stacked reservoirseal units within Paaratte Formation, top seal by Belfast Mudstone; top
Paaratte Formation/Timboon Sandstone sealed by mudstone units within the
Wangerrip Group (Massacre Shale, Pember Mudstone, Dilwyn Formation or
Mepunga Formation)
•
possible pre-Waarre Formation play, targeting the Heathfield or Windermere
Sandstone members of the Eumeralla Formation
•
Traps: Faulted anticlines, tilted fault blocks with cross-fault seal.
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Petroleum Systems
The Release Areas are a mix of shallow water regions with a proven petroleum system (Austral 2)
and deeper water frontier areas within which the Austral 3 petroleum system is unproven. O’Brien
and Thomas (2007) and O’Brien et al (2009) have shown that the vast majority of the hydrocarbon
inventory discovered within the Victorian Otway Basin has been generated by the Austral 2
petroleum system. The Austral 2 system consists of Lower Cretaceous (Albian-Aptian) organic-rich
source rocks which have generated hydrocarbons and charged the overlying basal Upper
Cretaceous Waarre siliciclastic reservoir unit. Commercial accumulations in the offshore and
onshore basin are restricted to areas within approximately 3000 m of where the Austral 2 petroleum
source rocks are actively generating and expelling hydrocarbons (Figure 6). This interval typically
occurs at depths below the seafloor of about 2,500-4,000 m. This observation has allowed the
prospective areas of the Otway Basin, where the Austral 2 system is currently at peak hydrocarbon
generation, to be mapped (Figure 7). It may be that the accumulations only occur close to the
generating source rocks because the faults which bound the accumulations within the Otway Basin
often leak - hence viable traps are located only in areas where the hydrocarbon charge rate
exceeds the average leakage rate.
Source Rocks
Source rocks of the Lower Cretaceous Austral 2 petroleum system charged the producing gas
fields and other undeveloped discoveries in the Otway Basin. These include the onshore fields in
the Port Campbell Embayment and all offshore gas fields in the greater Shipwreck Trough area.
Source intervals comprise coals and carbonaceous shales within two coal measure sequences in
the Aptian-Albian Eumeralla Formation. The older occurs at the base of the Eumeralla Formation
corresponding to the P. notensis spore-pollen zone and the younger lies in the middle of the
formation and corresponds to the C. striatus spore-pollen zone. Although geochemical analyses
suggest the source rocks have significant potential for liquids generation, well results to date
suggest that they have produced mainly gas with only small quantities of condensate and oil.
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Both the P. notensis and C. striatus coal measure sequences consist of usually thin coal beds
interbedded with carbonaceous mudstone rich in disseminated organic matter (DOM). Coal beds
range up to 3 m in thickness and constitute up to 30% of the total interval (Struckmeyer and Felton,
1990; Tupper et al, 1993). Mudstone outside these two coal measure sequences is generally found
to be organically lean. The Eumeralla Formation coals consist largely of duroclarite (BHP
Petroleum, 1992) consisting dominantly of vitrinite with subordinate but still significant liptinite
(commonly up to 15 %) and inertinite. Minor clarite is dominantly composed of vitrinite with
subordinate liptinite and rare inertinite. The DOM-rich interbedded claystone in the coal measures
contain vitrinite and liptinite in almost equal proportions, with minor inertinite (BHP Petroleum,
1992). The coals average 50% TOC, while the interbedded carbonaceous mudstone averages
4.5%. HI values average 210 mgHC/gTOC for the mudstone samples and 240 mgHC/gTOC for the
coal. Some individual values are in excess of 300 mgHC/gTOC. The high HI values, together with
the presence of Type I to III kerogens, suggest that both the coal and carbonaceous mudstone
source rocks are capable of generating both oil and gas, although gas is likely to be the major
product.
Upper Cretaceous source rocks (Austral 3 Petroleum System) in the Otway Basin include the
Waarre Formation, Flaxman Formation and Belfast Mudstone. These have not been shown to have
generated any significant hydrocarbon accumulations. This lack of success does not necessarily
mean that mature, generative, oil-prone Austral 3 source rocks are not developed in the Otway
Basin. Most of the wells drilled in the Otway Basin have been located on platform areas or onshore
where the Sherbrook Group has not reached sufficient maturity for significant hydrocarbon
generation. Few wells have been drilled in areas with thick, mature section (e.g. the Voluta Trough).
In addition, where wells have been drilled in these basinal areas, hydrocarbon samples originating
from possible Upper Cretaceous source rocks were not geochemically analysed.
Recent work by GeoScience Victoria (O’Brien et al, 2009) suggests that Austral 3 source rocks are
capable of generating hydrocarbons. The majority of the key wells in the eastern part of the basin
were analysed and revealed a very significant organic enrichment in the Turonian sequences
throughout much of the eastern Otway Basin. This enrichment appears to be best developed along
the outer margin of the basin, near the Tartwaup-Mussel Fault Zone and is less prominent - but still
present – toward the basin margin. This new study supports a concept in which the basal parts of
the Sherbrook Group became increasingly rich in organic matter basinward, as the system became
more fully marine in the Late Cretaceous. In these locations, organic enrichment was facilitated by
the development of the Global Anoxic Event close to the Cenomanian-Turonian boundary. The new
study has also revealed the development of source rock systems much later in the Late
Cretaceous; the best example of this appears to be at Normanby 1, where good source rock
intervals are developed in the Upper Cretaceous Paaratte Formation. The Austral 3 petroleum
system is a likely contributor to any hydrocarbon inventory located in Release Area V12-2
(Figure 6).
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Geochemical studies have identified the Eumeralla Formation as the primary source interval for the
gas in the Port Campbell Embayment and Shipwreck Trough areas (Mehin and Link, 1994; Foster
and Hodgson, 1995; Luxton et al, 1995; Boreham et al, 2004). Gas shows reported at Triton 1 in
the Victorian offshore (Luxton et al, 1995) and gas accumulations at Troas 1 and Breaksea Reef 1
in South Australia have also been ascribed to the Austral 2 petroleum system.
Although there appears to be potential for the generation of liquid hydrocarbons, exploration results
in the offshore areas actually indicate that the source rocks are predominantly gas-prone, with the
potential for only minor quantities of condensate. Oil potential within this petroleum system cannot
be ruled out, as the medium-gravity, waxy oils recovered from the onshore Victorian wells
Flaxmans 1 and Port Campbell 4 demonstrate. A possible retrograde condensate was also present
at the base of the gas column at Mylor 1. Whole-oil/gas chromatograms indicate that the oils are
derived from terrestrial, land-plant material (Kopsen and Scholefield, 1990; McKirdy et al, 1994;
Boreham et al, 2004). The Lindon 1 and Lindon 2 oils also belong to this petroleum system, but
have been extensively altered by microbial activity and water washing (McKirdy, 1987; Tabassi and
Davey, 1986).
Reservoirs
In the Release Areas, the main reservoir interval is provided by sandstones within the Waarre and
Flaxman formations. These host the majority of the hydrocarbon accumulations discovered in the
Victorian part of the Otway Basin, both onshore and offshore. The traps are associated with tiltedfault blocks developed within the Sherbrook Group and require cross-fault seal to be effective.
While the sandstones of the Waarre and Flaxman formations often exhibit excellent reservoir
properties, reservoir development is strongly facies-dependent. Where deeply buried (>3,000 m),
diagenetic overprints significantly reduce their potential as viable reservoir targets, particularly for
oil (Geary and Reid, 1998). The Waarre Formation in the Port Campbell area has been subdivided
into three sub-units (by Buffin, 1989; later modified by Partridge, 1999, 2001), which have been
termed, in ascending order; A, B and C. The basal Unit A, is a fining-upward package of finegrained volcanolithic sandstones and carbonaceous mudstones. Unit B is a predominantly
carbonaceous mudstone succession with subordinate thin interbeds of fine-grained dolomitic and
calcareous sandstones. Unit C is a well developed, medium- to coarse-grained quartz sandstone
and is the reservoir unit for the Port Campbell gas fields and the offshore Minerva and La Bella gas
fields (Geary and Reid, 1998). This unit has the best reservoir potential, with an average porosity of
17% and permeability of 2,700 mD (Mehin and Constantine, 1999).
The Waarre Formation is the major regional reservoir in the Victorian part of the Otway Basin.
Producible gas has been encountered in sixteen onshore fields in the Port Campbell area. In the
offshore Shipwreck Trough, the Waarre Formation is the principal reservoir for the gas
accumulations at Minerva, La Bella, Casino, Geographe and Thylacine.
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In the Geographe and Thylacine fields, an additional reservoir section is represented by a sandy
facies of the Belfast Mudstone, initially encountered by Thylacine 1 and informally named the
“Thylacine Member”. The sandy sediments are believed to be sourced from the Prawn Platform to
the east and accumulated as progradational coarsening upward sequences of a large fluvio-deltaic
system (Origin Energy, 2003).
The stratigraphically younger Paaratte Formation contains several coarsening-upward sequences
of dominantly quartzose sandstones that display excellent reservoir characteristics. A hydrocarbon
accumulation is yet to be encountered in these sandstones, as they have been the primary target of
only one offshore well (Discovery Bay 1). Its potential remains largely unassessed.
The Paleocene Pebble Point Formation was not considered an exploration target until the recording
of a live oil show in the unit at Curdie 1 in 1982, onshore in the Port Campbell Embayment. Since
then, small quantities of oil have also been recovered from Lindon 1 and Fahley 1, while residual oil
was encountered in the formation at Wilson 1 (Reid et al, 2001). However, poor reservoir
development (high porosities - up to 25% - but low permeabilities) in these wells, due to the
presence of chamositic clay in the matrix, prevented significant oil flows on test. Play validity
depends on the presence of better reservoir development elsewhere in the basin.
Seals
The most widely distributed sealing facies in the Otway Basin is the Belfast Mudstone, which
provides an excellent regional top seal to any hydrocarbon accumulation within the Waarre and
Flaxman formations. However, depending on the local facies regime, the Flaxman Formation has
demonstrated intra-formational sealing potential and is certainly mud-rich in several offshore wells.
However, the failure of Eric the Red 1 and Loch Ard 1 (O’Brien et al, 2006) was attributed to poor
quality of the sealing facies, which was sandier than anticipated. Poor seal quality was also cited in
the well completion report as the reason for failure of Prawn A1, located in Tasmanian waters to the
south. Poor seal integrity would appear to be the principal exploration uncertainty throughout the
Upper Cretaceous and Cenozoic succession across much of the Prawn Platform. Seismic sections
across Loch Ard 1 and Eric The Red 1 show that the sealing units of the Flaxman Formation and
the Belfast Mudstone are highly variable in terms of both their thickness and their lateral continuity.
This variability appears to be either controlled, or related to, active syn-depositional faulting. This
faulting episode has been termed the ‘Turonian Event’ in a previous prospectivity assessment of
the eastern Otway Basin (Geary and Reid, 1998).
Intraformational seals are also expected within the Paaratte Formation, which comprises alternating
mudstones and sandstones. Potential sealing units within the Wangerrip Group include the basal
Massacre Shale, Pember Mudstone, basal mudstone units of the Dilwyn Formation, and mudstones
in the Mepunga Formation.
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Apart from the distribution of sealing lithologies, the structural juxtaposition of lithologies and
sedimentary facies is a crucial ingredient for seal integrity. This is particularly relevant for the Upper
Cretaceous part of the basin fill which was subjected to intense syn-depositional tectonism that led
to the development of numerous tilted horst and graben structures.
Play types
Given that the highest exploration success rate in the central Otway Basin is related to the Austral 2
petroleum system, the Waarre/Flaxman play represents the most viable exploration target in the
shallower water of the Release Areas. As demonstrated by O’Brien and Thomas (2007), the
Eumeralla Formation at the top of the Otway Group currently is at peak maturity in the Shipwreck
Trough and in areas inboard of the Tartwaup-Mussel Fault Zone (Figure 3). All of the offshore
hydrocarbon fields are located either within, or less than 2,500-3,000 m from this zone of peak
generation. The larger gas fields in the offshore, such as Geographe, Thylacine and La Bella, are
situated within the zone of peak generation. Casino 1 is located on the edge of the source kitchen
and Henry 1 appears to be the commercial field located furthest away (perhaps 2,500 m) from peak
mature Eumeralla Formation (Figure 7).
In the deep water areas near the modern day continental shelf break, the Eumeralla Formation lies
below the peak maturity window and therefore any reservoirs here would require charge from a
stratigraphically younger and therefore shallower source interval (Figure 6 and Figure 8). The
Tartwaup-Mussel Fault Zone delineates the boundary between the effectiveness of the Austral 2
and Austral 3 petroleum systems (O’Brien et al, 2009). It is proposed that the Turonian section is
likely to be mature in areas southward of this fault zone and that therefore the Austral 3 petroleum
system is operational in this outer region, i.e. in Release Area V12-2. It is therefore capable of
charging reservoirs either within the Waarre-Flaxman succession or, depending on structural
configuration, reservoir units within the Paaratte Formation, depending on the offshore extent of
coarse to medium-grained facies of that formation. Seal would be provided by intraformational
mudstones, resulting in possible stacked reservoir-seal sequences, or by the Belfast Mudstone or
possibly the Skull Creek Mudstone.
In Release Area T12-1 the Waarre/Flaxman play was tested by Whelk 1 and, although
encountering good reservoir sandstones, failed to record any hydrocarbons because of a
interpreted facies change in the Belfast Mudstone equivalent. As shown in Figure 9, the Cretaceous
succession thickens considerably basinwards from the King Island High. Recent petroleum systems
modelling indicates reservoir facies within the Upper Cretaceous Waarre Sandstone are likely to be
in the gas window in that part of the basin. Structural configuration suggests that fault-block plays
are feasible targets; however, sealing capacity of mudstones in the Sherbrook Group remains
unknown.
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If access to the Austral 3 petroleum system is assumed, a top-Paaratte Formation/Timboon
Sandstone play could be considered. Paaratte Formation and Timboon Sandstone reservoirs at the
top of the Sherbrook Group depend upon the development of seal above the Maastrichtian
Unconformity within the overlying Paleogene passive margin sequence. Potential sealing units
within the Wangerrip Group include the basal Massacre Shale, Pember Mudstone, basal mudstone
units of the Dilwyn Formation, and mudstones in the Mepunga Formation. However, this play
remains untested with the exception of Normanby 1, located further west on the Bridgewater High.
Critical risks
Throughout the exploration history of the offshore Otway Basin, poor fault-seal integrity has often
been cited as the main reason for well failure. However, as recent geochemical studies (O’Brien et
al, 2009) indicate, it is the distribution of the present day, peak generation window for the respective
petroleum systems which is the primary determinant of prospectivity within at least the Victorian
part of Otway Basin, if not within the entire hydrocarbon province.
The shallow shelf regions of the Release Areas V12-1 and V12-2 are known to have access to the
prolific Austral 2 petroleum system, with Release Areas V12-1 and V12-2 lying within the Shipwreck
Trough, along trend with the majority of the main discoveries in the Otway Basin. Maturity modelling
suggests that the shelfal part inboard of the Tartwaup-Mussel Fault Zone, lies well within the area
of mature Eumeralla source rocks and it will be a matter of carefully mapping appropriate structures
on modern seismic, ideally in 3D-format. In these inboard areas, it is also very important to
understand lateral facies changes that range from fully terrestrial lower coastal plain to open shelf
depositional environments. Risk here is associated with recognising the extent of good quality
reservoir facies that are kept intact either by fault-seal mechanism or by the presence of
intraformational and regional sealing lithologies. In the palaeo-nearshore zone, such facies changes
occur rapidly and reservoir compartmentalisation is a common feature.
The limited well control on the Prawn Platform with respect to Release Area T12-1 provides only a
patchy insight into the genetic sequence relationships of the Upper Cretaceous Sherbrook Group,
within which the Waarre Formation is the prime objective. Secondly, the tectonic history of the area
suggests that the depositional architecture was strongly controlled by local structuring during the
Turonian, which makes play fairway mapping more difficult. The structuring also influences the
quality and distribution of the assorted potential sealing units.
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FIGURES
Figure 1
Location map of Release Areas V11-1, V11-2 and T11-1 in the eastern Otway
Basin.
Figure 2
Graticular block map and graticular block listings for Release Areas V11-1, V11-2
and T11-1, in the Otway Basin.
Figure 3
Structural elements of the Otway Basin. Location of seismic lines in Figure 6,
Figure 8 and Figure 9 is also shown.
Figure 4
Generalised stratigraphy of the Otway Basin (Jurassic-Quaternary), based on the
Otway Basin Biozonation and Stratigraphy Chart (Mantle et al, 2009), Geologic
Time Scale after Gradstein et al (2004) and Ogg et al (2008).
Figure 5
Generalised stratigraphy of the Otway Basin (Aptian-Danian), based on the
Otway Basin Biozonation and Stratigraphy Chart (Mantle et al, 2009). Geologic
Time Scale after Gradstein et al (2004) and Ogg et al (2008).
Figure 6
Hydrocarbon migration model for Austral 2 and Austral 3 petroleum systems
(after O’Brien et al, 2009). Line location is shown on Figure 3.
Figure 7
Peak prospectivity zones for the Austral 1, 2 and 3 petroleum systems in the
Otway Basin (modified from O’Brien et al, 2009).
Figure
8
Interpreted
composite seismic section from west to east across the Otway Basin (modified from
Hall and Keatley, 2009), showing peak generation zone. Line location is shown on Figure 3.
Figure 9
Geological interpretation of seismic line DS01-126 (a) and modelled present-day
maturity for same section (b). Line location is shown on Figure 3.
igure 8
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LOGAN, G.A. AND KRASSAY, A.A., 2004—Gas oil- source correlations in the Otway Basin,
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BUFFIN, A.J., 1989—Waarre Sandstone development within the Port Campbell Embayment. The
APEA Journal, 29(1), 299-311.
CLIFF, D.C.B., TYE, S.C. AND TAYLOR, R., 2004—The Thylacine and Geographe gas
discoveries, offshore eastern Otway Basin. The APPEA Journal 44(1), 441-462.
CONSTANTINE, A., LONERGAN, M. AND PARVAR, J., 2007—Halladale 1 DW1 Well Completion
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ELLIS, C., 2003b—Minerva 4 Well Completion Report, Interpretive Volume. BHP Billiton Petroleum
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FOSTER, J.D. and HODGSON, A.J.W., 1995—Port Campbell reviewed: methane and champagne.
APEA Journal, 35(1), 418-435.
GEARY, G.C. AND REID, I.S.A., 1998—Geology and prospectivity of the offshore eastern Otway
Basin, Victoria - for the 1998 Acreage Release. Victorian Initiative for Minerals and Petroleum
Report 55, Department of Natural Resources and Environment.
GEOLOGICAL SURVEY OF VICTORIA, 1995—The stratigraphy, structure, geophysics and
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