PETROLEUM GEOLOGICAL SUMMARY
RELEASE AREAS NT11-1 AND NT11-2,
MONEY SHOAL BASIN,
NORTHERN TERRITORY
Bids Close – Thursday 12 April 2012

In the vicinity of giant gas accumulations in the Calder Graben,
northeastern Bonaparte Basin.

Close to Darwin operations base and the Wickham Point LNG plant
supplied by the Bayu–Undan gas pipeline.

Large under-explored Mesozoic basin.

Shallow water depths (10–110 m).

Numerous shallow Mesozoic stratigraphic and structural plays.

Potential hydrocarbon charge from Mesozoic source rocks in the
Malita and Calder graben, northeastern Bonaparte Basin.

Potential hydrocarbon charge from Paleozoic source rocks in the
Goulburn Graben, Arafura Basin.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas NT11-1 and NT11-2, Money Shoal Basin, NT
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LOCATION
Release Areas NT11-1 and NT11-2 are located about 150 km north of Darwin
in the Arafura Sea. Water depths range from 10–110 m (Figure 1). The
graticular block maps and graticular block listings for these Release Areas are
shown in Figure 2. Release Area NT11-1 comprises 185 graticular blocks and
covers an area of approximately 15,540 km2. Release Area NT11-2 consists
of 136 full and part graticular blocks and covers an area of approximately
10,085 km2. Release Area NT11-1 is located in the Mesozoic to Cenozoic
Money Shoal Basin (Figure 3). In the northeastern part of this Release Area,
the Money Shoal Basin is underlain by the Goulburn Graben, which is part of
the Neoproterozoic to Permian Arafura Basin (Link to Arafura Basin
REGIONAL chapter). The eastern part of Release Area NT11-2 is located
within the Money Shoal Basin whereas the western part lies on the Darwin
Shelf which forms the northeastern margin of the Mesozoic to Cenozoic
Bonaparte Basin (Figure 3). The Release Areas are located to the southeast
of the Evans Shoal, Caldita and Barossa-Lynedoch gas accumulations in
Australian waters and the Abadi gas accumulation in Indonesian waters. The
Bayu–Undan to Darwin gas pipeline is located about 30 km south of Release
Area NT11-2 (Figure 1).
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RELEASE AREA GEOLOGY
Local Tectonic Setting
This summary of the regional petroleum geology is compiled from a
Geoscience Australia study of the Arafura and Money Shoal basins (Earl,
2006; Struckmeyer, 2006a, b; Totterdell, 2006). Release Area NT11-1 and the
eastern portion of Release Area NT11-2 are underlain by the Mesozoic to
Cenozoic Money Shoal Basin (Figure 3) which is a mainly offshore basin
located off the Northern Territory coastline. The basin is a tilted, passive
margin basin and contains sedimentary rock units that are generally
monoclinal and undeformed. These sediments were deposited mostly in a
marine environment with occasional incursions of deltaic and fluvial regimes.
Figure 4 shows the distribution and thickness (in milliseconds two-way time)
of the Jurassic to Lower Cretaceous succession and illustrates that the
depocentre aligns with the western Goulburn Graben and continues northwest
towards the Calder Graben. The total sedimentary section of the Money Shoal
Basin is about 4.5 km thick. Figure 4 also demonstrates that the basin thins
rapidly eastwards, with the base of the sedimentary section ranging in age
from Middle Jurassic in the west to Late Cretaceous in the east. These
sediments unconformably overlie the Arafura Basin and the offshore
continuation of the Pine Creek Inlier, a Paleoproterozoic orogenic province
containing a range of sedimentary, metamorphic and igneous rocks (Carson
et al, 1999). The eastern Arafura Basin overlies the Paleoproterozoic–
Mesoproterozoic (approximately 1815–1400 Ma) McArthur Basin
(Struckmeyer, 2006b).
Although the Money Shoal Basin is continuous with the Bonaparte Basin, the
Lynedoch Fault System, which traverses Release Area NT11-2 (Figure 3), is
used to separate the western margin of the basin from the Calder Graben and
Darwin Shelf of the Bonaparte Basin (Link to Bonaparte Basin REGIONAL
chapter). In the east, a Mesozoic hinge separates the Money Shoal Basin
from the Carpentaria Basin. The southern boundary of the Money Shoal Basin
is defined by the depositional edge of Mesozoic to Cenozoic sediments, while
to the north, the basin extends into Indonesian waters.
In the northeastern part of Release Area NT11-1, the Money Shoal Basin is
underlain by the Goulburn Graben of the western Arafura Basin, a
Neoproterozoic to Permian intracratonic basin. The Goulburn Graben is a
highly deformed, obliquely inverted rift that formed during a Pennsylvanian
(late Carboniferous) to Permian extensional event, and underwent
contractional deformation during the Triassic (Struckmeyer, 2006b). It
contains up to 10 km of Neoproterozoic to Permian sediments.
The western part of Release Area NT11-2 overlies the Darwin Shelf, which is
flanked by the Malita Graben of the northern Bonaparte Basin to the north and
the Petrel Sub-basin to the southwest. The Bathurst Terrace is a zone of
shallow basement between the Malita Graben and the Darwin Shelf that
consists of a series of narrow fault blocks where Paleozoic and Mesozoic
sediments are progressively truncated (Forman et al, 1974). The Darwin Shelf
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is an offshore extension of the Proterozoic Sturt Block (Mory, 1991). It has
been subjected to several episodes of peneplanation, and is covered by a thin
veneer of Mesozoic and Cenozoic sediments which thicken northwards into
the Malita Graben.
Structural Evolution and Depositional History
In terms of post-Triassic stratigraphy (Figure 5), the Money Shoal Basin
contains a sedimentary succession equivalent to that of the Bonaparte Basin
(Mory, 1988, 1991; McLennan et al, 1990; Miyazaki and McNeil, 1998).
However, the Money Shoal Basin succession is thinner and less complete
than that of the Bonaparte Basin because it consists of the proximal onlap
edge of the Mesozoic to Cenozoic succession. The basal sediments are Early
Jurassic in age and onlap the regional angular unconformity of Triassic age
(Figure 6 and Figure 7). Although the Triassic event resulted in the formation
of a peneplain across the region, it is likely that some topographic relief
remained, facilitating initial deposition of the Troughton Group.
In the Bonaparte Basin, the Oxfordian to Tithonian (Late Jurassic) was
characterised by rifting events that led to the formation of the Malita and
Calder graben and further west, the Vulcan Sub-basin (Pattillo and Nicholls,
1990; Longley et al, 2002). This is reflected by relatively small-scale normal
faulting along the boundaries of the Goulburn Graben, particularly along the
southern boundary. These faults are likely to be reactivated Pennsylvanian
(late Carboniferous) faults which controlled sedimentation during the Late
Jurassic to Early Cretaceous. The Jurassic faults underwent further
compressional reactivation in the Neogene, resulting in the development of
both small- and large-scale anticlinal features.
Stratigraphy
The Money Shoal Basin unconformably overlies the Arafura Basin succession
and comprises Jurassic to Cretaceous siliciclastic sediments and Cenozoic
carbonates that thin rapidly towards the east (Figure 4, Figure 5, Figure 6
and Figure 7). The Troughton Group is the oldest unit to have been
penetrated and is represented only by its youngest component, the Plover
Formation (Figure 5), which directly overlies the Triassic regional
unconformity. The oldest sediments, intersected at Tuatara 1, are of Early
Jurassic age (C. torosa to C. turbatus spore/pollen zone). The upper boundary
of the unit is defined by the regional Callovian unconformity. Deposition of the
Troughton Group occurred mostly in the western Goulburn Graben region
where it is in excess of 564 m thick at Tuatara 1 (Struckmeyer, 2006b). It thins
rapidly to the north and east and is absent from wells (Arafura 1, Goulburn 1
and Torres 1) in the eastern Goulburn Graben.
The Plover Formation comprises fine- to coarse-grained sandstones with
interbedded siltstones and claystones, and minor coal. A generally blocky to
serrated gamma log character, the absence of marine microfossils and the
presence of coal indicate an overall fluvial depositional environment. Barber et
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al (2004) suggested that a series of braided river systems fed into a wide,
northeast–southwest-trending marine shelf, with the Goulburn Graben the
focus of one of these rivers. Lowe-Young et al (2004) postulated increasing
marine influence in the upper Plover Formation in the Evans Shoal area of the
northern Bonaparte Basin. Seismically, the Plover Formation is characterised
by moderate to high amplitude, moderately continuous, parallel reflections but
the sequence geometry often is below seismic resolution.
The Flamingo Group includes all of the sedimentary succession above the
Callovian breakup unconformity and below the Valanginian unconformity
(Mory, 1988, 1991). The Callovian unconformity marks the commencement of
an extensional event throughout the northwest of Australia (Labutis et al,
1998; Pattillo and Nicholls, 1990; McLennan et al, 1990). However, in the
northern Bonaparte Basin the Callovian tectonic event was relatively mild and
its effects are even less pronounced in the Money Shoal Basin. Nevertheless,
the angular unconformity truncates the Plover Formation within tilted fault
blocks where it is preserved beneath the transgressive sandstones of the
Elang Formation. The Elang Formation is an important reservoir in the Malita
and Calder graben (Figure 5). In the Money Shoal Basin, an increase in the
thickness of the lower Flamingo Group is apparent across the reactivated
boundary fault of the Goulburn Graben.
In the northern Bonaparte Basin, the upper Flamingo Group is characterised
by a condensed section of open marine deepwater sediments consisting
mostly of mudstones (Frigate Shale). The laterally equivalent coarse to finegrained clastics of the Sandpiper Sandstone provide additional reservoir
targets in the region. The ‘Tuatara Formation’ intersected in Beluga 1
comprises Berriasian-aged sandstones (BHP Petroleum, 1992) and hence is
now placed within the upper Sandpiper Sandstone.
In the western Money Shoal Basin at Tuatara 1, the Flamingo Group is
mudstone-rich with a strong marine influence, but it becomes increasingly
sand-prone towards the east, reflecting deposition in mostly fluvio-deltaic
environments. Like the Troughton Group, the Flamingo Group is thickest in
the western Goulburn Graben region (up to 1230 m at Money Shoal 1), thins
rapidly to the north and east (Figure 4), and is absent from wells (Arafura 1
and Goulburn 1) in the eastern Goulburn Graben. A number of erosional
surfaces and flooding surfaces have been identified within this group
(Struckmeyer, 2006b).
A major feature of the Flamingo Group is a fluvial channel system along the
northern edge of the Goulburn Graben that straddles the hanging wall of the
reactivated graben-bounding fault system (Enclosure 4 of Miyazaki and
McNeil, 1998). It is present along the entire length of the Goulburn Graben but
is most pronounced near Kulka 1. A distinct flooding surface defines the upper
limit of the channel fill and separates the fluvio-deltaic sediments of the lower
Flamingo Group from the prograding marine deltaic deposits of the upper
Flamingo Group.
The intra-Valanginian unconformity separates the Flamingo Group from the
overlying Cretaceous Bathurst Island Group that comprises the Echuca
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Shoals Formation, Darwin Radiolarite, Wangarlu Formation and Puffin
Formation. The Bathurst Island Group consists of a series of stacked
prograding units that thicken into the Calder Graben near Lynedoch 1.
Overall, the unit consists mostly of fine-grained rocks including claystone, marl
and siltstone, with locally thick interbeds predominantly of fine-grained
sandstones deposited in deltaic to open marine environments. The distribution
of the group in the offshore Money Shoal Basin and the age of sediments
mapped onshore (Hughes, 1978; Carson et al, 1999) suggest that the most
extensive marine transgression occurred during the late Aptian to
Cenomanian. The increasing presence of planktonic foraminifera at
Lynedoch 1 suggests a westwardly deepening marine environment. Deeper
water environments are also indicated by the presence of upwardly fining
units suggestive of turbidites, particularly in the upper part of the Bathurst
Island Group. Submarine canyons and coeval deep-water deposits, such as
basinward shingled fan systems, consisting of slope fans and basin floor
sands are present, particularly north and south of Tuatara 1.
The Cenozoic carbonate-dominated Woodbine Group thickens rapidly
towards the Calder Graben, reaching about 800 m at Tuatara 1 and 1,300 m
at Lynedoch 1. The initial depositional setting of shallow marine to deltaic
environments was followed by more widespread open marine conditions.
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EXPLORATION HISTORY
Petroleum exploration in the Arafura region began in the 1920s when several
boreholes were drilled on Elcho Island in response to reported bitumen
strandings. In the 1960s and early 1970s, stratigraphic drilling occurred on
Bathurst and Melville islands (McLennan et al, 1990). During this time Shell
Development (Australia) was awarded exploration permits covering the
western region of the Arafura Sea and drilled the first well, Money Shoal 1
(1971) in the offshore Money Shoal Basin which also penetrated sediments of
underlying Arafura Basin. This well was drilled primarily to test the Mesozoic
Money Shoal Basin sequence. At the same time, Aquitaine was operating in
the central southern region of the Arafura Sea. The two operators carried out
extensive mapping based on seismic data and defined the Goulburn Graben
as an important structural feature. The next phase of exploration occurred in
the early 1980s with several wells (Arafura 1, Goulburn 1, Kulka 1, Tasman 1
and Torres 1) being drilled primarily to test the Paleozoic sequence within the
Goulburn Graben of the Arafura Basin. Petroleum exploration continued in the
late 1980s and early 1990s, targeting mostly Mesozoic plays in the Goulburn
Graben with three exploration wells (Chameleon 1, Cobra 1A and Tuatara 1)
being drilled. Since this time, seismic acquisition has continued, but no further
wells have been drilled.
Well Control
Nine petroleum exploration wells have been drilled in the offshore Money
Shoal Basin, all in the Goulburn Graben area. No wells have been drilled in
Release Areas NT11-1 and NT11-2 (Figure 1). However, four wells
(Cobra 1A, Kulka 1, Money Shoal 1 and Tuatara 1) lie to the north and
northeast of Release Area NT11-1 and provide stratigraphic control for the
Money Shoal Basin. Beluga 1, and Caldita 1 and 2 have been drilled to the
north of Release Area NT11-2 in the Calder Graben of the Bonaparte Basin,
and Newby 1, drilled on the margin of the Darwin Shelf and northern Petrel
Sub-basin, lies to the southwest of this Release Area. Three wells, Bathurst
Island 1, 2 and Tinganoo Bay 1, were drilled on Bathurst Island and Melville
Island, respectively, to the south of Release Area NT11-2.
Newby 1 (1969)
Newby 1 was drilled by Australian Aquitaine Petroleum Pty Ltd (1970) to test a
stratigraphic pinch-out and erosional wedge along the northwestern margin of
the Petrel Sub-basin, and targeted Upper Paleozoic and Mesozoic reservoirs.
The well reached 1148.5 mKB, penetrating Cretaceous to Jurassic sediments
before terminating in Proterozoic basement. No significant hydrocarbon
indications were encountered. This well is not regarded as a valid test
because of the absence of suitable trapping geometry.
Money Shoal 1 (1971)
Money Shoal 1 was drilled by Burmah Oil Company of Australia Limited in
69 m of water and was the first well drilled in the Arafura Sea (Shell
Development (Australia) Pty Ltd, 1971). It targeted a faulted anticline within
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the Goulburn Graben and was an important well for establishing the
stratigraphy of the region. The primary objective was Lower Cretaceous
sandstones (upper Flamingo Group) sealed by overlying Cretaceous shales.
The secondary objectives were Upper Cretaceous sandstones (Bathurst
Island Group) and Jurassic sandstones (lower Flamingo and Troughton
groups).
The well was initially believed to have penetrated a ‘Tertiary’ to pre-Cambrian
succession with a TD of 2590 mKB. However, re-interpretation of the well
(Earl, 2006) demonstrates that it intersected sediments of Cenozoic
(Woodbine Group), Cretaceous to Jurassic (Bathurst Island, Flamingo and
Troughton groups) and Permian (Kulshill Group) age. The Jurassic
sandstones (Troughton Group) exhibit good porosity; however, only minor oil
indications were encountered. Post-drill analysis indicates that the Jurassic
target probably does not constitute a valid structural closure. Despite the
Cretaceous sandstones probably being within closure, the failure to find
significant hydrocarbons in either the Jurassic or Cretaceous sandstones is
due to either lack of hydrocarbon charge or fault/seal breach, with late-formed
faults cutting the crest of the structure and a sandy Cretaceous (Bathurst
Island Group) seal.
Kulka 1 (1984)
Kulka 1 was drilled in 77 m of water by Diamond Shamrock Oil Company
(Australia) Pty Ltd (1985) to test a Mesozoic stratigraphic trap and a Paleozoic
down-thrown faulted anticline beneath the Jurassic angular unconformity. The
primary reservoirs targeted were Carboniferous and Devonian clastics and
carbonates, with secondary reservoirs being within the Mesozoic section.
The well provides stratigraphic control for the upper Paleozoic and Mesozoic
sections. It reached a total depth of 3998 mKB in a Pennsylvanian (upper
Carboniferous) siltstone unit (Kulshill Group). The Cretaceous (Bathurst Island
Group) sediments are dominantly composed of claystones with minor,
interbedded sandstones and mudstones that overlie a sandstone package
(Darwin Radiolarite and Flamingo Group). The Permo-Carboniferous section
(Kulshill Group) is thicker than anticipated with the fine grained sandstones
containing volcanic rock fragments and the presence of a diorite sill being
recorded at 2,555 mKB, which has been dated as 293 3 Ma. Devonian
sediments were not intersected.
A number of oil indications (fluorescence) were recorded within Upper
Jurassic sandstones and an oil show was interpreted to occur within
Pennsylvanian (upper Carboniferous) shaly sandstones. However, silica and
carbonate cementation have reduced the porosity and permeability of the
Carboniferous fine grained sandstones to such an extent that they have no
reservoir potential.
Tuatara 1 (1990)
Tuatara 1 was drilled by BHP Petroleum Pty Ltd (1991) in 115 m of water on
the northwestern edge of the Goulburn Graben and tested a fault block within
a broad faulted anticline. The primary objectives were sandstones within the
Lower–Middle Jurassic Plover Formation, sealed by Upper Jurassic–Lower
Cretaceous claystones of the Flamingo Group. Secondary objectives were
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Upper Jurassic lower Flamingo Group clastics and Paleozoic clastic and
carbonate reservoirs below the base Jurassic unconformity. The structure
formed in response to normal faulting in the Early–Middle Jurassic, with fault
location being controlled by the reactivation of Paleozoic faults. Pre-drill
interpretation implied that the more distal Mesozoic sediments at Tuatara 1
would be clay-rich in comparison to Kulka 1, hence minimising source and
seal risks.
The well penetrated the base of the Money Shoal Basin and was terminated
at 3874.2 mKB in a sandstone unit of presumed Devonian age. However,
there is no biostratigraphic evidence for a Devonian age and re-interpretation
of seismic data suggests that the well bottomed in Jurassic rocks that overlie
probable Cambrian dolomites (Earl, 2006).
The well encountered numerous oil indications (fluorescence) throughout the
Mesozoic section and oil and gas indications within Lower Cretaceous
sandstones. The porosities of the target reservoirs were lower than expected
because all seismic picks were 9–10% deeper than originally interpreted (BHP
Petroleum, 1991). The Upper Jurassic lower Flaming Group does not contain
an adequate seal to the Plover Formation reservoir. The well failed due to
insufficient seals and poor quality reservoirs.
Beluga 1 (1991)
Beluga 1 was drilled on the Bathurst Terrace that flanks the southern Malita
Graben (BHP Petroleum Pty Ltd, 1992). It was drilled to evaluate a
structural/stratigraphic play comprising an Upper Jurassic sand-dominated fan
(referred to as the Beluga Sequence), sealed by the transgressive marine
claystones of the Flamingo Group. The closure is modified to the southeast by
down-to-the-basin normal faulting. The results from this well are discussed in
detail by Anderson et al (1993), but they do not use the same informal
stratigraphic nomenclature (‘Jacaranda’, ‘Beluga’ and ‘Tuatara’ formations)
presented in the well completion report.
The well reached a TD of 3100 mKB in the Plover Formation and encountered
gas indications in the Bathurst Island Group, and gas shows within the
Flamingo Group and Plover Formation. The most significant gas shows and
hydrocarbon fluorescence were encountered in tight Flamingo Group
argillaceous sandstones within the Beluga Sequence [re-interpreted as the
Sandpiper Sandstone]. The Beluga Sequence comprises distal shelf and
slope fan sands. Log analysis indicates that potential reservoir sands were
encountered in the upper Flamingo Group over the depth range 2520–
2543 mKB (11–16% porosity; informal ‘Tuatara Formation’). These
sandstones are interpreted to have been deposited as channel fill in a shallow
marine setting. The lower Flamingo Group sequence (informal ‘Beluga
Formation’), the primary reservoir objective in the Beluga closure, was
deposited in a distal shelf or upper slope environment, away from the clastic
source. Abundant detrital clay, silica and minor carbonate cement, and
physical compaction account for the low porosity (average 10%) and very low
permeability (<1 mD) of this sequence. Dip analysis suggests that the
dominant direction of sediment transport was to the south, such that the
majority of the Flamingo Group sediments were derived from the Sahul
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Platform to the north and transported across a broad continental shelf. This
sequence does not represent a viable reservoir objective in this distal setting
due to the high amount of detrital argillaceous material, but it may be
satisfactory in more proximal facies to the north. Furthermore, quartz
sandstones of the fluvial to shallow marine Plover Formation were also found
to be tight due to silica cement and quartz overgrowth (average porosity 6%).
Tithonian outer shelf to upper continental slope fan sediments derived from
the north (‘Beluga Formation’) were deposited on uplifted and eroded shallow
marine deltaic sediments of late Callovian–Oxfordian age (‘Jacaranda
Formation’). Transgressive marine claystones subsequently onlapped the
Tithonian sequence to create the potential stratigraphic closure. During the
late Tithonian to Berriasian a series of progradational/aggradational cycles
progressively filled a broad shallow basin. Towards the end of the Berriasian
the onset of basin inversion is indicated by a change in sediment transport
direction (derived from the south/southeast) and normal faults parallel to the
graben margin which show increasing displacement stepping to the north. The
combination of depositional setting and structural inversion rotated the Beluga
feature down to the northwest and produced the potential for a closed feature.
Base seal, which was considered a significant pre-drill risk, was provided by
the base of the coarsening-upward ‘Beluga Formation’.
Source potential of the Upper Jurassic to Lower Cretaceous claystones was
found to be relatively poor, showing an affinity for the generation of gas to light
oil. The Middle Jurassic Plover Formation is considered to be early mature,
based on a vitrinite reflectance measurement of 0.6%.
The apparent sediment source direction for the Upper Jurassic sequences
and present structural geometry indicates that significant basin inversion
occurred during the latest Jurassic to Early Cretaceous. The majority of the
Flamingo Group sediments have been derived from the north, probably from
the Sahul Platform. Poor reservoir quality of the lower Flamingo Group
sandstones reduces the prospectivity for similar play types in this area, but
improved reservoir potential is predicted to the north along the northern
margin of the Malita Graben.
Cobra 1, 1A (1993)
Cobra 1A was drilled in 78 m water depth by BHP Petroleum Pty Ltd (1993)
on the northwestern margin of the Goulburn Graben and is the most recent
well drilled in the Arafura Sea. The exploration target was a stratigraphic trap
comprising sandstones within a faulted, erosional dome formed as a remnant
topographic high between two Upper Jurassic channels. The primary objective
was a Tithonian sandstone unit sealed by Berriasian claystones within the
Flamingo Group. Secondary objectives were Lower Cretaceous (upper
Flamingo Group) and Middle Jurassic (Plover Formation) sandstones.
The well reached a TD of 2542 mRT in Plover Formation sandstones. The
well intersected Money Shoal Basin sediments of Cenozoic (Woodbine
Group), Cretaceous (Bathurst Island Group and upper Flamingo Group) and
Jurassic (lower Flamingo Group and Plover Formation) age. The Bathurst
Island Group is dominated by marine mudstones with minor interbeds of
sandstone and traces of coal and is 1,192 m thick (Earl, 2006). The Flamingo
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Group consists of blocky sandstones with interbedded mudstones deposited
in a variety of deltaic environments. Although the Cretaceous and Jurassic
sandstones recorded excellent porosity, only minor oil indications
(fluorescence) were encountered.
The well relied on the Tithonian channel fill to act as a seal over the crest of
the closure. However, the ‘channel’ comprised interbedded sandstones and
claystones in an older channel that was cross cut by a younger channel. The
nature of the channel fill was unexpected and interpreted to be a thief zone,
which is the primary reason for well failure (Earl, 2006).
Caldita 1 (2005)
Caldita 1 was drilled in 2005 by ConocoPhillips Exploration Australia Pty Ltd.
The well targeted Elang and Plover sandstones within a large faulted anticline
(ConocoPhillips Australia Exploration Pty Ltd, 2006). Caldita 1 is reported as a
gas discovery, having a gas column that on test flowed at a rate of up to
33 MMscfd (DST 2, 3765.5–3775.4 mRT). The accumulation has P50
reserves of 2.9 Tcf of gas
(http://www.nt.gov.au/d/Minerals_Energy/Content/File/html/Petroleum_Reserv
es_Resources_Summary.htm).
The well reached a TD of 4037 mRT within the Plover Formation, with a
calculated extrapolated static bottom hole temperature of 166.39°C, with a
temperature gradient of 3.8°C per 100 m (seabed temperature was 12.1°C, as
measured by a remotely operated vehicle (ROV) (ConocoPhillips Australia
Exploration Pty Ltd, 2006). The interpretation report for this well is currently
confidential and no further information is available.
Caldita 2 (2007)
Caldita 2 was drilled by ConocoPhillips Australia Exploration Pty Ltd (2007) in
Permit NT/P61 as an appraisal well of the Caldita accumulation after the
acquisition of a 3D seismic survey. Caldita 2 is located 6 km west-northwest of
Caldita 1 and the primary objectives were the Elang and Plover formation
reservoirs as intersected in the discovery well.
The well was drilled in a water depth of 136.5 m and reached a TD of
3972 mRT (ConocoPhillips Australia Exploration Pty Ltd, 2007). No testing
was carried out in this well. The interpretation report for this well is currently
confidential and no further information is available.
For further details regarding wells and available data follow this link:
http://www.ret.gov.au/Documents/par/data/documents/Data%20list/data%20lis
t moneyshoal_AR11.xls
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Data Coverage
During the early 1990s Geoscience Australia (then the Bureau of Mineral
Resources) acquired a total of 5,342 km of regional deep seismic data across
the Arafura Basin. In the past 10 years, exploration activities have contributed
to the available dataset and have high-graded the prospectivity of the region.
These include, for example, non-exclusive regional 2D seismic data sets by
TGS Nopec in 1998 and Veritas DGC in 2002, and Synthetic Aperture Radar
acquisition and interpretation across the region by Infoterra (2003). Recently,
the PGS GeoStreamer Northern Margin Australia–Arafura Multiclient 2D
(NMWT) seismic survey has been completed
(http://www.pgs.com/Data_Library/Asia-Pacific/Australia/Arafura-NMAA-092D/), which is applicable to Release Areas NT11-1 and NT11-2.
To view image of seismic coverage follow this link:
http://www.ga.gov.au/energy/projects/acreage-release-andpromotion/2011.html#data-packages
PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL
No commercial discoveries have been made in either the Money Shoal Basin
or Arafura Basin. However, there are numerous hydrocarbon shows and
indications in wells drilled in the Goulburn Graben (Figure 3) (Figure 5).
Some of the most significant oil shows were intersected in Arafura 1, and
pervasive oil indications occur in Goulburn 1. Tasman 1 encountered an oil
show in an unnamed Carboniferous carbonate, and Kulka 1 discovered an oil
show in the Kulshill Group. A review of available geological data (Earl, 2006;
Struckmeyer, 2006a, b) together with the results from a survey investigating
potential hydrocarbon seepage in the Arafura Basin (Logan et al, 2006) show
that the region contains not only all the required petroleum systems elements
to generate, expel and trap hydrocarbons, but also evidence that generation
and expulsion has occurred.
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Table 1: Petroleum Systems Elements Summary for Money Shoal Basin
Bonaparte and Money Shoal basins
Lower–Middle Jurassic gas-prone fluvio-deltaic source rocks in
the Plover Formation.
Sources
Potential oil- and gas-prone source rocks in the Upper
Jurassic to Lower Cretaceous Frigate Shale and Echuca
Shoals Formation.
Goulburn Graben, Arafura Basin
Middle Cambrian marine source rocks in the Jigaimara
Formation.
Potential oil and gas-prone fluvio-deltaic source rocks in the
Upper Devonian Arafura Group and Permo-Carboniferous
Kulshill Group.
Bonaparte and Money Shoal basins
Primary clastic reservoirs are Lower–Middle Jurassic Plover
Formation and Middle–Upper Jurassic Elang Formation.
Secondary clastic reservoirs are Upper Jurassic–Lower
Cretaceous Sandpiper Sandstone and Upper Cretaceous
Wangarlu and Puffin formations.
Reservoirs
A secondary carbonate reservoir is fracture porosity in the
Lower Cretaceous Darwin Radiolarite.
Goulburn Graben, Arafura Basin
Cambro-Ordovician shallow marine limestones and dolomites
of the Goulburn Group.
Upper Devonian siltstones and sandstones of the Arafura
Group.
Bonaparte and Money Shoal basins
Lower Cretaceous Echuca Shoals Formation, together with the
Upper Jurassic Frigate Shale, forms the regional seal.
Seals
Intra-formational seals occur within the Lower–Middle Jurassic
Plover Formation and Upper Cretaceous Wangarlu Formation.
Goulburn Graben, Arafura Basin
Cambro-Ordovician mudstones at the top and base of the
Goulburn Group.
Upper Devonian mudstones at the top of the Arafura Group.
Permo-Carboniferous dolerite sills.
Play Types
Bonaparte and Money Shoal basins
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The main structural plays are broad faulted anticlinal
structures over tilted fault blocks at the base of the regional
seal. Tilted horst blocks are attractive targets on faulted
terraces adjacent to the Calder Graben.
Combination structural/stratigraphic traps are possible within
the turbidite sandstones of the Middle Jurassic–Lower
Cretaceous Flamingo Group and Upper Cretaceous Puffin
Formation.
Onlap, drape closure, channel and low stand wedge plays in
the Money Shoal Basin.
Goulburn Graben, Arafura Basin
Large faulted anticlines and fault blocks, sub-unconformity
plays, diagenetic and other stratigraphic traps.
Source Rocks
Goulburn Graben, Arafura Basin
The Arafura Basin contains several units with potential source rocks; the
Neoproterozoic Wessel Group, Cambrian–Ordovician Goulburn Group,
Devonian Arafura Group, and the Permo–Carboniferous Kulshill Group
(Boreham, 2006; Struckmeyer, 2006a, b). However, the only effective source
rock within the Arafura Basin is a marine shale of Cambrian age, probably
within the Jigaimara Formation, which has sourced the majority of oil shows
and indications within the wells drilled in the Goulburn Graben (Moore et al,
1996; Boreham and Ambrose, 2005; Sherwood et al, 2006; Boreham, 2006).
Migration and preservation of Cambrian-derived hydrocarbons have the
potential to be preserved in the northern Arafura Basin, and along the
northeastern and southwestern margin of the Goulburn Graben (Struckmeyer
2006b), including the northeasternmost corner of Release Area NT11-1 (see
Link to Arafura Basin REGIONAL Figure 5; Arafura Basin Regional Geology
chapter).
Potential source rocks within the Arafura Group and the Kulshill Group have
been modelled by Struckmeyer (2006b) to demonstrate the possible
generation and expulsion of hydrocarbons within the Goulburn Graben
(Figure 8). Figure 8 also shows that hydrocarbons generated from these
Paleozoic source rocks may have migrated into the northeasternmost corner
of Release Area NT11-1. The lack of a Kulshill Group-derived accumulation at
the nearby well Cobra 1A is attributed to lack of an effective seal rather than
source and reservoir issues (Earl, 2006).
Money Shoal and Northern Bonaparte Basins
The Lower–Middle Jurassic Plover Formation (Troughton Group) contains
effective source rocks within the Bonaparte and Money Shoal basins
(Figure 5), as well as being a proven reservoir target for hydrocarbon
discoveries in the northern Bonaparte Basin (Longley et al, 2002; Ambrose,
2004 a, b; Barrett et al, 2004; Edwards et al, 2004). The Plover Formation is a
fluvio-deltaic unit that contains fair to good oil- and gas-prone source rocks;
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however, these source rocks appear to be dry gas-prone within the Calder
Graben. In the Money Shoal Basin, the Plover Formation is composed of
blocky sands with minor interbedded mudstones and coals.
Other effective source rocks for oil and gas within the Bonaparte Basin include
the organic-rich shales of the Upper Jurassic–Lower Cretaceous Frigate
Shale (Flamingo Group) and the basal marine shales of the Lower Cretaceous
Echuca Shoals Formation (Bathurst Island Group) (Preston and Edwards,
2000; Longley et al, 2002). Where intersected in the northeastern Bonaparte
Basin, these source rocks appear to become gas-prone due to the dilution
and inertinitic nature of the organic matter (West and Passmore, 1994). In the
Money Shoal Basin, the Mesozoic sediments show a range in thermal
maturity as they thicken to the west; the lower Flamingo Group is marginally
mature to mature for oil generation (VR values of 0.6–0.79% are recorded at
Tuatara 1) and the Echuca Shoals Formation is immature to marginally
mature for hydrocarbon generation.
Reservoir Rocks
Goulburn Graben, Arafura Basin
Potential reservoir rocks in the Arafura Basin include shallow marine
limestones and dolomites of the Cambro-Ordovician Goulburn Group, and
terrestrial to fluvio-deltaic interbedded sandstones and mudstones of the
Devonian Arafura Group and Permo-Carboniferous Kulshill Group. The
Goulburn Group dolomite hosts an oil show and gas indication in Arafura 1
and oil indications in Goulburn 1. The unit has a maximum porosity of 7.7%
that relies on the development of secondary porosity through features such as
vugs and fractures (Earl, 2006).
Siltstones and sandstones of the Arafura Group are important reservoirs in the
region, hosting oil shows and indications in Arafura 1 and Goulburn 1, with the
better quality reservoir occurring at Goulburn 1.
Tasman 1 encountered an oil show in an unnamed Carboniferous carbonate.
The upper part of the Kulshill Group contains some good quality reservoir
units; however, only a minor oil show deeper in the section has been recorded
at Kulka 1.
Money Shoal and Northern Bonaparte Basins
In the northern Bonaparte Basin, Mesozoic reservoirs, notably the Jurassic
Plover Formation and basal Flamingo Group (Elang Formation), host
numerous hydrocarbon accumulations including the Caldita, Evans Shoal,
Lynedoch-Barossa, Sunrise and Abadi gas accumulations (Longley et al,
2002; Barrett et al, 2004; Cadman and Temple, 2004; Lowe-Young et al,
2004) (Figure 3 and Figure 5). The Sandpiper Sandstone (upper Flamingo
Group) and the upper Wangarlu and Puffin formations (Bathurst Island Group)
are also excellent quality reservoirs within the Bonaparte Basin (Barber et al,
2004; De Boer, 2004).
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Similarly, the Money Shoal Basin also contains reservoir quality clastics in the
Plover Formation, Flamingo Group and the Bathurst Island Group. These
Mesozoic reservoirs are well positioned to receive any late hydrocarbon
charge from underlying potential Paleozoic source rocks within the Goulburn
Graben, as well as the long range migration of Mesozoic-derived
hydrocarbons from the Calder Graben. Mesozoic hosted hydrocarbon
indications occur at Chameleon 1, Cobra 1A, Kulka 1, Money Shoal 1 and
Tuatara 1 (Struckmeyer, 2006b), with most occurring within the Plover
Formation and Flamingo Group. However, there is currently no geochemical
evidence that determines the origin of these Mesozoic reservoired
hydrocarbons.
In the Money Shoal Basin, fluvio-deltaic sandstones of the Plover Formation
have average porosities of 8.5% with a maximum of 27% at Tasman 1. Blocky
fluvio-deltaic sands of the Flamingo Group have an average porosity of
18.5%, with a maximum of 32% at Tasman 1 and a range of 5–17% at
Tuatara 1 (Earl, 2006). Within the upper Flamingo Group, there are
sandstones associated with an upper Tithonian incised channel complex
running the length of the western Goulburn Graben and a postulated turbidite
fan system in the Calder Graben (Barber et al, 2004). The Bathurst Island
Group contains potential reservoir units; where it is sandstone-rich, the Darwin
Radiolarite (eg at Kulka 1) has excellent porosity (average of 25 %). In the
upper Bathurst Island Group at Tuatara 1 porosities range from 13–33%,
although no permeability data are available (Earl, 2006). The reservoir
potential of basin floor sands (Puffin Formation) within this group is untested.
Seals
Goulburn Graben, Arafura Basin
The Paleozoic section contains numerous mudstone units which could provide
intraformational seals. Argillaceous sediments within the Goulburn and
Arafura groups in Arafura 1 and Goulburn 1 provide intraformational seals for
the most significant oil shows and indications. The generally poor reservoir
quality of the Paleozoic sediments in the Goulburn Graben means that fluid
movement is restricted within the section, with lateral decreases in reservoir
quality possibly providing sealing and trapping structures.
Money Shoal and Northern Bonaparte Basins
In the Bonaparte Basin, the regional seals for the Plover Formation and
Flamingo Group reservoirs are the thick claystones of the Frigate Shale
(Flamingo Group) and Echuca Shoals Formation (lower Bathurst Island
Group) (Figure 5). In the Money Shoal Basin, the claystones of the Wangarlu
Formation (upper Bathurst Island Group) are laterally and vertically extensive;
therefore, fault breach is unlikely due to the thickness of this unit. Other seals
in the region are less homogenous. The Upper Jurassic to Lower Cretaceous
Flamingo Group tends to be sand-dominated, but contains extensive
mudstones. These include maximum flooding surfaces and abandoned
channel fill and overbank deposits that could provide good intraformational
seals.
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Timing of Generation
Goulburn Graben, Arafura Basin
Peak oil generation and migration from potential Paleozoic source rocks in the
Goulburn Graben, where all exploration wells are located, pre-dates the
Triassic structural event and thus potential trap formation (Moore et al, 1996;
Struckmeyer, 2006a, b). Despite this, modelling by Struckmeyer (2006b)
demonstrated that some areas in the western Goulburn Graben could have
experienced a late phase of generation and expulsion from potential
Paleozoic source rocks (Figure 8).
Money Shoal and Northern Bonaparte Basins
Potential source rocks in the Plover Formation are typically immature in all
wells in the Goulburn Graben, apart from Tuatara 1. Here the unit reaches oil
maturity and has probably generated some oil, but expulsion is unlikely to
have occurred. However, modelling by Struckmeyer (2006b) at pseudo-well
site G, to the west of Tuatara 1 (Figure 8) and north of Release Area NT11-1,
where a thicker Money Shoal overburden (about 4 km) is present, has
demonstrated that oil expulsion occurred from within the Plover Formation and
lower Flamingo Group during the Late Cretaceous to Cenozoic.
Play Types
Goulburn Graben, Arafura Basin
The structural setting of the Goulburn Graben is conducive to a variety of
structural, stratigraphic and combination traps. The structural styles vary
significantly between the Money Shoal and Arafura basins, with some wells
testing different trap styles in both stratigraphic sections (for example
Chameleon 1 and Kulka 1). The structure of the Paleozoic section of the
Arafura Basin is dominated by features formed during the Triassic Fitzroy
Movement. This includes fault blocks, fault roll-overs, anticlines and subunconformity traps.
Money Shoal and Northern Bonaparte Basins
In the northern Bonaparte and Money Shoals basins, a variety of structural,
stratigraphic and combined structural/stratigraphic plays are present for
hydrocarbons expelled from Mesozoic source kitchens. In the case of the
Money Shoal Basin where it overlies the northern Goulburn Graben,
hydrocarbons may also be sourced from Paleozoic source rocks. Tilted fault
blocks, faulted anticlines and broad, low relief anticlinal drape over tilted fault
blocks provide the main structural plays. Tilted horst blocks are attractive
targets on faulted terraces adjacent to the Calder Graben. The possibility of
hanging wall fault traps on the down-thrown side of the bounding faults
provides a secondary play type that is relevant in Release Area NT11-2.
Potential stratigraphic traps in both basins include pinch-outs and onlap plays
associated with the Triassic unconformity, channel fills and slope- and basinfloor fans.
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A Tithonian channel system runs along the major bounding faults of the
Goulburn Graben, from east to west (Barber et al, 2004). Although the
channel system has been unsuccessfully tested at several locations (such as
Chameleon 1, Cobra 1A and Kulka 1) the feature provides numerous untested
stratigraphic/structural traps within the channel fill and associated erosion
features and may have relevance to the northwesternmost part of Release
Area NT11-1. The Upper Cretaceous prograding shelf and contiguous slope
and basin deposits of the upper Bathurst Island Group provide untested plays
within the northern Bonaparte and Money Shoal basins. Significantly, seismic
data show bright amplitudes within interpreted basin floor fans possibly
indicating the presence of hydrocarbons (Struckmeyer, 2006b).
Critical Risks
A recent audit of exploration wells in the Goulburn Graben (Earl, 2006)
identified timing of hydrocarbon charge, breach of structure and reservoir
quality as the major reasons for the failure of the wells. Thus, reservoir quality
of Paleozoic rocks and the timing of generation, expulsion and trap formation
in relation to the major structuring event in the Triassic are regarded as the
key risks. Risks for the younger, mostly stratigraphic plays include the
presence of suitable seals. The lack of large structures, adequate seals, and
the absence of Plover Formation reservoirs on the Darwin Shelf are issues, as
is the quality of the Flamingo Group reservoirs, which are tight at Beluga 1.
The long range migration of hydrocarbons from the Malita and Calder graben
source kitchens onto the Darwin Shelf and into the western Money Shoal
Basin is largely unproven, with only gas shows being recorded within the
Plover Formation and Flamingo Group at Beluga 1.
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FIGURES
Figure 1:
Location map of Release Areas NT11-1 and NT11-2 in the
Money Shoal Basin and northeastern Bonaparte Basin.
Figure 2:
Graticular block map and graticular block listings for Release
Areas NT11-1 and NT11-2 in the Money Shoal Basin and
northeastern Bonaparte Basin.
Figure 3:
Regional structural elements of the northeastern Bonaparte
Basin, Money Shoal Basin and Arafura Basin. The locations of
the seismic sections in Figure 6 and Figure 7 are shown.
Figure 4:
Thickness (milliseconds two-way time) of the Jurassic to Lower
Cretaceous sediments (Troughton and Flamingo groups) in the
Money Shoal Basin (Struckmeyer, 2006b).
Figure 5:
Stratigraphic correlations between the Malita and Calder
graben, northern Bonaparte Basin and the Money Shoal Basin,
based on the Bonaparte Basin Biozonation and Stratigraphy
Chart (Nicoll et al, 2009). Geologic Time Scale after Gradstein
et al (2004) and Ogg et al (2008). Hydrocarbon shows are
displayed. Seismic horizons after Kennard and Colwell (2001).
Figure 6:
Seismic line AGSO 118-14 through Release Area NT11-1 in
the Money Shoal Basin (location of line segment shown in
Figure 3).
Figure 7:
Seismic line AGSO 118-05 through Release Area NT11-2 on
the Darwin Shelf, northeastern Bonaparte Basin (location of
line segment shown in Figure 3).
Figure 8:
Interpreted hydrocarbon expulsion map from potential
Devonian (Arafura Group) and Permo-Carboniferous (Kulshill
Group) source rocks in the Goulburn Graben, Arafura Basin
and expulsion from Jurassic (Plover Formation, Troughton
Group) source rocks in the Money Shoal Basin and
northeastern Bonaparte Basin (Struckmeyer, 2006b). Inset:
hydrocarbon generation and expulsion rates of oil from the
Plover Formation at pseudo-well site G.
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Front page image courtesy of Petroleum Geo-Services.
2011 Release of Australian Offshore Petroleum Exploration Areas
Release Areas NT11-1 and NT11-2, Money Shoal Basin, NT
Release Area Geology
Page 23 of 23