Ashmore Platform Release Areas - Offshore Petroleum Exploration

PETROLEUM GEOLOGICAL SUMMARY

RELEASE AREAS AC11-1 AND AC11-2,

ASHMORE PLATFORM, BONAPARTE BASIN,

TERRITORY OF ASHMORE AND CARTIER ISLANDS

Bids Close – Thursday 13 October 2011

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Proximal to oil production from FPSO facilities in the Vulcan Subbasin.

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Shallow water (60 –280 m) frontier area.

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Good quality Triassic Sahul Group and Upper Cretaceous Puffin

Formation sandstone reservoirs.

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Source rock potential in Permian –Triassic section.

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Effective Upper Jurassic lower Vulcan Formation source rocks in adjacent Swan and Paqualin graben.

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Untested source potential in small Late Jurassic half graben.

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Play types include numerous Triassic horst blocks and Miocene reefs. Puffin Formation fan sandstones on eastern margin of

Ashmore Platform.

2011 Release of Australian Offshore Petroleum Exploration Areas

Release Areas AC11-1 and AC11-2, Ashmore Platform, Bonaparte Basin,

Territory of Ashmore and Cartier Islands Release Area Geology

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LOCATION

Release Areas AC11-1 and AC11-2 are located some 800 km west of Darwin in the Timor Sea, within the offshore area of the Territory of Ashmore and

Cartier Islands that adjoins the border with Indonesia. Water depths range from about 60 to 280 m within the Release Areas ( Figure 1 ). The graticular block maps and graticular block listings for these Release Areas are shown in

Figure 2 . Release Area AC11-1 comprises 34 graticular blocks and covers an area of 2,845 km 2 . Release Area AC11-2 consists of 32 graticular blocks and covers an area of 2,675 km 2 . The Release Areas are located on the Ashmore

Platform, in the western portion of the Bonaparte Basin ( Figure 3 ). The nearest production facilities are located in the adjacent Vulcan Sub-basin to the east, where oil is produced via Floating Production Storage and Offloading

(FPSO) facilities.




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RELEASE AREA GEOLOGY

Local Tectonic Setting

The Ashmore Platform is an extensive, elevated and highly structured block that borders the Vulcan Sub-basin to the east, the northern Browse Basin to the south and deepens into the Timor Trough to the west ( Figure 2 ). On the platform, 1500

–2000 m of flat-lying Cretaceous and Cenozoic strata overlie at least 4500 m of heavily faulted and folded Permo-Triassic sediments (see

Figure 4 , Figure 5 and Figure 6 ). Late Jurassic rifting in the Vulcan Subbasin to the east, during the breakup along the Argo margin to the southwest, led to tilted fault-block development on the Ashmore Platform prior to widespread peneplanation, subsidence and burial in the Cretaceous –

Cenozoic. Miocene –Pliocene convergence of the Australian Plate and southeast Asian microplates resulted in thrusting and foreland loading of the

Timor margin of the Australian Plate. This led to rapid subsidence of the Timor

Trough between the Ashmore Platform and the island of Timor. Significant fault reactivation occurred on the Ashmore Platform during this convergence.

Faulting across the Ashmore Platform is complex ( Figure 5 and Figure 6 ). A west-trending concave fault zone divides the platform into two segments; a western terrain with mainly west dipping faults, and an eastern terrain with both east and west dipping faults. The deeper Permo-Triassic section of the western terrain is dominated by westward-dipping faults, developed in response to pre-breakup rifting. In the east, the steeper eastward-dipping faults developed in response to the formation of the Vulcan Sub-basin. The overlying Cretaceous

–Cenozoic section is characterised largely by the upward propagation of this deep-seated faulting; related synthetic and secondary faulting resulted in the widespread development of hour-glass structures.

Structural Evolution and Depositional History of the Sub-basin

The stratigraphy of the Ashmore Platform is similar to that for the Vulcan Subbasin (both are shown in Figure 4 ), except that Jurassic sediments are either thin or absent over the Ashmore Platform. The Cretaceous to Cenozoic sediments have a maximum thickness of 2000 m, forming a relatively thin cover across Permo-Triassic tilted fault blocks ( Figure 5 and Figure 6 ).

Sedimentation in the area was probably initiated as a result of Pennsylvanian

(late Carboniferous) to Cisuralian (early Permian) rifting, with deposition of a thick succession of shallow marine to fluvio-deltaic sediments during the

Permian to Triassic referred to here as the Kinmore Group (which includes the

Hyland Bay Subgroup and Mount Goodwin Subgroup) and the Sahul Group.

North –south transpression in the Late Triassic resulted in uplift and erosion.

The Plover Formation was deposited in a fluvio-deltaic environment throughout the Early –Middle Jurassic, but it is generally absent across the

Ashmore Platform. Where intersections of the Troughton Group have been made on the Ashmore Platform, it comprises volcanics, as does the overlying




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Swan Group ( Figure 4 ). Widespread faulting and uplift commenced in the late

Middle Jurassic, concurrent with intracratonic rifting in the adjacent Vulcan

Sub-basin, and led to extensive erosion of (?)Jurassic and Triassic strata.

Post-rift thermal subsidence in the Valanginian resulted in transgression and renewed shallow marine deposition on the platform (Echuca Shoals

Formation). Subsidence continued throughout the Cretaceous with the deposition of marine mudstone and marl (Jamieson Formation), passing westward into shallow marine carbonates on the western portion of the

Ashmore Platform (Brown Gannet Limestone). An extensive submarine fan system developed across the southeastern margin of the Ashmore Platform and the adjacent Vulcan and Caswell sub-basins in the Late Cretaceous

(Puffin Formation). Subtropical and tropical carbonates were deposited throughout the region in the Paleogene and Neogene (Woodbine Group), although sedimentation was interrupted by a major hiatus in the Oligocene.




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EXPLORATION HISTORY

The first offshore exploration wells in the Bonaparte Basin were located on the

Ashmore Platform; Ashmore Reef 1 and Sahul Shoals 1 ( Figure 3 ) were drilled as stratigraphic tests in 1967 and 1969, respectively. Although these wells failed to encounter hydrocarbons, they indicated that the Jurassic section is either thin or absent and that Triassic sandstones form potential reservoirs over much of the Ashmore Platform.

In the early 1970s, exploration expanded into the adjacent Vulcan Sub-basin, and two additional wells were drilled on the Ashmore Platform; Brown

Gannet 1 (1972) and North Hibernia 1 (1973). Significant oil discoveries were made on the eastern margin of the Ashmore Platform during this period, at

Puffin 1, 2 and 3 (1972 –1975), but the nearby Prion 1 (1974) well was dry.

Between 1975 and 1982, relatively low levels of exploration drilling were recorded in the offshore Bonaparte Basin (a total of eight wells) largely due to sea-bed boundary disputes, with only one well being drilled on the Ashmore

Platform (Mount Ashmore 1, 1A, 1B, ST1, ST2) in 1980.

The discovery in 1983 of a commercial oil accumulation in Jabiru 1A, which tested a Jurassic horst block in the Vulcan Sub-basin, stimulated further exploration in the offshore part of the Bonaparte Basin and particularly within that sub-basin. This phase of exploration resulted in the discovery of a further three commercial oil accumulations in the Vulcan Sub-basin (Challis 1 in

1984, Skua 2 in 1985, and Cassini 1 in 1988), but only one additional well,

Rainbow 1 (1985), was drilled on the Ashmore Platform.

After a brief downturn in 1987, levels of exploration drilling again accelerated in the Vulcan Sub-basin, and eight additional wells were drilled on the eastern flank of the Ashmore Platform during the period 1988 –1992 (Cartier 1,

Caversham 1, Pascal 1, Lucas 1, Pokolbin 1, Yarra 1, Langhorne 1, Great

Eastern 1, Rothbury 1 and Warb 1A). All of these wells were dry, although residual degraded oil was encountered in calcarenites of the Miocene Oliver

Formation in Warb 1A (Western Mining Corporation Limited, 1992). Several significant oil and gas discoveries were made in the adjacent Vulcan Subbasin during this period (Montara 1, Pengana 1, Cassini 1, Bilyara 1 ST1,

Talbot 1, Maple 1, Birch 1, Tahbilk 1 and Halcyon 1, DW1).

Cromwell 1, 1A (2001) was the last well to be drilled on the Ashmore Platform.

It is located on the northeastern margin of the platform but it did not discover any hydrocarbons.

Moderate levels of exploration and development drilling have continued in the adjacent Vulcan Sub-basin throughout the last decade. In 2000 –2002, three discoveries, Tenacious 1, Audacious 1 and Cash 1 were made. These exploration successes were followed by oil and gas discoveries at Katandra 1

(2004) and Vesta 1 (2005), and oil at Swift North 1 and Swallow 1 (2006).




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Extension/appraisal drilling has been carried out at the Vesta and Oliver discoveries. Development and extension/appraisal drilling occurred in the

Puffin field (Puffin 7 –13) with oil production from 2007 to 2009.

Well Control

A total of 35 wells have been drilled on the Ashmore Platform, if all 14 wells in the Puffin field (Puffin 1 –13 and Pituri 1) are included, as well as those marginal to the western Vulcan Sub-basin. No wells have been drilled in

Release Area AC11-1 but three wells (Ashmore Reef 1, Mount

Ashmore 1, 1A, 1B, 1B ST1 and 1B ST2 and North Hibernia 1) have been drilled nearby on the western Ashmore Platform ( Figure 3 ). The majority of wells have been drilled on the eastern and southeastern portions of the platform, and include the seven wells in Release Area AC11-2 (Brown

Gannet 1, Great Eastern 1, Cartier 1, Caversham 1, Lucas 1, Pascal 1 and

Rothbury 1). Numerous wells have been drilled in the adjacent Vulcan Subbasin to the east and some wells have been drilled near the southern margin of the Ashmore Platform (Delta 1, Gryphaea 1 and Turbo 1) adjacent to the

Caswell Sub-basin, the major depocentre of the Browse Basin.

Ashmore Reef 1 (1968)

Ashmore Reef 1 was drilled by the Burmah Oil Company of Australia Ltd

(1968) as a stratigraphic test of the outer portion of the Ashmore Platform.

The well was drilled in 38.7 m of water to a total depth (TD) of 3914 mKB and intersected a thick succession of Cenozoic –mid Cretaceous carbonates and marls. Only a thin section of Lower Cretaceous shales, sandstones and calcarenites (Echuca Shoals Formation equivalent) are present. Upper

Jurassic volcanics (Swan Group), comprising basalt and interbedded tuffs

(317 m), unconformably overlie a thick succession of Upper Triassic shallow water marine clastics and carbonates (2,787

–3,914 mKB; Sahul Group) in which the well terminated. The well confirmed the presence of Eocene calcarenites and Upper Triassic sandstone reservoirs, but no significant hydrocarbon shows were recorded.

Brown Gannet 1 (1972)

Brown Gannet 1 was drilled by Arco Australia Ltd (1972a) near the crest of a large, faulted, northeast-trending anticline in the central part of the Ashmore

Platform. The anticlinal feature was mapped with apparent closure at base-

Cenozoic and near base-Cretaceous levels. The well, drilled in 110 m of water, reached a TD of 2,743 mKB in Upper Triassic clastics and minor carbonates (Sahul Group). The 576 m thick Triassic section was unconformably overlain by mid-Cretaceous to Paleogene and Neogene carbonates and marls. There were no significant hydrocarbon shows recorded during drilling. Log analysis indicated several possible hydrocarbon-bearing sandstones and limestones in the depth range 829

–906 mKB (Cartier

Formation), and sidewall cores in the depth range 846 –925 mKB exhibited pale yellow-white spotty fluorescence but no pronounced cut. However, a

Formation Interval Test (FIT) at 858 mKB of a porous limestone, with the highest and most reliable resistivity index, recovered water and no hydrocarbons. Reliable water saturations for these zones are difficult to




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calculate and are open to question due to log quality, but the overall data suggests that the anomalous zones are caused by the large washed-out borehole, possibly compounded by the presence of residual gas.

Puffin Oil Field

Puffin 1 (1972), Puffin 2 (1974), Puffin 3 (1975), Puffin 4 (1988), Pituri 1

(1994), Puffin 5 (2000), Puffin 6 (2001), Puffin 7 (2006), Puffin 8 (2007),

Puffin 9 (2006), Puffin 10, ST1, ST2 (2007), Puffin 11, ST1 (2008),

Puffin 12 ST1, ST2, ST3 (2009) and Puffin 13 (2009).

The Puffin oil field lies approximately 720 km west of Darwin on the eastern margin of the Ashmore Platform and western margin of the Vulcan Sub-basin.

It is located within Production Licence AC/L6 held by East Puffin Pty Ltd and

AED Oil Limited

( http://www.nt.gov.au/d/Minerals_Energy/Content/File/pdf/List_Offshore_Onsh ore_Title_Holders.pdf

). The Puffin 1 –3 and Pituri 1 exploration wells were drilled in the early 1970s by Arco Australia Ltd; however, it was more than a decade later before development and extension/appraisal wells were drilled

(Puffin 4 –6; 1988–2001). A comprehensive review of the entire Puffin field was undertaken by AED Oil Ltd utilising reprocessed Onnia 3D seismic data which resulted in the recommencement of drilling (Puffin 7 –12) during 2006–

2009 with Sinopec International Petroleum Exploration and Production

Corporation completing development of the Puffin field (Puffin 12 ST1,

ST2, ST3 and Puffin 13) in 2009. Production from the Puffin oil field commenced in October 2007 via the Front Puffin FPSO; however, operations were suspended in 2009 after 2,246 MMbbl of oil had been extracted

(Department of Resources, Minerals and Energy Group, 2010).

The oil in the Puffin field is located in four separate pools and reservoired in

Upper Cretaceous fan sandstones of the Puffin Formation. It is sourced from the Upper Jurassic lower Vulcan Formation in the adjacent Swan Graben.

Multiple oil charges are inferred, and the crude oils are interpreted to have lost their gases by solution (water washing) effects and leakage.

Puffin 1 (1972)

Puffin 1 was drilled by Arco Australia Ltd (1972b) to test the crest of an elongate northeast-trending anticline on the eastern flank of the Ashmore

Platform adjacent to the Swan Graben in the Vulcan Sub-Basin. The anticlinal feature was mapped with apparent closure at base-Cenozoic and near base-

Cretaceous levels.

The well, drilled in 102.4 m of water, reached a TD of 2,961 mKB. It penetrated 603 m of Upper Triassic clastics and shallow marine oolitic carbonates (Sahul Group), which were unconformably overlain by mid –Upper

Cretaceous sandstones and shales (Bathurst Island Group) and Cenozoic carbonates, marls and minor sandstones (Woodbine Group).

Wireline log interpretation and core analyses indicated the presence of heavy crude oil in vuggy carbonates from 1,021 –1,029 mKB (Prion Formation), trapped below the Eocene

–Miocene unconformity. A FIT at 2,067 m in

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Maastrichtian sandstone (Puffin Formation) indicated the presence of gas and

45



API crude oil. This was the first record of hydrocarbons in Cretaceous and

Paleogene sediments in the Bonaparte Basin.

Puffin 2 (1974)

Puffin 2 was drilled by Arco Australia Ltd (1974) to further determine the hydrocarbon potential of the oil discovered in Puffin 1. Seismic interpretation subsequent to the drilling of Puffin 1 resulted in Puffin 2 being located in a more favourable structural position on the crest of a separate culmination

9 km southwest of Puffin 1.

The well, drilled in 78 m of water, reached a TD of 2,560 mKB in Upper

Triassic clastics and carbonates (Sahul Group). Several oil and gas shows were recorded whilst drilling the Paleocene –Upper Cretaceous section. Gas and fluorescence were recorded from the interval 2,028 –2,036 mKB in a

Maastrichtian sandstone (Puffin Formation), and a FIT at 2,032 mKB recovered 0.2 m 3 gas, 1,800 cm 3 water and 7,500 cm 3 of 49



API oil. The sandstone unit over the depth range 2,028 –2,035 mKB was perforated and flowed on test at a maximum rate of 4,608 bopd. This was the most significant oil discovery in the Timor Sea area at this time. Pressure data and API gravity differences suggested that the Puffin 1 and 2 reservoirs were not contiguous, but the existing seismic and well control did not permit accurate delineation of the closure and areal extent of the structure. The Maastrichtian Puffin

Formation sandstones have an average porosity of 23% and were tentatively interpreted as a barrier bar complex.

North Hibernia 1 (1974)

North Hibernia 1 was drilled by B.O.C. of Australia Ltd (1974) to test a faultinduced structural high in the outer northwest portion of the Ashmore

Platform. Structural closure is the result of Jurassic and Miocene phases of faulting.

The well was drilled in 33 m of water and intersected a very thick section

(2,017 m) of Upper Triassic clastics and carbonates with minor coals, evaporites and volcanics (Sahul Group) in which the well terminated at

4,000 mRT. These are unconformably overlain by a thin Lower Cretaceous glauconitic sandstone (Echuca Shoals Formation equivalent) and a thick succession of mid-Cretaceous to Cenozoic carbonates and marls. No significant hydrocarbon shows were recorded.

Mount Ashmore 1B ST2 (1980)

Mount Ashmore was drilled by Woodside/Burmah Oil NL to test the hydrocarbon potential of Lower to Middle Jurassic and Triassic reservoirs sealed by Lower Cretaceous claystones in a large, faulted domal anticline on the southern portion of the Ashmore Platform.

Following the abandonment of Mount Ashmore 1 at 664 m and Mount

Ashmore 1A at 1,058 m due to mechanical problems, Mount Ashmore 1B was spudded and then sidetracked as Mount Ashmore 1B ST1 and subsequently

Mount Ashmore 1B ST2 due to drilling difficulties (Woodside Petroleum




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Development Pty Ltd, 1981). The well, drilled in 623 m of water, reached a TD of 2,655 mRT in Upper Triassic sandstones, claystones, siltstones and limestones (Sahul Group). These sediments are overlain by a succession of

Upper Jurassic claystones, sandstones, calcilutites and volcanics (Vulcan

Formation equivalents) beneath the predicted Lower Cretaceous regional seal; the Lower –Middle Jurassic Plover Formation was absent. The well confirmed the presence of reservoir sandstones, a valid structure and sealing units. No significant shows were observed during drilling and wireline logs indicated that all potential reservoirs are water-bearing. The operator attributed the lack of hydrocarbons to source and migration problems, and also noted that faulting may have rendered the trap ineffective. The well confirmed that the Mount Ashmore structure was formed at the beginning of the Miocene, but its origin remains uncertain; the doming may be the result of deep seated igneous intrusion and subsequent subsidence due to cooling of this igneous material.

Rainbow 1 (1985)

Rainbow 1 was drilled by BHP Petroleum Pty Ltd (1985) in 135 m of water on the eastern margin of the Ashmore Platform to test Upper Triassic sandstones within a base-Cretaceous fault-dependent closure on an east-trending horst block. The bounding faults of the structure have been rejuvenated with each phase of renewed tectonism; in the Late Triassic to Early Cretaceous, early

Paleocene, early Miocene, and have continued into the Neogene.

The well was drilled to a TD of 2,700 mKB within Triassic sandstones (Sahul

Group) and no hydrocarbons were encountered. The Triassic section comprises tight carbonates and thin carbonate-cemented sandstones overlying porous sandstones with intercalated shale and coal, and is unconformably overlain by a thin Lower Cretaceous glauconitic sandy claystone (Echuca Shoals Formation). A poor lateral seal across the bounding faults may explain the lack of hydrocarbons in the well, but the very low gas readings and absence of fluorescence may also indicate that the structure is unfavourably positioned to receive hydrocarbon charge and migration.

Cartier 1 (1988)

Cartier 1 was drilled by Santos Ltd (1988) and targeted Upper and Middle

Triassic sandstones in an east-northeast-trending tilted fault block, 18 km southeast of Brown Gannet 1.

The well, drilled in 100 m of water, reached a TD of 2,635 mKB and intersected Middle Triassic interbedded claystones, siltstones and minor sandstones (Sahul Group) that are unconformably overlain by Lower

Cretaceous thin glauconitic siltstones and marls (Echuca Shoals Formation).

No hydrocarbon shows were recorded. A thick section of unpredicted Upper

Cretaceous porous turbidite sandstones (Puffin Formation) was intersected which effectively breached the lateral fault seal of the structure. However, the total absence of hydrocarbon indications provides no evidence of the predicted long-distance migration of hydrocarbons from Upper Jurassic source rocks in the Swan Graben.




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Lucas 1 (1990)

Lucas 1 was drilled by Santos Ltd (1990) to test an east-northeast-trending faulted anticline near the eastern margin of the Ashmore Platform, 19 km west of the Puffin field. The primary objectives were sandstones of the Upper

Cretaceous Puffin Formation and Upper Triassic Nome Formation.

The well, drilled in 90 m of water, reached a TD of 2,800 mKB in sandstones/claystones of the Upper Triassic Nome Formation. While good quality reservoirs were encountered, no significant shows were observed. The lack of hydrocarbons may be attributed to discontinuous migration pathways from potential source kitchen areas in the Vulcan Sub-Basin.

Pascal 1 (1990)

Pascal 1 was drilled by BHP Petroleum Pty Ltd (1990) to test a northeasttrending horst block with an areally large, low-relief drape closure near the eastern margin of the Ashmore Platform. The primary objectives were Upper

Cretaceous submarine fan sandstones of the Puffin Formation and Upper

Triassic Nome Formation sandstones below the base-Cretaceous unconformity.

The well, drilled in 100 m of water, reached a TD of 2,850 mKB in interbedded sandstones, claystones and carbonates of the Upper Triassic Challis

Formation, but the predicted overlying Nome Formation was absent. The

Triassic sediments are unconformably overlain and sealed by a thin section of

Lower Cretaceous glauconitic claystones (Echuca Shoals Formation). The submarine fan sediments of the Puffin Formation were penetrated, showing good reservoir characteristics. No hydrocarbons were encountered in the well.

The total absence of hydrocarbons suggests that the structure has never been charged, and that there is no direct hydrocarbon migration pathway from the Swan and Paqualin graben source kitchens to the east.

Yarra 1 (1990)

Yarra 1 was drilled by TCPL Resources Ltd (1990) on the eastern margin of the Ashmore Platform. The primary objective was the Upper Triassic Nome

Formation and the secondary target was the Upper Cretaceous Puffin

Formation.

The well, drilled in 111 m of water, reached a TD of 3,248 mRT within the

Pollard Formation. It intersected a thick Upper Triassic section of porous and permeable sandstones and interbedded siltstones, claystones and thin coals

(Nome Formation) as well as carbonates, sandstones and siltstones (Challis

Formation). The Triassic section was sealed by a thin Lower Cretaceous glauconitic claystones of the Darwin Radiolarite (Echuca Shoals Formation).

The predicted Puffin Formation fan sandstones were absent. Yarra 1 is considered a valid structural test of a late Miocene horst block, but no evidence exists for migration of hydrocarbons into or through the prospect.

Great Eastern 1 (1991)

Great Eastern 1 was drilled by TCPL Resources Ltd (1991a) to test a fourway dip closure mapped at both Cretaceous and Eocene levels on the




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eastern margin of the Ashmore Platform. The primary target was the Upper

Cretaceous Puffin Formation with the base-Eocene Grebe Sandstone (Grebe

Sandstone Member, Hibernia Formation) being the secondary target.

The well, drilled in 114 m of water, reached a TD of 2,800 mKB in the Vee

Formation (Bathurst Island Group). No hydrocarbons were intersected within either the primary or secondary objectives. There is no evidence for the migration of hydrocarbons into or through the prospect, but post-drill analysis suggests that the well was drilled outside closure.

Langhorne 1 (1991)

Langhorne 1 was drilled by TCPL Resources Ltd (1991b) to test the Upper

Triassic Nome Formation in a northeast-trending horst block near the eastern margin of the Ashmore Platform.

The well, drilled in 121.5 m of water, reached a TD of 2,600 mRT, and intersected good quality reservoir sandstones in the Nome Formation before terminating in the Challis Formation. The target is overlain by Upper Jurassic claystones and siltstones (Montara Formation, Swan Group, 20 m thick) and thin Lower Cretaceous glauconitic sandstones and claystones (Echuca

Shoals Formation, 2.5 m thick). No hydrocarbon shows were encountered, and there remains some doubt as to the validity of the structural closure.

Rothbury 1 (1991)

Rothbury 1 was drilled by BHP Petroleum on behalf of TCPL Resources Ltd

(1992a) to test a crescent shaped stratigraphic-structural play within a series of downthrown fault blocks on the northeastern extension of the Puffin structure. The primary objective of the well was to test the presence and hydrocarbon potential of the Tithonian delta front to submarine fan sandstones of the Upper Swan Formation (upper Vulcan Formation, Swan

Group). Lateral seal was to be provided by the Lower Swan Formation (lower

Vulcan Formation, Swan Group).

Rothbury 1, drilled in 115 m of water, intersected a sedimentary succession ranging in age from Holocene to Middle Jurassic and terminated at a TD of

3,027 mRT within the Lower Swan Formation (lower Vulcan Formation).

Reservoir quality, basal sandstones were encountered within the Grebe

Sandstone Member, and although sealed by 36 m of calcareous claystones, lie outside of structural closure. The Cretaceous Puffin, Wangarlu and Darwin formations (Bathurst Island Group) and the Late Jurassic (Tithonian) Upper

Swan Formation (upper Vulcan Formation) were not present in the well. The

Vee Formation (Bathurst Island Group) was found to overlie the mid-

Valanginian unconformity.

Geochemical analyses of the most organic-rich siltstone samples from the

Lower Swan Formation (lower Vulcan Formation) indicated that they were moderate to good quality oil-prone source rocks that are marginally mature for hydrocarbon generation. Minor solvent fluorescence was observed in twelve sidewall cores over the depth range 2,885 –3,015 m within this formation.




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Caversham 1 (1992)

Caversham 1 was drilled by TCPL Resources Ltd (1992b) to test a crescent shaped stratigraphic-structural play within a series of downthrown fault blocks on the northeastern extension of the Puffin structure, in a similar structural setting as that drilled by the Rothbury 1 well located some 1.2 km to the south-southeast. The primary objective was the Tithonian delta front to submarine fan sandstone of the Upper Swan Formation (upper Vulcan

Formation, Swan Group) above the Tithonian unconformity. Claystones of the

Albian Wangarlu Formation (Jamieson Formation, Bathurst Island Group) were predicted to form an effective seal.

The well, drilled in 115 m of water, terminated in the Lower Swan Formation

(lower Vulcan Formation, Swan Group) at a TD of 3,080 mRT, with no reservoir quality sediments being intersected. A thin unit of the Upper Swan

Formation (upper Vulcan Formation) was intersected and consisted of argillaceous greensand grading to glauconitic claystone. Solvent fluorescence and geochemical analyses of hydrocarbon indications within greensands from two sidewall cores (2,925 –2,927 mRT) suggest that they have migrated into this formation. Minor solvent fluorescence also occurred within claystones from sidewall cores taken within the Lower Swan Formation (lower Vulcan

Formation).

Pituri 1 (1994)

Pituri 1 was drilled by BHP Petroleum Pty Ltd (1995) to test a stratigraphic trap along the large, low relief fault block penetrated by Puffin 2. The trap is formed by the up-dip pinchout of a 15 m (Pituri) submarine fan sandstone within the Upper Cretaceous upper Puffin Formation. Claystones of the uppermost Puffin Formation were predicted to provide the vertical and lateral seal. The oil charge was to have been generated in the Swan Graben and migrated into Pituri 1 via fill-spill from the down-dip Puffin structure. The secondary objective was to test the Eocene Prion Formation calcarenites immediately below the Miocene unconformity. A fault-independent, low relief, four-way dip closure was believed to lie at the top of the Prion Formation carbonates.

The well, drilled in 89 m of water, penetrated a sedimentary sequence that ranged in age from Holocene to Cretaceous and reached a TD of 2,124 mRT within the Puffin Formation. Potential reservoir units were encountered within the Eocene Prion Formation and Grebe Formation (Grebe Sandstone

Member, Hibernia Formation). However, the fan sandstones within the uppermost Puffin Formation were absent; instead, the section was composed of calcareous claystone. The deepest Puffin Formation sandstones within the well (2,084 –2,142 mRT) have excellent reservoir characteristics (average porosity of 26%); however, the absence of significant hydrocarbons (only minor fluorescence being observed) is probably due to lack of structural closure at this depth. This sandstone unit is below the oil-water-contact at

Puffin 1.

Calcarenites recovered from conventional core in the Prion Formation (1,018

–

1,019 mRT) display brownish-black heavy oil staining in vugs and moldic

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porosity. Geochemical analyses determined that the solvent-extracted hydrocarbons comprised biodegraded oil. Log interpretation gave an average porosity of 33 %, but high water saturations were calculated. The calcarenites are sealed vertically by a 20 m thick marl; however, the relief is too low for a significant accumulation to exist at this location.

An approximately 1 m net oil column was interpreted from logs over the depth

1,706

–1,710 mRT within the Eocene Grebe Formation. The top 9 m of the sand is variably cemented by calcite and pyrite, with the lower portion of the sand exhibiting excellent porosity (27%). The oil-bearing sandstone is sealed by overlying intra-formational marine claystones. This zone probably lacks significant closure in Pituri 1; however, the well identified the basal Grebe

Sandstone Member section as a new play type.

For further details regarding wells and available data follow this link: http://www.ret.gov.au/Documents/par/data/documents/Data%20list/data%20li st_ashmore_AR11.xls




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Data Coverage

The Release Areas are covered by sparse regional data of various vintages, as well as good quality regional 2D speculative seismic survey grids acquired across the entire Ashmore Platform in 1996 –1998. These latter data provide

5 –10 km line spacing over Release Areas AC11-1 and AC11-2 (Digicon BR97 and Veritas BR98).

Immediately to the southeast of Release Area AC11-2 is the Petroleum Geo-

Services (PGS) Vulcan MegaSurvey that comprises the reprocessed Onnia

North MC3D seismic survey which provides a sub-basin-wide review

( http://www.pgs.com/Data_Library/Asia-

Pacific/Australia/Vulcan_MegaSurvey/ ). The North West Shelf Digital Atlas

(NWSDA) complements the Vulcan Megasurvey by providing a regional understanding of the petroleum provinces. This package also contains regional grids for bathymetry, gravity, magnetic, total organic carbon (TOC) content and Rock-Eval pyrolysis data ( http://www.pgs.com/Data_Library/Asia-

Pacific/Australia/North-West-Shelf-Digital-Atlas/ ).

There have been a significant number of new seismic surveys conducted on the Ashmore Platform that include:



The PGS GeoStreamer Northern Margin Australia –Arafura Multiclient

2D (NMWT) seismic survey ( http://www.pgs.com/Data_Library/Asia-

Pacific/Australia/Arafura-NMAA-09-2D/ ), which crosses Release Areas

AC11-1 and AC11-2.



The Fugro Tiffany non-exclusive 3D seismic survey

( http://www.fugromcs.com.au/Australia/3D_Cartier_Tiffany_3D.htm

), which crosses into the southern part of Release Area AC11-1. The primary objective for the Cartier Survey was to image the Puffin

Formation with the secondary objectives being the Triassic Nome

Formation and deeper Permian plays. The Tiffany (and Cartier West) seismic surveys primarily targeted the Oxfordian Sandstones of the

Swan Group with the secondary objective being the Nome Formation.



The Fugro Cartier Main non-exclusive 3D seismic survey

( http://www.fugromcs.com.au/Australia/3D_Cartier_Tiffany_3D.htm

) is located to the immediate south of Release Area AC11-2 but includes one graticular block of the Release Area.



The Fugro URSA 3D 2009 seismic survey was acquired on the platform immediately north of Release Area AC11-2.



The PGS GeoStreamer New Dawn long offset Multiclient 2D (PGS-

MC2D) seismic, gravity and magnetic surveys

( http://www.pgs.com/Data_Library/Asia-Pacific/Australia/New-Dawn-

2D/ ) are located to the south of the Release Areas.




Page 14 of 24

To view image of seismic coverage follow this link: http://www.ga.gov.au/energy/projects/acreage-release-andpromotion/2011.html#data-packages




Page 15 of 24

PETROLEUM SYSTEMS AND HYDROCARBON POTENTIAL

Petroleum Systems

Of the five wells drilled on the western and central Ashmore Platform, Brown

Gannet 1 is the only well that recorded hydrocarbons; a gas show within the

Oligocene Cartier Formation. A possible source of this gas could be from the

Permian Kinmore Group. From fluid inclusion studies of potential reservoir sections in seven wells on the platform (Geoscience Australia, 2003) the

Triassic sandstones in Ashmore Reef 1B were found to contain grains with oil inclusions (GOI) values ranging up to 0.2

–0.3%. Hence, there is the potential for an indigenous petroleum system to occur on the Ashmore Platform.

A Mesozoic petroleum system is effective on the eastern margin of the

Ashmore Platform, as exemplified by the Puffin oil field. The oil has been sourced from the Upper Jurassic lower Vulcan Formation in the adjacent

Swan Graben and has migrated into the Upper Cretaceous (Campanian

–

Maastrichtian) submarine fan sandstone reservoirs of the Puffin Formation

(Edwards et al, 2004; Figure 4 ). Oil shows also occur in Puffin 1 in the uppermost Prion Formation and in Puffin 2 in the Paleocene Johnson

Formation. In the nearby wells, Parry 1 has an oil show within the Puffin

Formation and Pituri 1 has an oil show in the Eocene Grebe Sandstone

Member of the Hibernia Formation. Pollard 1 and Warb 1A are drilled on the eastern flank of the Ashmore Platform where it abuts the Paqualin Graben and Cartier Trough and these wells have oil shows within the Oliver

Sandstone Member and Oliver Formation, respectively. They are presumed to have been sourced from the lower Vulcan Formation.




Page 16 of 24

TABLE 1: PETROLEUM SYSTEMS ELEMENTS SUMMARY

Sources

Upper Jurassic, oil-prone marine source rocks in the lower

Vulcan Formation and in transgressive marine shales of the

Montara Formation

Lower –Middle Jurassic, local, thin gas-prone to oil and gas-prone coals and carbonaceous pro-delta mudstones within the fluvio-deltaic Plover Formation

Potential gas-prone Permo-Triassic source rocks

Upper Cretaceous (Campanian –Maastrichtian) submarine fan sandstones of the Puffin Formation

Reservoirs

Seals

Triassic sandstones of the Sahul Group

Secondary reservoirs are the lower Eocene sandstones of the

Grebe Sandstone Member (Hibernia Formation) and

Paleogene carbonates and calcarenites of the Woodbine

Group

Lower Cretaceous claystones of the Echuca Shoals and

Jamieson formations provide the regional seal

Paleogene to Neogene carbonates of the Woodbine Group provide secondary seals

Play Types

Late Triassic tilted fault blocks, unconformity pinchouts and broad anticlines sealed by Lower Cretaceous claystones above the Jurassic –Early Cretaceous unconformity

Upper Cretaceous Puffin Formation fan sandstones on eastern platform margin which have access to Jurassic-sourced hydrocarbons migrating from the Swan and Paqualin graben

Miocene reefs within the Oliver Formation

Source Rocks

The proven Upper Jurassic source rocks of the Vulcan Sub-basin are generally either absent or thin and shallowly buried (immature) across the

Ashmore Platform ( Figure 5 and Figure 6 ). However, structures on the eastern margin of the platform have the potential to trap migrating hydrocarbons from the Swan and Paqualin source kitchens. Locally, in the outer parts of the Ashmore Platform, isolated half-graben of the presumed

Jurassic syn-rift section have been identified which may have oil-prone source potential. These graben are up to 5 km wide and several hundred metres thick




Page 17 of 24

(200

–500 ms TWT), and are overlain by a post-rift section of approximately

2,500 m thickness (1.5 s TWT).

The source potential of the older Permo-Triassic section is unknown. The equivalent Permian section on the Londonderry High, Sahul Platform and

Petrel Sub-basin in the eastern and northern Bonaparte Basin is known to have gas potential, whereas the overlying Lower Triassic shallow marine transgressive section (Mount Goodwin Subgroup) has poor source potential in those areas (Edwards and Summons, 1996).

Reservoirs

The major reservoir units across the Ashmore Platform are the shallow marine and fluvio-deltaic Triassic sandstones of the Sahul Group, of which the Nome

Formation equivalents have excellent reservoir quality and the Challis

Formation equivalents have good reservoir quality. The submarine fan sandstones of the Upper Cretaceous (Campanian

–Maastrichtian) Puffin

Formation are also a primary target but are restricted to the southeast margin of the platform (de Boer, 2004). Secondary potential reservoirs are the sandstones of the lower Eocene Grebe Sandstone Member, Hibernia

Formation and Paleogene carbonates of the Woodbine Group.

Seals

Claystones of the Lower Cretaceous Echuca Shoals and Jamieson formations provide a potential regional seal across the Ashmore Platform. The

Paleogene to Neogene carbonate section has a high seal risk.

Expulsion and Migration

Basin modelling in the Vulcan Sub-basin and adjacent Ashmore Platform was undertaken by Kennard et al (1999b) and progressively refined by Chen et al

(2002), Fujii et al (2004) and Neumann et al (2009). Modelled oil and gas expulsion from the lower Vulcan and Plover formations in the Swan and

Paqualin graben and Cartier Trough migrated westwards onto the flank of the

Ashmore Platform. Specific to Release Area AC11-2, migration has been demonstrated into the Puffin structure and towards Warb 1A; however, the migration pathways do not extend as far as Lucas 1, Pascal 1, Rainbow 1 or

Sahul Shoals 1.

The westward migration limits are primarily controlled by the absence of the

Plover Formation carrier beds onto the Ashmore Platform, but modelled and observed migration limits within the Upper Cretaceous Puffin Formation do not extend to the western margin of that fan system (Pascal 1, Lucas 1 and

Cartier 1). Thus, there is a migration path risk for potential traps located away from the eastern margin of the platform to be charged from Jurassic sources in the Vulcan Sub-basin. Any such structures are only viable targets if longdistance migration occurs, or older Triassic-Permian sources are effective on the platform.




Page 18 of 24

Hydrocarbon generation modelling has not been undertaken to assess the source-charge potential of the isolated half-graben of presumed Jurassic section in the outer parts of the Ashmore Platform. However, these syn-rift sediments are overlain by an approximately 2,500 m thick post-rift section

(1.5 s TWT) and, based on previous modelling of wells on the Ashmore

Platform (Kennard et al, 1999b), potential oil-prone source units within the lower part of this syn-rift section are likely to be sufficiently mature for hydrocarbon generation and expulsion.

Play Types

Drilling on the Ashmore Platform has focused on the Upper Cretaceous Puffin

Formation sandstone fans and Triassic sandstones (Nome and Challis formations) that immediately underlie the base-Cretaceous unconformity.

Most of the drilling activity has been focused on the eastern margin of the platform, relying on Jurassic sourced hydrocarbons migrating from the adjacent Swan, Paqualin and Cartier depocentres in the Vulcan Sub-basin.

Top Triassic targets have been tested by wells on the western, central and northern parts of the platform (Ashmore Reef 1, Sahul Shoals 1, Brown

Gannet 1, North Hibernia 1 and Cartier 1). The main trap types for this play are tilted fault blocks, unconformity pinchouts and broad anticlines that are all sealed by Lower Cretaceous claystones above the Jurassic –Early Cretaceous unconformity. The deeper top Permian section has only been intersected at

Sahul Shoals 1, where it comprises tight recrystallised limestones.

Secondary potential targets include Eocene carbonates and sandstones

(Grebe Formation) in which residual oil shows were encountered in Pituri 1.

These targets may have potential to be charged from either the isolated

Jurassic syn-rift graben (oil-prone) or the deeper Lower Triassic –Permian

(potentially gas-prone) sections on the northern and central parts of the platform.

A potential new play type on the Ashmore Platform comprises Lower –Middle

Miocene reefs within the Oliver Formation. More than 30 patch reef structures have been identified on the southeastern and eastern margin of the Ashmore

Platform, and confirmed by reefal facies intersected in the Lucas 1, Pascal 1 and Prion 1 wells (Gorter et al, 2002). A possible Miocene barrier reef trend has also been identified in the western portion of the Ashmore Platform

(Bernardel, 2005; Ryan et al, 2009).

However, these build-ups are relatively small, usually less than 5 km in width and less than 100 m thick.

Interpreted ?Lower Cretaceous reef or mound structures that overlie eroded

Triassic horst blocks have been documented on the southern portion of the platform, south of the Release Areas. These mounds appear to be unfaulted and unaffected by fault-reactivation in the region, thereby potentially overcoming the preservation risk present elsewhere on the platform.




Page 19 of 24

Critical Risks

Critical risk factors for the Ashmore Platform are the existence of effective source rocks on the platform, suitable migration pathways from known source rocks within the adjacent Vulcan Sub-basin, as well as trap integrity. The platform is heavily faulted, and these faults were generally active during each phase of renewed tectonism and many extend to the seafloor. However, synthetic aperture radar data provides no evidence of active oil slicks on the platform (Infoterra, 2003).




Page 20 of 24

FIGURES

Figure 1:

Figure 2:

Figure 3:

Figure 4:

Figure 5 :

Figure 6:

Figure 7:

Location map of Release Areas AC11-1 and AC11-2 on the

Ashmore Platform, Bonaparte Basin.

Graticular block map and Graticular Block listings for Release

Areas AC11-1 and AC11-2 on the Ashmore Platform,

Bonaparte Basin.

Regional structural elements of the western Bonaparte Basin, showing the location of seismic sections in Figure 5, Figure

6 and Figure 7 .

Stratigraphic correlations between the Ashmore Platform and

Vulcan Sub-basin, Bonaparte 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). Accumulations ( bold ) and hydrocarbon shows are also displayed. Seismic horizons after Kennard and Colwell (2001).

Seismic line AGSO 130/10 through Release Area AC11-1 on the Ashmore Platform (location of line shown in Figure 3 ).

Seismic line AGSO 98r/07 through Release Areas AC11-1 and

AC11-2 on the Ashmore Platform (location of line shown in

Figure 3 ).

Seismic line AGSO 98r/08 through Release Area AC11-2 on the Ashmore Platform (location of line shown in Figure 3 ).




Page 21 of 24

REFERENCES

ARCO AUSTRALIA LTD, 1972a — Well Completion Report, Brown

Gannet No.1, unpublished.

ARCO AUSTRALIA LTD, 1972b

—Well Completion Report, Puffin No.1, unpublished.

ARCO AUSTRALIA LTD, 1974 — Well Completion Report, Puffin No.2, unpublished.

BERNARDEL, 2005

—Report on Ashmore Platform ‘Seeps and Signatures’ focused seismic interpretation study. Geoscience Australia, unpublished.

BHP PETROLEUM PTY. LTD. 1985 —Rainbow-1 Well Completion Report, unpublished.

BHP PETROLEUM PTY. LTD. 1990 —AC/P2, Well Completion Report,

Pascal 1, Interpretive Data, unpublished.

BHP PETROLEUM PTY. LTD. 1995

—Pituri-1 AC/P2, Well Completion

Report, Interpretive Data, unpublished.

B. O. C. OF AUSTRALIA LTD. 1974 —North Hibernia No.1 Completion

Report, unpublished.

BURMAH OIL COMPANY OF AUSTRALIA LTD, 1968

—Ashmore Reef No.1,

Well Completion Report, unpublished.

CHEN, G., HILL, K.C. AND HOFFMAN, N., 2002 —3D structural analysis of hydrocarbon migration in the Vulcan Sub-basin, Timor Sea. In: Keep, M. and

Moss, S.J. (editors), The Sedimentary Basins of Western Australia 3,

Proceedings of the Petroleum Exploration Society of Australia Symposium,

Perth, 2002, 377

–388.

DE BOER, R.A., 2004

—The Puffin Sandstone, Timor Sea, Australia: Anatomy of a submarine fan. In: Ellis, G.K., Baillie, P.W. and Munson, T.J. (editors),

Timor Sea Petroleum Geoscience, Proceedings of the Timor Sea Symposium,

Darwin, 19

–20 June 2003. Northern Territory Geological Survey, Special

Publication 1.

DEPARTMENT OF RESOURCES, MINERALS AND ENERGY GROUP,

2010

—[Web Page] EnergyNT 2009 Energy Activities for the Northern

Territory 2009. Northern Territory Government, Darwin, 33p. http://www.nt.gov.au/d/Minerals_Energy/Content/File/pdf/PetroleumSummarie s/2009_EnergyNT.pdf

(last accessed 10 January 2011)

EDWARDS, D.S., PRESTON, J.C., KENNARD, J.M., BOREHAM, C.J., VAN

AARSSEN, B.G.K., SUMMONS, R.E. AND ZUMBERGE, J.E., 2004 —

Geochemical characteristics of hydrocarbons from the Vulcan Sub-basin, western Bonaparte Basin, Australia. In: Ellis, G.K., Baillie, P.W. and Munson,




Page 22 of 24

T.J. (editors), Timor Sea Petroleum Geoscience, Proceedings of the Timor

Sea Symposium, Darwin, 19 –20 June 2003. Northern Territory Geological

Survey, Special Publication 1, 169 –201.

EDWARDS, D.S. AND SUMMONS, R.E., 1996

—Petrel Sub-basin Study

1995 –1996: Organic Geochemistry of Oils and Source rocks. Australian

Geological Survey Organisation Record 1996/42, 77p.

FUJII, T., O’BRIEN, G.W., TINGATE, P AND CHEN, G., 2004—Using 2D and

3D basin modelling to investigate controls on hydrocarbon migration and accumulation in the Vulcan Sub-basin, Timor Sea, northwestern Australia.

The APPEA Journal 44(1), 93-122.

GEOSCIENCE AUSTRALIA, 2003

—Destructive Analysis Report DAR1311

GOI Analysis – Ashmore Platform. CSIRO Report for Geoscience Australia

(unpublished).

GORTER, J.D., REXILIUS, J.P., POWELL, S.L. AND BAYFORD, S.W.,

2002

—Late Early to Mid Miocene patch reefs, Ashmore Platform, Timor Sea –

Evidence from 2D and 3D seismic surveys and petroleum exploration wells.

In: Keep, M. and Moss, S. (editors), The Sedimentary Basins of Western

Australia 3, Proceedings of the Petroleum Exploration Society of Australia

Symposium, Perth, 2002, 355-375.

GRADSTEIN, F., OGG, J. AND SMITH, A. (EDITORS), 2004 —A Geologic

Time Scale 2004. Cambridge: Cambridge University Press, 589.

INFOTERRA, 2003 —Global seeps database (unpublished) http://www.infoterra.co.uk/global-seeps (last accessed 10 January 2011).

KENNARD, J.M. AND COLWELL, J.B., 2001

—Line drawings of AGSO –

Geoscience Australia’s regional seismic profiles, offshore northern and northwestern Australia. AGSO Record 2001/36, AGSOCAT 36353.

KENNARD, J.M., COLWELL, J.B., EDWARDS, D.S., WEBSTER, M.A.,

MONTGOMERIE, N.R. AND STEGE, B., 1999a

—Vulcan Sub-basin well composites. CD-ROM. AGSOCAT 25307.

KENNARD, J.M., DEIGHTON, I., EDWARDS, D.S., COLWELL, J.B.,

O’BRIEN, G.W. AND BOREHAM, C.J., 1999b—Thermal history modelling and transient heat pulses: new insights into hydrocarbon expulsion and ‘hot flushed’ in the Vulcan Sub-basin, Timor Sea. The APPEA Journal, 39(1), 177–

207.

NEUMANN, V., DI PRIMO, R. AND HORSEFIELD, B., 2009

—Source rock distributions and petroleum fluid bulk compositional predictions on the Vulcan

Sub-basin, offshore Western Australia. Report for Geoscience Australia 67. https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS

&catno=69210 (last accessed 10 January 2011)




Page 23 of 24

NICOLL R.S., KENNARD, J.M., LAURIE, J.R., KELMAN, A.P., MANTLE D.J.

AND EDWARDS D.S., 2009 —Bonaparte Basin, Biozonation and Stratigraphy,

2009, Chart 33. On CD: Basin Biozonation and Stratigraphy Charts, 2009.

Geoscience Australia.

OGG, J. G., OGG, G. AND GRADSTEIN, F. M., 2008 —The Concise Geologic

Time Scale. Cambridge: Cambridge University Press, 177.

RYAN, G.J., BERNARDEL, G., KENNARD, J.M., JONES, A.T., LOGAN, G.A. and ROLLET, N., 2009

—A precursor extensive Miocene reef system to the

Rowley Shoals reefs, WA: evidence for structural control of reef growth or natural hydrocarbon seepage? The APPEA Journal, 49(1), 337 –363.

SANTOS LTD, 1988

—Cartier 1 Well Completion Report, unpublished.

SANTOS LTD, 1990 —Lucas 1, Well Completion Report, Interpreted Data, unpublished.

TCPL RESOURCES LTD, 1990

—AC/P13, Offshore Northern Territory, Timor

Sea, Australia, Well Completion Report, Yarra-1, unpublished.

TCPL RESOURCES LTD, 1991a —AC/P13, Offshore Northern Territory,

Timor Sea, Australia, Well Completion Report, Great Eastern-1, unpublished.

TCPL RESOURCES LTD, 1991b

—AC/P13, Offshore Northern Territory,

Timor Sea, Australia, Well Completion Report, Langhorne-1, Volume II

Interpretive Data, unpublished.

TCPL RESOURCES LTD, 1992a

—AC/P13, Offshore Northern Territory,

Timor Sea, Australia, Well Completion Report, Rothbury-1, unpublished.

TCPL RESOURCES LTD, 1992b —AC/P13, Offshore Northern Territory,

Timor Sea, Australia, Well Completion Report, Caversham-1, unpublished.

WESTERN MINING CORPORATION LIMITED, 1992

—AC/P11 Timor Sea,

Australia, Warb 1, 1A, Well Completion Report (Interpretive), unpublished.

WOODSIDE PETROLEUM DEVELOPMENT PTY LTD, 1981 —Mount

Ashmore No.1B, NT/P5, Completion Report, unpublished.

Front page image courtesy of Petroleum Geo-Services.




Page 24 of 24

Ashmore Platform Release Areas - Offshore Petroleum Exploration

PETROLEUM GEOLOGICAL SUMMARY

RELEASE AREAS AC11-1 AND AC11-2,

ASHMORE PLATFORM, BONAPARTE BASIN,

TERRITORY OF ASHMORE AND CARTIER ISLANDS

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Ashmore Platform Release Areas - Offshore Petroleum Exploration

PETROLEUM GEOLOGICAL SUMMARY

RELEASE AREAS AC11-1 AND AC11-2,

ASHMORE PLATFORM, BONAPARTE BASIN,

TERRITORY OF ASHMORE AND CARTIER ISLANDS

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