Geology - Offshore Petroleum Exploration Acreage Releasepetroleum-acreage.slicedlabs.com.au/2008/site/documents/geo_Petrel.… · 2008 Release of Australian Offshore Petroleum Exploration

2008 Release of Australian Offshore Petroleum Exploration Areas Release areas NT08-1 to NT08-3, and W08-1 to W08-3, Petrel Sub-basin, Bonaparte Basin

2008 RELEASE OF AUSTRALIAN OFFSHORE PETROLEUM EXPLORATION AREAS

RELEASE AREAS NT08-1, NT08-2 AND NT08-3, AND

RELEASE AREAS W08-1, W08-2 AND W08-3 PETREL SUB-BASIN, BONAPARTE BASIN

NORTHERN TERRITORY / WESTERN AUSTRALIA SECTIONS SUMMARY - RELEASE AREAS NT08-1, NT08-2 AND NT08-3, AND RELEASE AREAS W08-1, W08-2 AND W08-3 BONAPARTE BASIN GEOLOGY

BONAPARTE BASIN REGIONAL GEOLOGY BASIN EVOLUTION AND TECTONIC DEVELOPMENT REGIONAL HYDROCARBON POTENTIAL EXPLORATION HISTORY HYDROCARBON RESERVES FIGURES

RELEASE AREAS NT08-1, NT08-2 AND NT08-3

LOCATION GRATICULAR BLOCK LISTINGS AND MAP

RELEASE AREAS W08-1, W08-2 AND W08-3

LOCATION GRATICULAR BLOCK LISTINGS AND MAP RELEASE AREA GEOLOGY

Rift-related structures Stratigraphy

EXPLORATION HISTORY Petrel Sub-basin Exploration History Well Control Key Wells Listing Seismic Coverage

HYDROCARBON POTENTIAL Petroleum Systems Hydrocarbon Families and Source Rocks Timing of Generation and Expulsion Reservoirs Seals Play Types Critical Risks

FIGURES

REFERENCES (All Bonaparte Release areas)


SUMMARY RELEASE AREAS NT08-1, NT08-2 AND NT08-3, AND RELEASE AREAS W08-1, W08-2 AND W08-3 PETREL SUB-BASIN, BONAPARTE BASIN NORTHERN TERRITORY / WESTERN AUSTRALIA BIDS CLOSE - 9 April 2009

Under-explored, shallow water areas in a proven Palaeozoic gas province

Close to the Petrel, Tern and Blacktip gas fields and the Blacktip pipeline

Faulted anticlines, salt associated structures and stratigraphic traps Special Notices apply, refer to Guidance Notes


BONAPARTE BASIN REGIONAL GEOLOGY The Bonaparte Basin is located predominantly offshore (Figure 1) and covers an area of approximately 270,000 km2 of Australias northwest continental margin. The basin contains up to 15 km of Phanerozoic marine and fluvial siliciclastics, as well as marine carbonates. The regional geology, structural evolution and petroleum potential have been described by Laws and Kraus (1974), Gunn (1988), Lee and Gunn (1988), Gunn and Ly (1989), MacDaniel (1988), Mory (1988, 1991), Botten and Wulff (1990), Hocking et al, 1994, Woods (1994), and summarised by Cadman and Temple (2004). Recent papers on the petroleum geology of the region are presented in the Proceedings of the Timor Sea Symposium, Darwin, June 2003 (Ellis et al, 2004). The Bonaparte Basin is bounded to the northwest by the Timor Trough, where water depths exceed 3000 m. In the northeast, beyond the limits of the Darwin Shelf, the basin adjoins the Arafura and Money Shoal basins. To the southwest, it is contiguous with the Browse Basin. The basin is structurally complex and comprises a number of Palaeozoic and Mesozoic sub-basins and platform areas (Figure 1). It developed during two phases of Palaeozoic extension, followed by Late Triassic compression, and then further extension in the Mesozoic that culminated in the breakup of Gondwana in the Middle Jurassic (OBrien et al, 1993). Convergence of the Australia-India and Eurasia plates in the Miocene to Pliocene resulted in flexural downwarp of the Timor Trough and widespread fault reactivation across the western Bonaparte Basin. The Petrel Sub-basin is a northwest-trending Palaeozoic rift that occurs in the eastern portion of the Bonaparte Basin and extends onshore. It contains a thick section of mostly Palaeozoic and thinner Mesozoic sediments, and is underlain by Proterozoic crystalline basement (dolerite in well sections) and sediments of the Proterozoic Kimberley Basin (Colwell and Kennard, 1996). The eastern and southwestern margins of the sub-basin are flanked by platforms of relatively shallow basement and thin sediment cover. Sedimentation in the sub-basin commenced in the Cambrian, and northeastsouthwest rifting was initiated in the Late Devonian to Early Carboniferous. Offshore, the Petrel Sub-basin is orthogonally overprinted by a northeast-trending structural grain that resulted from Late Palaeozoic and Mesozoic rifting. The Malita and Calder grabens form a major, northeast-trending rift system that lies between the Petrel Sub-basin and the Sahul Platform. The grabens contain a thick succession of Late Palaeozoic, Triassic, Jurassic and Early Cretaceous sediments. The Sahul Platform, which underlies most of the Joint Petroleum Development Area (JPDA), is an area of relatively shallow basement. The PermoTriassic succession in this area was uplifted to form a structural high during Jurassic extension of the adjacent Malita and Calder grabens. The Vulcan Sub-basin is a major northeast-trending, Late Jurassic rift depocentre in the western part of the Bonaparte Basin. It is flanked to the


southeast and northwest by PermoTriassic platforms; the Londonderry High and the Ashmore Platform, respectively. The Sahul and Flamingo synclines are northwest-trending depocentres that link and offset the northeast-trending Malita-Calder graben and Vulcan Sub-basin rift systems. These synclines are separated by the Laminaria and Flamingo highs. BASIN EVOLUTION AND TECTONIC DEVELOPMENT The Bonaparte Basin has undergone a complex structural history. The Phanerozoic evolution of the region has been described by Gunn (1988), Veevers (1988), Pattillo and Nicholls (1990), OBrien et al (1993), AGSO NW Shelf Study Group (1994), Baillie et al (1994), Whittam et al (1996) and Kennard et al (2002). Neogene tectonism and its implications for petroleum exploration in the Bonaparte Basin are described by McCaffrey (1988), Shuster et al (1998), Keep et al (1998, 2002) and Longley et al (2002). Key events in the evolution of the Bonaparte Basin include:

Widespread volcanism and subsidence initiated deposition in the onshore portion of the Petrel Sub-basin in the Cambrian.

Late Devonian to Early Carboniferous extension formed the northwest-trending Petrel Sub-basin.

Extension in the Late Carboniferous to Early Permian overprinted the older trend with a northeast-oriented structural grain. The proto-Vulcan Sub-basin and Malita Graben developed at this time.

A compressional event in the Late Triassic caused uplift and erosion on the Londonderry High, the Ashmore and Sahul platforms, and the southern margins of the Petrel Sub-basin.

In response to Mesozoic extension, the Vulcan Sub-basin, Sahul Syncline, Malita Graben and Calder Graben became major Jurassic depocentres. This structuring coincided with the commencement of sea-floor spreading in the Argo Abyssal Plain to the west of the Browse Basin.

With the onset of thermal subsidence in the Early Cretaceous (Valanginian), a thick wedge of fine-grained, clastic and subsequently carbonate sediments prograded across the offshore Bonaparte Basin throughout the Cretaceous and Tertiary.

Regional compression associated with the collision of the Australia-Indian Plate with the Southeast Asian micro-plates in the Miocene formed the Timor Trough and the strongly faulted northern margin of the adjacent Sahul Platform.

The stratigraphy of the basin is summarised in Figure 2. Palaeozoic sediments are largely restricted to the onshore and inboard portions of the Petrel Sub-basin, while Mesozoic and Cenozoic sequences are largely confined to the outboard portion of the Bonaparte Basin. Volcanic and clastic sedimentation commenced in the onshore Petrel Sub-basin in the Cambrian. This pre-rift sequence contains extensive evaporite deposits,


but the precise age (Ordovician, Silurian or Devonian), lateral continuity and extent of these salt bodies is poorly known. Subsequent salt tectonics (flow, diapirism and withdrawal) has controlled the development of numerous structural and stratigraphic traps within the sub-basin (Edgerley and Crist, 1974; Gunn, 1988; Durrant et al, 1990; Lemon and Barnes, 1997). Northeastsouthwest rifting was initiated in the Late Devonian, and clastic and carbonate sediments were deposited in shallow marine and non-marine environments within the Petrel Sub-basin. During the Carboniferous, a thick succession of marine and fluviodeltaic (Bonaparte Formation to Point Spring Sandstone) and, finally, glacial sediments (Kuriyippi Formation and Treachery Shale) were deposited in response to post-rift subsidence and salt withdrawal. The initial northwest-trending Late DevonianEarly Carboniferous rift-sag system (ie, Petrel Sub-basin in the eastern Bonaparte Basin) was orthogonally overprinted in the Late Carboniferous to Early Permian by northeast-trending rifts to form the proto-Malita Graben and probably a proto-depocentre in the Vulcan Sub-basin (OBrien, 1993; Baxter, 1996). A succession of northwest-thickening, shallow marine to fluviodeltaic, Permian and Triassic sediments was then deposited across the Bonaparte Basin (Keyling to Cape Londonderry formations). These form the reservoir facies for the gas discoveries in the Petrel Sub-basin and on the Londonderry High. Compression in the Late Triassic resulted in reactivation and inversion of the previous Palaeozoic fault systems (OBrien et al, 1993) and caused widespread uplift and erosion on the Ashmore Platform, Londonderry High and in the southern portion of the Petrel Sub-basin. Late TriassicEarly Jurassic fluvial sedimentation (Malita Formation) was followed by a thick widespread succession of EarlyMiddle Jurassic fluvial and coastal plain deposits (Plover Formation) throughout most areas of the Bonaparte Basin except for the Ashmore Platform and crest of the Londonderry High. The Plover Formation forms a major source and reservoir unit over much of the northern Bonaparte Basin. The onset of rifting in the mid-Callovian resulted in a widespread marine transgression and the deposition of retrogradational deltaic sandstones (Elang, Laminaria and Montara formations), which form reservoir units in many of the commercial petroleum accumulations in the northern Bonaparte Basin. Continued rifting and rapid subsidence resulted in the deposition of a thick succession of marine mudstones (Vulcan Formation and Frigate Shale) within the Vulcan Sub-basin, Sahul Syncline, Malita Graben and Calder Graben. These marine sediments contain good quality oil-prone source rocks, but source quality decreases within the Malita and Calder grabens. Mesozoic extension ceased with the onset of sea-floor spreading in the Valanginian and was followed by widespread thermal subsidence and flooding of the western Australian continental margin. Fine grained clastics and carbonates of the Bathurst Island Group were deposited across the Bonaparte Basin during this phase. At the base of the Bathurst Island Group, claystones of the Echuca Shoals Formation provide a regional seal for the hydrocarbon


accumulations in the Vulcan Sub-basin. This unit thins onto the platform areas in the west (Ashmore and Sahul platforms) and in the Petrel Sub-basin to the east. The Late Cretaceous and Cenozoic sections typically comprise thick, prograding platform carbonates. Lowstand sandstones accumulated in the Maastrichtian (Puffin Formation) and Eocene (Grebe Formation). Regional compression, associated with the collision of the AustraliaIndia Plate with the Southeast Asian micro-plates, reactivated Mesozoic faulting and breached many fault-dependent structures in the Vulcan Sub-basin and adjacent areas. This regional tectonism resulted in the loss of hydrocarbons from previous accumulations (OBrien and Woods, 1995; OBrien et al, 1999; Longley et al, 2002) and leakage to the sea floor that appears to have controlled the development and distribution of present-day biohermal mounds in the region (Bishop and OBrien, 1998; OBrien et al, 2002). PETREL SUB-BASIN The Petrel Sub-basin is an asymmetric, northwestsoutheast-trending Palaeozoic rift that contains a succession of thick Palaeozoic and thinner Mesozoic sediments. The eastern and western faulted margins of the sub-basin converge onshore to form a southern termination. To the south and east of the Petrel Sub-basin, extensions of the Halls CreekFitzmaurice Mobile Zone separate this sub-basin from the Precambrian Victoria River Basin and Pine Creek Geosyncline. Extensive basement shelves overlain by a thin cover of Phanerozoic sediments lie on the eastern, western and southern margins of the Petrel Sub-basin. To the east, the Kulshill Terrace and Moyle Platform extend to the north-northeast into the Darwin Shelf. In the southwest, the Berkley Platform has been sub-divided into several, smaller southeast-trending horst (Lacrosse Terrace and Turtle-Barnett High) and graben (Cambridge Trough) structures. Strata within the Petrel Sub-basin dip regionally to the northwest about a northwest-plunging synclinal axis, resulting in exposure of Early Palaeozoic sediments in the southern onshore area, and in the progressive subcropping of Late Palaeozoic, Mesozoic and Cenozoic sediments offshore. The Late PalaeozoicMesozoic section exceeds 15 km in thickness in the central and northern Petrel Sub-basin. VULCAN SUB-BASIN The Vulcan Sub-basin is a northeast-trending, Mesozoic, extensional depocentre in the western Bonaparte Basin. The sub-basin comprises a complex series of horsts, grabens and marginal terraces, and abuts the Londonderry High to the east-southeast and the Ashmore Platform to the west-northwest (Figure 1). The structurally significant and proven hydrocarbon source provinces of the Swan Graben and Paqualin Graben die out to the northeast beneath the younger (Neogene) Cartier Trough. The Montara Terrace flanks the Swan Graben to the east, while the Jabiru Terrace borders the eastern margin of the Cartier Trough. The southern boundary of the Vulcan Sub-basin with the northern Browse Basin is somewhat arbitrary. OBrien et al (1999) considered that the boundary is marked by a fault relay zone that overlies a major northwest-trending Proterozoic fracture system. The Vulcan Sub-basin developed as part of an upper plate rift margin (OBrien, 1993). The rift margin developed as a linked array of northwest-trending


accommodation zones orthogonal to northeast-trending normal faults (Etheridge and OBrien, 1994; OBrien et al, 1996, 1999). Thermal sag phase sedimentation continued until the Late Tertiary, resulting in over 10 km of sediment-fill in the deeper graben (Baxter et al, 1997). ASHMORE PLATFORM The Ashmore Platform is an extensive, elevated and highly structured block. It borders the Vulcan Sub-basin to the east, the northern Browse Basin to the south and deepens into the Timor Trough to the west. On the platform, up to 1500 m of flat-lying Cretaceous and Cenozoic strata overlie up to 4500 m of heavily faulted and folded PermoTriassic sediments. Rifting through to the Late Jurassic breakup of the Argo margin to the south led to tilted fault-block development prior to widespread peneplanation, subsidence and burial in the CretaceousCenozoic. It has been subjected to fault reactivation due to the MiocenePliocene convergence of the Australian Plate and the southeast Asian micro-plates. LONDONDERRY HIGH The Londonderry High is characterised by a highly faulted sequence of Palaeozoic and Triassic rocks that acted as a major sediment source for adjacent depocentres during the Late Jurassic rifting (Whibley and Jacobsen, 1990; de Ruig et al, 2000), overlain unconformably by a relatively unfaulted, Late Jurassic and younger succession. Although most faulting terminates at the top of the Triassic sequence, some faults show evidence of Miocene reactivation. On higher parts of the Londonderry High the Triassic section is deeply eroded. Uplift and erosion are less pronounced on the eastern and northern flanks where the unconformity is underlain by progressively younger sediments. NORTHERN BONAPARTE BASIN The northern Bonaparte Basin, as redefined by Whittam et al (1996), encompasses the area to the northwest of the Petrel Sub-basin that contains a thick Mesozoic and Cenozoic succession. Two major depocentres of Late Jurassic to Early Cretaceous age are recognised in the northern Bonaparte Basin (Figure 1); the northeastsouthwest-trending Malita and Calder grabens, and the northwestsoutheast-trending Sahul Syncline, including its western extension, the Nancar Trough. These depocentres are flanked to the north by the Sahul Platform and to the south by the Londonderry High. The stratigraphy and geological history of the northern Bonaparte Basin has been described by Mory (1988), Gunn (1988), MacDaniel (1988), Veevers (1988), Pattillo and Nicholls (1990), OBrien et al (1993), Whittam et al (1996), Labutis et al (1998) and Shuster et al (1998), and is summarised by Cadman and Temple (2004). The present day configuration of the northern Bonaparte Basin results from the intersection and superimposition of three cycles of rifting: an initial northwesttrending Late Devonian rift extending outboard from the Petrel Sub-basin, northeast-trending Late CarboniferousPermian rifting, and Jurassic rifts in the Malita and Calder grabens and Vulcan Sub-basin. The pre-existing Palaeozoic structural grain had considerable influence on the distribution and thickness of the Mesozoic and Cenozoic succession on the western part of the Sahul


Platform (particularly during the Triassic), and is expressed in the northwestsoutheast-trend of both the Sahul and Flamingo synclines (Whittam et al, 1996). This structural grain is cross-cut by a series of Jurassic faults, the strike of which varies from northeastsouthwest in the area adjacent to the Londonderry High, through north-northeast to south-southwest at the western-end of the Malita Graben and to eastwest in the area of the Flamingo and Laminaria highs. Woods (1992) attributes this latter eastwest-trend to Tithonian tectonism. Whittam et al (1996) concluded that the geological history in the northern Bonaparte Basin and Vulcan Sub-basin are broadly similar, but there are significant differences recognised in the northern Bonaparte Basin: The strong influence of the PermoCarboniferous rifting event in the

distribution and thickness of the Triassic succession. The tectonic event at the Jurassic/Triassic boundary, which marks the onset

of extension during the Mesozoic. The relative unimportance of the Callovian phase of tectonism that initiated

subsidence in the Vulcan Sub-basin. The Tithonian extensional event resulted in the development of eastwest-

trending horsts and grabens that characterise the structure of the Sahul Syncline and Flamingo Syncline region, which have proven to be the most prospective structural traps in the area.

The identification of the base-Aptian disconformity as a regional seismic marker that is the principal structural mapping horizon in the region, and the most reliable indicator of regional structure at the top of the Callovian reservoir section.

These differences have important implications for petroleum exploration in the area. Variations in the subsidence history and timing of tectonic events between the two regions influenced the distribution and preservation of potential reservoir and source rocks (Whittam et al, 1996). For example, it is considered unlikely that deposition of the Elang/Laminaria Formation reservoir sandstones would be widespread on the Laminaria and Flamingo highs and Sahul Platform if the major Callovian extension that affected the Vulcan Sub-basin had occurred on the western part of the Sahul Platform. Similarly, differences in subsidence history and in the thickness of the mid-Cretaceous to Cenozoic succession had a major impact on the timing of hydrocarbon generation, and on the extent to which later episodes of faulting affected the integrity of Jurassic traps. SAHUL PLATFORM AND TROUBADOUR TERRACE The Permian to Cenozoic Sahul Platform is a structural element of the Bonaparte Basin located offshore on Australia's northwestern margin in water depths of 50 to 1500 m. Much of the Sahul Platform falls within the Joint Petroleum Development Area between Australia and East Timor (Figure 1). The Sahul Platform is an area of relatively shallow basement. It is further divided into the Troubadour High in the east, where basement is approximately 3 km deep, and the Kelp High in the west, where basement is interpreted to be significantly deeper (Whittam et al, 1996). The Troubadour High is also referred to as the Sunrise High (Longley et al, 2002). The Troubadour Terrace forms part of the same structural feature as the Sahul Platform and is only arbitrarily


separated from it. Sediment thicknesses vary from 3 km on the Troubadour High to more than 5 km on the Kelp High. The Sahul Platform was originally part of a broad, northeast to southwest-trending Late Palaeozoic sag basin. Following Early Jurassic rifting, the platform became a depocentre for non-marine and marginal to shallow marine clastics in the Early to Middle Jurassic. Subsequent breakup in the Callovian produced a series of narrow, confined depocentres (Malita Graben and Sahul Syncline) to the south and west of the elevated Sahul Platform. Late Jurassic and Early Cretaceous strata are mainly confined to these depocentres, and either consist of thin condensed marine mudstones across the Sahul Platform and Troubadour Terrace or are absent. Late Miocene to Pliocene convergence of the Australian and Eurasian plates resulted in flexural down-warp of the Timor Trough to the north, and generation of the Kelp High and Troubadour High faulted anticline structures. Late Cretaceous to Tertiary strata consists predominantly of marine carbonates. Hydrocarbon discoveries on the Sahul Platform include the Greater Sunrise gas field, and a gas accumulation at Chuditch. Middle Jurassic strata are of greatest economic significance because they contain the main reservoir and source rock units. There is also limited reservoir potential in Permian to Triassic strata. Gas was recovered from the Hyland Bay Formation at Kelp Deep 1. A regional seal is provided by Late Jurassic and Cretaceous mudstones. The main exploration targets are complex faulted anticlines with hydrocarbons trapped at the apex of large regional structural closure. To date, the Troubadour High has proven to be the most viable exploration area on the Sahul Platform. Exploration on the Troubadour Terrace is sub-mature with only four wells drilled by 2000, resulting in the discovery of the Evans Shoal gas accumulation. Since this time, drilling has been concentrated in the eastern portion of the terrace (Barossa 1, Caldita 1 and 2 and Evans Shoal South 1). The Abadi gas accumulation is located on what is thought to be the northeastern extension of the Sahul Platform and Troubadour Terrace. The Middle Jurassic Plover Formation is of greatest economic significance because it hosts the main reservoir and source rock units. Late Jurassic and Cretaceous mudstones form the regional seal, with the main exploration targets being complex faulted anticlines. SAHUL SYNCLINE The Sahul Syncline (and its western extension, the Nancar Trough) is a prominent Palaeozoic to Mesozoic northwest-trending trough located between the Londonderry and Flamingo highs in the northern Bonaparte Basin (Figure 1). It is the primary source kitchen for petroleum accumulations discovered on the adjacent Laminaria and Flamingo highs. Botten and Wulff (1990) considered that the Sahul Syncline formed in the Late Triassic to Middle Jurassic, whereas Durrant et al (1990) believe it formed as part of the Late Devonian rift system in the Petrel Sub-basin. OBrien et al (1993) and Robinson et al (1994) described the Sahul Syncline as a sag feature, and suggested that the Late Carboniferous to Early Permian extension reactivated pre-existing, northwest-trending fault zones (such as the Sahul Syncline) as transfer faults.


Subsidence in the Permian and Triassic led to the deposition of a thick sedimentary succession in the region between the Londonderry High and Sahul Platform (including the present day Sahul Syncline, Flamingo High and Flamingo Syncline). Tectonic compression in the Late Triassic resulted in uplift and erosion of the Flamingo High, but deposition continued within the Sahul Syncline where a thick section of the Plover Formation was deposited. Further subsidence, as a result of minor Callovian and then more pronounced Tithonian extension, controlled the deposition of the Late Jurassic to Early Cretaceous clastic sequences (Elang/Laminaria Formation and Flamingo Group). In axial areas of the syncline, the Plover and Elang/Laminaria sandstones lie too deep to constitute valid exploration objectives, but these units form good quality reservoirs on the Laminaria and Flamingo highs. Following continental breakup in the Valanginian, a thick CretaceousCenozoic thermal sag section accumulated across the Sahul Syncline. MALITA AND CALDER GRABENS The Malita and Calder grabens form a major, northeast-trending rift system that contains a significant thickness of Late Palaeozoic, Triassic, Jurassic and Early Cretaceous sediments. The grabens are bounded by northeast to east-northeast-trending faults that show large displacement. Mesozoic and Cenozoic sediments are probably up to 10 km thick in these grabens and are underlain by a considerable section of Late CarboniferousPermian sediments. Key features of the stratigraphic succession deposited in these areas are: EarlyMiddle Jurassic Plover Formation sediments thicken markedly into the

grabens, and may include good quality source rocks. Thick, organic-rich mudstones of the Late Jurassic Flamingo Group may

also have source potential in the area. Tithonian turbiditic sandstones (which were intersected in Heron 1) may

provide valid exploration targets in the grabens. The Early Cretaceous Echuca Shoals Formation may provide additional

source potential in the graben. The CretaceousTertiary section exceeds a thickness of 4000 m in the

central Malita Graben.


REGIONAL HYDROCARBON POTENTIAL HYDROCARBON FAMILIES AND SOURCE ROCKS Hydrocarbon families and their postulated source rocks have been extensively documented within the Bonaparte Basin. Recent papers that published the detailed geochemistry of oils and source rocks from the Petrel Sub-basin are Edwards et al (1997, 2000), Gorter et al (2004, 2005), and Gorter (2006a). Geochemical studies of Vulcan Sub-basin oils include those by Carroll and Syme (1994), George et al (1997, 1998, 2004a), van Aarssen et al (1998a, b), Edwards et al (2004) and Dawson et al (2007). In the northern Bonaparte Basin appraisal of the hydrocarbon potential of the JurassicEarly Cretaceous source rocks has been undertaken by Brooks et al (1996a, b), and Preston and Edwards (2000). Gas studies were undertaken by AGSO and Geotech (2000). Oiloil and oilsource rock correlations in the northern Bonaparte Basin have been made by Gorter and Hartung-Kagi (1998), and Preston and Edwards (2000), while George et al (2002a, b, 2004a, b and c) carried out oilfluid inclusion oil correlations.

Oil-oil and gas-condensate/oil comparisons have been made throughout the Bonaparte Basin by Edwards and Zumberge (2005) and Edwards et al (2006), respectively, from which much of the following text is taken. Figure 3 shows the hydrocarbon families of the Bonaparte and Browse basins and their interpreted origin after Edwards et al (2004). In the Petrel Sub-basin, an oil family comprising the Barnett, Turtle and Waggon Creek oils was recognised (Figure 3), of which the offshore oils at Barnett and Turtle have undergone biodegradation. This oil family was generated from anoxic marine mudstones. Such source rocks have been located at 208 m depth in the NBF-1002 mineral hole by McKirdy (1987), Edwards and Summons (1996) and Edwards et al (1997), and were placed within the Early Carboniferous Milligans Formation. However, recent reappraisal of the Petrel Sub-basin stratigraphy by Gorter et al (2004, 2005) and Gorter (2006a) assigned these sediments to the earliest Early Carboniferous (earlymiddle Tournaisian) Langfield Group. Most of the gas discoveries reservoired in the Late Permian Hyland Bay Formation in the outboard Petrel Sub-basin and on the Londonderry High are attributed to Permian source rocks within the Hyland Bay Formation and/or Keyling Formation (Edwards et al, 1997, 2000; Edwards and Zumberge, 2005). This hydrocarbon family is represented in Figure 3 by condensate recovered from the Petrel gas accumulation. The stable carbon isotopic signatures of the gases recovered from the Petrel, Tern and Blacktip accumulations indicate that at least two source units generated these gases (Edwards et al, 2006). The biomarker signature of the recovered condensates from Petrel and Tern are consistent with derivation from land-plant material. As yet, gas-source rock correlations have not been undertaken to determine the exact sources of the gases, but both the Hyland Bay and Keyling formations are rich in land-plant remains and were deposited in prodelta marine and deltaic to coastal plain environments, respectively. In the Vulcan Sub-basin, two oil families are recognised; a marine oil family comprising the oils from Birch, Cassini, Challis, Jabiru, Puffin, Skua, Talbot and


Tenacious, and waxy terrestrial oils from Bilyara, Maret and Montara (Figure 3). The majority of the oil accumulations (including all produced oils) throughout the sub-basin are sourced from the Late Jurassic lower Vulcan Formation. Their source rocks comprise marine mudstones that contain variable amounts of terrigenous organic matter (Carroll and Syme, 1994; Edwards et al, 2004; Dawson et al, 2007. The most likely source of the waxy oil family is from fluviodeltaic to marginal marine mudstones, possibly within the Plover Formation, which contains a greater terrestrial component than the lower Vulcan Formation (Edwards et al, 2004). The oils from Oliver 1 and Puffin 3 are mixtures and hence plot separately from the other Vulcan Sub-basin families in Figure 3. In the central northern Bonaparte Basin (Laminaria and Flamingo highs), oils reservoired within the MiddleLate Jurassic Plover and Elang formations, which includes all the commercial accumulations, have been divided into two end-member families by Preston and Edwards (2000). As shown in Figure 3, the first family includes the relatively land-plant-influenced oils in the northwestern part of the area (Bluff, Buffalo, Corallina, Jahal, Krill and Laminaria accumulations), and the second family includes the relatively marine-influenced oils/condensates to the southeast (Bayu, Elang, Hingkip, Kakatua, Kakatua North, Trulek and Undan accumulations). Oils of intermediate composition occur between these accumulations. While none of the oils can be uniquely correlated with a single source unit, Preston and Edwards (2000) concluded that all of the accumulations in this area are sourced predominantly from the Middle Jurassic Plover Formation and Late Jurassic Elang Formation, with additional contributions from the overlying sealing units: the land-plant-rich, Late Jurassic Frigate Formation in the northwest, and the marine-dominated, Late JurassicEarly Cretaceous Flamingo Group in the southeast. In the central northern Bonaparte Basin, a separate oil family is found comprising the non-commercial oils reservoired in the younger Early Cretaceous Darwin Formation from Elang West 1, Layang 1 and Kakatua North 1 (Preston and Edwards, 2000). These oils are believed to originate from the Sahul Syncline that contains post-rift, organic-rich marine sediments in the Early Cretaceous Echuca Shoals Formation. The oil from Elang West 1 has a similar composition to oils sourced from the Early Cretaceous (eg, Caswell 2) in the Browse Basin (Figure 3). REGIONAL PETROLEUM SYSTEMS Numerous petroleum systems of various ages have been documented within the Bonaparte Basin (Bradshaw et al, 1994, 1997; Colwell and Kennard, 1996; McConachie et al, 1996; Kennard et al, 1999, 2000, 2002; Edwards and Zumberge, 2005);

A Late Devonian-sourced petroleum system (Larapintine 3), An Early Carboniferous-sourced petroleum system (Larapintine 4) A Permian-sourced petroleum system (Gondwanan 1), An EarlyMiddle Jurassic-sourced petroleum system (Westralian 1), A Late Jurassic-sourced petroleum system (Westralian 2), and An Early Cretaceous-sourced petroleum system (Westralian 3).


Barrett et al (2004), following the nomenclature proposed by Magoon and Dow (1994), defined seven petroleum systems in the offshore Bonaparte Basin, consisting of three Jurassic, three Permian and one Permo-Carboniferous systems;

Jurassic Elang-Elang(!) Petroleum System (Sahul Syncline and Flamingo High) Plover-Plover(.) Petroleum System (Malita Graben and Sahul Platform) Vulcan-Plover(!) Petroleum System (Vulcan Sub-basin)

Permian Hyland Bay-Hyland Bay(?) Petroleum System (Kelp High) Hyland Bay/Keyling-Hyland Bay(.) Petroleum System (central Petrel Sub-

basin) Permian-Hyland Bay(?) Petroleum System (Londonderry High)

Permo-Carboniferous Milligans-Kuriyippi/Milligans(!) Petroleum System (southern Petrel Sub-

basin The distribution of these petroleum systems are shown in Figure 4, and are presented in montage format by Earl (2004). As noted earlier, the source of the Permo-Carboniferous system in the southern Petrel Sub-basin is now believed to be the Langfield Group (Gorter et al, 2004, 2005; Gorter, 2006a), rather than the Milligans Formation, so this system requires redefinition and re-mapping.


EXPLORATION HISTORY Offshore exploration of the Bonaparte Basin commenced in 1965 when regional aeromagnetic data were acquired. This was supplemented by regional seismic coverage acquired between 1965 and 1974. The first offshore exploration wells, Ashmore Reef 1 and Sahul Shoals 1, located on the Ashmore Platform, were drilled as stratigraphic tests. Although these wells failed to encounter hydrocarbons, they indicated that the Jurassic section is either thin or absent and that Triassic sandstones form potential petroleum reservoirs over much of the Ashmore Platform. Between 1969 and 1971, seven wells were drilled in the offshore Petrel Sub-basin. This drilling campaign resulted in the discovery of the Petrel and Tern gas accumulations reservoired within the Late Permian Hyland Bay Formation, which constitutes a primary exploration target in the outboard Petrel Sub-basin. In the early 1970s, exploration expanded beyond the limits of the Petrel Basin into the Vulcan Sub-basin and onto the Londonderry High and Sahul Platform. Between 1971 and 1975, an additional 24 wells were drilleda further five in the Petrel Sub-basin, two on the Sahul Platform, seven in the Vulcan Sub-basin, five on the Londonderry High, three on the Ashmore Platform and two in the Malita Graben. Several significant petroleum discoveries were made during this period including Puffin, Troubadour and Sunrise. Between 1975 and 1982 relatively low levels of exploration drilling were recorded in the offshore Bonaparte Basin (a total of eight wells) due to disputation between Indonesia and Australia over sovereignty of the sea-bed boundary. The discovery in 1983 of economic oil and gas 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 21 exploration wells were drilled in the next three years (1984 to 1986). Of these wells, 12 were located in the Vulcan Sub-basin and on the western flank of the Londonderry High. This phase of exploration resulted in the discovery of a further three commercial oil accumulations in the Vulcan Sub-basin (Cassini, Challis and Skua). Oil production from the Jabiru, Challis and Cassini fields is via Floating Production Storage and Offloading Vessels (FPSOs). Production ceased at Skua in 1997. During the mid 1980s, two non-commercial discoveries of oil were made in stacked reservoirs within the Early Carboniferous Milligans Formation and Late Carboniferous to Early Permian Kuriyippi Formation at Turtle 1 (1984) and Barnett 1 (1985) in the inshore Petrel Sub-basin. After a brief downturn in 1987, levels of offshore exploration drilling in the Bonaparte Basin accelerated. Between 1988 and 1990, 31 exploration wells were drilled in the Vulcan Sub-basin. Drilling results from these wells proved disappointing, although several other oil and gas discoveries were made. Further to the north on the Troubadour Terrace, Evans Shoal 1 (1988) intersected a significant gas accumulation within the Jurassic Plover Formation, leading to an appraisal well, Evans Shoal 2, later in the same year.


Resolution of the territorial dispute between Indonesia and Australia in 1991 established the Zone of Cooperation (ZOC) and allowed exploration on the Sahul Platform to resume. Between 1992 and 1998, the focus of exploration in the offshore Bonaparte Basin shifted to this area. Of the 73 exploration wells drilled here during this period, 43 were located either on or adjacent to the Sahul Platform, Laminaria High and Flamingo High. The first commercial petroleum success in the area resulting from this phase of exploration occurred in 1994, when Elang 1 discovered liquid hydrocarbons and identified a new oil play on the Flamingo and Laminaria highs. In 1999, Timor-Leste was granted independence by Indonesia. This created a climate of uncertainty with regard to petroleum exploration in the Zone of Cooperation. In that year, only one exploration well (Jura 1) was drilled in the former ZOC Area A. Since that time, Coleraine 1 (2000) and Kuda Tasi 1 (2001) have been drilled within ZOC Area A. These wells were followed by oil recoveries at Kuda Tasi 2 (2003) in what is now known as the Joint Petroleum Development Area (JPDA). Exploration drilling on the Londonderry High in 2000 identified numerous gas accumulations within the Hyland Bay Formation at Prometheus 1, Rubicon 1, Ascalon 1A and Saratoga 1. In the Petrel Sub-basin, two wells (Sandbar 1 and Blacktip 1) were drilled during 2001 in the inshore portion of the basin. No hydrocarbons were encountered in Sandbar 1, but Blacktip 1 was completed as a gas discovery. This well encountered a 20 m gross gas column within the Triassic Mount Goodwin Formation, and a 339 m gross gas column from several high quality, stacked reservoir zones within the Early Permian Keyling Formation. Further drilling in the Petrel Sub-basin met with limited success, with Shakespeare 1 and Weasel 1 recording only minor oil and gas indications. Polkadot 1 (2004) encountered non-commercial gas in the Hyland Bay Formation, but the recently drilled well Blacktip North 1 (2006), which also targeted gas in this formation, was dry. Although drilling continued in the Vulcan Sub-basin throughout 20022003, no new commercial discoveries were made. However, from June 2005 to mid-2006, there has been a revival in exploration success with the wildcat wells Katandra 1, 1A and Vesta 1 discovering both oil and gas. Development and extension drilling at Puffin has continued (Puffin 710), and commissioning of the Puffin North East Field is nearing completion, with the first crude cargo lifted from the Front Puffin FPSO in October 2007. Extension/appraisal wells to the Montara field successfully discovered more oil at Swift North 1, ST1 and Swallow 1, and production from the Montara-Skua-Swift/Swallow fields is scheduled to commence in late 2008. During 20022003, drilling on the Laminaria High and Flamingo High has been focussed on the development of the accumulations at Buffalo, Kuda Tasi, Laminaria and Bayu/Undan. Of the few recent exploration wells that have been drilled in this area, Firebird 1 (2005) discovered gas.


Drilling has been active in the Malita and Calder grabens since mid-2005, with gas discoveries at Caldita 1 (2005), Evans Shoal South 1 (2006) and Barossa 1, ST1 (2006), and with appraisal drilling continuing at Caldita 2 (2007). HYDROCARBON RESERVES INITIAL RESERVES BONAPARTE BASIN

Field Liquids MMbbl*

Gas Tcf

Gas MMboe1 Date Source

Audacious - Audacious 1 area only 3.10 0.00 0.00 Sep-05 DPIFM Barnett 2.70 0.00 0.00 Aug-00 DPIFM Barossa 0.00 2.70 459.00 Feb-07 DPIFM Blacktip 0.00 1.15 195.11 Dec-06 DoIR Buffalo 20.55 0.00 0.46 Dec-06 DoIR Caldita 0.00 2.90 493.00 Nov-05 DPIFM Cash/Maple 34.20 1.65 280.50 Jul-05 DPIFM Challis and Cassini 59.90 0.00 0.00 Dec-05 DPIFM Corallina 97.00 0.00 0.00 Dec-06 DPIFM Evans Shoal 0.00 8.30 1411.00 Mar-03 DPIFM Evans Shoal South 0.00 0.07 12.58 May-07 DPIFM Jabiru 112.40 0.00 0.00 Dec-05 DPIFM Katandra 1.20 0.00 0.00 Dec-04 DPIFM Laminaria 103.40 0.00 0.00 Dec-06 DPIFM Montara, Bilyara, Tahbilk, Padthaway 20.80 0.36 61.76 Jun-03 DPIFM Oliver 20.40 0.35 58.67 Sep-03 DPIFM Petrel 5.90 0.97 164.90 Apr-05 DPIFM Puffin 14.30 0.00 0.00 Oct-05 DPIFM Skua 20.20 0.00 0.00 Dec-99 DPIFM Greater Sunrise 299.00 7.68 1305.60 Jan-04 DPIFM Swan 5.00 0.07 11.90 Jan-00 DPIFM Talbot 1.80 0.00 0.00 Aug-05 DPIFM Tenacious 4.60 0.00 0.00 Apr-99 DPIFM Tern 5.66 0.47 79.55 Dec-05 DoIR Turtle 7.74 0.00 0.00 Dec-05 DoIR Vesta 14.20 0.00 0.00 Sep-05 DPIFM

*Liquids includes crude oil and condensate, 1 Conversion factor for gas (Tcf to MMboe) is 0.17x1000. All reserves are P50. All developed field resources from DoIR have been compiled using the remaining reserves plus the cumulative production as of December 2006. All other fields are reserves as of 31st December 2006. DoIR - Department of Industry and Resources, Western Australia, http://www.doir.wa.gov.au/documents/mineralsandpetroleum/PWA_Sept_2007.pdf. DPIFM - Department of Primary Industry, Fisheries and Mines, Northern Territory.


FIGURES Figure 1: Structural elements map of the Bonaparte Basin showing location

of the 2008 release areas and petroleum accumulations. Figure 2: Stratigraphic summary of the Bonaparte Basin (after Cadman and

Temple, 2004). Figure 3: Oil family dendrogram from hierarchical cluster analysis showing

origin of major petroleum accumulations in the Bonaparte and Browse basins (after Edwards et al, 2004).

Figure 4: Distribution of the petroleum systems of the offshore Bonaparte

Basin (after Barrett et al, 2004; Earl, 2004).


2008 RELEASE OF AUSTRALIAN OFFSHORE PETROLEUM

EXPLORATION AREAS RELEASE AREAS NT08-1, NT08-2 AND NT08-3 PETREL SUB-BASIN, BONAPARTE BASIN NORTHERN TERRITORY BIDS CLOSE - 9 April 2009 LOCATION Release areas NT08-1, NT08-2 and NT08-3 are located in the Joseph Bonaparte Gulf about 200 km west of Darwin and to the northeast of the Petrel gas accumulation (Figure 1). The Release areas overlie the offshore portion of the Petrel Sub-basin, a distinct depocentre of the Bonaparte Basin (Figure 2). Over most of the sub-basin, water depths are less than 100 m. Release Area NT08-1 comprises 63 graticular blocks or parts thereof, and covers an area of approximately 4865 km2. No wells have been drilled in it, but Curlew 1 and Newby 1 were drilled just to the north of the Release Area (Figure 1). Release Area NT08-2 comprises 77 graticular blocks, and covers an area of approximately 6430 km2. It contains one well, Flat Top 1, while Billawock 1 was drilled some 50 km to the south of the Release Area (Figure 2). Release Area NT08-3 comprises 51 graticular blocks or parts thereof, and covers an area of approximately 4070 km2. No wells have been drilled in this Release Area, but it abuts the Petrel retention leases NT/RL1 and WA-6-R (Figure 1).


GRATICULAR BLOCK LISTINGS AND MAP RELEASE AREA NT08-1 PETREL SUB-BASIN, BONAPARTE BASIN, NORTHERN TERRITORY Map Sheet SD 52 (Darwin) 25 part 26 part 27 28 29 30 31 32 33 34 35 36 37 38 98 part 99 100 101 102 103 104 105 106 107 108 109 110 170 part 171 part 172 173 174 175 176 177 178 179 180 181 182 243 part 244 part 245 246 247 248 249 250 251 252 253 254 316 part 317 part 318 319 320 321 322 323 324 325 326 Assessed to contain 63 blocks (includes 54 full blocks and 9 part blocks) RELEASE AREA NT08-2 PETREL SUB-BASIN, BONAPARTE BASIN, NORTHERN TERRITORY Map Sheet SD 52 (Darwin) 39 40 41 42 43 44 45 111 112 113 114 115 116 117 183 184 185 186 187 188 189 255 256 257 258 259 260 261 327 328 329 330 331 332 333 399 400 401 402 403 404 405 471 472 473 474 475 476 477 543 544 545 546 547 548 549 615 616 617 618 619 620 621 687 688 689 690 691 692 693 759 760 761 762 763 764 765 Assessed to contain 77 full blocks


RELEASE AREA NT08-3 PETREL SUB-BASIN, BONAPARTE BASIN, NORTHERN TERRITORY Map Sheet SD 52 (Darwin) 389 part 390 391 392 393 394 395 396 397 398 461 part 462 463 464 465 466 467 468 469 470 533 part 534 part 535 536 537 538 539 540 541 542 607 608 609 610 611 612 613 614 680 681 682 683 684 685 686 753 754 755 756 757 758 Assessed to contain 51 blocks (includes 47 full blocks and 4 part blocks)


2008 RELEASE OF AUSTRALIAN OFFSHORE PETROLEUM EXPLORATION AREAS

RELEASE AREAS W08-1, W08-2 AND W08-3 PETREL SUB-BASIN, BONAPARTE BASIN WESTERN AUSTRALIA BIDS CLOSE 9th April 2009 LOCATION Release areas W08-1, W08-2 and W08-3 are located in the Joseph Bonaparte Gulf about 300 km west of Darwin. The Release areas overlie the offshore portion of the Petrel Sub-basin, a distinct depocentre of the Bonaparte Basin (Figure 2). Release areas W08-1 and W08-2 are located northwest of the Petrel gas accumulation and Release Area W08-3 is located between the Tern and Petrel gas accumulations. Over most of the sub-basin, water depths are less than 100 m. Release Area W08-1 comprises 45 graticular blocks, or parts thereof, and covers an area of approximately 2985 km2. One well, Gull 1, has been drilled in the Release Area, with Marsi 1 and Schilling 1 drilled to the west (Figure 1). Curlew 1, Darwinia 1, 1A and Jacaranda 1 were drilled to the northeast of this Release Area. Release Area W08-2 comprises 45 graticular blocks, or parts thereof, and covers an area of approximately 3505 km2. No wells have been drilled in this Release Area, but it abuts the Petrel retention lease WA-6-R (Figure 1). One well, Billabong 1, has been drilled to the west of the Release Area. Release Area W08-3 comprises 34 graticular blocks, or parts thereof, and covers an area of approximately 2705 km2. No wells have been drilled in this Release Area, but it juxtaposes the Petrel retention leases NT/RL1 and WA-6-R and the Tern retention lease WA-27-R (Figure 1). Wells drilled to the west of the Release Area include Fishburn 1, Frigate 1 and Sandpiper 1. South of the Release Area are the wells Penguin 1 and Polkadot 1. Located further south is the Blacktip gas accumulation and pipeline.


GRATICULAR BLOCK LISTINGS AND MAP RELEASE AREA W08-1 PETREL SUB-BASIN, BONAPARTE BASIN, WESTERN AUSTRALIA Map Sheet SC 52 (Melville Island) 2973 part 3045 part 3046 part 3117 3118 part 3189 3190 part 3191 part 3261 3262 3263 part 3264 part 3333 3334 3335 3336 part 3405 3406 3407 3408 part 3409 part Map Sheet SD 52 (Darwin) 21 22 23 24 25 part 26 part 94 95 96 97 98 part 166 167 168 169 170 171 part 238 239 240 241 242 243 part 244 part Assessed to contain 45 blocks (includes 28 full blocks and 17 part blocks) RELEASE AREA W08-2 PETREL SUB-BASIN, BONAPARTE BASIN, WESTERN AUSTRALIA Map Sheet SD 52 (Darwin) 310 311 312 313 314 315 316 part 317 part 382 383 384 385 386 387 388 389 part 454 455 456 457 458 459 460 461 part 526 527 528 529 530 531 532 533 part 534 part 598 599 600 601 602 603 670 671 672 673 674 675 Assessed to contain 45 blocks (includes 39 full blocks and 6 part blocks)


RELEASE AREA W08-3 PETREL SUB-BASIN, BONAPARTE BASIN, WESTERN AUSTRALIA Map Sheet SD 52 (Darwin) 743 744 745 746 747 815 816 817 818 819 820 821 887 888 889 890 891 892 893 894 part 961 962 963 964 965 966 part 1035 1036 1037 1038 part 1107 1108 1109 1110 part Assessed to contain 34 blocks (includes 30 full blocks and 4 part blocks)


RELEASE AREA GEOLOGY The Petrel Sub-basin is located offshore northwest Australia and belongs geographically to the Joseph Bonaparte Gulf. Parts of the sub-basin extend onshore in the south (Figure 2). The Northern Territory/Western Australia border crosses the Petrel Sub-basin in which water depths are generally less than 100 m. The stratigraphic and tectonic development of the Petrel Sub-basin has been discussed in detail by Mory (1988, 1991), Gunn (1988), Lee and Gunn (1988), Gunn and Ly (1989), McConachie et al (1996) and Colwell and Kennard (1996). It is most recently summarised by Kennard et al (2002) and Cadman and Temple (2004). The Petrel Sub-basin is an asymmetric, northwest-southeast-trending Palaeozoic rift that contains a succession of thick Palaeozoic and thinner Mesozoic sediments. The stratigraphy of the Palaeozoic and Mesozoic sediments are shown in Figures 4 and 3, respectively. The eastern and western faulted margins of the sub-basin converge onshore to form a southern termination. To the south and east of the Petrel Sub-basin, extensions of the Halls Creek-Fitzmaurice Mobile Zone separate this sub-basin from the Precambrian Victoria River Basin and Pine Creek Geosyncline. Extensive basement shelves are overlain by a thin cover of Phanerozoic sediments and are developed on the eastern, western and southern margins of the Petrel Sub-basin. To the east, the Kulshill Terrace and Moyle Platform extend to the north-northeast into the Darwin Shelf. In the southwest, the Berkley Platform extends eastward into the Cambridge and Turtle-Barnett highs, where it is flanked by the Lacrosse Terrace (Figure 2). Strata within the Petrel Sub-basin dip regionally to the northwest with a northwest-plunging synclinal axis, resulting in exposure of Early Palaeozoic sediments in the southern onshore area, and in the progressive subcropping of Late Palaeozoic, Mesozoic and Cenozoic sediments offshore. The Late Palaeozoic-Mesozoic section exceeds 15 km in thickness in the central and northern Petrel Sub-basin. Representative regional cross-sections and seismic lines across the Release areas in the Petrel Sub-basin are shown in Figures 5, 6, 7 and 8. RIFT-RELATED STRUCTURES Late Devonian (?late Givetian/Frasnian) to earliest Carboniferous (Tournaisian) upper-crustal extension produced a series of rift-related structures, particularly in the south and southwest of the basin (Gunn, 1988; OBrien et al, 1993; Colwell and Kennard, 1996). These structures lie to the southwest of the axis of the main post-late Tournaisian basin sag known as the Petrel Deep (Figures 2, 5 to 8), indicating a possible partitioning between the mechanisms that controlled upper-crustal extension and the subsequent sag-dominated phase of the basins tectonic evolution. Release areas NT08-1, NT08-2, NT08-3, W08-1, W08-2 and W08-3 are all situated over the Petrel Deep.


These rift-related extensional structures are bounded by major normal faults (and/or fault systems) and include basement platforms (eg, Berkley and Moyle platforms), horst blocks (eg, Cambridge High), rotated fault blocks (eg, Lacrosse Terrace), and grabens (eg, Cambridge Trough). Many of these features lie within, or are adjacent to, the 2008 Release areas (Figure 2). The Berkley Platform is an area of planated shallow basement (tholeiitic dolerite intersected in Berkley 1) that essentially forms an offshore extension of the Proterozoic Kimberley Basin. It dips to the northeast and is bounded on its northeastern margin by a major down-to-basin fault. Its landward extent approximates to the Kimberley coastline which, from its linear nature, may be fault controlled. The platform is overlain by about 2.5 km of Late Carboniferous and younger sediments. The Moyle Platform forms the eastern (largely-onshore) flank of the Petrel Sub-basin where it consists of shallow crystalline basement, probably equivalent to those of the Pine Creek Geosyncline and Victoria River Basin. It is bounded on its eastern side by major faults of the Fitzmaurice Mobile Zone and on its western side by the Moyle Fault. It passes northward into the Darwin Shelf. The basement is overlain by ?Late Carboniferous-Early Permian sediments, as intersected at Moyle 1. The Cambridge High is an eastward-dipping, narrow basement horst block that extends from the Berkley Platform in the west to the Turtle-Barnett High in the east. It is bounded by reactivated normal fault systems and flanked by major depocentres to the south (Cambridge Trough) and to the north (Lacrosse Terrace, Petrel Deep). Initially, much of the syn-rift sediment in the southern Petrel Sub-basin appears to have been trapped south of the Cambridge High and adjacent Turtle-Barnett High. As the available accommodation space was filled, syn-rift sediments spread out as a series of alluvial fans across the highs and onto the developing Lacrosse Terrace to the north, and beyond. Movement on the faults bounding the Cambridge High during the late Tournaisian at the end of the syn-rift phase led to widespread erosion of syn-rift sediments across the high. The Turtle-Barnett High is a fault-bounded, approximately north-south-trending high-standing basement block, which juxtaposes the Cambridge High and Lacrosse Terrace. The position and trend of the high suggest that it may be related to reactivation of faults along the western edge of the Halls Creek Mobile Zone. Fault movements along its northwestern flank appear to post-date the formation of the main down-to-basin faults that form the northern margins of the Cambridge High and Lacrosse Terrace. However, during much of the Late Devonian-earliest Carboniferous (ie during syn-rift deposition), the Turtle-Barnett High was a high-standing feature that probably shed sediments into the adjacent developing depocentres of the Cambridge Trough and Keep Inlet Sub-basin. Like the adjacent Cambridge High, the feature was covered by sediments of the Bonaparte Formation and it was probably uplifted and eroded during the late Tournaisian at the end of the syn-rift phase. The Lacrosse Terrace is largely restricted to the area between the Turtle-Barnett High and Lesueur 1, and comprises a rotated basement block that is overlain by syn-rift and younger sediments.


STRATIGRAPHY The stratigraphy of the Petrel Sub-basin has been compiled from Beere and Mory (1986), Mory and Beere (1988), Jones et al (1996), Gorter (1998), Gorter et al (1998), and Gorter et al (2004, 2005). The stratigraphy is shown in Figure 3 and a detailed revision of the Carboniferous stratigraphy (Gorter et al, 2005) is shown in Figure 4. Sedimentation in the Petrel Sub-basin commenced in the Cambrian and continued into the Early Ordovician, with the deposition of shallow marine clastics and carbonates. This was followed, most probably in the Late Ordovician, by extensive evaporite deposits of unknown lateral continuity. These evaporites appear to be of similar age to those of the Carribuddy Group in the Canning Basin. A detailed account of salt diapirs and salt-related tectonics can be found in Edgerley and Crist (1974), Woodside Australian Energy (2002) and Leonard et al (2004). Rifting was initiated in the Late Devonian and siliciclastic sediments and carbonates were deposited in terrestrial and shallow marine environments. In the southern onshore portion of the basin, the Frasnian sediments of the Cockatoo Group are dominated by coarse clastics and conglomerates (Mory and Beere, 1988). Northward, the coarse-grained Cockatoo Group facies gradually changes to siltstones and shales with interbedded sandstones and sandy limestones, and is known as the Bonaparte Formation (Mory and Beere, 1988). In the Famennian, the clastics of the Cockatoo Group are replaced by the reefal carbonates of the Ningbing Group around the margins of the basin, while in the deeper central onshore and offshore portions of the basin, deposition of the Bonaparte Formation continued essentially unchanged. By the Early Carboniferous, rifting had produced a northwest-trending basin, in which marine, fluvio-deltaic and glacial sediments accumulated as a result of post-rift subsidence and salt withdrawal during the Carboniferous and Permian. These Carboniferous and Permian sediments represent the bulk of the basin-fill in the Petrel Sub-basin. In the Early Carboniferous (Early Mississippian) the reefal facies was replaced by mixed carbonates, and fine-grained clastics of the Langfield Group (Mory and Beere, 1988) on the basin margins with deposition of the Bonaparte Formation continuing in the deeper portion of the basin. Towards the end of the Tournaisian, an unconformity separates the Weaber Group, represented at its base by the Milligans Formation, from the underlying Langfield Group (Gorter et al, 2004, 2005; Gorter, 2006a). The Weaber Group, as developed in the southern part of the Petrel Sub-basin, represents a complex period of packages of sedimentation separated by short unconformities (Gorter et al, 2005). The Early Carboniferous Milligans Formation was defined by Mory (1991) as consisting of fossiliferous shales and siltstones. The Milligans Formation is intersected in Bonaparte 1 between 497-2280 m, and extends throughout the inboard (Cambridge Trough and Keep Inlet Sub-basin) and onshore parts of the sub-basin. This formation has been


redefined and is regarded as being of latest Tournaisian to late Visean in age (Gorter et al, 2004, 2005). The basin margin equivalent of the Milligans Formation is known as the Waggon Creek facies, predominately pebbly sandstones and conglomerates overlain by sandstones and shales. The Yow Creek Formation is a basinal shale that is bound by unconformities at the base and top. The overlying Utting Calcarenite and Kingfisher Shale are lateral equivalents of the coarse clastic-dominated Burvill Formation developed near the basin margin. The Middle Mississippian Tanmurra Formation comprises a thick succession of sandstones and sandy carbonates deposited throughout the Carlton Sub-basin, Cambridge Trough and Keep Inlet Sub-basin. The uppermost units of the Weaber Group are the Sandbar Sandstone and Sunbird Formation (Gorter et al, 2005). The Sunbird Formation consists of mixed lithologies with the lower part dominantly carbonate and the middle and upper parts of carbonates and interbedded quartzose sandstones. The Late Mississippian to Early Pennsylvanian Wadeye Group is represented on the basin margins by the Point Spring Sandstone, consisting of sandstones, pebbly sandstones and minor siltstones, and, in the deeper parts of the basin, by the finer grained clastics of the Arco and Aquitaine formations (Gorter et al, 2005). The Kulshill Group comprises the Kuriyippi Formation and the basin-margin equivalent Border Creek Formation, both overlain by the regional Treachery Shale and the Keyling Formation. In the inboard areas, this group is known as the Keep Inlet Formation. The Late Pennsylvanian Kuriyippi Formation, as defined by Mory (1991), is a thick succession of sandstones, shales and minor coals, overlain by glacial sandstones and conglomerates. Their capacity to entrap oil and gas is demonstrated at Barnett and Turtle on the Turtle-Barnett High. The Early Permian Treachery Shale comprises tillites, carbonaceous shales, siltstones, sandstones and minor limestones and coals. A sequence stratigraphic interpretation of potential reservoir sandstones and sealing lithologies within the lower Kulshill Group (Treachery Shale and Kuriyippi Formation) is presented by Gorter (2006b). The Early Permian Keyling Formation is defined at the type section in Kulshill 1 (Mory, 1991) and comprises delta-plain and marginal marine sandstones, siltstones, shales and minor coals and limestones; the coals and marginal marine shales have moderate to very good oil and gas potential in parts of the sub-basin. The Kinmore Group comprises the Fossil Head, Hyland Bay and the Mount Goodwin formations. The Early Permian Fossil Head Formation and the Late Permian Hyland Bay Formation comprise a thick (up to around 2300 m) succession in the central and outer parts of the Petrel Sub-basin. The Fossil Head Formation comprises siltstones and mudstones with minor sandstones and limestones. The Hyland Bay Formation has been revised to the Hyland Bay Sub-group by Gorter (1998) as shown in Figure 3, with the terminology used interchangeably herein depending on the vintage of the report being quoted. The Hyland Bay Sub-group consists of pro-delta, deltaic and shoreface mudstones, siltstones and sandstones, as well as open shelf carbonates and has been sub-divided into five formations (Gorter, 1998); the Pearce (including the basal Torrens Member), Cape Hay, Dombey, Tern and Penguin formations (Figure 3).


Robinson and McInerney (2004) published palaeogeographic reconstructions of the most important reservoir units within the Hyland Bay Sub-group. The Pearce Formation is represented by shelf and platform carbonates. The Cape Hay Formation (Gorter, 1988) is the equivalent to the Hay Member of Bhatia et al (1984). It is the reservoir unit for the gas accumulations at Penguin 1, Petrel and Fishburn 1, and was deposited as part of a widespread, river-dominated delta system with restricted shoreface conditions (Robinson and McInerney, 2004). The Dombey Formation carbonates provide the top-seal to the Cape Hay Formation. The Tern and Penguin formations comprise more open-marine sediments and belong to a broad, prograding shoreface system that may have persisted into the Early Triassic represented by sandstones in Ascalon 1A (Robinson and McInerney, 2004). The Tern Formation is the reservoir for the Tern gas accumulation and is interpreted to represent shoreface and shoal environments (Robinson and McInerney, 2004). The Hyland Bay Sub-group is conformably overlain by the thick transgressive marine claystones of the Early Triassic Mount Goodwin Formation, which provides both vertical and lateral seal across the Petrel Sub-basin and the Londonderry High. The Kinmore Group is conformably overlain by the Troughton Group, in the Petrel Sub-basin and on the southeastern side of the Londonderry High, and the partially laterally equivalent Sahul Group on the western side of the high. The Troughton Group comprises the Cape Londonderry, Malita and Plover formations. It is a thick clastic sequence of marginal-marine to marine sandstones, siltstones and dolomitic shales. The Sahul Group is also marine to marginal marine, but contains more carbonates and shales than the Troughton Group. The regressive Cape Londonderry Formation consists of sandstones and minor amounts of siltstones and shales, and was deposited during a relatively stable sag phase. In the Middle Triassic, uplift and northeast-southwest rifting was initiated, which resulted in the widespread erosion of the Cape Londonderry Formation and parts of the Mount Goodwin Formation. Depositional environments changed from marine to terrestrial, culminating with red-bed deposition of the Late Triassic-Early Jurassic Malita Formation. Late Triassic compressional inversion related to the Fitzroy Movement involved extensive uplift and erosion along the southern margin, and created structural traps within the sub-basin. The MiddleLate Jurassic Plover Formation contains sandstones that may have excellent reservoir qualities, as well as shales with some source potential. These sediments were deposited in deltaic to near-shore environments and are thick within the outer Petrel Sub-basin. The Late JurassicEarly Cretaceous (Valanginian) Flamingo Group represents a time of minor extension and subsidence. The basal marine shale, the Frigate Shale, can form an excellent top seal and cross-fault seal to the Plover Formation. The overlying Sandpiper Sandstone is an excellent reservoir unit. After the Valanginian, the basin was submerged during a post-rift sag phase. The Bathurst Island Group comprises the Darwin and Wangarlu formations, and


is a thick, shale-dominated marine succession that is widespread across the Bonaparte Basin. Radiolarian shales or micaceous mudstones at the base of the Bathurst Island Group provide a regional seal. A regional erosional event occurred between the Late Cretaceous (Santonian) and Miocene leading to the accumulation of the Woodbine Group on a progradational shelf of the passive margin. The collision of the Australian Plate with the Banda Arc resulted in north-south compression and minor inversion of the generally east-west normal faults and possible strike-slip movement along older northeast-southwest-trending Triassic-aged faults.


EXPLORATION HISTORY PETREL SUB-BASIN In 1839, the crew of HMS Beagle found bitumen in water wells sunk on the banks of the Victoria River in the southern Petrel Sub-basin. This is one of the earliest oil shows documented in Australia. Initial petroleum exploration began in the 1950s, with seismic, aeromagnetic and gravity surveys being undertaken by the Bureau of Mineral Resources (BMR) in 1956. The first well was the stratigraphic well Spirit Hill 1, which was spudded in 1959 by Westralian Oil Ltd and encountered oil indications. This well was followed by gas discoveries in the onshore southern Petrel Sub-basin at Bonaparte 2 (Alliance Oil Development Australia N.L.) in 1964 and Keep River 1 (Australian Aquitaine Petroleum Pty Ltd) in 1969. Some of the earliest geological and geophysical surveys were undertaken by the Scripps Institution of Oceanography and the BMR, and included sea bottom echo profiling and sampling (van Andel and Veevers, 1967). The first offshore well to be drilled was Lacrosse 1 in 1969 by Arco Australia Ltd, who then drilled Petrel 1, 1A, 2, Gull 1, Tern 1, Sandpiper 1 and Penguin 1 throughout the early 1970s, resulting in the discovery of gas at Petrel, Tern and Penguin. Also at this time, Australian Aquitaine Petroleum Pty Ltd drilled Newby 1 and Flat Top 1. Since the early drilling success, only a few significant discoveries have been made, including the Blacktip gas discovery in 2001. In summary, the gas-condensate accumulations discovered to date in the Petrel Sub-basin include: offshore Blacktip, Curlew, Fishburn, Penguin, Petrel and Tern; and onshore dry gas at Bonaparte, Garimala, Keep River, Vienta, Waggon Creek and Weaber. In addition, the small oil accumulations at Turtle and Barnett were discovered in 1984 and 1985, respectively, in the inboard offshore part of the sub-basin. Petroleum-bearing reservoirs are found in numerous Carboniferous and Permian formations. The Eni Australia B.V. owned Blacktip gas-condensate field is the only accumulation that is being commercialised and will deliver gas to Darwin by January 2009. Construction of a 285 km gas pipeline from the Blacktip gas plant, near Wadeye (pronounced Wadeyre) in the Northern Territory, to an existing pipeline connecting the Amadeus Basin to Darwin, is imminent. The Wadeye pipeline will initially be capable of delivering 30 petajoules of gas per year into the Northern Territory gas market (PetroleumNews, November 2007). Since the discovery of Blacktip in 2001, further success has remained elusive during the drilling of Sandbar 1 (2001), Shakespeare 1 (2003), Weasel 1 (2003), Polkadot 1 (2004), Blacktip North 1 (2006) and Marina 1 (2007); however, detailed results are not yet available on open file. Nevertheless, new seismic surveys and a follow-up exploration well to Marina 1 are proposed in petroleum exploration permit WA-318-P (PetroleumNews, October 2007). In addition, the Penguin/Polkadot gas accumulation may become commercially viable once the Blacktip production hub is in place (http://www.seaaoc.com/newsB4.html), and work is continuing to develop the Petrel and Tern gas accumulations.

http://www.seaaoc.com/newsB4.html


WELL CONTROL The Release areas are located in the vicinity of several hydrocarbon discoveries. Release areas NT08-3 and W08-2 are located adjacent to the Petrel gas discovery and Release Area W08-3 is juxtaposed to the Petrel and Tern gas discoveries; all of these Release areas are in proximity to the Blacktip gas field. Release Area NT08-2 contains the exploration well Flat Top 1 (1970). Curlew 1 (1975) and Newby 1 (1969) were drilled just outside of the Release areas NT08-1 and NT08-2. Release Area W08-1 contains the exploration well Gull 1 (1971), with Marsi 1 (1996) being drilled just outside of this Release Area. Billabong 1 (1992), Fishburn 1 (1992), Frigate 1 (1978) and Sandpiper 1 (1971) were all drilled to the west of areas W08-2 and W08-3. Penguin 1 (1972) and Polkadot 1 (2004) are located just to the south of Release Area W08-3 (Figure 1). Newby 1 (1969) Newby 1, located in permit NT/P71 adjacent to Release areas NT08-1 and NT08-2, was drilled by Arco Australia Ltd to test a stratigraphic pinch-out and erosional wedge along the northwestern margin of the Petrel Sub-basin, and targeted Late Palaeozoic 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 at its location. Petrel Gas Accumulation Petrel 1 (1969), Petrel 1A (1970), Petrel 2 (1971), Petrel 3 (1982), Petrel 4 (1988), Petrel 5 (1994), and Petrel 6 (1996). Petrel 1, drilled by Australian Aquitaine Petroleum Pty Ltd, discovered the Petrel gas accumulation although the hole was lost due to a blow-out of Permian gas. The relief well, Petrel 1A, killed the blow-out approximately one year later. Since then, a total of five further wells have drilled the Petrel Anticline. The accumulation lies 270 km west of Darwin and is situated within retention leases NT/RL1 and WA-6-R that are held by Santos Ltd. The accumulation is hosted within the Cape Hay Member of the Hyland Bay Formation between 3500-4000 mSS. Porosities of up to 20 % or more were recorded; however, permeabilities are low. The gas at Petrel is moderately dry, with condensate to gas ratios of between 2.8 and 50.5 m3 of condensate per million m3 of gas (0.5 and 9 bbls/MMscf, respectively). Flat Top 1 (1970) Flat Top 1 (in Release Area NT08-2) was drilled by Australian Aquitaine Petroleum Pty Ltd to test a stratigraphic pinch-out play of Permian sandstones at the basin margin. The well was located in a slightly more basinal setting than that of Newby 1 to test the thickness of the Permo-Triassic sediments before reaching basement. The secondary objective was to test the Late Jurassic sandstones as encountered at Newby 1. The third objective was to test the age, nature and thickness of a shallow reef-like anomaly known on the bathymetric maps as the Flat Top Bank. The well intersected the Bathurst Island Formation and the primary objectives in the Flamingo Group, Troughton Group (Plover Formation) and Kinmore Group (Hyland Bay Sub-Group). It also penetrated the Early Permian to Latest Carboniferous section down to the Kuriyippi Formation, before reaching TD at 2174 mRT in Proterozoic quartzitic basement. Gas


indications were detected in the Bathurst Island Formation-Flamingo Group, Hyland Bay Sub-Group and Keyling Formation. A small quantity of gas with air contamination, recovered by FIT from the Hyland Bay Formation, is interpreted as dissolved gas in formation water. The failure of this well is attributed to the absence of an effective stratigraphic trap. Gull 1 (1970) Gull 1 was drilled by Arco Australia Ltd and is located 119 km northwest of Petrel 1, in the outermost part of the Petrel Deep, adjacent to the Sahul Syncline and Malita Graben. The well was drilled to test the Late Permian to Late Carboniferous section within a large dome-shaped structure located above an intrusionnow known to be the crest of a collapsed salt diapir (Figure 8). However, the well did not reach its objective, terminating at 3421.4 mKB within the Triassic section (Malita Formation). Apart from minor methane indications (at the base Bathurst Island Group), no hydrocarbon shows were observed, and no good reservoir sediments were identified. Below 2134 mKB, the strata shows more advanced diagenesis than has been encountered in the previously drilled offshore wells. The absence of hydrocarbons at Gull 1 can be explained by either the timing of uplift of the Gull structure, which occurred after the Middle Miocene and therefore too late to trap hydrocarbons, and/or a lack of hydrocarbons migrating through this section. Sandpiper 1 (1971) Sandpiper 1 was drilled by Arco Australia Ltd to test a structure with significant closure in both the Cretaceous and Jurassic sections. The well penetrated Tertiary and Mesozoic sediments from the sea floor to 944 mKB (Plover Formation). A diapiric cap rock extending from 944-1753 mKB was penetrated before first salt was encountered. Massive salt was drilled from 1794 mKB to a TD of 1892 mKB (Figure 6). The cap rock is believed to range from Early Carboniferous to Late Devonian in age, and Middle-Late Devonian palynomorphs were recovered from cuttings some 150 m within the salt diapir, indicating a minimum age for the salt (Colwell and Kennard, 1996). Several indications of methane were detected while drilling, but wireline logs indicate that all porous units are either water-bearing or have high water saturation. The drilling confirmed the seismically interpreted presence of diapiric salt features in the southern portion of the Bonaparte Basin. Tern Gas Accumulation Tern 1 (1971), Tern 2 (1982), Tern 3 (1982), Tern 4 (1994) and Tern 5 (1998). The Tern gas accumulation was discovered in 1971, with a total of five wells drilling the northwest-southeast-trending anticlinal structure. This accumulation is situated 300 km west of Darwin and approximately 50 km to the southwest of the Petrel gas accumulation, and is situated within retention lease WA-27-R held by Santos Ltd. The accumulation is hosted in the Hyland Bay Formation (Tern Member) within a salt-related faulted anticline (Figure 6). Porosities of greater than 20 % have been identified at depths of about 2600 m. Initial gas reserves are estimated to be 0.47 Tcf with 5.66 MMbbl of oil/condensate. Penguin 1 (1972) Penguin 1 was drilled by Arco Australia Ltd on a turtle-back anticline (Figure 5). A thick sedimentary sequence ranging from Early Permian to Recent in age was penetrated and the well reached TD at 2756.9 mRT in the Fossil Head


Formation. Several gas shows were recorded near the base of the Late Permian sediments (Pearce Formation, Hyland Bay Sub-Group), and two wireline formation tests taken in the basal member at 2540 m and 2535 m recovered 3.6 and 3.5 m3, respectively, of methane. Curlew 1 (1975) Curlew 1, located in permit NT/P64 adjacent to Release areas NT08-1 and W08-1, was drilled by Arco Australia Ltd to test a large faulted domal closure over a salt piercement structure. Six Formation Interval Tests (FITs) were carried out in the well, and encountered gas indications in the targeted Late Jurassic and Early Cretaceous sandstones (Flamingo and Plover formations), with the well reaching TD at 2035 mKB in the Petrel C formation (Plover Formation). Well failure analysis indicated that the trap was invalid. Frigate 1 (1978) Frigate 1 was drilled by Arco Australia Ltd and is located 68 km southwest of Petrel 1 and 14 km west of Tern 1 in the Petrel Deep. The well was drilled on a large, faulted anticlinal structure located on the southern flank of the Petrel Sub-basin. The objective of the well was to test the member 'A' and 'C' sandstones of the Petrel Formation (Flamingo Group and Plover Formation, respectively) beneath the thick shale section of the Bathurst Island Formation. A sedimentary sequence ranging in age from Tertiary to Middle Triassic was drilled to TD (1585.5 mKB). Although good reservoir sandstones are present in the Jurassic section, and there is valid structural closure, only minor gas indications were detected. Turtle and Barnett Oil and Gas Accumulations Turtle 1 (1984), Turtle 2 (1989), Barnett 1 (1985), Barnett 2 (1989) and Barnett 3 (1990). The Turtle and Barnett accumulations were discovered on the Turtle-Barnett High in 1984 and 1985, respectively. The discoveries are located approximately 320 km southwest of Darwin within retention leases WA-13-R and NT/RL3, respectively. The oil is reservoired in sandstones of the Keyling Formation, Treachery Shale, Kuriyippi Formation, Tanmurra Formation and Milligans Formation, and gas is reservoired in sandstones of the Langfield Group. The reservoirs are located in a large domal drape closure. Initial oil reserves are estimated to be 7.7 MMbbls for Turtle and 9.6 MMbbls for Barnett (see Cadman and Temple, 2004) In two drill stem tests (DSTs) carried out in Barnett 2, 39API oil flowed to the surface on jet pump at rates of 120 and 146 m3/d (752 and 921 bbls/d, respectively) from the Kuriyippi Formation. A DST undertaken within the Langfield Group flowed gas to the surface at a rate of 2550 m3/d (0.09 MMscf/d), with a trace of 44API condensate. Medium to light (33 to 36API) oil was recovered (but did not flow) from the Treachery Shale during two DSTs carried out in Turtle 1, and from the Tanmurra and Milligans formations during two DSTs carried out in Turtle 2. Oil was also recovered by wireline formation tests carried out in Barnett 1, Turtle 1 and Turtle 2 (Durrant et al, 1990). Conventional cores were taken from the silty sandstone reservoir section in Barnett 1, 2 and 3, and in Turtle 1 and 2. The sandstones contain residual oil and have an average core-plug porosity of 17 % and an average permeability of


10 mD. These sandstones exhibit poor reservoir characteristics due to the presence of a calcareous matrix and authigenic clays. However, these units often show extensive fracturing. Drilling problems encountered at Turtle 2 are attributable to an extensive network of fractures developed in the oil-bearing reservoirs. Jacaranda 1 (1984) Jacaranda 1, located in permit NT/P63 to the north of areas NT08-1 and W08-1, was drilled by Tricentrol Exploration Overseas Ltd to test the Petrel Formation (Flamingo Group and Plover Formation) sandstones in a four-way dip closure, flanking the Malita Graben; however, the validity of the trap is in doubt. The well terminated in the Petrel Formation (Plover Formation) at 3783 mRT, but the reservoirs were of poor quality and no hydrocarbon indications were encountered. Dark solid material that fluoresced was described as being distributed in pores and along bedding planes and was interpreted to be kerogen or bitumen. Minor gas indications were encountered in argillaceous siltstones of Late Cretaceous age. Darwinia 1, 1A (1985) Darwinia 1, located in permit NT/P64, was drilled in the Malita Graben by Tricentrol Exploration Overseas Ltd to test two Late Cretaceous sandstones, both with a small area of four-way dip closure and a larger area of fault dependent closure. A major fault, antithetic to the southern bounding fault zone of the Malita Graben, was interpreted as the main conduit for vertically migrating hydrocarbons. The Late Jurassic shales are believed to be present in the central graben (as intersected at Heron 1) and could provide a top seal. Darwinia 1 was drilled to 657 mKB and the 20 inch casing set at 648 mKB. The casing subsequently collapsed and the well was plugged and respudded as Darwinia 1A which reached TD at 2426 mKB before being plugged and abandoned with minor gas indications in the Late Cretaceous section. The sandstones of the objective horizons were all water wet, but had excellent porosities and permeabilities. Billawock 1 (1992) Billawock 1, located in permit NT/P43 (Figure 2), was drilled by BHP Petroleum Pty Ltd targeting deltaic sandstones of the Treachery Shale in a roll-over anticline on the down-thrown side of a major basin-margin fault. The well reached TD at 1734 mRT in the Kuriyippi Formation and confirmed the high quality of the target reservoirs. Oil indications were intersected in the Hyland Bay, Fossil Head, Keyling, Treachery and Kuriyippi formations. The oil is believed to have been sourced in situ from immature-early mature source material. Post-drill analysis concluded that the Billawock structure probably does not have access to mature source rocks. Billabong 1 (1992) Billabong 1 was drilled by BHP Petroleum Pty Ltd to test the Jurassic Plover Formation within a faulted, three-way rollover structure. The main fault strikes northwest-southeast with a southward throw. The main objectives were the Sandpiper Sandstone and the Plover Formation, both of which were penetrated, with the well reaching TD at 2028 mKB in the Plover Formation. The third objective, the Hyland Bay Formation was not intersected and only minor hydrocarbon indications were recorded. This corroborated the pre-drill risk


assessment that long distance migration from the Malita Graben source kitchen was a major concern. The Plover Formation sandstones have an average porosity of 18 % but are water-saturated. Seal would have been provided by the overlying Frigate Shale. The Sandpiper Sandstone has 21 % average porosity but is also water-saturated. Fishburn 1 (1992) Fishburn 1, located to the west of Release Area W08-3, was drilled by BHP Petroleum Pty Ltd to test a tilted fault block with three-way dip closure. The Plover Formation was the primary objective and the underlying Hyland Bay Formation sandstones provided the secondary objective. The tilted fault block is controlled by the intersection of two fault trends with both the target horizons trapped by a faulted three-way roll-over configuration. The well intersected a 51 m gross gas column in the Hyland Bay Formation, reaching TD at 2870 mKB. The primary reservoir facies within the Plover Formation and the overlying basal sandstones of the Frigate Shale were dry. Average porosity was recorded at 20 % between 1566.7-1860.8 mKB, but water saturation was 100 %. Prior to drilling, the risks were considered to be the long distance required for migration of hydrocarbons, and poor fault-seal integrity. As is the case at Tern, the gas column is reservoired in the lower section of the Tern Member and the upper section of the Cape Hay Member. The sandstones have an average porosity of 15 %, with average permeability of 10.4 mD. The gas-water contact occurs at 2370 mKB, at a level where the reservoir is not completely sealed by the Mount Goodwin Formation, which was expected to be the main sealing unit. Marsi 1, ST1 (1996) Marsi 1, ST1 was drilled by Mount Isa Mines Ltd in the outermost part of the Petrel Deep, adjacent to the Sahul Syncline and Malita Graben to the west of Release Area W08-1. The well tested a low relief closure, mapped as a remnan

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Geology - Offshore Petroleum Exploration Acreage Releasepetroleum-acreage.slicedlabs.com.au/2008/site/documents/geo_Petrel.… · 2008 Release of Australian Offshore Petroleum Exploration