Resources

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 early 1950s and resulted in seismic, aeromagnetic and gravity surveys being undertaken by the Bureau of Mineral Resources (BMR) in 1956. The first well to be drilled in the Bonaparte Basin was the onshore stratigraphic well Spirit Hill 1, which was spudded in 1959 by Westralian Oil Limited. It penetrated Carboniferous to Late Devonian sediments in which oil indications were recorded. This well was followed by the onshore gas discovery at Bonaparte 2 by Alliance Oil Development Australia in 1964 where gas flowed from reservoirs within the Mississippian Kingfisher Shale to Milligans Formation. Keep River 1, drilled by Australian Aquitaine Petroleum Pty Ltd in 1969, also flowed gas from the Milligans Formation. Other wells drilled by Australian Aquitaine Petroleum Pty Ltd in 1966 were Kulshill 1 and 2 which recorded oil shows, and Moyle 1, which was plugged and abandoned without encountering any hydrocarbons.

Some of the earliest offshore geological and geophysical surveys were undertaken by the Scripps Institute of Oceanography and the BMR, and included sea bottom echo profiling and sampling (van Andell and Veevers, 1967). Offshore exploration was conducted by several consortia, including the Arco Australia Ltd (Arco) led joint venture, which drilled the first offshore well, Lacrosse 1, in 1969. Arco then went on to drill Petrel 1, 1A, 2, Gull 1, Tern 1, Sandpiper 1, Pelican Island 1 and Penguin 1 throughout the early 1970s, resulting in the discovery of gas at Petrel, Tern and Penguin. Arco's later drilling of Curlew 1 (1975) and Frigate 1 (1978), were not able to maintain their earlier successes. Also during the 1970s, Australian Aquitaine Petroleum Pty Ltd (Australian Aquitaine) was actively drilling in the offshore Petrel Sub-basin; however, none of their wells (Newby 1, Flat Top 1, Bougainville 1 and Kinmore 1) resulted in discoveries.

Australian Aquitaine continued to drill exploration wells in both the onshore and offshore Petrel Sub-basin throughout the early 1980s, as well as appraising the Petrel and Tern accumulations. However, it was Western Mining Corporation Limited that discovered the small oil accumulation at Turtle (1984) in the southern, offshore part of the sub-basin. Petroleum-bearing reservoirs were found in numerous Carboniferous and Permian formations. The Barnett oil accumulation was discovered in 1989 with the drilling of Barnett 2 by Elf Aquitaine Exploration Australia Pty Ltd. Onshore, gas was discovered by Santos Ltd in the Garimala 1 well drilled in 1988.

In the early 1990s, appraisal of the offshore Petrel and Tern accumulations continued, as did the appraisal of the onshore Weaber gas accumulation, first discovered in 1982 by Australian Aquitaine. Of the eight offshore exploration wells drilled at this time, only Fishburn 1, drilled by BHP Petroleum Pty Ltd, was successful in making another gas discovery. Of the four wells drilled onshore in the 1990s, Waggon Creek 1 and Vienta 1 were gas discoveries made by Amity Oil NL.

Since the gas discovery at Blacktip 1 in 2001 by Woodside Energy Ltd, further success in this sub-basin has remained elusive, despite the drilling of Sandbar 1 (2001), Shakespeare 1 (2003), Weasel 1 (2003), Blacktip North 1 (2006), Marina 1 (2007) and Sidestep 1 (2008). Frigate Deep 1 was drilled by Santos Ltd and reached a TD of 2520 m in August 2008. The well is reported as a 'new field gas discovery' (upstreamonline.com, 25 August 2008), but no further information is currently available. At the time of writing, Windjana 1 is being drilled 26.5 km west-southwest of Matilda 1.

The Eni Australia B.V. (Eni) owned Blacktip gas-condensate field is, to date, the only accumulation that is being commercialised in the Petrel Sub-basin and will deliver gas to Darwin for the Power and Water Corporation. Eni has recently drilled Blacktip 2 to appraise the accumulation's reserves and the drilling of development wells is imminent. The 287 km Bonaparte pipeline runs from Eni's gas processing facility near Wadeye to Ban Ban Springs (about 130 km southeast of Darwin) and will transport gas to the existing Amadeus Basin to Darwin pipeline (www.abc.net.au/news/stories/2008/12/09/2441244.htm). The Bonaparte gas pipeline will initially be capable of delivering up to 30 petajoules of gas per year to the Northern Territory gas market (www.theterritory.com.au/resources/img/pdf/publications/territory_quarterly/TQ-2-2008.pdf). In addition, the Penguin (and Polkadot 1, 2004) gas accumulation may become commercially viable when the Blacktip production hub is in place. Further work is continuing to develop the Petrel and Tern gas accumulations.

In summary, a total of 53 exploration wells have been drilled in the Petrel Sub-basin; of these wells, 14 are hydrocarbon discoveries, giving a technical success of 26% and a 6% historical success rate for accumulations greater than 0.5 Tcf (3 discoveries; Blacktip, Petrel and Tern). To date, over 2.4 Tcf of gas with 10.6 MMbbls of condensate reserves have been proven within this sub-basin. The Barnett and Turtle accumulations collectively contain 10.4 MMbbls recoverable biodegraded oil from a much larger in-place volume. A synopsis of the reservoir units containing hydrocarbon accumulations and shows in the Petrel Sub-basin is shown in Table 1.

Well Control

Release Area NT09-Special contains the Barnett oil accumulation and Release Area W09-Special contains the Turtle oil accumulation. Both Release Areas are located in close proximity to the Blacktip gas field and are also in the vicinity of the Tern and Petrel gas fields.

Several wells have been drilled north of Release Area NT09-Special; these include Kinmore 1 (1974) and Shakespeare 1 (2003). The wells Kulshill 1 (1966), Kulshill 2 (1966) and Sunbird 1 (1994) are located to the east, with Kingfisher 1 (1994) to the south.

Immediately to the west of Release Area W09-Special is the exploration well Matilda 1 (1985). Further to the west of this Release Area are the wells; Lesueur 1 (1980), Cambridge 1 (1984), Lacrosse 1 (1969), Sandbar 1 (2001), Weasel 1 (2003) and Windjana 1 (2009). Pelican Island 1 (1972) was drilled to the southwest.

NOTE: Formation names and terms shown in square brackets are updates of the information presented in the well completion reports and follow the terminology of Gorter et al (2005, 2008 and 2009).

Kulshill 1 (1966)

Kulshill 1 was drilled onshore by Australian Aquitaine Petroleum Pty Ltd (1966a), 15 km south of the township of Port Keats in the Northern Territory. The well was drilled to investigate the Paleozoic stratigraphy of the northeastern part of the onshore portion of the Petrel Sub-basin and the petroleum prospectivity of the Kulshill Structure, which was interpreted to be a faulted anticline.

The well reached a TD of 4394 mRT in sandstones of the Late Devonian Cockatoo Formation [Cockatoo Group], which had lower porosity than predicted. Oil shows were reported in cuttings of Permian to Carboniferous age during the drilling of the well. These shows progressively decreased with depth. Gas was associated with the oil shows in the Carboniferous sediments and increased in intensity with depth. The most significant oil shows occur within the Treachery and Kuriyippi formations. Six drill stem tests (DSTs) were conducted in the well, including two in the aforementioned formations; however, none yielded oil.

Kulshill 2 (1966)

Kulshill 2 was drilled onshore by Australian Aquitaine Petroleum Pty Ltd (1966b) 3 km south of Kulshill 1. The well was drilled on a central fault block, close to the culmination of the Kulshill Structure and in a higher structural position than Kulshill 1. The well was designed to test the reservoir quality of the Permian and Carboniferous sediments and investigate facies changes between the two wells.

The well reached a TD of 1961 mRT within the Milligans Beds [re-interpreted as the Arco Formation]. Traces of methane were detected throughout the drilling below 274 m, probably originating from the numerous coals. Oil and gas indications were encountered over a more restricted depth range than at Kulshill 1, with the most significant oil shows being observed in the Milligans Beds [Arco Formation]. These shows are described as a dark brown to black bitumen cement, and light brown to brown free oil that exhibited a strong dark greenish-yellow fluorescence. However, the oil shows are restricted to sandstones of poor porosity (3%) and no permeability.

Lacrosse 1 (1969)

Lacrosse 1, drilled by Arco Limited (1969) on the Lacrosse Terrace in the Petrel Sub-basin, was the first well to be drilled in the offshore Bonaparte Basin. The well, drilled in 32 m of water, was designed to evaluate the hydrocarbon potential of the Lacrosse Structure and identify the major seismic reflectors mapped over the Lacrosse Terrace. Although the well was drilled 'on-structure', it was considered a stratigraphic test. It targeted Permian and Carboniferous reservoirs in a dip-rollover feature on the up-thrown side of a bounding fault.

The well penetrated Permian and Carboniferous sediments and terminated at a TD of 3054 mKB within the Medusa Beds [re-interpreted as the Tanmurra Formation]. Two cores taken over the depth range 1742.5–1758.7 mKB [interpreted as the lower Treachery Formation to the upper Kuriyippi Formation] were partially saturated with residual dark-brown oil with an estimated API gravity of 15–20°. The reservoir units have porosities of up to 26% and permeabilities of up to 514 mD. However, DST 1 (1717–1759 mKB) failed to recover hydrocarbons, probably because of the poor lateral permeability exhibited by the lenticular reservoir sandstones.

Petrel Gas Field

Petrel 1 (1969), Petrel 1A (1970), Petrel 2 (1971), Petrel 3 (1982), Petrel 4 (1988), Petrel 5 (1994) and Petrel 6 (1996).

The Petrel gas field lies 270 km west of Darwin and is situated within Retention Leases NT/RL1 and WA-6-R held by Santos Limited. The field is reported to contain initial recoverable resources of 970 Bcf gas and 5.9 MMbbls condensate (RDPIFR, 31 December, 2007).

Petrel 1, drilled by Arco Australia Limited in 100 m of water, was the second well to be drilled in the Petrel Sub-basin. It was drilled to evaluate the hydrocarbon potential of a large anticline and discovered the Petrel gas accumulation, although the hole was lost due to a blow-out of Permian gas (Arco Ltd - Australian Aquitaine Petroleum Pty Ltd, 1969). The relief well, Petrel 1A, extinguished the blow-out approximately one year later and the Petrel 1 well was sealed off in January 1971. Since then, a total of five wells have been drilled on the Petrel Anticline. The accumulation is hosted within the Cape Hay Formation of the Hyland Bay Subgroup between 3500–4000 mKB. Gas is also reservoired within the Pearce and Torrens formations of the Hyland Bay Subgroup in Petrel 2. Porosities of up to 20% or more were recorded in the Cape Hay Formation in Petrel 1; however, permeabilities are low. The gas at Petrel is moderately dry, with a condensate-to-gas-ratio (CGR) of between 0.5–9 bbls/MMscf (2.8–50.5 m³/MMm³).

Tern Gas Field

Tern 1 (1971), Tern 2 (1982), Tern 3 (1982), Tern 4 (1994) and Tern 5 (1998).

The Tern gas field is situated 300 km west of Darwin and approximately 50 km to the southwest of the Petrel gas accumulation. It is situated within Retention Lease WA-27-R, which is held by Santos Limited. The field is reported to contain initial recoverable resources of 468 Bcf gas and 5.7 MMbbls condensate (DMP, December, 2007).

The Tern gas accumulation was discovered by Arco Australia Limited (1971b) and four wells have been drilled subsequently, to appraise the northwest-trending salt-related, faulted anticline. Tern 3 tested a separate culmination on the southern extension of the Tern structure. At Tern, the main reservoir is the Tern Formation of the Hyland Bay Subgroup. In addition, gas is also reservoired within the Dombey Formation at Tern 2 and 3, and within the Cape Hay Formation at Tern 4. Porosities in excess of 20% have been identified at depths of about 2600 m.

Pelican Island 1 (1972)

Pelican Island 1 was drilled by Arco Australia Limited (1972) on Pelican Island in the southern part of the Petrel Sub-basin. The well was drilled to evaluate the hydrocarbon potential of Carboniferous sediments on a large, faulted anticline.

The well penetrated a thick sequence of Carboniferous sediments, with the lower Bonaparte Beds [Milligans Formation] being the oldest dated section in the well. After penetrating 183 m of salt, the well was terminated at a TD of 1981 mKB within a salt diapir of presumed Late Devonian age.

Residual oil was recorded at shallow depths in tight sandstones of Carboniferous age [Arco Formation], and gas shows were encountered in the underlying Tanmurra Formation and Bonaparte Beds. These gas shows have been re-interpreted to occur within the Yow Creek and Milligans formations. Log and sidewall core analyses indicated that these hydrocarbon zones were either too tight or too thin to warrant formation testing.

Kinmore 1 (1974)

Kinmore 1 was drilled by Australian Aquitaine Petroleum Pty. Ltd. (1974) on the southeastern flank of a domal feature of diapiric origin on the northwest-plunging Bougainville-Kinmore anticlinal ridge, 37 km southeast of Bougainville 1. The major objective in the well was the Kulshill Formation.

The well was drilled in 29 m of water and reached a TD of 3250 mKB within massive salt of a diapiric core, with sandstones of the Kulshill Formation [re-interpreted as the Kuriyippi Formation, Kulshill Group] being the oldest penetrated sediments. Minor oil and gas indications were recorded from the basal unit of the Kulshill Formation Sandstone Member [Kuriyippi Formation], but are interpreted to be water-saturated. An untested structure exists on the northern flank of the Kinmore diapir.

Lesueur 1 (1980)

Lesueur 1 was drilled in 57.5 m water depth by Australian Aquitaine Petroleum Pty Ltd (1980) on the western margin of the Petrel Sub-basin, at the northernmost extent of the Lacrosse Terrace, 53 km southwest of Penguin 1. The well was positioned near the crest of a large anticlinal closure associated with the main basin-margin fault, ideally located to trap hydrocarbons migrating up-dip from the Petrel Deep. The primary reservoirs targeted were the Kulshill and Tanmurra formations.

The well intersected sediments ranging in age from Triassic to Carboniferous, and terminated within the Bonaparte Beds [re-interpreted as the Kingfisher Shale] at 3589 mKB. The quality of the sandstone reservoirs within the Kulshill Formation [Kuriyippi, Aquitaine and Arco formations] is good, but they are water-bearing. The limestones and calcareous sandstones of the Tanmurra Formation are gas-bearing, but are too tight to flow gas at economical rates. Although the Bonaparte Beds [Kingfisher Shale] had oil shows, they have very low permeabilities. Source rock analyses of sediments from the Tanmurra Formation and Bonaparte Beds [Kingfisher Shale] indicate poor hydrocarbon potential.

Cambridge 1 (1984)

Cambridge 1 was drilled by Western Mining Corporation Limited (1985a) on the Cambridge High, some 16 km west-northwest of Lacrosse 1. Sandstones of the Kulshill Formation were the primary objective, while the Tanmurra Formation limestones and Bonaparte Beds clastics were secondary objectives. The Fossil Head Formation is the regional seal. The faulted anticlinal trap relies on fault-seal of Kulshill Formation reservoirs against the Fossil Head Formation.

The well was originally scheduled to drill to 2450 mRT, but all horizons were intersected high to prognosis. Igneous intrusives were encountered below the Bonaparte Beds [re-interpreted as the Bonaparte Formation] at 2213.5 mRT and drilling was terminated at a TD of 2228 mRT. Gas indications were recorded while drilling and a maximum of 2000 ppm methane and traces of ethane were recorded in the Hay Member of the Hyland Bay Formation to base-Kulshill Formation [Hyland Bay Subgroup to Border Creek Formation]. The heavier homologues of propane and butane were limited to a thin unit between 1950–1990 mRT within the Bonaparte Beds [Milligans Formation]. However, gas was seldom associated with oil shows. Oil indications were recorded in the Hyland Bay Formation, Fossil Head Formation and Kulshill Formation [Hyland Bay Subgroup to Border Creek Formation]. The most significant oil shows occur within the Fossil Head Formation and these were tested by two open-hole drill stem tests (DST 1 and 1A; 555–557.5 mRT), but no hydrocarbons were recovered. Analyses of oil from three sidewall cores at 147 m, 413.5 m and 575 m [Hyland Bay Subgroup, Fossil Head Formation and Keyling Formation, respectively], indicate that the oil is a mixture of unaltered and biodegraded oil, similar to those analysed at Turtle 1. The lack of hydrocarbons may result from the lack of integrity or continuity of the fault-seal.

Turtle Oil Accumulation

Turtle 1 (1984) and Turtle 2 (1989).

The Turtle oil accumulation was discovered on the Turtle-Barnett High in 1984 by the Turtle 1 well. The discovery is located approximately 305 km southeast of Darwin. The initial recoverable oil resources are 7.7 MMbbls for the Turtle accumulation (DMP, December 2007).

The reservoirs are located in a large domal drape closure. There are four separate oil columns within the Permian and Carboniferous section, as well as numerous oil shows. Oil columns are present within the Keyling and Treachery formations in Turtle 2. The deepest oil column occurs within the Tanmurra Formation and uppermost Milligans Formation [re-interpreted as the Kingfisher Shale]. In Turtle 1, oil columns occur within the Treachery and Ditji formations. In the two Turtle wells, oil shows occur from the Tern Formation to the Kingfisher Shale. Medium to light (33–36°API) oil was recovered (but did not flow) from the Treachery Formation during two DST's carried out in Turtle 1, and from the Tanmurra Formation and upper Milligans Formation [Kingfisher Shale] during two DSTs carried out in Turtle 2. Oil was also recovered by wireline formation tests carried out in Turtle 1 and 2 (Durrant et al, 1990).

Turtle 1 (1984)

Turtle 1 was drilled in 24 m of water by Western Mining Corporation Limited (1984) 15 km northwest of the Barnett oil field. The well was designed to evaluate the hydrocarbon potential of all Permian and Carboniferous reservoirs on the Turtle Structure – a domal drape closure at all levels over a tilted pre-Tanmurra Formation horst block. The primary objectives were sandstones in the Kulshill Formation and carbonates in the Tanmurra Formation. Secondary objectives were sandstones in the Hyland Bay Formation, Fossil Head Formation and pre-Tanmurra Formation sediments.

The well reached a TD of 2700 mRT within interbedded sandstones, shales, limestones and siltstones of the Bonaparte Beds [basal Milligans Formation]. The Carboniferous to Permian section was similar to that predicted but most formations were encountered high to prediction. Excellent reservoir rocks were encountered within the Hyland Bay Formation [Hyland Bay Subgroup] and uppermost Fossil Head Formation [Torrens Formation]. The Kulshill Formation [Keyling Formation, Ditji Formation, Treachery Formation and Kuriyippi Formation] contained the most extensive reservoirs in which numerous oil shows were recorded. The lower parts of the Kulshill Formation [Wadeye Group], the Tanmurra Formation and Bonaparte Beds [Kingfisher Shale and Milligans Formation] were very tight and appear to have only fracture porosity. Gas shows emanating from probable fractures occur in the basal Kulshill [Wadeye Group] and Tanmurra formations and the Bonaparte Beds [Kingfisher Shale and Milligans Formation].

Six conventional cores were taken to evaluate hydrocarbon shows – five in the Kulshill Formation [Kulshill Group] and one at the Tanmurra Formation/Bonaparte Beds [Kingfisher Shale] boundary.

A series of FITs were carried out to define pressure gradients and sample formation fluids. Eight cased-hole DSTs were carried out to evaluate the hydrocarbon potential of a number of zones of interest in the Kulshill Formation identified during drilling and wireline logging. Medium to light oil was recovered in the RFTs and while reversing out during two DSTs undertaken in the Treachery Formation. DST 4 (1622–1624 mRT) reversed out 26 bbls 32.5°API gravity oil, and DST 5 (1618.85–1621 mRT) reversed out 32.7 bbls of 32.7°API gravity oil. DST 5 also flowed oil and gas to the surface, but at a rate too small to measure.

Despite excellent reservoir characteristics, the tested zones had a very poor production performance, which has been attributed to a combination of viscous oil and low gas factors.

Post drill analysis suggests that the Turtle 1 well was a valid test drilled at or near the crests of the closures. The well was plugged and abandoned as a new field oil discovery.

Turtle 2 (1989)

Turtle 2 was drilled in 24.6 m of water by Western Mining Corporation Limited (1990), 3.25 km south of Turtle 1. The well tested the up-dip potential of the oil shows encountered in Turtle 1 in a faulted anticline. The well was located over crestal culminations in the Kinmore and Kulshill groups, but was off-structure in relationship to the underlying Weaber Group. The primary objectives were sandstones of the upper Kuriyippi Formation, with secondary objectives in the Keyling Formation, Treachery Shale, Point Springs Sandstone and lower Kuriyippi Formation.

Turtle 2 was originally scheduled to a TD of 2440 mRT in the Tanmurra Formation, but was deepened during drilling to test a pinchout play of the Milligans Formation against the tilted horst of the Turtle High. The well reached a TD of 2760 mRT within the Bonaparte Formation [re-interpreted to be within the basal Milligans Formation]. Drilling problems encountered at Turtle 2 are attributable to an extensive network of fractures developed in the Carboniferous oil-bearing reservoirs.

Oil shows were encountered throughout the Permian and Carboniferous sediments [from the Cape Hay Formation to the Milligans Formation]. Hydrocarbon shows in the top Keyling and Treachery formations do not appear to be constrained within structural closure, suggesting that there is a stratigraphic component to the trap. The oil shows in the Tanmurra Formation and Milligans Formation [Kingfisher Shale and Milligans Formation] are constrained within a stratigraphic pinchout onto the Turtle High. Four DST's were carried out in the well:

• DST 1/1A: 2632–2721 mRT recovered 22 bbls of 34.5°API gravity oil (but did not flow) from the Milligans Formation [Kingfisher Shale and Milligans Formation].
• DST 2: 2571–2607 mRT recovered 30 bbls of 36°API oil (but did not flow) from the lower Tanmurra Formation.
• DST 3: 2420–2447 mRT in the basal Point Spring Sandstone [Arco Formation]/top Tanmurra Formation failed to recover any significant reservoir fluids.
• DST 4A–C: 1614.5–1807 mRT in the upper Kuriyippi Formation [Treachery Formation–Kuriyippi Formation] failed to recover any significant reservoir fluids.

The oils recovered from DST1/1A and 2 are believed to have been recovered from a badly damaged fracture system.

In addition to the DSTs, two cased-hole RFTs were conducted at 1645 mRT in the Kuriyippi Formation [Treachery Formation] and at 927.1 m in the upper Keyling Formation, with the latter test recovering four gallons (18.2 litres) of heavy, viscous oil (14.3°API gravity). The oil column within the Keyling Formation is interpreted to be between 13 m gross (RFT pressure) and 17.7 m gross (core shows). The interpreted oil column at 1439–1444 mKB within the Treachery Formation was not tested.

The hydrocarbon shows in Turtle 2 were grouped into two types. The Kulshill Group oil shows were a mixture of a severely biodegraded, heavy black oil and a degraded light brown oil. The Weaber Group hydrocarbon shows comprised non-degraded, black oil with associated gas.

Lithological comparisons between Turtle 1 and 2 showed that the Kulshill Group sediments are sandier in Turtle 2, with higher sand/shale ratios in both the Treachery and upper Kuriyippi formations. Porosity and permeability measurements from core plugs are reported from four conventional cores cut in silty sandstone reservoirs:

• Core 1: 922–940 mRT in the top Keyling Formation exhibited good to excellent reservoir characteristics with porosities and permeabilities ranging from 12.2 to 30.9% and 22–3053 mD, respectively.
• Core 2: 1443.2–1439.5 mRT in the top Treachery Formation exhibited fair to good reservoir characteristics with porosities and permeabilities ranging from 7.8 to 25.8% and 0.19 to 915 mD, respectively.
• Core 3: 1614.27–1597.5 mRT in the top Kuriyippi Formation exhibited a range in both porosity (3.6–25.2%) and permeability (<0.01–116 mD), being a poor to fair reservoir.
• Core 4: 2495.15–2483 mRT in the Tanmurra Formation the limestones exhibited poor to no reservoir potential, with a thin sandstone having a maximum porosity of 11.8%.

The sandstones of the Tanmurra and Milligans formations exhibit poor reservoir characteristics due to the presence of a kaolinite–calcite cement and authigenic clays. However, these units show extensive fracturing, with log evaluation indicated porosities of >10% in the clastic sections.

Barnett Oil Accumulation

Barnett 1 (1985), Barnett 2 (1989) and Barnett 3 (1990).

The Barnett oil accumulation was discovered on the Turtle-Barnett High by Barnett 2 in 1989, following the initial oil discovery at Turtle 1. The discovery is located 300 km southeast of Darwin and the initial recoverable oil resources are 2.7 MMbbls for the accumulation (RDPIFR, 31 December 2007).

The reservoirs are located in a large domal drape closure. Oil is reservoired within Permian and Carboniferous section, including sandstones of the Keyling Formation, Quoin Formation, Kuriyippi Formation and Wadeye Group. Oil also occurs within the Weaber Group in Barnett 2.

Barnett 1 (1985)

Barnett 1 was drilled in 36 m of water by Australian Aquitaine Petroleum Pty Ltd (1985), 14 km northwest of Turtle 1. The well tested a northwest-trending broad anticline that terminates on the eastern flank with a series of north-trending faults. The structure is controlled by the Barnett-Turtle High, which is onlapped by upper Milligans Formation sandstones and draped by the Tanmurra Formation. The primary objective was to test a Kulshill Formation oil play following the drilling of Turtle 1. A secondary objective was the [Keyling Formation] sands beneath the Fossil Head Formation. Tertiary objectives were a sandy limestone play in the Tanmurra Formation and a Milligans Formation unconformity sandstone play.

The well reached a TD of 2350 mKB within the Milligans Formation [Utting Calcarenite] with all formation tops encountered close to prediction. Drilling confirmed the existence of a valid structure; however, the well did not encounter a significant hydrocarbon accumulation.

Good reservoirs (13–28% porosity) with oil shows were encountered in sandstones of the Kulshill Formation [Keyling Formation, Quoin Formation and Kuriyippi Formation, Kulshill Group]. Core 1, taken at 833–852 mKB [Keyling Formation], had consistent porosities of 20–30% and permeabilities >500 mD. Core 2 taken at 1311–1317 mKB [Quoin Formation] had porosities of 20–22% and permeabilities of 300–600 mD. Cores 3 and 4 were taken in finer grained sandstones at 1538–1561.5 mKB [Kuriyippi Formation] and had porosities of 10–18% and average permeabilities of 1 mD. The Tanmurra and Milligans formations did not contain any potential reservoirs.

Log analysis of the Kulshill Formation indicated 20% oil saturation, with the oil shows confined to tight reservoirs. The associated formation waters are fresh and of meteoric origin. Numerous RFTs and DSTs were conducted; however, the only oil recovery was in RFT No. 10 (Run 11) at 2033 mKB in Unit 'A' of the Kulshill Formation [Arco Formation] when 300 cc of 24° API gravity oil was recovered. The oil shows are interpreted to consist of a biodegraded residual oil and a second crude oil with a predominantly marine source character, although a terrestrial component was also identified. The lack of an accumulation at Barnett 1 is attributed to either reservoir flushing, breaching of the closure by faulting, lack of migrated hydrocarbons or a combination of all three factors.

Fair marine source rocks were encountered in the upper Kulshill Formation. The top of the oil window was placed approximately at 2200 mKB (Ro = 0.7%) within the upper Milligans Formation [Kingfisher Shale].

Barnett 2 (1989)

Barnett 2 was drilled in 24 m of water by Elf Aquitaine Exploration Australia Pty Ltd 1 km south-southwest of Barnett 1 and 11.8 km west-northwest of Turtle 2. Santos Limited purchased the permit in December 1989 and submitted the well completion report (Santos Limited, 1990). Barnett 2 tested an anticline mapped within the upper Milligans Formation on the Barnett Structure up-dip of Barnett 1. Barnett 2 is classed as an exploration well since its primary objective, the 'Barnett Member' of the upper Milligans Formation, was not penetrated in Barnett 1, although good oil shows were recorded from this formation in Turtle 2. The secondary objective for the well was the Kulshill Group up-dip of Barnett 1. Another objective was a tilted fault block in the lower Milligans Formation.

Barnett 2 was drilled to a TD of 2818 mKB within the Bonaparte Formation. As a result of significant oil and gas shows within the Permian and Carboniferous sediments, four DSTs were conducted, as follows;

• DST 1: 2393–2419.5 mKB flowed gas at a rate of 0.09 MMscfd (2550 m³/d) and recovered 7L of 44.4°API gravity oil from the Milligans Formation [Yow Creek Formation].
• DST 2: 1929–1935 mKB flowed formation water at a rate of 1073 bbl/d from the Kuriyippi Formation [Aquitaine Formation].
• DST 3: 1491–1497 mKB flowed 38.6°API gravity oil to the surface on jet pump at a rate of 752 bbl/d (120 m³/d) from the Kuriyippi Formation.
• DST 4: 1491–1506.5 mKB flowed 38.6°API gravity oil to the surface on jet pump at a rate of 921 bbl/d (921 m³/d) from the Kuriyippi Formation.

The extrapolated bottom hole temperature at 2818.8 mKB was calculated to be 102°C, with an extrapolated geothermal gradient of 2.61°C/100 m. The well was cased and suspended as a possible future oil producer.

Barnett 3 (1990)

Barnett 3 was drilled by Santos (NT) Pty Ltd in 1990 some 0.3 km southwest of the Barnett 2 well. The primary objectives were sandstones (14.9 and 15.0 sands) in the top of the Kuriyippi Formation that flowed oil in Barnett 2. Secondary objectives were sandstones within the Keyling Formation and Treachery Shale; these objectives were not within closure in Barnett 1 (Santos - Petroz - Gas and Fuel Expl - Lenoco - Southern Cross - Cultus - Gulf Resources, 1990).

The well reached a TD of 1700 mKB within the Kuriyippi Formation. No resistivity anomalies were recognised and a comprehensive Sequential Formation Test (SFT) program indicated a water gradient for all reservoir zones. The primary reservoir sandstones of the top Kuriyippi Formation were intersected 16 m low to prognosis and were of poor quality. Residual brown oil, that exhibited fluorescence under UV light, was observed in cuttings throughout the Keyling Formation. Oil indications were recorded while drilling fossiliferous zones within shales of the Fossil Head Formation.

Matilda 1 (1985)

Matilda 1 was drilled by Western Mining Corporation Limited (1985b) 21 km west-northwest of Turtle 1. The well targeted sandstones of the Kulshill Formation in the basinward flank of a salt-induced structure. Secondary objectives were limestones of the Tanmurra Formation and sandstones of the Bonaparte Beds.

The well was originally scheduled to drill to a depth of 2350 mRT, but drilling ceased at a TD of 2313 mRT after the Bonaparte Beds were penetrated higher than expected. The well has been re-interpreted to terminate within the Utting Calcarenite. Minor gas indications were recorded in the Fossil Head Formation to mid-Kulshill Formation [Keyling Formation], with minor wet gases detected in the Bonaparte Beds [Utting Calcarenite]. Minor oil indications identified from cuttings that fluoresced with a dull yellow colour and exhibited a very slow cut and crush cut were reported in the Fossil Head to mid-Kulshill Formation [Keyling Formation] sediments. Reservoir quality was poor (average porosity 15%). All RFTs were unsuccessful due to either tight formations or packer failure. No DSTs were conducted and no cores were cut due to the paucity of hydrocarbon shows.

The Matilda structure relied on fault-seal of the salt piercement structure. The lack of hydrocarbons may be due to inadequate fault-seal of the Kulshill Formation against the salt intrusion. Multiple structural and stratigraphic closures within Permian–Late Devonian sediments along the flank of the Matilda salt diapir have not been tested.

Kingfisher 1 (1994)

Kingfisher 1 was drilled by Teikoku Oil (Bonaparte Gulf) Co., Ltd. (1994a) 28 km south-southeast of the Barnett oil accumulation. The well was drilled near the top of a salt induced drape structure at the top of the Milligans Formation. It tested sandstone reservoirs of the Kuriyippi and upper Milligans formations as primary objectives, and the underlying lower Milligans and Bonaparte formations as the secondary objectives.

The well, drilled in 26 m of water, reached a TD of 3257 mRT within the Bonaparte Formation [Ningbing Group-equivalent]. The stratigraphic sequence penetrated was as predicted; however, the top Bonaparte Formation was 692 m high to prognosis, and the Kuriyippi Formation 244 m high to prognosis. The objective Kuriyippi Formation and Point Springs Sandstone [Wadeye Group] have a fair reservoir quality, whilst the Milligans Formation [Weaber Group] has poor reservoir quality.

Only minor hydrocarbon shows were encountered during drilling. Gas peaks within the Bonaparte Formation [Ningbing Group-equivalent] from below 2612.5 mRT were less than 1.5% and dry with the composition usually greater than 95% methane. Wireline log analysis showed there were no significant hydrocarbons in the well and an RFT at 1900.5 mRT within the Milligans Formation [Tanmurra Formation] recovered mud filtrate.

Sunbird 1 (1994)

Sunbird 1 was drilled by Teikoku Oil (Bonaparte Gulf) Co., Ltd. (1994b) 40 km east-southeast of the Barnett oil accumulation. The well was drilled near the top of a fault-related drape structure at the top of the Milligans Formation and was designed to test Carboniferous sandstones, with the Kuriyippi and upper Milligans formations as the primary objectives and the Point Spring Sandstone as the secondary objective.

The well, drilled in 43 m of water, reached a TD of 3324 mRT within the Milligans Formation [Bonaparte Formation]. The Kuriyippi Formation and Point Spring Sandstone [Wadeye Group] potential reservoirs have fair porosity and permeability, and fair sand to shale ratios. However, the Milligans Formation potential reservoirs have poor porosity and permeability, and poor sand to shale ratios.

Only minor hydrocarbon shows were encountered during drilling. Wireline log analysis showed that there were no significant hydrocarbons in the well and RFT pressure plots gave normal pressure water gradients within the Kuriyippi Formation and Point Spring Sandstone [Wadeye Group]. An RFT sample at 2091.2 mRT within the Point Spring Sandstone [Aquitaine Formation] recovered mud filtrate. The well was plugged and abandoned without testing, as a dry hole.

Cape Ford 1 (1997)

Cape Ford 1 was drilled in 28 m of water, 4 km south of Turtle 1, on the southwestern flank of the northwest-plunging Turtle High by Cultus Petroleum NL (1998) in the Joseph Bonaparte Gulf. The well tested a stratigraphic pinchout play downdip of Turtle 2, which was drilled 1 km to the north-northeast. The primary objective was the Tanmurra Formation, with the secondary objectives being sandstones within the Treachery Shale, top Kuriyippi Formation, basal Point Springs Sandstone and Milligans Formation. The well was located to intersect a seismic anomaly identified from amplitude-versus-offset (AVO) and acoustic impedance inversion studies. The seismic anomaly was interpreted to represent a thick, high porosity sandstone (TN2 Sand Unit) within the Tanmurra Formation. The trap configuration was a stratigraphic pinchout of proposed fan-delta reservoir units against the Turtle High. The sands developed in response to erosion of the Turtle High during the Early Carboniferous.

The well was plugged and abandoned 144 m into the Bonaparte Formation at a TD of 3022 mRT. Oil shows were encountered within the Treachery Shale [Treachery Formation], Kuriyippi Formation, Point Spring Sandstone [Wadeye Group], and in the Weaber Group [Sunbird, Tanmurra, Yow Creek and Milligans formations]. Evaluation of wireline logs assessed a total of 62.1 m of potential log pay below the Treachery Shale [Treachery Formation], none of which was considered net oil pay. Structural interpretation indicates that the hydrocarbon occurrences are not controlled by structural closure, implying a stratigraphic trap.

The top of the reservoir section within the Tanmurra Formation was encountered at 2615 mRT. This reservoir section is 65 m thick and comprises two sandstones separated by a 5 m thick claystone. The reservoir had lower porosity than predicted, with the topmost clean sandstone having 12% porosity for 4.6 m of logged pay. The reservoir section contained hydrocarbons, with dead oil and a maximum of 50% hydrocarbon fluorescence being observed in cuttings. A strong gas peak (54 units), comprising methane to butane, was recorded.

Two oil-stained, fine-grained intraformational sandstones were penetrated within the Milligans Formation [Yow Creek Formation] at 2770–2792 mRT and Milligans Formation 2819–2840 mRT. Despite being thicker and cleaner than the sandstones penetrated at Turtle 2, they had lower average porosity (˜11%) and were not fractured.

Pervasive, late stage diagenetic carbonate (calcite or dolomite and ankerite) cementation of the sandstones from the Milligans Formation to the Point Spring Sandstone [Wadeye Group] has resulted in the loss of porosity and permeability. Early calcite cementation of some sandstones within the Milligans Formation would have caused them to be impervious to dolomitic alteration, and hence they may never have been potential reservoirs. No production testing was conducted due to the tight reservoir sandstones and absence of fracture porosity.

Blacktip Gas Field

Blacktip 1 (2001) and Blacktip 2 (2009).

The Blacktip gas accumulation was discovered by the drilling of Blacktip 1 in 2001. The accumulation is situated approximately 300 km southwest of Darwin. The initial recoverable gas resources are 957.2 Bcf (DMP, December 2007).

Blacktip 1 (2001)

Blacktip 1 was drilled in 2001 by Woodside Energy Ltd in 55 m of water on a four-way-dip closure on the Lacrosse Terrace. The well was drilled to evaluate the hydrocarbon potential of the Blacktip Structure, a Late Triassic compression-induced, fault-independent anticline with amplitude/AVO support at intra-Mount Goodwin Formation and base Keyling Formation (Woodside Australian Energy, 2002a; Leonard et al, 2004).

The well reached a TD of 3181 mRT within the Treachery Formation. The deeper Kuriyippi Formation target was not reached. The results of the well proved that the AVO effects were related to gas bearing units within the Mount Goodwin Formation [Mount Goodwin Subgroup], Keyling Formation and the Treachery Formation. Additional gas-bearing units were not clearly visible on the seismic possibly due to a combination of reservoir quality and thickness, and depth of burial of the sandstones.

The section penetrated was close to prediction and eight major gas-bearing sandstones were encountered. The primary gas reservoir sandstones occur within the Keyling Formation and are sealed by the Fossil Head Formation, which also contains gas. Additional gas-saturated zones are located within the Mount Goodwin Formation [Ascalon Formation, Mount Goodwin Subgroup] which contains a 20 m gross gas unit, and two gas columns occur within the Treachery Formation (Leonard et al, 2004; Gorter et al, 2008).

Within the Keyling Formation, a cumulative gross gas column of 339 m was identified, with three reservoir sandstones being tested. The flows were constrained by surface equipment and tubing.

• DST 1: 2767–2785 mRT flowed gas at a rate of 34.4 MMscfd (974,000 m³/d) through a 1" choke.
• DST 2: 2570–2588 mRT flowed gas at a rate of 27 MMscfd (764,500 m³/d) through a 1" choke.
• DST 3: 2169–2187 mRT flowed gas at a rate of 28 MMscfd (792,000 m³/d) through a 1" choke.

The sustained high flow rates (89 MMscfd; Leonard et al, 2004), recorded on testing the three combined gas-saturated zones in the Keyling Formation, indicate the presence of good quality reservoirs in the Blacktip Structure. The porosity of the Keyling Formation is between 15 to 28% and the permeability is up to 800 mD (Leonard et al, 2004). The gas at Blacktip is dry, with a CGR of 5 bbl/MMscf (28 m³/MMm³). The gas is low in carbon dioxide (<1%).

Gas and fluid composition analysis indicates a similar hydrocarbon composition to the Petrel and Tern gas fields to the north. Blacktip 1 has confirmed that the Keyling Formation over this part of the Petrel Sub-basin has excellent reservoir qualities. It has also demonstrated that potential reservoir/seal pairs occur in the underlying Treachery Shale [Treachery Formation] (Woodside Energy Ltd, 2002a). The well was plugged and abandoned as a gas discovery.

Blacktip 2 (2009)

Blacktip 2 is an appraisal well drilled on the Blacktip structure by Eni Australia B.V. in 2009. Data from this well is still confidential and further information is unavailable at this time.

Sandbar 1 (2001)

Sandbar 1 was drilled in 2001 by Woodside Energy Ltd in the western portion of the Cambridge Trough and targeted a dip closure in a basin-floor fan sandstone of the Milligans Formation (Waggon Creek Member) and in the underlying sandstones of the Bonaparte Formation. The structure was formed during the Carboniferous by the combined effects of block faulting and possibly salt withdrawal in the underlying Silurian–Devonian section (Woodside Australian Energy, 2002b).

The well, drilled in 17 m of water, reached its objectives and terminated at a TD of 2950 mRT within the Bonaparte Formation; however, only minor gas indications and fluorescence were recorded. Lithological descriptions suggested that no sandstones of reservoir quality were encountered within the sediments from the Tanmurra Formation to the Bonaparte Formation. Although there is no closure within the Kuriyippi Formation, Point Spring Sandstone [Wadeye Group] and Tanmurra Formation, petrophysical evaluation of these reservoir sandstones indicated that they are water-wet.

Shakespeare 1 (2003)

Shakespeare 1 was drilled in 2003 by Woodside Energy Ltd on a Late Triassic compression-induced, faulted anticlinal structure some 280 km west-southwest of Darwin and 60 km north-northeast of the Turtle oil accumulation. The primary objective was to evaluate the hydrocarbon potential of Early Permian fluvio-deltaic sandstones of the Keyling Formation. Secondary objectives were sandstones of the Kuriyippi Formation and Treachery Shale. Claystones of the Fossil Head Formation were interpreted to form a top seal and hydrocarbon charge was modelled to have been sourced from the Keyling and Kuriyippi formations within the Petrel Sub-basin to the northwest (Woodside Australian Energy, 2003a).

The well, drilled in 28 m of water, reached a TD of 2182 mRT within interbedded sandstones and claystones of the Keyling Formation. All formation tops came in as predicted except the Keyling Formation, which was encountered at 1986 mRT, some 53 m deep to prognosis. Although the Keyling Formation comprised good quality sandstones (average log porosity 18%) all potential reservoirs are evaluated as water-bearing. Indications of minor amounts of residual oil from a 50 m section in the Keyling Formation is inferred from log analysis and weak fluorescence observed in the cuttings.

Due to the lack of hydrocarbons at the primary objective level, the option to deepen the well was not exercised. Shakespeare 1 is interpreted to have tested a valid structural closure with good quality reservoir development at the objective level. Lack of lateral fault seal is interpreted as the reason for failure (Woodside Australian Energy, 2003a). The well was plugged and abandoned as a dry hole with hydrocarbon indications.

Weasel 1 (2003)

Weasel 1 was drilled in 2003 by Woodside Energy Ltd 325 km west-southwest of Darwin and just to the north of the Cambridge 1 and Lacrosse 1 wells on the Lacrosse Terrace. The well was drilled to evaluate the hydrocarbon potential of the fluvio-deltaic sandstones of the Keyling Formation in a four-way dip closure in the hanging wall of a northwest-trending basin margin fault. Secondary objectives were fluvial clastics of the Kuriyippi Formation sealed by intra-formational claystones (Woodside Australian Energy, 2003b).

The well, drilled in 38 m of water, reached a TD of 1776 mRT within sandstones of the Kuriyippi Formation. All formation tops came in close to prognosis. Good quality sandstones were encountered within the Keyling, Kuriyippi and Treachery formations, with average porosities of 23%, 15% and 18%, respectively. All potential reservoirs were evaluated as water-bearing, although weak hydrocarbon indications were reported from cuttings in the Keyling Formation.

Weasel 1 is interpreted to have tested a valid structural closure with good quality reservoir development at the objective levels. Geochemical analyses of the residual oil within the Keyling Formation indicated the presence of a severely biodegraded oil. The reason for failure at Weasel 1 is interpreted to be trap integrity (Woodside Energy Ltd, 2003b). The well was plugged and abandoned as a dry hole with minor hydrocarbon indications.

Blacktip North 1 (2006)

Blacktip North 1 was drilled northwest of Blacktip 1 in November–December 2006 by Eni Australia B.V. The well reached a TD of 3120 mRT and was plugged and abandoned. Data from this well is still confidential and further information is unavailable at this time.

Rig Release Year shown. Areas marked with an asterick highlight those wells for which complete data sets are not yet available. Data accurate as at 31 March 2009

Seismic Coverage

Release Areas NT09-Special and W09-Special are covered by numerous grids of primarily 2D seismic data, with data density generally increasing towards the Turtle and Barnett oil accumulations in the southern part of the Release Areas. Seismic coverage in the northern part of Release Area NT09-Special includes the Baal Bone (1999) and the B88 (1989) 2D siesmic surveys, which have line spacings of between 1 and 5 km. The northern part of Release Area W09-Special is primarily covered by the WA-279/280-P (King Shoals) 2D seismic survey, which was acquired in 1999 and has a line spacing of 1–2 km. The central and southern parts of the Release Areas are covered by relatively more detailed 2D grids (typically with line spacing of approximately 1 km), including the SPA 5SL/1992-93 and Neptune 1990 surveys in NT09-Special and the Suzanne 1984 survey in W09-Special. Two 3D seismic surveys are situated either within or partially within the Release Areas. The B90-2D/3D Barnett seismic survey, which was acquired in 1990, covers approximately 56 km² over the Barnett oil accumulation in the southern part of Release Area NT09-Special. The Thresher 2D and 3D seismic survey, acquired in 1989, is situated adjacent to, and partially over, the southern margin of Release Area W09-Special. The most recent seismic acquisition in the Release Areas was the SNT04 - NT/P67 2D seismic survey, in which 136 line km were acquired by Santos in NT09-Special in September 2004.