Areas W07-18, W07-19, W07-20 and W07-21
Beagle Sub-basin, Carnarvon Basin
Exploration History
Exploration of the Beagle Sub-basin region began in 1965 with regional seismic, gravity and magnetic surveys. Subsequent exploration led to the drilling of 13 wildcat wells between 1971 and 1983. The wells tested a range of plays, including uplifted Triassic–Jurassic fault blocks, Triassic and Jurassic anticlines, and fault controlled structures down dip of the main basin-margin fault. Drilling confirmed the presence of a thick Late Palaeozoic–Cainozoic sedimentary sequence which contained prospective reservoir, source and seal units. Despite several minor shows, no significant hydrocarbon discoveries resulted.
Only two wells were drilled in the sub-basin between 1983 and 1992 (Trafalgar 1 in 1988, and Aurora 1 in 1990), together with two wells along the northern margin of the adjacent Dampier Sub-basin (Bounty 1 in 1983, and Calypso 1 in 1985). However, no hydrocarbon shows were recorded in these wells.
In the early 1990’s, a third wave of exploration activity was initiated in the sub-basin. Nebo 1 (1993) encountered thin oil-bearing sands in the Callovian Calypso Formation, and was the first well to confirm the presence of an active petroleum system in the Beagle Sub-basin (Osborne, 1994). In 1994–1995 the same joint venture consortium drilled 3 unsuccessful wells (Cimba 1, Darwin 1 and Halo 1).
In 1998, Mutineer 1B discovered oil in the Late Jurassic Angel Formation at the northern tip of the Dampier Sub-basin, and this discovery helped encourage further exploration in the adjacent Beagle Sub-basin. Woodside subsequently drilled four unsuccessful wells (Serval 1, Ermine 1, Grey Rabbit 1 and Tayra 1) in the western-central sub-basin in 1999–2001, and IB Resources drilled two unsuccessful wells (Manaslu 1 and Huascaran 1) in the central sub-basin in 2001–2002. Wigmore 1, the most recent well to be drilled in the Beagle Sub-basin, was drilled by Kerr McGee in 2002–2003 in the outer, deep-water, northwest portion of the sub-basin, and was also unsuccessful.
Twenty five wells have been drilled to date in the Beagle Sub-basin (Figure 1). No commercial accumulations of hydrocarbons have been encountered, and Nebo 1 is the only significant discovery in the sub-basin. The following summaries are based on the relevant well completion reports, and a review presented by Blevin et al (1994a).
De Grey 1 (1971) tested stacked targets, a possible stratigraphic onlap onto the Main Unconformity, and a deeper rotated Triassic fault block, on the De Grey Nose. There were no hydrocarbon shows recorded during drilling, and the well reached a total depth (TD) of 2088 mRT in Triassic sandstone. Subsequent mapping has shown that closure is absent at the Triassic level, and that the post-breakup ‘onlapping sequence’ is potentially a transgressive sand sheet without closure near the well (Blevin et al, 1994a). A review of the well has revised the age of sediments at total depth to be Early–Middle Triassic (Ingram, 1990), rather than the Late Triassic age originally interpreted during post-drill analysis.
Picard 1 (1972) was the first well to test structures in the main Mesozoic depocentre of the Beagle Sub-basin. The well was an apparent crestal test of a large north-trending Middle–Early Jurassic horst block, draped by an Early Cretaceous seal. The well reached a TD of 4216 mRT, and intersected a thick section of Middle–Early Jurassic sandstone with interbedded claystones, siltstone and minor coal, including a 216 m thick predominantly claystone section (3665–3881 mRT). Analysis by Surdam and Warme (1984) and Robertson Research (1986) concluded that the Early–Middle Jurassic Athol and Legendre claystones have good to very good oil source potential. Only minor fluorescence and gas shows were recorded in thin shaly sand interbeds within the Early Jurassic section, and wireline logs indicated that all sands were water saturated. Reactivation of north-trending bounding faults during the Late Cretaceous to early Tertiary may have breeched the Picard structure (Blevin et al, 1994a).
Sable 1 (1972) tested a large northeast-trending Triassic–Jurassic fault block in the southwest Beagle Sub-basin. The well reached a TD of 3972 mRT in the Late Triassic Mungaroo Formation and penetrated a thick section of Early Jurassic to Late Triassic interbedded sandstone and claystone, overlain by Early Cretaceous claystone. Only minor fluorescence and gas shows were recorded in the Early Jurassic section, and wireline logs indicated that all sands in the section were water saturated. The Sable 1 well is regarded as a valid test of the southern Sable horst block, but more recent seismic data across the area indicates that faults bounding the Sable Block have undergone minor periods of reactivation into the Early Tertiary (Blevin et al, 1994a).
Cossigny 1 (1972) tested a large down-thrown fault block on the southern margin of the main Mesozoic depocentre of the Beagle Sub-basin, adjacent to the elevated De Grey Nose to the south and the deeper Cossigny Trough to the north. The well reached a TD of 3203 mRT, and penetrated a thick section of Middle Triassic to Early Jurassic sandstone with minor interbedded claystone, siltstone and coal, including a 65 m thick section of Middle Triassic dolomite and limestone. The Triassic–Jurassic section was unconformably overlain by mid-Cretaceous argillaceous sediments, the regionally sealing Early Cretaceous section being absent. No hydrocarbon shows were encountered during drilling, and subsequent seismic data indicates that only minor closure is present in the Miocene at Cossigny 1.
Ronsard 1 (1973) was drilled to test a fault controlled Jurassic horst block with overlying drape closure in the central southwest portion of the Beagle Sub-basin. The well reached a TD of 2848 mKB in Early Jurassic interbedded sandstone and claystone with minor coal. This Early Jurassic section is unconformably overlain by a 38 m thick section of Early Cretaceous (early Aptian–late Neocomian) claystone, which is in term unconformably overlain by 31 m of interbedded marl, claystone and calcilutite of Albian age. No hydrocarbons were recorded during drilling or post drill analysis of sidewall and conventional cores. The well is considered to be a valid test of the structure. However, Early Tertiary reactivation of the north-trending faults bounding the structure has juxtaposed the thin sealing Neocomian claystone drape against the porous Late Cretaceous Toolonga calcilutite; thus any generated hydrocarbons could have leaked across the fault (Blevin et al, 1994a).
Poissonier 1 (1973) targeted Permian–Triassic sands in a down-thrown fault block along the southeastern basin-margin fault against the Lambert Shelf. The well was intended to test the potential of pre-Locker Shale sandstones down faulted against impermeable basement. Overlying Jurassic–Triassic sandstones truncated by the basal Cretaceous unconformity represented a secondary objective. The well intersected basic igneous basement at 1947 mKB, unconformably overlain by a thick sequence of sandstones, claystones, siltstones and minor coal of Early Jurassic and Triassic age. No significant hydrocarbon shows were recorded, but minor fluorescence was observed above the objective horizons in the upper Locker Shale and overlying sandstones of the Mungaroo Formation. Remapping of the area indicates there is little or no closure at the Triassic and Middle Jurassic unconformity levels (Blevin et al, 1994a).
Sandstones intersected beneath the Locker Shale have been reassessed as Early Carboniferous (Visean) in age, rather than earliest Triassic as originally thought (Ingram, 1990). The revised age of this pre-Locker Shale sandstone does not eliminate the concept of basal Triassic transgressive sandstone plays, and also highlights that Palaeozoic sandstones could be considered targets in inboard portions of the sub-basin.
Depuch 1 (1974) tested a fault controlled Jurassic horst block draped by Early Cretaceous claystone on the eastern margin of the Thouin Graben in the central eastern portion of the Beagle Sub-basin. The well reached a TD of 4300 mKB and intersected a thick section of Early–Middle Jurassic interbedded sandstones, claystones, siltstones and minor coal (Legendre Formation), overlain by 60 m of Callovian sandstone and claystone (Calypso Formation) and 180 m of Neocomian claystone (Forestier Claystone). No significant hydrocarbon shows were recorded, but fluorescence was noted over several sections within the Calypso and Legendre formations, although this was usually associated with the occurrence of carbonaceous material.
Regional mapping indicates that the well was sited on the flanks of a Jurassic fault block and lies only marginally within closure at the top Legendre level, and outside of closure at the top Calypso level (Kufpec, 1994).
Jarman 1 (1978) tested a large anticline on the northwest flank of the Cossigny Trough in the central southern Beagle Sub-basin. Closure at the top of the Late Jurassic sandstone (primary objective) and at the Main Unconformity level (secondary objective) were originally mapped as simple rollovers without the presence of major faulting. The well reached a TD of 2906 mKB within Middle Jurassic sandstone (Legendre Formation). No significant hydrocarbons were recorded while drilling, although four sidewall cores exhibited weak to moderate white solvent fluorescence. Jarman 1 was the first well in the Beagle Sub-basin to test post-breakup sandstones (Angel Formation) as the primary objective. Remapping of the area indicates the well was drilled outside structural closure along the flanks of the much larger Jarman Anticline (Blevin et al, 1994a).
Finucane 1 (1978) tested a faulted horst anticline on the southwest margin of the Beagle Sub-basin adjacent to the Dampier Sub-basin. The objective was sandstones of probable Middle–Early Jurassic age lying beneath the Main Unconformity. The well reached a TD of 3300 mKB and penetrated 195 m section of Middle Jurassic sandstones, claystones and minor coal (Legendre Formation), overlain by 122 m of Tithonian sandstones (Angel Formation), in turn unconformably overlain and sealed by Neocomian claystone (Forestier Claystone). No significant hydrocarbon shows were encountered and potential reservoir sands were water saturated. Post-drill mapping suggests that Finucane 1 was drilled outside structural closure (Blevin et al, 1994a).
Bruce 1 (1979) tested a Middle Triassic anticline down-dip of the southeastern basin margin fault against the Lambert Shelf, approximately 15 km west-southwest of Poissonier 1. The structure is interpreted to have been initiated by Late Triassic–Middle Jurassic right lateral wrench movement along small scale antithetic faults orthogonal to the main-basin margin fault (Blevin et al, 1994a). The well reached a TD of 2168 mKB and intersected a thick succession of Late–Middle Triassic sandstones, siltstones and claystones with minor carbonates (Mungaroo Formation), gradationally overlying a Middle–Early Triassic section of claystones and minor siltstones and sandstones (Locker Shale). The Triassic section is unconformably overlain by 50 m of Early Cretaceous claystone. Sidewall cores in Middle Triassic sandstones (Mungaroo Formation) directly beneath a 54 m thick siltstones and claystone unit (Cossigny Member) showed good bright gold fluorescence, bright silver blue solvent fluorescence and visible brown oil stain.
The Bruce 1 well confirmed the existence of a regional mid-Triassic seal (Cossigny Member) which has a distinctive seismic character, and the local generation of early mature hydrocarbons. Post-drill mapping suggests the well was drilled inside closure at the mid-Triassic level, but outside closure at the level of the Early Cretaceous seal, and that faulting above the Middle Triassic Cossigny Member may have breached the seal (Blevin et al, 1994a).
Delambre 1 (1980) tested a Middle Jurassic–Triassic eroded tilted fault block on the Brigadier Trend at the outer western margin of the Beagle Sub-basin. The well had two objectives, Middle Jurassic sandstones (Legendre Formation) subcropping the Main Unconformity horizon and sealed by Early Cretaceous claystone, and Early Jurassic–Late Triassic sandstones sealed by Early Jurassic claystone. The well reached a TD of 5495 mKB and penetrated a thick section of Middle Jurassic (Bathonian to Bajocian) sandstones, siltstones and claystones beneath the Main Unconformity, grading downward to Early Jurassic (Aalenian) to Late Triassic (Carnian) marginal marine claystones, sandstones and siltstones. Minor fluorescence and gas shows were recorded within Middle Jurassic to Late Triassic sandstones and claystones. The well appears to be a valid test of dip and postulated fault closure at the Main Unconformity and base Jurassic levels; however, there is some evidence of minor late stage (post-MU) reactivation of faults bounding the structure.
North Turtle 1 (1982) tested a tilted fault block outboard of the North Turtle Fault Zone in the eastern portion of the Beagle Sub-basin. The primary targets were 1) Early Jurassic sandstones of the ‘lower Depuch Formation’ (Legendre Formation equivalent), 2) Early Jurassic–Late Triassic sandstones of the ‘Bedout Formation’ (North Rankin and Brigadier Formations equivalent), and 3) Late Triassic sandstones of the ‘Upper Keraudren Formation’ (Mungaroo Formation equivalent). A secondary target was Middle Jurassic sandstones of the ‘upper Depuch Formation’ (Legendre Formation equivalent). The prognosed total depth of the well was 5,000 m. The well reached a TD of 4420 mKB without encountering any significant hydrocarbons, and was terminated within sandstones and minor interbedded siltstones, mudstones and coals of an unexpectedly thick ‘Depuch Formation’ because of porosity deterioration within these Early Jurassic sediments. The deeper ‘Bedout’ and ‘Upper Keraudren Formation’ targets were not reached, and there was no structural development at the intersected secondary target (‘upper Depuch Formation’) level.
Bounty 1 (1983) tested a Tithonian sandstone (Angel Formation) drape over a tilted fault block near the southwest margin of the Beagle Sub-basin where Late Jurassic sediments begin to thicken into the northernmost Dampier Sub-basin; here the Angel Formation is oil-bearing at Talisman 1. The secondary objective was westward-dipping Middle to Early Jurassic sandstones (Legendre Formation) subcropping the Main Unconformity. The well reached a TD of 3524 mKB within Tithonian sandstones without reaching the Middle Jurassic secondary objective due to operational difficulties. There were no significant hydrocarbon shows, but a ‘black, tar-like substance’ was noted on ‘1 % of sandstone grains’, together with moderate fluorescence, over the depth range 3231–3234 mKB in Tithonian sediments. Bounty 1 appeared to be a valid test of the structure, and the results suggest problems with regional migration and/or charge in this region.
Calypso 1 (1985) tested a faulted anticline at the northeastern end of the Lewis Trough in the Dampier Sub-basin, near the southern margin of the Beagle Sub-basin. The primary target was Early Cretaceous (Berriasian) to Late Jurassic (Tithonian) sandstones of the Angel Formation, which is oil-bearing in Talisman 1 8 km to the south, with a secondary target of Middle–Early Jurassic sandstones (Legendre Formation) below the Main Unconformity. Calypso 1 reached a TD of 2843 mKB within the Middle Jurassic Legendre Formation, and penetrated good quality reservoir sands of the Angel Formation. There were only minor hydrocarbon shows in the well, and the primary and secondary objectives were water wet.
Trafalgar 1 (1988) tested a composite four-way dip closed antiformal trap with faulting on its southern flank, in the central southern Beagle Sub-basin. The primary target was post-breakup Tithonian sandstones (Angel Formation) up-dip from Jarman 1. The well reached a TD of 2743 mKB within Middle Jurassic sandstones and interbedded claystones, siltstones and rare coal (Legendre Formation). The post-breakup sands predicted at Trafalgar were found to be interbedded siltstones and claystones with very poor reservoir potential, and no hydrocarbon shows were recorded in the well.
Aurora 1 (1990) was drilled near the southern margin of Beagle Sub-basin and the northeast Dampier Sub-basin, and tested a culmination on a transpressional en-echelon fault block mapped at the top Angel Formation. The primary reservoir objective was the Berriasian–Tithonian Angel Formation, which is oil bearing at Talisman 1, 18.7 km to the south-southwest. The underlying Late–Middle Jurassic sandstones of the Calypso Formation and Legendre Formation were secondary objectives. The well reached a TD of 3021.7 mRT in the Legendre Formation, unconformably overlain by sandstones of the Angel Formation and the regional Forestier Claystone seal. No hydrocarbon indications were encountered.
Nebo 1 (1993) targeted a large fault-dependent anticlinal structure (Nebo High) located in the southern Thouin Graben. The Nebo High has closure mapped in both time and depth at several levels extending from the Oxfordian Unconformity up to the Aptian Unconformity. The structure below the Oxfordian Unconformity comprises a major tilted fault block beneath the central Nebo High and separates tilt blocks beneath the flanks. The primary objective was deltaic sandstones of the Middle Jurassic Legendre Formation, sealed by claystones of the overlying Callovian Calypso Formation. Sandstones of the Tithonian Angel Formation were predicted as a possible secondary objective, but these were absent over the crest of the structure. The well reached a TD of 3132 mRT (-3110 mSS) in the Legendre Formation. Sandstones within the Legendre Formation were found to be porous (15–19 % average log porosity), but water wet. However, oil was discovered in thin sandstones within the overlying Calypso Formation. A total of 5.9 m of potential net oil pay was interpreted in 6 discrete thin sands (17–26 % average log porosity) over a gross section of 33 m, below 2663 mRT. A drill stem test perforated over the best reservoir zone in the depth range 2664.5–2668 mRT was carried out, and the well flowed 42 °API oil at a maximum flow rate of 1840 BPD on a ½ inch choke. The lack of shows in the underlying target Legendre Formation was attributed to the poor seal quality of the overlying Calypso Formation at the Nebo location.
Cimba 1 (1994) tested a tilted horst block on the up-thrown eastern margin of the Thouin Graben, 3.1 km to the north-northeast of Depuch 1 in the eastern Beagle Sub-basin. The primary objective was deltaic sandstones of the Middle Jurassic Legendre Formation, and marine sands within the overlying Calypso Formation provided a potential secondary objective. The well reached a TD of 2603 mRT within the Legendre Formation. No hydrocarbon shows were encountered, and all potential reservoirs were interpreted to be water-bearing. The demonstrated structural relief between Cimba 1 and Depuch 1 suggests that the well tested a valid trap.
Darwin 1 (1995) tested the crest of a four-way dip closure situated along the axis of the North Turtle Graben near the eastern margin of the Beagle Sub-basin. At mapped base Cretaceous level, the structure is controlled by drape over normal faults antithetic to the main graben-bounding faults, and by regional dip. The primary objective was the Callovian Calypso Formation, with secondary targets in the Early Cretaceous Muderong Shale and Forestier Claystone, Late Jurassic Angel Formation, and the deeper Middle Jurassic Legendre Formation. The well reached a TD of 2723 mRT within the Legendre Formation. No hydrocarbon shows were encountered, and the primary target sandstones of the Calypso Formation were water wet (including two very good quality sandstones with 12–30 %, average 25 %, calculated log porosity), as were sands in the Forestier Claystone and Legendre Formation. No sands were encountered in the Muderong Shale, and the Late Jurassic Angel Formation/Dingo Claystone was absent. Post-drill depth conversion confirmed that the well was a valid structural test at the Calypso and Legendre reservoir levels, but that sandstones within the overlying Forestier Claystone are out of closure. The complete lack of hydrocarbon shows or gas in the Jurassic reservoirs indicates that there has been no hydrocarbon migration into the Darwin structure. The most likely cause for ineffective migration involve problems in the migration pathways from the Beagle Trough and North Turtle Graben kitchens, and poor migration efficiency through a very high sandstone net-to-gross section. Other potential problems involve the type, distribution and volume of mature source rocks and their expulsion efficiency in a sand-prone depositional system.
Halo 1 (1995) was drilled on the eastern flank of the Nebo High within the Thouin Graben to test prognosed Late Jurassic sands of the Angel Formation that were not encountered on the bald crest of the structure at the Nebo 1 oil discovery 1.25 km to the west. The thin oil-bearing sands of the Calypso Formation intersected in Nebo 1 were not considered an objective in Halo 1 due to its structurally lower position. The well reached a TD of 3000 mRT within a thicker than prognosed section of the Calypso Formation (a greater upper thickness of the unit preserved below the Oxfordian Unconformity). A thickened section of Early Cretaceous (Berriasian) claystones was intersected beneath the Forestier Claystone (the ‘Halo Claystone’), but the targeted age-equivalent Angel Formation sandstones were not present. Beneath the Halo Claystone, a thin Kimmeridgian belemnitic limestone unit (the ‘Thouin Limestone’) was encountered above the Oxfordian Unconformity. No hydrocarbons were encountered, and thin potential reservoir sands within the Calypso Formation were water-bearing as anticipated (these sands occur below the level of interpreted highest-known-water in Nebo 1). Correlation with Nebo 1 suggests that the top of the Legendre Formation is likely to lie only a short distance (2–7 m) below the total depth drilled.
Serval 1 (1999) was drilled in the southwest Beagle Sub-basin and tested the Angel Formation sands in a crestal four-way dip closure. A secondary objective was to test the underlying Legendre Formation sands. The well penetrated 105 m of blocky Angel Formation sandstone (with an average porosity of 21 %) overlying interbedded sandstones and claystone of the Legendre Formation. The well reached a TD of 3210 mRT in the Legendre Formation. Both of these sands units are water wet. The intervening Calypso Formation and Dingo Claystone were absent due to truncation beneath the main unconformity, as evident on seismic. Minor fluorescence were observed in four sidewall cores, one near the top of the Angel Formation and three associated with an argillaceous section near the top of the Legendre Formation. These shows may indicate that migration into the trap was limited, or may have resulted from the contaminated, recycled, mud system. The failure of the well was considered to be due to lack of hydrocarbon charge.
Ermine 1 (1999) was drilled in the western portion of the Beagle Sub-basin to test the Legendre Formation in a near crestal dip and fault closed horst block. The overlying Angel Formation was identified as a possible secondary target. The well reached a TD of 2710 mRT in the Legendre Formation, and the Angel Formation was absent. No hydrocarbon shows were encountered in the well, and failure was considered to be due to a lack of hydrocarbon charge, although fault seal integrity was also questionable. Lack of charge may be due to inadequate source richness, insufficient maturity, or migration bypass of the faulted horst structure.
Grey Rabbit 1 (2001) tested a fault dependent closure on the northern end of the Ronsard Horst, adjacent to the eastern flank of the Ronsard Graben in the central western portion of the Beagle Sub-basin. The objective was the Legendre Formation sandstone, unconformably overlain and sealed by the Forestier Claystone and Muderong Shale. The well reached a TD of 2518 mRT and penetrated a 60 m section of the Legendre Formation that showed excellent reservoir properties, with 75 % net to gross and net sandstone average log porosity of 22.5 %. No hydrocarbon shows were encountered and the objective Legendre Formation was water wet. The failure of the well is considered to be lack of effective hydrocarbon charge from mature Early Jurassic section (Athol Formation) in the Ronsard Graben.
Tayra 1 (2001) was a crestal test of a fault dependent, hanging-wall, compressional rollover with small four-way dip closure on the eastern margin of the Ronsard Graben in the central southwest portion of the Beagle Sub-basin. The fault juxtaposes the objective Legendre Formation on the hanging wall against the Athol Formation on the foot wall. Top seal is provided by the overlying Calypso Formation and by the regionally sealing Forestier Claystone and Muderong Shale. The well reached a TD of 2907 mRT in sandstones of the Legendre Formation, and also penetrated a 6 m section of undifferentiated Late Jurassic claystone and calcilutite (Dingo Claystone equivalent) and an unexpected 29 m section of Oxfordian marine fan sandstone (interpreted as the Eliassen Formation) above the Calypso Formation. No hydrocarbon shows were encountered, and the objective Legendre Formation was water wet and poorer that prognosed reservoir quality (average log porosity 14.6 % and 68 % net/gross). Potential reservoir sandstones of the Oxfordian Eliassen Formation were also water bearing (average log porosity 16.7 % with a net/gross of 89 %). The objective Legendre Formation in Tayra 1 has direct access to the underlying mature Athol Formation potential source unit in the Ronsard Graben, so the complete lack of hydrocarbons in the small fault-independent crestal portion of the closure indicates that the generative potential of the Athol Formation is inadequate to charge the Tayra structure.
Manaslu 1 (2001) tested the Middle Jurassic Legendre Formation in a faulted anticline in the central-western portion of the Beagle Sub-basin. The well reached a TD of 2,531 mRT without any significant hydrocarbon shows. Detailed interpretative results have not been released at the time of this review.
Huascaran 1 (2002) tested the Middle Jurassic Legendre Formation in a rotated fault block in the eastern central Beagle Sub-basin, approximately 3 km west of the Nebo 1 oil discovery well. The well reached a TD of 2970 mRT without any significant hydrocarbon shows. Detailed interpretative results have not been released at the time of this review.
Mutineer/Norfolk and Exeter accumulations: The Mutineer/Norfolk structure (Petroleum in Western Australia, October 2002) is a north–south trending mid-Jurassic tilt block at the northern tip of the Dampier Sub-basin, adjacent to the southern margin of the Beagle Sub-basin. The Exeter structure is a separate culmination 9 km southwest of the Mutineer/Norfolk complex. The primary reservoir in the Mutineer/Norfolk and Exeter region is within the Late Jurassic upper Angel Formation. These sandstones are distributed as amalgamated sheet turbidites bodies that originated from the north or northeast of the basin to drape and onlap the rifted tilt block topography. The likely hydrocarbon source rock is the Late Jurassic Dingo Claystone within the Kendrew Trough of the Dampier Sub-basin to the south/southwest. The Forestier/Muderong shale provides top seal to the structures.
Exploration drilling in this area commenced with Bounty 1 (1983), followed by Pitcairn 1 (1987) and Mutineer 1B (1988). Mutineer 1B (1998) intersected an 8.2 m oil column, Norfolk 1 (March 2002) a 15 m oil column, and Norfolk 2 (March 2002) a 9 m oil column. The Mutineer 2 well (April 2002) was designed to test the northern extent of the field, but did not encounter the reservoir Angel sands. Exeter 1 (April 2002) encountered a 23 m gross oil column, and Exeter 2 (May 2002) an 11 m gross oil column. However, Bligh 1 (September 2002) was unsuccessful. Extension of the Mutineer High play fairway into the Beagle Sub-basin to the north carries a high risk of being bald of the Angel Formation reservoir sands, as is Mutineer 2 and Bligh 1.
Wigmore 1 (spudded November 2002) tested a large fault-controlled closure in a complex faulted area near the junction of the Beagle Sub-basin and the Delambre Platform. The envisaged petroleum system at Wigmore consists of a dual source from the Early Jurassic Picard Shale and Athol Formation, with reservoirs in the Early Jurassic North Rankin Formation and Middle Jurassic Legendre Formation (Petroleum in Western Australia, April 2003). Thick transgressive shales of the Muderong Shale provide the top seal, whereas at the North Rankin Formation level, the Early to Middle Jurassic Picard Shale and Athol Formation provide top and flank seal. The well reached a TD of 5394.7 mMD RT (5135.86 m TVD SS). Although detailed interpretative results have not been released, the lack of any reported hydrocarbons in Wigmore 1 (as well as in Whitetail 1, in the adjacent Rowley Sub-basin to the northeast) downgrades the prospectivity of the deeper outer portion of the Beagle Sub-basin.
Relevant Wells Listing
| Well | Operator | Year | Total Depth (m) | Hydrocarbons |
|---|---|---|---|---|
| Aurora 1 | Marathon Petroleum Australia Ltd | 1990 | 3020 | No shows |
| Bligh 1 | Santos Limited | 2002 | 3205 | No shows |
| Bounty 1 | Marathon Petroleum Australia Ltd | 1983 | 3524 | No shows |
| Bounty 2 | Santos Limited | 2004 | 3811 | Potential oil zone, gas indication |
| Bounty 2 ST1 | Santos Limited | 2004 | 3807 | Potential oil zone, gas indication |
| Bruce 1 | Stirling Petroleum NL | 1979 | 2168 | Strong oil indication |
| Calypso 1 | Marathon Petroleum Australia Ltd | 1985 | 2843 | Oil & gas indications |
| Cimba 1 | Kufpec Australia Pty Ltd | 1994 | 2600 | Oil indication |
| Cossigny 1 | B.O.C. of Australia Ltd | 1972 | 3203.4 | Oil indication |
| Darwin 1 | Apache Beagle Pty Ltd | 1995 | 2723 | No shows |
| De Grey 1 | B.O.C of Australia Limited | 1971 | 2087.9 | No shows |
| Delambre 1 | Woodside Petroleum Development Pty Ltd | 1980 | 5495 | Oil & gas indications |
| Depuch 1 | B.O.C. of Australia Ltd | 1974 | 4300 | Oil & gas indications |
| Ermine 1 | Woodside Energy Ltd | 1999 | 2710 | No shows |
| Exeter 1 | Santos Limited | 2002 | 3212 | Strong oil indication |
| Exeter 2 | Santos Limited | 2002 | 3245 | Proven oil zone, gas indication |
| Finucane 1 | Woodside Petroleum Development Pty Ltd | 1978 | 3300 | Oil indication |
| Grey Rabbit 1 | Woodside Energy Ltd | 2001 | 2518 | No shows |
| Halo 1 | Kufpec Australia Pty Ltd | 1995 | 3000 | No shows |
| Huascaran 1 | IB Resources Pty Ltd | 2002 | 2970 | Oil indication |
| Jarman 1 | Woodside Petroleum Development Pty. Ltd. | 1978 | 2906 | Oil indication |
| Manaslu 1 | IB Resources Pty. Ltd. | 2001 | 2531 | No shows |
| Mutineer 1 | Santos Ltd | 1998 | 872 | No shows |
| Mutineer 1A | Santos Ltd | 1998 | 1690 | Oil Indication |
| Mutineer 1B | Santos Ltd | 1998 | 3399 | Proven oil zone, gas indication |
| Mutineer 2 | Santos Limited | 2002 | 3250 | Oil indication |
| Mutineer 3 | Santos Limited | 2002 | 3320 | Proven oil zone |
| Nebo 1 | Kufpec Australia Pty Ltd | 1993 | 3132 | Proven oil & gas zones |
| North Turtle 1 | BP Petroleum Development Australia Pty Ltd | 1982 | 4420 | Oil & gas indications |
| Picard 1 | B.O.C. of Australia Limited | 1972 | 4216 | Oil & gas indications |
| Poissonnier 1 | B.O.C. of Australia Ltd. | 1974 | 1962 | Oil indication |
| Ronsard 1 | B.O.C. of Australia Ltd | 1973 | 2848 | No shows |
| Sable 1 | B O C of Australia Limited | 1972 | 3971.5 | Oil indication |
| Serval 1 | Woodside Energy Ltd | 1999 | 3210 | Oil indication |
| Tayra 1 | Woodside Energy Ltd | 2001 | 2907 | No shows |
| Trafalgar 1 | Ampol Exploration Limited | 1988 | 2743 | No shows |
| Wigmore 1 | Kerr McGee NW Shelf Energy Australia Pty. Ltd. | 2003 | 5394.7 | No shows |