Resources

The offshore Carnarvon Basin was established as a major hydrocarbon province in the 1960s and early 1970s, with WAPET's island and shallow water drilling program (Mitchelmore and Smith, 1994). Giant discoveries were made, including (in 1964) a billion barrels of oil-in-place at Barrow Island in the Barrow Sub-basin. Tryal Rocks 1, drilled in 1970, was one of the first tests of an offshore prospect. Early Cretaceous Barrow Group sandstones were intersected in the well but no significant hydrocarbon shows were recognised (Auld et al, 2002). The giant gas fields on the Rankin Platform were found in 1971 with the North Rankin 1 and Goodwyn 1 exploration wells. There was no immediate market for the gas and the main focus of exploration in the offshore Carnarvon Basin was the inboard oil trend in the Dampier and Barrow Sub-basins.

In the late 1970s and early 1980s exploration in the Carnarvon Basin again shifted westwards to the deepwater Exmouth Plateau. During this phase, the giant Gorgon gas field was discovered on the southern Rankin Platform. In 1984 the North West Shelf Project commenced domestic gas production from the North Rankin field and in 1989 the first LNG cargo was shipped to Japan .

Demand for LNG in Asia and rising energy prices have seen increased exploration along the Rankin Platform and on the Exmouth Plateau in recent years. One of the largest discoveries yet made in Australia is Jansz, a super-giant gas field in a new play type drilled in 2000 on the Exmouth Plateau in the Carnarvon Basin (Jenkins et al, 2003). Other recent large gas finds have been made along the Rankin Platform at Wheatstone, Pluto, Xena, Clio and Julimar.

Triassic horst blocks were the initial play type successfully pursued along the Rankin Platform with success from North Rankin (1971) in the north to Gorgon (1980) in the south; and more recent discoveries such as Wheatstone (2004). In the mid-1990s discoveries at Perseus (1995) and Keast (1997) demonstrated that downside-fault block traps were also viable gas targets on the Rankin Platform and the recent discoveries within the Julimar Complex have proven the success of stratigraphic traps identified with geophysical techniques (Apache Corporation, 2008).

Well Control

More than 100 exploration and appraisal wells have been drilled along the Rankin Platform resulting in the discovery of many giant gas fields. No wells have been drilled in Release Areas W09-9, W09-10 and W09-11. The key wells in the areas surrounding the Release Areas are described below and are grouped geographically. The wells located on the central Rankin Platform, and relevant to Release Areas W09-9 and W09-10, are discussed first, then follow those located on the southern Rankin Platform, Alpha Arch and Exmouth Plateau that are relevant to Release Area W09-11.

North Tryal Rocks 1 (1972)

North Tryal Rocks 1 drilled to test the Mungaroo Formation within a Triassic horst recovered a small quantity of gas by wireline formation test.

West Tryal Rocks 1 (1973)

West Tryal Rocks 1, located to the immediate southeast of Release Area W09-10, was drilled in 1972 by WAPET. Gas was recorded in sandstones of the Mungaroo Formation in a Triassic horst block, extending the proven trend from the south where the North Rankin and North Tryal Rocks discoveries were made earlier that year.

Malus 1 (1972)

Malus 1, drilled to a total depth of 3658 mRT, tested the hydrocarbon potential of a large, uplifted and tilted fault block to the southwest of the Rankin Trend. This feature extends into Release Area W09-9. This well penetrated sediments of Late Jurassic age (O .montgomeryi to W. spectabilis biozones) for the first time on the Rankin Platform. The Jurassic section was composed of Tithonian marls and claystones (Dingo Claystone) and Oxfordian sands (Jansz Sandstone equivalent?) which unconformably overlie interbedded claystones, sandstones and minor coals of the Brigadier and Mungaroo formations (Figure 3). No significant hydrocarbons were encountered and wireline log evaluation and test results showed that all intervals penetrated were water-bearing.

Sultan 1 (1979)

This well was drilled to test the Mungaroo Formation on a horst on the Rankin Platform (Figure 5 [PDF, 267KB]), and is located mid-way between Release Areas W09-9 and W09-10. The Mungaroo Formation sandstones were found to be water-bearing. A core cut in one of the sandstones, exhibited porosities ranging from 14 to 23% and permeabilities ranging from 2 to 128 mD. A core plug (with the lowest porosity and permeability) had a residual oil saturation of 0.8%.

Bluebell 1 (1983)

Bluebell 1 was drilled by WAPET to test the Mungaroo Formation on a tilted horst on the Rankin Platform to the south of Release Area W09-10. The structure is surrounded by the gas-bearing Chrysaor, Gorgon and West Tryal Rocks horsts. The top of the Mungaroo Formation was penetrated 549 m deeper than predicted. Two cores were cut in the Brigadier Formation, and two in the Mungaroo Formation. Reservoir properties determined by core analysis are poor. Sandstones of the Mungaroo Formation are water-bearing. The well may not have been drilled at an optimal location on the structure, and gas-bearing pools may exist further updip to the southwest in the structure.

Echo 1 (1988), Yodel 1 (1990)

The Echo/Yodel field at the southern end of the Rankin Trend was discovered in 1988 with the drilling of Echo 1. This well tested a Triassic fault block trap. The well intersected a 19 m gross gas column in upper E Unit Mungaroo Formation sands sealed by the Early Cretaceous Forestier Claystone (Bal et al, 2002). Yodel 1 was drilled in 1990 to test lower E Unit Mungaroo sands updip from Echo 1, where these excellent reservoir quality sands were water wet. In Yodel 1 a 40 m gross gas column was intersected in the Lower E Unit sands with an intervening claystone. The Triassic lower E unit sands were found to be hydrocarbon-bearing and with a different gas-water-contact (GWC) than that seen in the Echo 1 well. The condensate yield from Yodel 1 was also different to that from Echo 1. The Yodel 1 well successfully demonstrated the sealing nature of the Mungaroo Formation E unit claystones. (Bal et al, 2002).

Venture 1, 1ST1 (1990), Venture 2 (1995)

Venture 1 was drilled to test the Mungaroo Formation close to the boundary between the Rankin Platform and the Barrow Sub-basin (Figure 5 [PDF, 267KB]). After a gas kick whilst drilling claystones and siltstones of the Muderong Shale, the pipe became stuck and the original hole was sidetracked. 3L of liquid hydrocarbon with an API gravity of 36° were recovered from the mud pit after a gas kick with an accompanying 16 barrel pit gain at 2949 mRT. This liquid hydrocarbon is likely to be a condensate separated from the gas. After the mud weight had been increased to 1.88 g/cc to cope with increasing mud gas, the well was plugged and abandoned within the Muderong Shale (WAPET, 1991).

After the 1993 Venture-Carey 3D seismic data sets had been interpreted, Venture 2 (1995) was drilled to test Upper Jurassic and Lower Cretaceous fan sandstones on a rollover structure adjacent to the Triassic Venture horst structure some 4 km northeast of the Venture 1 well. Below the Muderong Shale, the well intersected the Barrow Group and reached total depth in the Dingo Claystone. This well was not programmed to drill into the Triassic Venture horst. Although high-density mud (up to 2.05 g/cc) was used, strong wet gas shows were encountered in the Muderong Shale, Barrow Group and Dingo Claystone. However, only thin sandstones were intersected in these sequences. No testing was attempted in the well.

Chrysaor 1 (1994), Dionysus 1 (1996)

The Chrysaor and Dionysus gas fields are located on the Rankin Platform immediately to the west of Release Area W09-10. In the mid 1990s, the established Triassic fault block play was targeted by WAPET and its successor Chevron Australia Pty Ltd, in deeper water along the eastern margin of the Exmouth Plateau. Chrysaor 1 (1994) and Dionysus 1 (1996) were drilled by WAPET to test potential DHIs north of the giant Gorgon gas field and led to the discovery of further giant gas fields with significant quantities of associated condensate (Longley et al, 2001; Walker, 2007). From 1999 to 2001, gas discoveries were also made at Geryon/Callirhoe, Orthrus, Maenad and Urania, all of which have strong AVO-signatures (Korn et al, 2003). Most of the discovery wells tested Triassic horsts where good quality reservoir facies were intersected in Late Triassic sediments, and, to a lesser extent, in the Early Jurassic (Brigadier Formation) sediments. Overlying seals in the Late Triassic and Early Jurassic were preserved on some fault blocks, and where this section has been removed due to Late Jurassic erosion, traps can occur beneath the regional Cretaceous seal.

Sculptor 1 (1995)

Sculptor 1 was drilled in 1995 to test the hydrocarbon potential of one of the east-west orientated fault blocks to the south of the Echo/Yodel field. High quality lower E Unit Mungaroo Formation sandstones were intersected and a gross 18 m gas column was encountered, with the GWC masked by shale. Pressure and gas composition data support Sculptor 1 being isolated from Echo/Yodel field according to Bal, et al (2002).

Keast 1 (1997)

Keast 1 was the first well to be drilled within the Keast Graben to the east of Echo/Yodel field (Woodside, 1997). In the graben the Early Jurassic Brigadier Formation (A. reducta biozone) is preserved and directly underlies the Early Cretaceous Forestier Claystone (E. torynum biozone). Keast 1 tested a structural/stratigraphic trap and reached a total depth of 3763 mRT in sandstones of Norian age representing the G Unit of the Mungaroo Formation. Five different hydrocarbon bearing zones were encountered in the Brigadier and Mungaroo formations (D and E units).

Malmsey 1 (1998)

Malmsey 1, located to the immediate south of Release Area W09-9 was drilled by Woodside Energy Ltd on the same large triangular horst block drilled by Malus 1. At this near crestal location the Early Cretaceous Muderong Shale directly overlies the Mungaroo Formation, while in Malus 1 both the Late Jurassic Dingo Claystone and Early Jurassic Brigadier Formation were intersected. Malmsey 1 encountered well developed reservoir sandstones within the Triassic Mungaroo Formation, 138 m higher than predicted and water wet. Malmsey 1 encountered the objective, the Triassic Mungaroo Formation sandstones belonging to the F, G, H and I Units (Woodside, 1998; Seggie et al, 2007). No significant hydrocarbon shows were encountered and petrophysical evaluation indicates that all potential reservoir sands are water wet. The well encountered 337 m of potential net'reservoir' sand. Average log porosity ranged from 20% in the F and G Unit sandstones, higher than prognosis, to 14.6% in the H Unit sandstones. The well completion report (Woodside, 1998) suggests that sealing bounding faults on the Malmsey-Malus horst have prevented migration of hydrocarbons into the structure.

Jansz 1 (2000), Io 1 (2001)

The supergiant Jansz/Io gas accumulation introduced a new play type to the basin. Hydrocarbons are stratigraphically trapped in an Oxfordian shallow marine sandstone (Figure 4) on the western limb of the Kangaroo Syncline (Jenkins et al, 2003). The field covers an area of approximately 2000 km² and the discovery wells Jansz 1, drilled by Mobil Exploration & Producing Australia Pty Ltd, and Io 1, drilled by Chevron Australia Pty Ltd, are located 18 km apart. The Oxfordian (W. spectabilis biozone) gas reservoir at Jansz 1 and Io 1 is in pressure communication with Tithonian and Triassic to Early Jurassic Brigadier Formation gas-bearing sandstones at Geryon 1 and Callirhoe 1 (Jenkins et al, 2003), a further 30 km away. Appraisal wells Jansz 2 (2002) and Jansz 3 (2003), plus a prominent AVO-response indicate that this discovery has a large areal extent and its mapped shape demonstrates the stratigraphic nature of the trap (Figure 4 [PDF, 80KB]).

Iago 1 (2000)

Iago 1 is located on the Rankin Platform about 8 km to the south of Release Area W09-9. It was drilled by ChevronTexaco on an offset structure to the North Tryal Rocks gas accumulation, which was discovered in 1972. The well encountered a total net gas pay of 20 m in high-quality sandstones at the top of the Mungaroo Formation (AA Sand, see ChevronTexaco, 2003 and Sibley et al, 1999). About 30 m of Early Cretaceous Forestier Claystone (the deepwater facies equivalent of the Barrow Group) seals the Mungaroo Formation sandstones.

Wheatstone 1 (2004)

Wheatstone is a giant gas accumulation on the Rankin Platform located to the immediate west of Release Area W09-9. Over 53 m of net gas sands were intersected in the Tithonian overlying the main reservoir interval of 126 m in the Triassic Mungaroo AA sands (Chevron, 2004). A seven well appraisal program has been completed and the planned development is for both export LNG and domestic gas (Chevron, 2008).

Pluto 1 (2005)

Pluto 1 is a giant gas discovery made by Woodside Energy Ltd in April 2005 on the Rankin Platform between Release Areas W09-9 and W09-10. As with Release Area W09-10, the accumulation straddles the shelf break. The Triassic sandstone is the reservoir in the Pluto accumulation (Walker, 2007). The fast-track Pluto gas development is currently under construction. The Pluto project is a production platform-based development with a trunk pipeline to the mainland. A Pluto production platform will provide nearby undeveloped or yet to be discovered gas accumulations with aggregation possibilities and could become a regional hub. The operator intends to commence gas production from the Pluto accumulation in 2010.

Julimar 1 (2007)

The Julimar Complex is located on the central Rankin Platform to the immediate east of Release Area W09-10. During 2007 and 2008 Apache Corporation made six gas discoveries within the Julimar Complex - Julimar 1, Julimar East 1, Julimar Southeast 1, Julimar Northwest 1, Brunello 1 and Brulimar 1. These wells intersected stacked gas pay in a number of Mungaroo Formation sandstones and the size of the gas accumulation is thought to be in the range of 2 to 4 Tcf According to the operator (Apache Corporation, 2008). In the Julimar Complex, geophysical techniques have been successfully used to target gas sands in stratigraphic traps.

Spar 1 (1976)

Spar 1 was drilled as a 3000 m test of a domal closure in the top of the Barrow Group and was ultimately drilled to a total depth of 3721 mRT as a result of encouraging hydrocarbon shows in the objective section. Two discrete gas accumulations were discovered in the Barrow Group, separated vertically by shales and water wet sands. Log evaluation indicates 86.6 m of net and effective and 7.5 m of probable gas pay. Spar 1 discovered the first substantial hydrocarbon accumulation yet found in the Flacourt Formation of the Barrow Group. The well terminated in the basal Cretaceous (P. iehiense biozone) because of rapidly increasing formation pressure and resultant high mud weights.

Zeepaard 1 (1980)

Zeepaard 1 was drilled by Esso Australia Ltd in 740 m of water to a total depth of 4215 mKB within the Mungaroo Formation. Zeepaard 1 is a gas discovery located on the Exmouth Plateau less than 20 km west of Release Area W09-11. The primary objective was sandstones of the Mungaroo Formation within a horst, and the secondary objective was turbidite sandstones of the Barrow Group on a stratigraphic pinch-out trap on the down-thrown side of a fault. Both sandstones were found porous and permeable. Minor gas shows were recorded in the Barrow Group. Gas was recovered by a wireline formation test at 4014.5 mKB from a thin sandstone in the Mungaroo Formation. The Dingo Claystone is thin (55 m) in this well, but this formation, as well as the underlying Mungaroo Formation, is over-pressured. The lower part of the Barrow Group and the Dingo Claystone have good oil sourcing potential with high quantities of extractable hydrocarbons and a high proportion of sapropel. These units are early mature with mean vitrinite reflectance values of up to 0.64%. Claystones within the Mungaroo Formation have good TOC contents with mixed oil and gas-prone kerogen types (Esso Australia Limited, 1981).

Gorgon 1 (1980)

Gorgon 1 was drilled by WAPET and reached a total depth of 4401 mRT. It is the discovery well on a giant gas/condensate field located about 10 km to the north of Release Area W09-11. The well was drilled towards the southern end of a large fault-bounded uplifted Triassic horst draped by younger sediments. Sandstones in both the Early Cretaceous Barrow Group and Late Triassic Mungaroo Formation were the well objectives. The main accumulation is within Triassic sandstones of the Mungaroo Formation. The gas composition is relatively high in carbon dioxide and the plans for the development of the field include geological storage of the CO₂ in reservoirs below Barrow Island (Gorgon Project, 2008).

Griffin 1 (1990)

The Griffin and Chinook/Scindian oil fields are located on the Alpha Arch some 40 km south of Release Area W09-11. The Griffin/Ramillies oil field was originally discovered by the Hilda 1A well, which was drilled in 1974, to primarily test the Triassic Mungaroo Formation within a horst on the Alpha Arch. The primary target was water-bearing, and an oil discovery in the Mardie Greensand was not considered as an economically viable accumulation at that time, and the petroleum exploration permit was relinquished. BHP Petroleum Pty Ltd (BHP) drilled Griffin 1 in 1990 and discovered a commercial oil accumulation. In the previous year, BHP drilled the Chinook 1 oil discovery well in an adjoining petroleum exploration permit. Petroleum is reservoired in the Zeepard Formation of the Barrow Group and the overlying Mardie Greensand in these oil fields. Reservoir quality is far better in the Zeepard Formation than in the Mardie Greensand. Top seal is provided by the Muderong Shale. To date, Griffin/Ramillies is the largest offshore oil field in the Barrow Sub-basin, with initial oil reserves of 149.6 MMbbls (Department of Mines and Petroleum, Western Australia, 2008).

Minden 1 (1991)

Minden 1 is located on the Alpha Arch, approximately 10 km south of Release Area W09-11. It was drilled by BHP as a test of the Triassic Mungaroo Formation with a secondary target in the overlying Barrow Group. Due to overpressured gas sands in the Barrow Group, the primary target was not reached and the well terminated in the Early Cretaceous (D. lobispinosum biozone)

York 1 (1993)

York 1 is located on the Alpha Arch some 20 km south of Release Area W09-11. It was drilled to test the Birdrong Sandstone on a four-way dip closure with 15 m vertical relief. Good reservoir sandstones with high net-to-gross ratios were intersected in the Birdrong Sandstone and underlying Zeepaard Formation. The Birdrong Sandstone has core plug porosities of 15 to 20% and permeabilities of up to 3000 mD. The well intersected the entire Zeepaard Formation and reached a total depth of 3372 mRT in the Barrow Group (E. torynum biozone), without encountering any significant hydrocarbons. The mapped closure may not be valid on the York structure. This well was not drilled into a deeper target of possible slope fan sandstones that may form stratigraphic traps in the intra-Barrow Group on the York structure.

East Spar 1 (1993)

The East Spar field was discovered by the East Spar 1 well drilled by Western Mining Corporation in 1993. The field is a Barrow Group gas accumulation in a four way dip closure. Careful depth conversion was required to reveal the East Spar structure which is not apparent in time. The gas-bearing sandstone at the top of the Barrow Group was deposited as an incised-valley fill at a progradational edge of the Barrow Delta lobe. The sandstone is overlain by the shallow marine, glauconitic Mardie Greensand, which acts as a thief zone. Top-seal is provided by the Muderong Shale. Production commenced in 1996, and gas and condensate are piped to processing facilities on Varanus Island, which is located 60 km east of the field (Craig et al, 1997).

Woollybutt 1 (1997)

The producing Woollybutt oil field is located off the Alpha Arch in the western Barrow Sub-basin, some 30 km southeast of the Release Area W09-11. The West Barrow 1A (1982) and 2 (1985) wells were the first to test the Woollybutt structure. Because of overpressure-related drilling problems, the Mardie Greensand or top Barrow Group sandstone was not tested in either well. More than ten years later the Woollybutt 1 well discovered an oil pool in these sandstones. The top Barrow Group sandstone, the prime reservoir in the Woollybutt field, was deposited as an incised-valley fill within the top-set sequence of the Barrow Delta. The lateral continuity of the sandstone is poor on the Woollybutt structure (Hearty et al, 2002). The Woollybutt field was commissioned in 2003.

Euryale 1 (1999)

Euryale 1 is located close to the northern boundary of Release Area W09-11 in about 700 m of water. It was drilled by WAPET targeting Barrow Group sands in a faulted anticlinal closure formed by drape over a rotated Triassic fault block at depth. Euryale 1 was a valid structural test and good sands were intersected in the Barrow Group but were water wet. The well reached a total depth of 3298 mRT in the Barrow Group/Zeepaard Formation (S. areolate biozone). Potential reservoirs deeper in the Barrow Group or in the Triassic remain untested on the structure. Poor reservoir quality sandstones in the Mardie Greensand, directly overlying the Barrow sands, were also water wet and may have acted as a thief zone for any hydrocarbons at this top porosity level beneath the Muderong Shale regional seal.

Antiope 1 ST1 (2000)

Antiope 1 ST1, drilled by BHP on the Alpha Arch, is a gas discovery in the Early Cretaceous Zeepaard Formation . The well targeted an anticline in the hanging wall of the Minden Fault based based on interpretation of 2D seismic data. Antiope  1 was sidetracked due to mechanical problems and Antiope ST1 intersected a total of 20.5 m of gas-bearing sandstone, composed of two discrete gas-on-water sands.

Xanthe 1 (2001)

Xanthe 1 was drilled by BHP to test a drape anticline on the Alpha Arch, located about 15 km to the south of Release Area W09-11. The primary targets were the Early Cretaceous sandstones of the Birdrong Sandstone and Zeepaard Formation. Good quality sands were intersected in both units but were found to be water wet. The well completion report (BHP Petroleum, 2001) states that lack of structural closure is the most likely reason for the failure of Xanthe 1, given that it is a low relief structure that is very sensitive to lateral velocity changes.

Lauda  1 and 2, and Maier 1 (2005)

These three wells were drilled in early 2005 by OMV in petroleum exploration permit WA-280-P, which adjoins Release Area W09-11. They were sited using the non-exclusive Minden Multi Client 3D seismic survey. Lauda 1 intersected a 6 m gross oil column at the top of the Barrow Group. Lauda 2, which was a sidetrack of Lauda 1, did not intersect the oil column, and Lauda 1 was plugged and abandoned. Maier 1 was a dry well.

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

Although there are no wells drilled within the Release Areas, there is a dense grid of 2D seismic of various vintages as well as recent 3D seismic coverage, some of which is open file. A full listing of the seismic is available in the Rankin Platform Data Listing [XLS, 363KB].