Petroleum exploration in the Ceduna Sub-basin occurred in four major cycles - the late 1960s to early 1970s, the early 1980s, the early 1990s and, most recently, from 2000-2007. In nearly 50 years of exploration in the offshore Bight Basin, less than 100000 line-km of seismic data have been acquired and only 10 petroleum exploration wells have been drilled (see Figure 7 Regional Geology of the Bight Basin, this CD). The majority of these wells were drilled in water depths of less than 250 m along the margins of the basin, where the source rock quality of mid to Late Cretaceous marine deposits has been reduced by the influx of terrigenous organic matter into proximal depositional facies. More distal facies are found in the Ceduna Sub-basin (Figure 2 [PDF, 416KB]), the thickest depocentre, which covers an area of 126300 km2. Five wells have been drilled in the sub-basin - Platypus 1, Potoroo 1, Borda 1, Greenly 1 and Gnarlyknots 1/1A. Three of these wells (Platypus 1, Greenly 1 and Borda 1) were originally assigned to the 'Duntroon Basin', however, reinterpretation of the basin boundaries by Bradshaw et al (2003), shows they were drilled in the Ceduna Sub-basin. With the exception of Gnarlyknots 1/1A, the wells were drilled in relatively shallow water near the basin margin and the deeper part of the sub-basin remains untested (Figure 1 [PDF, 648KB] and Figure 2 [PDF, 416KB]).
The first petroleum exploration permits held over the current Release Areas were granted to Shell Development (Australia) Ltd (Shell) in 1966. OEL 38 covering most of the Bight Basin and was converted to a number of exploration petroleum permits (EPP) between 1968 and 1969, with the current Release Areas covered in part by EPPs 5, 6, 10 and 11. Between 1966 and 1976 Shell carried out seven seismic surveys (R4 to R10) over these areas, acquiring over 14500 line-km of 2D seismic reflection data. Magnetic data was also recorded along most of the deep water lines. In 1966, Shell, in conjunction with Outback Oil Co. NL (Outback), recorded 16000 km of regional aeromagnetic data over OELs 33 and 38. Several prospects were developed from these activities and three exploration wells were drilled, Echidna 1 and Platypus 1 in 1972 and Potoroo 1 in 1975. Potoroo 1 is located in the northernmost part of the Release Area S09-1 (Figure 1 [PDF, 648KB] and Figure 2 [PDF, 416KB]). By 1977, Shell had surrendered all of its Bight Basin exploration petroleum permits.
The early 1980s was a period of relatively lacklustre exploration in the central Ceduna Sub-basin. During this period EPPs 16, 17 and 19, covering the current Release Areas, were held by BP Petroleum Development Pty Ltd (BP) and Hematite Petroleum Pty Ltd, a consortium headed by Sterling Petroleum NL and by Outback Oil Co. NL respectively. In 1982, Outback acquired 539 line-km of seismic in EPP 19, with the contractor Geophysical Service Inc. recording an additional 827 line-km of data in adjacent permits on a non-exclusive basis (O'Neil, 2003). However, interest in the area was so low that most of the data was left unprocessed and by 1984 all the permits had been surrendered (Stagg et al, 1990).
In 1982, EPP 21, which was located to the east of the current Release Areas overlying the central Duntroon Sub-basin, was granted to a joint venture, ultimately operated by BP after a farm-in in 1985. In 1983, the joint venture acquired 2102 line-km of reflection seismic data in conjunction with a geochemical hydrocarbon seepage sniffer survey, with a further 1017 line-km of seismic data acquired in 1984 (Stagg et al, 1990; O'Neil, 2003). These surveys defined several large prospects in the Duntroon and Ceduna Sub-basins, and led to the drilling of Duntroon 1 in early 1986 (see Figure 7 Regional Geology of the Bight Basin, this CD). The well was dry and subsequent mapping indicated that it had been drilled off-structure on the flank of a large faulted closure (O'Neil, 2003).
After an exploration hiatus through the late 1980s, BP flew an Airborne Laser Fluorosensor (ALF) survey in early 1990, under the auspices of a Scientific Investigation Authorisation. The survey covered the entire inboard Bight Basin and was conducted as part of a regional evaluation prior to an expected release round. A total of 27624 line-km of data were recorded at a line spacing of 5 km over an area of approximately 108508 km2 (Mackintosh and Williams, 1990). The initial results were poor with only two definite, but weak fluors detected. However, reprocessing and reinterpretation of the data recorded a total of 941 confident fluors (Cowley, 2001). The fluors are concentrated in three regions in the Ceduna Sub-basin, one in the vicinity of Greenly 1 and two other dense, but less confidently interpreted areas approximately 50 km south and approximately 100 km southwest of Potoroo 1.
A new phase of exploration began in 1991, when BHP Petroleum (Australia) Pty Ltd (BHP) was awarded EPPs 25 and 26 covering the eastern Ceduna and Duntroon sub-basins, east of the current Release Areas. In 1991, 1046 line-km of seismic data acquired by the EPP 21 joint venture was reprocessed and three new seismic surveys (DH91, DH92 and HD95) acquired high quality 2D seismic data from 1991 to 1995. These new data indicated that all prior drilling had been sited on invalid structures (O'Neil, 2003). BHP drilled three wells in 1993; Borda 1 and Greenly 1 lie within the remapped boundaries of the Ceduna Sub-basin (Bradshaw et al, 2003), while Vivonne 1 was drilled in the Duntroon Sub-basin (see Figure 7 Regional Geology of the Bight Basin, this CD). Although all were plugged and abandoned, their results are encouraging and emphasise the highly unpredictable stratigraphy and complex structural history of the basin. Borda 1 was designed to test a Late Cretaceous to Cenozoic play sealed by Cenozoic marls, similar in style to the highly productive Gippsland Basin play. The most likely cause of failure was the presence of thick Late Cretaceous claystones, which inhibited vertical migration from the Bronze Whaler Supersequence to reservoirs in the Wobbegong Supersequence (Messent, 1998). Greenly 1 tested a basal Late Cretaceous play, reaching a total depth of 4860 mRT. Oil and gas were recovered at 4209 mRT during testing (RFT) and numerous oil indications were recorded from 3430-4524 mRT and 4770-4818 mRT (Messent, 1998). These results represent the first major indication of hydrocarbons in the sub-basin, identifying the presence of a valid source rock and thus considerably upgrading the prospectivity of the Ceduna Sub-basin. Vivonne 1 tested a Late Cretaceous play and reached a total depth of 3000 mRT. The lack of a suitable migration pathway from the Bronze Whaler Supersequence is thought to have contributed to the failure of this well (Messent, 1998).
The latest phase of petroleum exploration commenced in 1999, with the release by the Commonwealth Government of eleven areas for petroleum exploration. Three petroleum exploration permits were awarded in 2000 to a joint venture comprising Woodside Energy Ltd (operator), Anadarko Australia Co. Ltd and PanCanadian Petroleum Corp. (now EnCana Corp.). The permits, EPP 28, EPP 29 and EPP 30 covered the majority of the current Release Areas. The joint venture acquired a large quantity of 2D seismic data and drilled an exploration well, Gnarlyknots 1/1A (Figure 7 [PDF, 870KB]). The Flinders 2D Seismic Survey, completed in May 2001, recorded a total of 15636 line-km of closely spaced, full fold data across the three permits. The seismic grid ranges from 4 x 4 km in the west to 4 x 8 km in the northern and eastern portions of the survey area and recording parameters were optimised to capture any potential AVO effects (Bruins et al, 2001). In early 2006, 1250 km2 of 3D seismic data (Trim 3D Seismic Survey) was acquired over EPP 29. This survey overlies the northern portions of the current Release Areas S09-4 and S09-5. The Gnarlyknots 1A well was plagued by mechanical problems and abandoned prematurely due to bad weather (1500 m above the prognosed total depth). Although Gnarlyknots 1A failed to recover hydrocarbons, several encouraging results were recorded. These include excellent quality sandstone reservoirs, marine shale top seals and thermogenic hydrocarbon shows, which indicate the presence of a mature source rock down-dip (Tapley et al, 2005). Although the joint venture identified numerous leads (Figure 7 [PDF, 870KB]), some with amplitude support, all three permits were surrendered in 2007.
Geoscience Australia (GA) and its predecessor agencies have a long history of research in the Bight Basin, conducting several gravity and magnetic surveys and acquiring over 28000 line-km of regional 2D seismic data. More recently, GA carried out an integrated basin study of the eastern Bight Basin (1998-2003) using regional seismic and well data. Resulting petroleum system and play models predict numerous potential petroleum systems in Jurassic and Cretaceous age depocentres from the Eyre, Duntroon and Ceduna sub-basins (Blevin et al, 2000; Totterdell et al, 2000, Struckmeyer et al, 2001). These studies were followed by a marine survey (Bight Basin Geological and Sampling Survey) in 2007 (Totterdell, in press), which targeted and recovered potential source rocks of late Cenomanian to early Turonian age (Totterdell et al, 2008) from the northwestern edge of the Ceduna Sub-basin (Figure 2 [PDF, 416KB]).
Ten wells have been drilled in the offshore Bight Basin; six of these are located in the Ceduna Sub-basin. Of these, Potoroo 1 and Gnarlyknots 1/1A are located within the current Release Areas, while Jerboa 1 and Greenly 1 are key wells drilled adjacent to the Release Areas (Figure 1 [PDF, 648KB] and Figure 2 [PDF, 416KB]). Most of the wells have been drilled close to the margins of the basin where the sedimentary section is relatively thin. Oil and gas shows were recorded in Greenly 1, while other wells have recorded oil and gas indications. To date no commercial hydrocarbons have been discovered in the Ceduna Sub-basin.
Potoroo 1 (1975)
Potoroo 1 was drilled on the northern edge of the Ceduna Sub-basin by Shell Development (Australia) Pty. Ltd in 1975 and is located in the northernmost part of the current Release Area S09-1 (Figure 1 [PDF, 648KB] and Figure 2 [PDF, 416KB]). The well was drilled to test a structure within the Platypus Formation (White Pointer Supersequence) with dip closure against a major basement fault. The target interval was characterised by strong seismic reflections, similar to the'Platypus' sands encountered in Platypus 1, drilled in the adjacent Duntroon Sub-basin (Messent, 1998).
Potoroo 1 intersected an Early Cretaceous to Holocene, lacustrine to marine sedimentary succession characterised by interbedded siltstone and claystone; Precambrian basement was intersected at 2815 mRT. Reservoir sandstones were not encountered in the target interval (Messent, 1998). The well intersected a major fault that marks the present-day northern edge of the Early Cretaceous units. Occasional high gas peaks (methane with traces of ethane up to 6000 ppm) were recorded from below the top of the Wigunda Formation (Tiger Supersequence) to a total depth (TD) of 2924 mRT (Messent, 1998). Gas recorded in the Platypus Formation (White Pointer Supersequence) was associated with coal (Messent, 1998). The primary cause of failure was attributed to the lack of reservoirs within the target horizon, together with the lack of hydrocarbon migration into the structure (Messent, 1998). There is also considerable doubt as to whether the well was drilled'on structure'.
Jerboa 1 (1980)
Jerboa 1 was drilled approximately 200 km east-northeast of the current Release Areas in the Eyre Sub-basin (Figure 1 [PDF, 648KB] and Figure 2 [PDF, 416KB]). The well was drilled by Esso Australia Ltd in 1980 on the footwall of a major half-graben bounding fault. The well targeted Late Jurassic to Early Cretaceous sandstone reservoirs in the Sea Lion-Bronze Whaler supersequences. Closure on the prospective section was provided by drape over the Precambrian basement fault block (Messent, 1998). Jerboa 1 penetrated a small, localised hanging wall section close to the bounding fault, intersecting Late Jurassic to Recent, lacustrine to marine sedimentary successions with multiple reservoir-seal pairs. Recent work on the fluid history of the well (Liu and Eadington, 1998; Ruble et al, 2001) documented the presence of a 15 m net palaeo-oil zone extending over the gross interval 2470-2495 mRT in sandstone of the Sea Lion Supersequence. Geochemical studies of the oil clearly point to a lacustrine source (Ruble et al, 2001). Source rocks penetrated in the well are immature to marginally mature. Deeper parts of the adjacent half graben may contain mature, lacustrine source rocks deposited during rift development.
Greenly 1 (1993)
Greenly 1 was drilled by BHP Petroleum Pty Ltd in 1993 approximately 275 km southeast of the current Release Areas (Figure 1 [PDF, 648KB] and Figure 2 [PDF, 416KB]). The well was drilled within the previously defined Duntroon Basin, however, re-mapped basin margins by Bradshaw et al (2003) place it within the Ceduna Sub-basin. The well was designed to test a simple anticlinal structure, targeting Late Cretaceous sandstone reservoirs at the base of the Wigunda Formation (Tiger Supersequence). However, structural misinterpretation resulted in the well drilling the hanging wall of a tilted fault block (Messent, 1998).
Oil and gas were recovered from the Wigunda Formation (Tiger Supersequence) during testing (RFT). The oil was recovered as a surface scum and as a water/oil mixture (Messent, 1998). Numerous oil indications were also reported from the Wigunda and Platypus formations (Tiger and White Pointer supersequences). The most likely source of the hydrocarbons is the upper Borda Formation (Bronze Whaler Supersequence) (Smith and Donaldson, 1995; Messent, 1998). Vitrinite reflectance data and Bottom Hole Temperature measurements indicate the top of the oil window is at approximately 3600 mRT and the well is still within the oil window at TD (4860 mRT) (Wong, 1994; Messent, 1998).
The absence of significant hydrocarbons at Greenly 1 is most likely due to a combination of poor reservoir quality and the lack of closure at the target horizon (Messent, 1998). There was also an error in the structural interpretation. Due to significant horizon mis-picks during seismic interpretation, the target horizon was in excess of 2000 m deeper than predicted (Messent, 1998).
Gnarlyknots 1/1A (2003)
Woodside Energy Ltd and its joint venture partners drilled Gnarlyknots 1/1A in April 2003. The wells lie in the central portion of Release Area S09-2 (Figure 1 [PDF, 648KB] and Figure 2 [PDF, 416KB]). Gnarlyknots 1 was abandoned at 1824 mRT due to mechanical difficulties and Gnarlyknots 1A was spudded approximately 50 m to the southwest. The well was designed to test the petroleum systems within the more distal Late Cretaceous depositional systems of the Ceduna Sub-basin where oil-prone, marine source rocks are more likely (Tapley et al, 2005). The well was drilled to test as much of the prospective basin stratigraphy as possible by penetrating four stratigraphic horizons with fault-dependent closure within a tilted fault block, targeting reservoir seal pairs predicted in the intra-Santonian and top-Coniacian intervals (Woodside, 2004). However, due to adverse weather conditions the well was abandoned at 4736 mRT near the top of the Tiger Supersequence, some 1500 m above the predicted total depth, with several key targets remaining untested. Although Gnarlyknots 1A failed to recover hydrocarbons, several encouraging indications were observed. Tapley et al (2005) reported the following hydrocarbon indications:
- fluorescence and cut in side wall cores and cuttings from 4383 mRT;
- methane-depleted wet gas to gas-condensate response in the primary objective (intra-Santonian) - observed using Fluid Inclusion Stratigraphy analysis - consistent with a highly mature palaeo-charge;
- strong proximity to pay indicators within local shale seals below 4600 mRT, possibly indicating proximity to an oil column below the TD of the well; and
- indications that thermogenic gas has migrated into the structure from mud gas isotope analysis in the primary objective.
The failure of Gnarlyknots 1A to discover significant hydrocarbons is attributed to the well being drilled outside of any independent fault closure, and the absence of valid cross-fault seals within the sand-prone coastal plain deposits (Tapley et al, 2005). Due to technical problems, causing early abandonment, the well failed to test several key targets.
Table 1: Key wells listing
|Apollo 1||Outback Oil Company NL.||1975||876 mKB||No tests|
|Borda 1||BHP Petroleum Pty Ltd||1993||2800 mRT||No tests|
|Duntroon 1||BP Petroleum Development Limited||1986||3510 mRT||No tests|
|Echidna 1||Shell Development (Australia) Pt Ltd||1972||3832 mRT||No tests|
|Gnarlyknots 1||Woodside Energy Ltd||2003||1824 mRT||No tests|
|Gnarlyknots 1A||Woodside Energy Ltd||2003||4736 mRT||No tests|
|Greenly 1||BHP Petroleum Pty Ltd||1993||4860 mRT||Minor gas|
|Jerboa 1||Esso Australia Limited||1980||2537.5 mRT||No tests|
|Platypus 1||Shell Development (Australia) Pty Ltd||1972||3892.9 mRT||No tests|
|Potoroo 1||Shell Development (Australia) Pty Ltd||1975||2924 mRT||No tests|
|Vivonne 1||BHP Petroleum Pty Ltd||1993||3000 mRT||No tests|
Seismic coverage over the Release Areas (Figure 7 [PDF, 870KB]) ranges from excellent to poor, and comprises a mixture of vintages ranging from the 1970s through to recently acquired data. Between 1967 and 1977, Shell Development Australia Pty Ltd acquired over 14500 km line-km of seismic data across the Ceduna Sub-basin, while at about the same time the Bureau of Mineral Resources (BMR, now GA) acquired approximately 15000 line-km of 2D data across the Bight Basin. Most of these older surveys have line spacings of between 5 and 25 km. Two deep seismic (16 seconds TWT) transects across the Great Australian Bight, together with deep seismic data across the South Australian Abyssal Plain and Recherche Sub-basin, were acquired by the Australian Geological Survey Organisation (AGSO, now GA) in 1997. Seismic Australia (now Fugro Multi Client Services), in joint venture with AGSO, acquired 8500 line-km of regional seismic data across the Ceduna Sub-basin during 1998-99 (HRGAB and DWGAB surveys). Line spacings for these seismic surveys range from approximately 10 to 40 km. More recently, Woodside Energy Ltd acquired the Flinders 2D Seismic Survey (2001) and Trim 3D Seismic Survey (2006). The Flinders 2D Seismic Survey comprises 15636 line-km of closely spaced 2D seismic data with magnetics and gravity data recorded concurrently. The seismic grid ranges from 4 x 4 km in the west to 4 x 8 km in the northern and eastern portions of the survey area. The Trim 3D Seismic Survey acquired 1250 km2 of seismic data in the former permit EPP 29. This survey overlies the northern portions of Release Areas S09-4 and S09-5 (Figure 7 [PDF, 870KB]).
Many of the earlier seismic datasets were reprocessed by Fugro Multi Client Services in 1999 and 2004 and a new data product comprising reprocessed seismic, new potential field data and satellite SAR seep data over the Ceduna Sub-basin is also currently available.
A full listing of the seismic is available in the Ceduna Sub-basin Data Listing [XLS, 326KB].
Additional publications, reports and data covering the Release Areas and broader Bight Basin are available from GA and Primary Industries and Resources SA (PIRSA). Data and analyses include gravity, magnetics and bathymetry grids, depth-time functions, results of SAR and ALF seepage surveys, company reports and related publications.
For more information: