Regional Geology of the Bight Basin

Regional geology of the bightbasin

basin outline

The Jurassic–CretaceousBightBasin is a large, mainly offshore basin situated along the western and central parts of the continental margin of southern Australia, in water depths of less than 200m to over 4,000m. The basin extends from south of CapeLeeuwin in the west to south of Kangaroo Island in the east, where it adjoins the OtwayBasin (Bradshaw et al, 2003; Figure1). To the south, the uppermost sequences of the BightBasin onlap highly extended continental crust and rocks of the continent–ocean transition on the abyssal plain between Australia and Antarctica (Sayers et al, 2001). The BightBasin is overlain unconformably by the dominantly cool-water carbonates of the CenozoicEuclaBasin. The basin contains five main depocentres—the Ceduna, Duntroon, Eyre, Bremer and Recherche sub-basins (Figure1 and Figure2). To the north and east of the main depocentres, a thin BightBasin succession overlies Proterozoic basement (including the Gawler Craton and Albany-Fraser Orogen) and deformed Proterozoic–lower Paleozoic rocks of the Adelaide Fold and Thrust Belt (AFTB) (Figure2). Basement trends have had a profound influence on the structural development of the BightBasin, controlling the location and orientation of early basin-forming structures (Stagg et al, 1990; Totterdell et al, 2000; Teasdale et al, 2003; Totterdell and Bradshaw, 2004).

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basin evolution and tectonic development

The BightBasin is one of a series of Mesozoic to Cenozoic depocentres that developed along Australia’s southern margin during the breakup of eastern Gondwana (Fraser and Tilbury, 1979; Bein and Taylor, 1981; Willcox and Stagg, 1990; Stagg et al, 1990; Hill, 1995; Totterdell et al, 2000; Norvick and Smith, 2001; Teasdale et al, 2003; Totterdell and Bradshaw, 2004). The basin evolved through repeated episodes of extension and thermal subsidence leading up to, and following, the commencement of sea-floor spreading between Australia and Antarctica (Totterdell and Bradshaw, 2004). The tectonostratigraphic development of the basin can be described in terms of four basin phases that reflect those different tectonic drivers (Figure3; Totterdell et al, 2000). Deposition in the basin took place during a global, first order, transgressive-regressive cycle, as shown on the sea-level curve in Figure3.

Mid-Jurassic–Lower Cretaceous extension and post-rift subsidence

The BightBasin was initiated during a period of Middle–Upper Jurassic to Lower Cretaceous upper crustal extension (Figure3). At this time a convergent margin existed on the eastern side of the continent. Incipient rifts were developing between Australia and Antarctica, India and Antarctica, and India and Western Australia, the extensional systems forming a triple junction (Norvick and Smith, 2001). Rifting along this system eventually resulted in sea-floor spreading between India and Australia/Antarctica, but the rift along the southern margin failed at that time. In the Bight Basin, a northwest-southeast to north-northwest–south-southeast extension direction, superimposed on east–west and northwest–southeast-oriented basement structures, resulted in oblique to strongly oblique extension and the formation of en-echelonhalf graben in the Bremer (Figure4), Eyre (Figure5), inner Recherche, Ceduna (Figure6 and Figure7) and Duntroon (Figure8) sub-basins. The location of the major rift fault systems is shown in Figure2. The areal extent of the early extensional structures beneath the CedunaSub-basin cannot be determined due to the thickness and nature of the sedimentary section. The anomalously thick nature of the sub-basin may indicate, however, that Jurassic–Lower Cretaceous rifts are present at depth.

The Early Cretaceous was characterised by post-rift thermal subsidence in the BightBasin (Figure3). By the mid-Cretaceous, open ocean lay to the west and a seaway extended along the margin to the eastern BightBasinarea. The rocks deposited during the initial extensional phase and the subsequent period of thermal subsidence were largely non-marine, with some marine influence becoming evident late in this phase, in wells located on the inboard margins of the basin.

Mid Cretaceous accelerated subsidence

An abrupt increase in subsidence rate in the mid-Albian (Totterdell et al, 2000; Totterdell and Bradshaw, 2004) signalled the start of the third basin phase (Figure3). This period of accelerated subsidence, which continued until the commencement of sea-floor spreading between Australia and Antarctica in the late Santonian, coincided with a period of rising global sea level (Figure3). This combination of factors resulted in a high rate of creation of accommodation, the first major marine flooding event in the basin and the widespread deposition of marine silts and shales of the Albian–Cenomanian Blue Whale Supersequence. Progradation of deltaic sediments into a narrow seaway (White Pointer Supersequence) commenced in the Cenomanian. Rapid deposition resulted in a short-lived period of shale mobilisation and growth faulting throughout the northern half of the CedunaSub-basin (Figure2, Figure6 and Figure7). The Cenomanian deltaic facies include a broad band of coaly sediments in the inner part of CedunaSub-basin. The White Pointer Supersequence is overlain by the marginal marine, deltaic and open marine sediments of the Turonian–Santonian Tiger Supersequence. In wells, the Tiger Supersequence is dominated by mudstones and a few thick sandstone units, while in seismic sections, it has a largely flat-lying, aggradational character.

Australian–Antarctic sea-floor spreading and post-breakup subsidence

The commencement of ultra-slow to very slow sea-floor spreading in the latest Santonian was followed by a period of thermal subsidence and the establishment of the southern Australian passive margin (Figure3). This phase is represented by the latest Santonian–Maastrichtian Hammerhead Supersequence, a sand-rich deltaic system characterised by strongly prograding stratal geometries (Figure6 and Figure7). Because of the slow rate of sea-floor spreading, the seaway into which the deltas prograded would have been relatively narrow. A dramatic reduction in sediment supply at the end of the Cretaceous saw the abandonment of deltaic deposition. Regional uplift resulted in the erosion of the Hammerhead Supersequence, and much of the underlying Tiger Supersequence from the EyreSub-basin (Figure5), and the progressive erosion of the Cretaceous section across the Madura Shelf (Figure7).

From the late Paleocene to present, the largely cool-water carbonates of the EuclaBasin accumulated on a sediment-starved passive margin. In the middle Eocene (around 45Ma) there was a dramatic increase in the rate of spreading (Tikku and Cande, 1999), which resulted in widespread subsidence of the margin.

regional hydrocarbon potential

The thick sedimentary succession in the Bight Basin and its evolution from local half-graben depocentres during the Jurassic, to an extensive sag basin in the Early Cretaceous and passive margin during the Late Cretaceous to Holocene, implies that there is significant potential for the presence of multiple petroleum systems.

Regional Petroleum Systems

Source Rocks

In the eastern Bight Basin depocentres (Ceduna, Eyre and Duntroon sub-basins), regional sequence stratigraphic analysis suggests the presence of at least eight potential source rock units at different stratigraphic levels(Blevin et al, 2000;Totterdell et al, 2000; Struckmeyer el al, 2001). These include Upper Jurassic syn-rift lacustrine shale, Lower Cretaceous fluvial and lacustrine deposits, Aptian–Albian marginal marine to coastal plain mudstone and coal, Albian–Cenomanian and Turonian–Santonian marine shale, Cenomanian deltaic and shallow marine shale and coal, and Santonian–Campanian prodelta shales (Figure3).

While the Jurassic–Lower Cretaceous non-marine source rocksare important in the shallower, more proximal parts of the basin, the key to the petroleum prospectivity of the region resides in Upper Cretaceous marine and deltaic facies. Recent dredging of upper Cenomanian–Turonian organic-rich marine rocks has confirmed the presence of high quality source rocks in the basin and has significantly reduced exploration risk.

In the BremerSub-basin, where no drilling has taken place, understanding of potential petroleum systems is derived from regional seismic interpretation and analysis of targeted dredge sampling. There, the best potential source rocks are interpreted to occur in Upper Jurassic–Lower Cretaceouslacustrine and fluvialstrata.

Reservoirs and Seals

In the CedunaSub-basin, excellent reservoir rocks and potential intraformational seals are present in the Upper Cretaceous deltaic successions, and regional seals could be provided by Upper Cretaceous marine shales. Upper Cretaceous potential reservoir rocks could be of importance in the proximal parts of the basin, however, seal is a risk in this area of the basin. Interpretation of seismic data illustrate numerous play types in the basin and some structures show amplitude anomalies, providing many exploration targets. In the shallower half-graben systems of the Bremer, Eyre and Duntroon sub-basins, prospective targets are Upper Jurassic–Lower Cretaceous sandstones overlain by thick, dominantly lacustrine mudstone successions.

Timing of Generation

Petroleum systems modelling (Totterdell et al, 2008; Struckmeyer, 2009)suggests that generation and expulsion from the upper Cenomanian–lower Turonian potential source rocks in the Ceduna Sub-basin commenced in the Turonian, however the bulk of expulsion occurred during the mid-Campanian to Holocene, after structuring related to breakup. As a result, potentially significant accumulations of both liquid and gaseous hydrocarbons are modelled to be present within sandstones of the Turonian–Santonian Tiger and/or uppermost Santonian–Maastrichtian Hammerhead supersequences (Struckmeyer, 2009). Sediment loading of the Upper Cretaceous succession and, in particular, the Hammerhead supersequence, was the critical event in the maturation of successively younger systems.

Generation and expulsion from potential Jurassic source rocks occurred during the Early Cretaceous in most of the CedunaSub-basin, however, on the inboard flanks of the sub-basin where the overburden is less than about 3,000–4,000m, expulsion is likely to have occurred during the late Early to Late Cretaceous. Regional petroleum systems modelling suggests that expulsion from the overlying Lower Cretaceous source rocks would have occurred from the Albian to Turonian. Some of the early generated and expelled hydrocarbons are likely to have been lost during major structuring related to breakup.

In the DuntroonSub-basin, expulsion from Upper Jurassic–Lower Cretaceous potential source rocks is likely to have largely occurred in the Late Cretaceous, following the major phase of structuring prior to breakup (Smith and Donaldson, 1995).

Burial history modelling indicates that in the EyreSub-basin, the early rift section in the deepest half-graben entered the oil window in the latest Cretaceous. The presence of an active petroleum system is supported by the identification of a breached accumulation at Jerboa1 in the Eyre Sub-basin, based on the presence ofGrains with Oil Inclusions (GOI™) anomalies in the basal reservoir units (Ruble et al, 2001).

In the BremerSub-basin, appropriate maturities for hydrocarbon generation are likely in the main basin depocentres where sediments have been buried to depths of over three kilometres. Burial history modelling has shown that for the oldest predicted source rocks (Jurassic lacustrine facies) the major phase of oil and gas expulsion occurred during rapid burial in the Tithonian–Valanginian. Generation and expulsion from overlying Lower Cretaceous fluvio-lacustrine shale and coal is modelled to have occurred from the Berriasian to Turonian (Ryan et al, 2005).

Play Types

The Bight Basin contains a broad range of structural and stratigraphic plays (Totterdell et al, 2000; Tapley et al, 2005). In the CedunaSub-basin the main plays are associated with faults in the post-Albian section (Figure6 and Figure7), including hanging wall and footwall traps with rollovers or dip closures. Inner basin plays are mostly fault-related traps with targets in Cenomanian to Santonian reservoirs, charged laterally and vertically from Turonian and older sources. Outer basin plays are mostly fault related traps with targets in Campanian deltaic reservoirs, charged by either Cenomanian–Turonian and older marine shales, Cenomanian coal or Santonian–Campanian pro-delta shales. Stratigraphic plays, particularly within progradational Upper Cretaceous deltaic facies of the Hammerhead Supersequence are also potentially important. In the Duntroon Sub-basin, key plays relate to Hammerhead and Wobbegong supersequence reservoirs sealed by thick transgressive marls at the base of the Dugong Supersequence, and intraformational plays within the dominantly fine-grained Lower Cretaceous section.In the Bremer and Eyre sub-basins, as well as along the northern and eastern flanks of the Ceduna Sub-basin, the key plays are structural closures related to half-graben bounding faults and associated stratigraphic plays.

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exploration history

Petroleum exploration in the Bight Basin has occurred in three major cycles – the late 1960s to early 1970s, the early 1990s, and 2000-present (see O’Neil, 2003). In nearly 50 years of explorationin the offshore BightBasin, approximately 100,000line-km of seismic data have been acquired and only 10 petroleum exploration wells have been drilled (Figure9). With the exception of Gnarlyknots1/1A, all wells have been drilled in relatively shallow water near the basin margin and the deeper part of the sub-basin remains largely untested. There have been no hydrocarbon discoveries in the BightBasin and the area remains an exploration frontier. Recently, exploration activity in the BightBasin has increased and there are currently exploration permits in the BremerSub-basin(Enovation Petroleum and Cathay Petroleum), the central CedunaSub-basin (BP Exploration), and the eastern Ceduna–Duntroon sub-basins (Bight Petroleum; Figure10).

During the 1960s and 1970s, exploration was carried out by Shell Development (Australia) (Shell) and Outback Oil. Seismic, shipboard magnetic and aeromagnetic data were acquired. Several prospects were developed from these activities and three exploration wells were drilled; Echidna1 and Platypus1 in 1972 and Potoroo1 in1975. By 1977, Shell had surrendered all of its BightBasin exploration petroleum permits. The early 1980s was a period of relatively lacklustre exploration in the central CedunaSub-basin, with exploration efforts concentrating on shallower, flanking depocentres. Outback Oil and BP undertook exploration in the Duntroon Sub-basin, resulting in the drilling of Duntroon1, while Esso Exploration and Production Australia (Esso), in joint venture with Hematite Petroleum (Hematite), focused their exploration efforts on the Eyre Sub-basin, acquiring seismic and drillingJerboa1.

In early 1990, BP flew an Airborne Laser Fluorosensor (ALF) survey that covered the inboard BightBasin.The initial results were poor, but reprocessing and reinterpretation of the data resulted in the identification of 941 confident fluors(Cowley, 2001). In 1991,BHP Petroleum (Australia) (BHP) commenced an exploration program focusing onthe eastern Ceduna and Duntroon sub-basins, east of the current Release Areas. BHP drilled three wells in 1993—Borda1 and Greenly1(CedunaSub-basin), andVivonne1(DuntroonSub-basin). Although all were plugged and abandoned, their results vastly improved knowledge of the basin succession, and gas shows andoil indications in Greenly1 provided some exploration encouragement.

The latest phase of petroleum exploration commenced in 2000 when three petroleum exploration permits were awarded to a joint venture comprising Woodside Energy (operator), Anadarko Australia and PanCanadian Petroleum (now EnCana). The permits, EPP28, EPP29 and EPP30, covered the majority of the current Release Areas. The joint venture acquired a large quantity of 2Dseismic data and drilled an exploration well, Gnarlyknots1/1A. In early 2006, 1,250km2 of 3Dseismic data (Trim 3DSeismic Survey) were acquired over EPP29, however, in 2007 Woodside surrendered its permits. Also during this period, permits were held in the eastern BightBasin (DuntroonSub-basin and adjacent portion of the CedunaSub-basin) by the Woodside-Anadarko-EnCana joint venture and Santos Offshore. Approximately 2,300km of seismic data were acquired during the exploration programs in these permits, which were both surrendered in 2007.

In 2009, six areas in the central CedunaSub-basin were released for bidding, followed in 2010 by the release of two exploration areas in the eastern Ceduna–Duntroon sub-basin. In January 2011, BP Exploration was awarded 4 permits (EPP37–40) in the central CedunaSub-basin. The guaranteed work program for the permits includes 4 exploration wells and ~12,000km2 of 3Dseismic data. In June 2011, Bight Petroleum was awarded the two Ceduna-Duntroon permits (EPP41 and42); the 3-year work program includes one well.

Geoscience Australia (GA) and its predecessor agencies have a long history of research in the BightBasin, particularly in the eastern part, conducting several gravity and magnetic surveys and acquiring over 28,000line-km of regional 2D seismic data. GA’s 2007 Bight Basin Geological and Sampling Survey (Totterdell et al, 2008; Totterdell and Mitchell, 2009), targeted and sampled potential source rocks of late Cenomanian to early Turonian agefrom the northwestern edge of the Ceduna Sub-basin. The discovery of these potential source rocks underpinned the 2009 acreage release.

The BremerSub-basin, in the far western part of the basin, is a frontier region in which no wells have been drilled. The western BightBasinhas seen two phases of exploration, in the early 1970s and during the past 5 years. Initial exploration in the area was undertaken by Esso Australia Limited and Continental Oil Company between 1972 and 1974. During this time, seismic and aeromagnetic data were acquired across the BremerSub-basin and shelfal areas to the east. Esso identified some large structures in the BremerSub-basin, but no further work was undertaken.From 2003–2005 Geoscience Australia undertook a petroleum prospectivity study of the BremerSub-basin, acquiring seismic data and dredge sampling (Bradshaw, 2005). These data underpinned the release of exploration areas in 2005. Two permits (WA-279-P and WA-280-P) were initially awarded to Plectrum Petroleum, but in 2008 the permit titles were transferred to a joint venture comprising ArcadiaPetroleum and Enovation (now Cathay Petroleum). In 2009–10, the joint venture acquired over 4,000km of 2Dseismic data.

Figures

References

BEIN, J. AND TAYLOR, M.L., 1981—The Eyre Sub-basin: recent exploration results. The APEA Journal, 21(1), 91–98.