The Gippsland Basin is a Cretaceous-Neogene hydrocarbon province that hosts Australia’s largest oil and gas fields which have been in production since the late 1960s. Despite its mature status, much of the southern and eastern parts of the basin remain underexplored and offer a variety of untested plays.
The Gippsland Basin in southeastern Australia is located about 200 km east of the city of Melbourne. Covering about 46 000 km2, two-thirds of the basin is located offshore where several giant oil and gas fields were discovered in the late 1960s (Figure 1). The basin was developed into Australia’s premier hydrocarbon province, maintaining that status until large scale hydrocarbon production on the North West Shelf was established in the 1990s. Most of the hydrocarbon accumulations in the Gippsland Basin are hosted by the Upper Cretaceous to Paleogene Latrobe Group, a sedimentary system that is dominated by marginal marine to lower coastal plain depositional environments. Remaining reserves are estimated at 400 MMbbl (6.4 GL) of liquids and 5 Tcf (141.6 Gm3) of gas (Geoscience Australia, 2012).
The Gippsland Basin is bounded to the north by Paleozoic basement of the Eastern Uplands, to the west by uplifted Lower Cretaceous fault-blocks and to the southwest by the Bassian Rise, a Paleozoic basement feature which separates it from the Bass Basin to the southwest. More than 400 exploration wells have been drilled in the basin and approximately 90 000 line km of 2D seismic data and more than forty 3D seismic surveys have been acquired. Consequently, exploration within the Gippsland Basin is mature in comparison to many other Australian basins, but it remains relatively underexplored in the southern and eastern offshore areas, in particular around the Bass Canyon. (Figure 1).
The Gippsland Basin region contains a number of significant regional population centres and is serviced by an extensive road system. Petroleum infrastructure is well developed, with a network of pipelines transporting hydrocarbons produced offshore to onshore petroleum processing facilities at Longford and Orbost (Figure 2). From there, pipelines deliver the gas across southeastern Australia, to Sydney in New South Wales, to Adelaide in South Australia and to Tasmania. Although recent industry activity in the Gippsland Basin has been dominated by field developments and field extensions, exploration for both oil and gas is expected to continue due to the basin’s probable untapped potential and the increasing demand for natural gas across southeastern Australia.
The Gippsland Basin formed as a consequence of the break-up of Gondwana in the latest Jurassic/earliest Cretaceous (Rahmanian et al, 1990; Willcox et al, 1992, 2001; Norvick and Smith, 2001; Norvick et al, 2001) and the basin evolution is recorded by dominantly siliciclastic sedimentary sequences from the Upper Cretaceous to Eocene and by carbonate sequences from the lower Oligocene to Holocene. Within the Latrobe Group, four subgroups are defined, each of which is bounded by presumed basin-wide unconformities, and each consists of formations that are distinguished according to their main depositional facies assemblages (Figure 3 and Figure 4). Other unconformities and disconformities are only recognised biostratigraphically. This is of particular relevance in the context of the upper Latrobe Group, where extensive channel incision and subsequent infill processes resulted in complex sedimentary sequences that developed over slightly different time frames, which cannot be resolved by seismic mapping alone. The tectonostratigraphic development of the Gippsland Basin is summarised by Wong et al (2001) and Blevin and Cathro (2008).
The Gippsland Basin forms the easternmost part of an Early Cretaceous rift system between Antarctica and Australia. Initial basin architecture consisted of a rift valley complex composed of multiple, overlapping or isolated, approximately east-trending half graben. Continued rifting into the Late Cretaceous generated a broader extensional geometry which consisted of a depocentre (the Central Deep) flanked by fault-bounded platforms and terraces to the north and south (Figure 5). The Rosedale and Lake Wellington fault systems marked the northern margins of the Central Deep and Northern Terrace respectively, with the Darriman and Foster fault systems defining the southern margin of the Central Deep, and the northern boundary of the Southern Platform (Figure 1), respectively. The Pisces Sub-basin has recently been re-interpreted as a series of NE-trending en-echelon half graben that cut across the easternmost margin of the Southern Platform. The extensional faults were reactivated prior to breakup in the Tasman Sea off the Gippsland Basin (Blevin et al, 2013). To the east, the Central Deep is characterised by rapidly increasing water depths; these exceed 3000 m in the Bass Canyon (Hill et al, 1998). The eastern boundary of the basin is defined by the Cape Everard Fault System, a prominent north-northeast striking basement high (Moore and Wong, 2001). The western onshore extent of the basin is traditionally placed at the Mornington High. However, the extent of the Latrobe Group is effectively defined by outcrops of the underlying Lower Cretaceous Strzelecki Group (Hocking, 1988).
Initial rifting in the Early Cretaceous resulted in total crustal extension of approximately 30% (Power et al, 2001), producing a complex system of graben and half graben into which the volcaniclastic Strzelecki Group was deposited (Figure 3 and Figure 4). Between 100 and 95 Ma (Cenomanian), a phase of uplift and compression (Duddy and Green, 1992), produced a new basin configuration and provided accommodation space for large volumes of basement-derived sediments. Renewed crustal extension during the Late Cretaceous, perhaps associated with both Turonian extension between Australia and Antarctica evident in the Otway Basin to the west, and opening of the Tasman Sea to the east, established the Central Deep as the main depocentre (Figure 1). Initial deposition (Emperor Subgroup) into the evolving rift valley was dominated by large volumes of material that were eroded from the uplifted basin margins. A series of large, deep lakes developed, resulting in the deposition of the lacustrine Kipper Shale (Marshall and Partridge, 1986; Marshall, 1989; Lowry and Longley, 1991). The Kersop Arkose represents the earliest erosion of uplifted granites at the southern basin margin, and the alluvial/fluvial Curlip Formation (Partridge, 1999; Bernecker and Partridge, 2001) overlies and interfingers with the Kipper Shale.
The Longtom Unconformity (Figure 3 and Figure 4) separates the freshwater lacustrine dominated Emperor Subgroup from fluvial and marine sediments of the Golden Beach Subgroup, with the first marine incursion recorded by the upper Santonian sediments of the Anemone Formation (Golden Beach Subgroup) in the eastern part of the basin (Partridge, 1999; Bernecker and Partridge, 2001). Many of the earlier generated faults were reactivated during this tectonic phase, and it is likely that the change in depositional environment was related to the onset of the Tasman Sea rifting.
Rift-related extensional tectonism continued until the early Eocene and produced pervasive northwest-striking normal faults, especially in the Central Deep. A succession of fluvial, deltaic and marine sediments was deposited across the basin forming the Halibut Subgroup (Figure 3). This subgroup comprises upper coastal plain fluvial sediments (Barracouta Formation) and lower coastal plain, coal-rich sediments of the Volador and Kingfish formations. The marine Kate Shale separates the Cretaceous Volador Formation from the Paleocene Kingfish Formation, and has the potential to be a significant intra-Latrobe Group seal. The Mackerel Formation overlies the Kate Shale in the eastern part of the basin (Figure 4) and consists of near-shore marine sandstones with intercalated marine shales. The formation marks the increasingly marine influence on sedimentation in the eastern part of the Central Deep.
By the middle Eocene, sea-floor spreading had ceased in the Tasman Sea and there was a period of basin sag, during which the offshore basin deepened but little faulting occurred. The lower coastal plain, coal-rich Burong Formation was deposited during this phase, followed by the transgressive shallow to open marine Gurnard Formation, which is a condensed section characterised by fine- to medium-grained glauconitic siliciclastic sediments (Figure 3 and Figure 4).
In the late Eocene, a compressional period began to affect the Gippsland Basin, initiating the formation of a series of northeast to east-northeast-trending anticlines (Smith, 1988). Compression and structural growth peaked in the middle Miocene and resulted in partial basin inversion. All the major fold structures at the top of the Latrobe Group, which became the hosts for the large oil and gas accumulations, such as Barracouta, Tuna, Kingfish, Snapper and Halibut, are related to this tectonic episode. Tectonism continued to affect the basin during the late Pliocene to Pleistocene, as documented by localised uplift. Uplift affected the Pliocene section on the Barracouta, Snapper and Marlin anticlines, as well as around the township of Lakes Entrance. Ongoing tectonic activity continues in the basin as relatively minor earthquakes which occur along and around major basin bounding faults to the present day.
Post-rift sedimentary processes dominated the Gippsland Basin from the early Oligocene, with the deposition of the basal unit of the Seaspray Group, the Lakes Entrance Formation (Figure 3 and Figure 4). These onlapping, marly sediments provide the principal regional seal across the basin. Subsequently, the deposition of the thick Gippsland Limestone, also part of the Seaspray Group, provided the critical loading for the source rocks of the deeper Latrobe and Strzelecki groups, with the majority of hydrocarbon generation (or certainly the preserved component) occurring in the Neogene.
Late loading of the source rocks as a result of the deposition of relatively thick Cenozoic sequences, means that traps developed during the Neogene can be charged with economic quantities of hydrocarbons.
Despite its relatively small areal extent, the Gippsland Basin hosts numerous economic hydrocarbon accumulations, including a number of oil and gas fields that are considered ‘giants’ by global standards. All currently producing fields are located on the western and northern parts of the present shelf; only four discoveries (Archer/Anemone, Angler, Blackback and Gudgeon) have been made in the eastern, deeper water area (Figure 1 and Figure 2).
It has been a matter of speculation as to why there is a concentration of gas accumulations in the north, whereas oil fields are more common in the southeast (Figure 6). The reasons for this may be due in part to the initial focus on top-Latrobe Group plays, which has resulted in numerous discoveries in sediments from the N. asperus and P. asperopolus biozones. The Latrobe Group is thickest in the Central Deep, where prospective reservoirs are located below 3500 mSS (approx. 2.5 seconds TWT) and it is thus not surprising that less is known about the prospectivity of older sediments.
Another explanation for the distribution of oil and gas in the Gippsland Basin is the nature of the Latrobe Group source systems themselves. The upper coastal plain Latrobe Group depocentres, located between Barracouta and Kingfish, may have produced a mostly gas-prone hydrocarbon inventory, whereas the lower coastal depocentres east of Kingfish would probably be more oil-prone, as originally suggested by Moore et al (1992).
The strong spatial compartmentalisation of the hydrocarbon inventory is discussed in detail by O’Brien et al (2008). Analyses of palaeo-charge histories, source rock characteristics and basin modelling indicate that the majority of large fields in the Central Deep received an early oil charge and had significant palaeo-oil columns in the Neogene. These were subsequently displaced by a later gas charge triggered by increased maturation and gas expulsion from a gas-prone upper coastal plain source kitchen south of Barracouta (O’Brien et al, 2008; Liu et al, 2010).
The most recent attempt at explaining the apparent separation of oil and gas fields in the basin was put forward by Hoffman and Preston (2014). Their study, examining hydrocarbon geochemistry, charge and migration histories, draws attention to hydrocarbon modification processes, such as water washing and biodegradation, that operated after the initial hydrocarbon charge and produced different reservoir fill patterns across the basin.
Oils of the Gippsland Basin are derived from the Jurassic to Cenozoic Austral Supersystem sequences (Bradshaw, 1993), and are likely to be predominantly derived from coals and carbonaceous shales of the Latrobe Group (Summons et al, 2002). Within this supersystem, the Austral 3 Petroleum System is attributed to have sourced the majority of hydrocarbons (including all producing fields) reservoired within the Latrobe Group (O’Brien et al, 2008; Tingate et al, 2011). Recent work has differentiated the oils in the Gippsland Basin into two main oil families (Summons et al, 2002; Volk et al, 2010, 2011); both are believed to originate largely from the Latrobe Group (Austral 3 Petroleum System). Marine source rocks within the Anemone Formation (Latrobe Group) may also contribute additional hydrocarbons (Gorter, 2001), adding more complexity to this petroleum system. In addition, hydrocarbons sourced from the Strzelecki Group and attributed to the Austral 2 Petroleum System are also being invoked to explain the origin of some accumulations along the northern margin and in the onshore part of the basin (O’Brien et al, 2008).
Only a few wells have penetrated the oil- or gas-mature section of the deeper Halibut and the Golden Beach subgroups and hence the distributions of the main source rock units and source rock kitchens are not fully understood. It is generally considered that the source rocks for both the oil and gas in the basin are represented by organic-rich, non-marine, coastal plain mudstones and coals (Burns et al, 1984, 1987; Moore et al, 1992). Source rocks of dominantly terrestrial plant origin (Type II/III kerogen) are widely distributed throughout the Latrobe Group and generally exhibit high TOC values (>2.0%), high Rock-Eval pyrolysis yields and moderate to high hydrogen indices (>250 mgHC/gTOC), suggesting that they have the potential to generate both oil and gas. The richest Latrobe Group source rocks (mainly humic to mixed organic matter types) occur within lower coastal plain and coal swamp facies. Well correlations show that much of the T. lilliei biozone (within the Golden Beach Sub-group) is represented by low energy, lagoonal/paludal sediments in the east-southeast. This facies extends beneath the giant Kingfish oil field and across the basin to the north. In the Central Deep, T. lilliei sediments accumulated in a marine environment as interbedded sandstones and marine shales (Rahmanian et al, 1990; Moore et al, 1992; Chiupka et al, 1997). Data from Hermes 1, located in the southern part of the basin, proves the existence of a thick, rich source rock unit at this level. The >950 m T.lilliei section within this well has TOC values that generally exceed 10% (Petrofina Exploration Australia S.A., 1993).
A study of condensate recovered from the Archer/Anemone discovery in the southeastern part of the basin, suggests that source rock potential may also exist within marine sediments (Gorter, 2001; Partridge, 2003). The most likely source rocks are the marine shales of the Anemone Formation, Golden Beach Subgroup. Recently, Partridge (2012) analysed seven cuttings samples from the type section of the Anemone Formation at Anemone 1, 1A and confirmed the presence of common to abundant marine microplankton. Other work also suggests that the Strzelecki Group sediments within the onshore and offshore Gippsland Basin have the potential to generate significant quantities of dry gas (O’Brien et al, 2008). Fair to good quality Strzelecki Group source rocks have been intersected in a number of wells, including Wellington Park 1 and Dutson Downs 1 onshore, and Wirrah 1, 2 and 3 offshore. Overall, the Strzelecki Group appears to have a broadly similar source rock quality to its temporal equivalent, the proven gas-generating, Albian–Aptian Eumeralla Formation in the Otway Basin.
The work by O’Brien et al (2008) indicates that the gas reservoired in onshore Gippsland Basin fields such as Gangell, Seaspray and Wombat was most likely generated from the Strzelecki Group. Similarly, dry gas accumulations located on the Northern Terrace, such as Patricia-Baleen and Sole, may well have a Strzelecki source. If this interpretation is correct, this gas has probably migrated to the top-Latrobe level in the Neogene, following loading by the prograding carbonate shelf. It may be that these ‘Strzelecki-sourced’ gases are present around the basin margins (and not in the Central Deep) because they are actually able to migrate up to the top-Latrobe level through the Latrobe Group shales which are thin or absent, something that would be impossible through the very thick Latrobe shales within the Central Deep.
If the validity of the Strzelecki Group as a working source is confirmed, then traps which are remote from the mature Central Deep Latrobe Group source, such as those located either in the Seaspray depression and on the Northern Terrace or Northern Platform, or in Latrobe migration shadows, can still be charged with relatively dry gas, providing that the local, mature Strzelecki Group source generated hydrocarbons in the Neogene.
Reservoirs and seals
Most of the major hydrocarbon accumulations in the Gippsland Basin are reservoired in high quality sandstones of the Cobia and Halibut subgroups, where marine near-shore barrier and shoreface sandstones are traditionally regarded as the best reservoirs in the basin. The most productive of these were drilled either at or near the top of the Latrobe Group and are commonly referred to as the ‘top-Latrobe coarse clastics reservoirs’. This can be confusing, given that similar coarse sandstones are developed throughout the stratigraphic column. All these sandstones are diachronous and developed in response to periodic marine regressive cycles associated with low depositional rates. This provided an ideal environment for high levels of reworking and winnowing of the deltaic and coastal plain sediments. Geographically, this reservoir facies is best developed in the Barracouta, Snapper, Marlin, Bream and Kingfish fields. Reservoir distribution in intra-Latrobe sequences can be complex and frequently involves multiple stacked sandstone/shale alternations characteristic of fluvio-deltaic environments. Submarine channelling, the presence of numerous, thin, condensed sequences and the overall lower net-to-gross ratio contribute to lower reservoir qualities. Nevertheless, there are many examples of good quality reservoirs in deltaic sandstones, as well as in fluvial and submarine channels. Latrobe Group reservoir porosities average 15–25% across the basin, with the best primary porosities preserved in fluvial/ deltaic sandstones that are texturally mature and moderately well sorted.
In contrast to the Latrobe Group, the identification of permeable reservoirs within the Strzelecki Group has proven difficult, though primary porosities can be high. Unless an improved model for the prediction of permeability within the Strzelecki Group sands can be developed, such targets are inherently high-risk.
An effective regional seal for the top-Latrobe Group reservoirs is provided by calcareous shales and marls of the lower Oligocene–lower Miocene Lakes Entrance Formation at the base of the Seaspray Group (Bernecker and Partridge, 2001; Partridge et al, 2013). In the eastern part of the basin, the lowermost Seaspray Group is represented by a condensed section of calcareous shales, termed the ‘Early Oligocene Wedge’ (EOW) by Partridge (1999). The Oligocene–Miocene marine carbonates which comprise the EOW and the upper Oligocene to Miocene Swordfish Formation (Seaspray Group) are now recognised as lateral equivalents of the Lakes Entrance Formation (Blevin and Cathro, 2008; Goldie Divko et al, 2010; Blevin et al, 2013).
The thickness of this seal varies considerably and ranges from approximately 100 m to over 300 m in deeper water parts of the basin (O’Brien et al, 2008). In addition, many potential intraformational sealing units are present within the Latrobe Group. These include floodplain sediments deposited in upper and lower coastal plain environments, as well as lagoonal to offshore marine shales. These seals are commonly thin and mostly occur within stacked sandstone/mudstone successions; the low shale volume in such settings makes the prediction of cross-fault seal problematic. Excellent seals, such as the Turonian lacustrine Kipper Shale, are developed adjacent to the basin-bounding faults. Other effective seals are provided by several distinct volcanic horizons of Campanian to Paleocene age (e.g., as in the Kipper Field). The Kipper Shale exceeds 500 m in thickness, whereas the volcanics are often less than 50 m thick, although they are known to exceed 100 m in the Kipper field.
Timing of generation
From limited published data, it is concluded that the main period of hydrocarbon generation and expulsion commenced in the Miocene as a result of increased sedimentary loading of the Cenozoic carbonate sequences (Smith et al, 2000). Some interpretations suggest that hydrocarbon generation and migration is currently at a maximum (Duddy et al, 1997). In the major depocentres of the basin, restricted areas underwent an early phase of generation and migration at or around the middle Eocene. It is important to realise that at that time, no regional Lakes Entrance seal was in place and any traps would have involved older intra-Latrobe Group sealing units and earlier formed traps.
Clark and Thomas (1988) proposed that peak generation and primary migration in the Gippsland Basin occurs at depths of 4–5 km for oil and 5–6 km for gas (O’Brien et al, 2008). Peak hydrocarbon generation within the Latrobe Group source rocks is considered to take place with Ro at 0.92–1.0% (Clark and Thomas, 1988), which agrees well with the findings of Burns et al (1987), whose maturity data (Methylphenanthrene Index of Radke and Welte, 1983) indicated that most Gippsland Basin oils were generated with Ro at 0.9–1.16%. The hydrocarbons reservoired in the western Gippsland Basin have undergone some biodegradation and water washing (Burns et al, 1987) as a result of the invasion of the fresh-water wedge in the late Cenozoic (Kuttan et al, 1986).
During its long exploration history, a large variety of play types have been successfully tested in the Gippsland Basin. The giant oil and gas fields discovered early in the history are all related to large anticlinal closures in the Central Deep at top-Latrobe Group level, where coarse-grained coastal plain and shallow marine barrier sands provide excellent reservoirs (Figure 6). Further top-Latrobe discoveries have been made in increasingly deeper water, including erosional channel plays in the eastern part of the basin such as Blackback, Marlin and Turrum. In these, channel cut and fill sediments are preserved as complex successions of intraformational reservoir and seal facies.
Other top-Latrobe play types are known to exist on the flanks of the basin. On the northern and southern terraces, the Latrobe Group rapidly decreases in thickness and pinches out near the bounding faults of the Northern and Southern platforms. Stratigraphic pinch-out plays have been tested on both the Northern and Southern terraces. Here the top-Latrobe Group is represented in the west by the coal-bearing lower-middle coastal plain sediments of the Burong Formation and in the east by the marine sandy glauconitic mudstones of the Gurnard Formation (Figure 3 and Figure 4). The Gurnard Formation is characterised by facies changes and acts as a seal as well as a reservoir unit on the northern margin where it hosts the Patricia-Baleen gas accumulation (Bernecker et al, 2002). Structural play types are also developed on the basin terraces. The Leatherjacket oil and gas discovery is an example of an inverted normal fault-closure that comprises top- and intra-Latrobe Group reservoir objectives.
Structural plays are dominant within the intra-Halibut Subgroup Group and Golden Beach Subgroup. They commonly involve down-thrown fault traps that comprise intra-Latrobe fluvial reservoirs and intraformational seals. The Basker/Manta/Gummy oil and gas field in the northeastern Central Deep is an example of such a play type. The Golden Beach Subgroup play is restricted to the Central Deep where the main fairway is represented by the Chimaera Formation comprising fluvial and coastal plain sediments sealed by either Campanian volcanics, upthrown shales of the Emperor Subgroup or intraformational mudstones. The play is proven on lowside fault closures at the Kipper gas field (Bernecker et al, 2002).
Recent mapping of the Pisces Sub-basin shows there is a significant thickness of sediment present in the easternmost half graben, which may be prospective for hydrocarbon generation if source facies are present (Blevin et al, 2013). A new play was successfully tested by the Longtom 2 and 3 wells which targeted fluvial units within the Emperor Subgroup. This subgroup is dominated by the Kipper Shale, which can be up to 1000 m thick (Bernecker and Partridge, 2001), but it also comprises underlying and overlying coarse-grained fluvial sediments. The stratigraphic position of the Emperor Subgroup has meant that it has been penetrated by drilling only on the Northern and Southern terraces. However, the recent Longtom gas discovery confirms the viability of this new play type along the flanks of the Central Deep.
Exploration plays in the Strzelecki Group have been identified in the onshore Seaspray Depression. The Seaspray and Wombat gas discoveries, assessed as uncommercial, but under review for a possible tight gas stimulation program, are most likely sourced from Lower Cretaceous coaly floodplain deposits and hosted by fluvial sandstones with moderate to good porosity but low permeability. As such, this configuration resembles the gas discoveries in the coeval Otway Group in the onshore Otway Basin. It has been suggested that the gas in the Sole field on the offshore Northern Terrace is sourced from the Strzelecki Group. If this is the case, then the shallower areas outside the Central Deep may offer additional exploration opportunities.
The history of oil production in the Gippsland Basin dates back to 1924, when the Lake Bunga 1 well, which was drilled near the town of Lakes Entrance, encountered a 13 m oil column in glauconitic conglomerates overlying the Latrobe Unconformity at a depth of 370 m. Over 60 wells were drilled in the ensuing years, and by 1941, this area had produced more than 8000 bbl (1272 KL) of heavy oil (15–20° API). The most productive well was the Lakes Entrance Oil Shaft which produced 4935 bbl (784.5 KL; Beddoes, 1972; Boutakoff, 1964).
Significant levels of exploration did not begin in the offshore Gippsland Basin until the mid-1960s, following the acquisition of seismic surveys which allowed the imaging of the Central Deep and the mapping of several large, anticlinal closures. The first successful well, East Gippsland Shelf 1 – later known as Barracouta 1 – was drilled by Esso in 1964/65 and discovered a 102.5 m gas-condensate column at a depth of 1060 mKB. After the subsequent discovery of a large gas-condensate accumulation at Marlin in 1966, the Gippsland Basin was perceived essentially as a gas-prone province. However, when Kingfish 1 was drilled in 1967, it encountered the largest Australian oil field known to that time (1.2 Bbbl [191 GL] recoverable) and the Gippsland Basin gained international recognition as both a giant oil and giant gas province.
By the end of 1969, eleven fields had been discovered and the first five (Barracouta, Marlin, Snapper, Kingfish and Halibut) were in production. After the initial exploration phase, which had high success rates, the subsequent discoveries made by the Esso/BHP Petroleum joint venture were more limited through the early 1970s; Cobia 1 (1972), Sunfish 1 (1974) and Hapuku 1 (1975) discovered significant volumes of hydrocarbons, but only Cobia came into production. In 1978, following the boost to exploration resulting from the introduction of Import Parity Pricing (i.e. the removal of artificial government pricing caps on locally produced crude oil), the giant Fortescue oil field was discovered, followed by the Seahorse and West Halibut discoveries.
Stimulated by the OPEC world oil price rise in 1979 and the relinquishment of a significant portion of the original exploration permit by Esso/BHP in October that year, new explorers, including Aquitaine, Shell and Phillips, commenced exploration in 1980. Shell, which had previously discovered the Sole dry gas field in 1973, mapped the Basker-Manta structures and drilled two successful wells, Basker 1 and Manta 1. Discoveries which were then deemed non-commercial were made at West Seahorse, Baleen and Sperm Whale by Hudbay Oil in 1981. West Tuna, drilled in 1984, was the last of the large to giant oil discoveries made by the Esso/BHP Petroleum joint venture. This play was atypical, as the oil was trapped by fault sealing mechanisms rather than having accumulated in a large anticlinal closure. In 1986, the Esso/BHP Petroleum joint venture discovered the Kipper gas field - estimated at 500 Bcf (14.2 Bm3) recoverable - a significant find which intersected a 213 m gas column in fluvial sandstones of the Golden Beach Subgroup. Lasmo made a minor, but significant, gas discovery near the northern basin margin at Patricia 1 (adjacent to Baleen) in 1987, with sales gas reserves of the order of 70 Bcf (2 Bm3). This field was developed by OMV and later taken over by Santos Limited. Another drilling campaign in 1989/1990, led to the discovery of the Blackback oil and gas field on the shelf edge, in water depths greater than 400 m. In 1989/90, Petrofina drilled the Archer/Anemone discovery in the southern part of the basin. Although the field proved non-commercial, the well encountered substantial quantities of oil and gas and further confirmed the prospectivity of the older part of the Latrobe Group (Golden Beach Subgroup).
Additional exploration wells were drilled in the 1990s, though no new discoveries were made. The principal operator, the Esso/BHP Petroleum joint venture, concentrated their efforts on development and work-over drilling in order to optimise production from the existing fields. Following the privatisation of State Government-owned gas utility companies between 1995 and 1999, a restructured gas market emerged which made it more attractive for explorers to search for gas in the basin. This, together with a sustained recovery in the oil price, sparked a significant resurgence in exploration activity. In 2010, Esso Australia Pty Ltd announced an oil and gas discovery on the northern margin of the Central Deep; South East Remora 1 intersected significant oil and gas columns in the upper Latrobe Group and Golden Beach Subgroup, with traps associated with the Rosedale Fault (ExxonMobil, 2010).
In the last decade, a number of new companies have been granted exploration licences in the basin and have committed to extensive work programs. Apache Energy entered the basin in 2004 after gaining interest in permits VIC/P54, VIC/P58 and VIC/P59. The company drilled a number of wells in 2008/2009 and acquired new 3D seismic data in VIC/P59 in 2007, but relinquished this permit in early 2012. Nexus Energy has also been active in the Gippsland Basin recently, currently exploring within VIC/P54 and producing gas from the Longtom field. This field was discovered by Nexus Energy in 2006, with the successful drilling of Longtom 3, which intersected a suite of gas-bearing sandstones within the Emperor Subgroup. The well was brought into production in 2009 through two horizontal wells that were tied-back to the processing facility at Orbost which is shared by Santos Limited and Cooper Energy. Santos produces gas from the Patricia-Baleen field at Orbost also and maintains non-operating interests in the Kipper gas field, while Cooper Energy holds 65% interest in the Basker/Manta/Gummy production licences and 50% in the Sole gas field.
Larus Energy Ltd entered the Gippsland Basin in 2011, and operated three exploration permits on the southern margin (VIC/P63 and VIC/P64, and T/46P in Tasmanian waters), until March 2014. Other significant players in the Gippsland Basin are Bass Strait Oil Company Ltd, who operate VIC/P41 on the northern basin margin. The company identified several large volume prospects analogous to the Kipper and Basker/Manta/Gummy fields that lie along strike to the west of this permit. Small independent company 3D Oil was working to develop the West Seahorse oil field within VIC/P57 before it sold its interest to Carnarvon Hibiscus Pty Ltd. First oil production is planned for Q1 2015. The company will also evaluate the Sea Lion prospect to the northwest of West Seahorse.
The latest exploration permit was awarded to Liberty Petroleum in November 2014. Permit VIC/P70 is located southwest of the giant Kingfish oil field and covers the Archer/Anemone and Angler gas discoveries. Liberty will evaluate the resource potential of these accumulations and surrounding areas and is committed to the drilling of two wells in the primary permit term.
On a regional scale, several 3D seismic surveys have been acquired in the last decade, with the result that much of the basin is now covered by 3D seismic data. Esso/BHP Billiton completed two major 3D seismic surveys, including the 4060 km2 Northern Fields survey, between October 2001 and July 2002. This was followed by the 1000 km2 Tuskfish survey which extended over the Blackback-Terakihi area and extended southwards into VIC/P59. In 2001, Encana acquired the Midas 2D seismic/gravity/magnetic survey, which covers ~830 line km across the head of the Bass Canyon, covering some of VIC/P70. A further 150 km of 2D seismic was acquired by Eagle Bay Resources NL across the former permit VIC/P65.
Sizable 3D surveys have also been acquired by Apache Energy and Bass Strait Oil Company Ltd in recent years. Drillsearch also conducted the Furneaux 2D seismic survey in early 2010, covering their permits in the southwestern part of the Gippsland Basin with a total of 1116.7 line km acquired in Victorian waters. This survey was followed by the 8000 line km 2D Gippsland Basin Southern Flanks Marine Survey (GDPI10), co-funded by the State and Commonwealth Governments, acquired over the Southern Terrace and Platform using the same seismic vessel, the M/V Aquila Explorer (SeaBird Exploration). The seismic stratigraphic interpretation report of this survey (Blevin et al, 2013) evaluates the seal potential of the basin’s southern margin.
Recent estimates of the basin’s undiscovered resource potential consider that there is 2–4 Tcf (56.6-113.3 Gm3) of gas and up to 600 MMbbl (95.4 GL) of liquids yet to be discovered in the Gippsland Basin (GeoScience Victoria, unpublished data). Despite its long history of extensive exploration, many parts of the basin, especially the southern and eastern regions, are still relatively poorly understood and explored. In the context of high oil prices and a growing demand for gas in south-eastern Australia, the Gippsland Basin should continue to attract investment from both local and international explorers.
Overall production of crude oil and condensate from the Gippsland Basin has been declining for over three decades, associated with an increased water cut, while gas production has remained steady. In the year 2013, crude oil and condensate production was 16.4 MMbbl (2.6 GL), compared to 19.0 MMbbl (3 GL) in the previous year (APPEA, 2014, 2013). LPG production was steady at around 9.5-9.9 MMbbl (1.5-1.6 GL), and sales gas reached 0.23 Bcf (6.5 MMm3) in 2013. Hydrocarbon production has remained relatively strong due to infill drilling in the developed fields and work-overs undertaken to renew down hole equipment and to open new zones.
Work is currently underway to expand natural gas production from the Tuna field which commenced in 2013 with additional supplies to come from the Kipper and Turrum fields. The Kipper Tuna Turrum project is the largest domestic gas development in eastern Australia and production will help maintain the production levels from the basin which has been producing for over 40 years. Gas from the Kipper field which holds about 620 Bcf (17.6 Bm3) of recoverable gas and from the Turrum filed, holding about 1 Tcf (28.3 Gm3) of gas (ExxonMobil, 2014) is expected to be produced from 2016 onwards.
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