Areas V07-1, V07-2 and V07-3

Gippsland Basin

Basin Geology

The Gippsland Basin, one of Australia’s most prolific oil and gas provinces, is located in southeastern Victoria, about 200 km east of Melbourne, an area well served by roads and population centres (Figure 1). About two thirds of the basin lies offshore in water depths that typically range from 0 to 200 m, although water depths exceed 3000 m in the northwest–southeast-trending Bass Canyon off the continental shelf (Figure 2).

The Gippsland Basin region is well served by roads and has numerous population centres. Petroleum infrastructure is excellent, with a network of pipelines bringing the produced hydrocarbons to the onshore petroleum processing facilities near Longford. A new network of gas pipelines distributes Gippsland Basin gas to customers in Victoria, Tasmania, New South Wales and South Australia. To date, approximately 4 billion barrels (Bbbls) of liquid hydrocarbons have been produced from the offshore Gippsland Basin. Oil production rates peaked in 1985 and have since been in decline (Figure 3). In contrast, gas production has increased steadily and a continuing upward trend, driven by a higher demand for cleaner energy, is anticipated.

It has been acknowledged that the basin’s undiscovered oil and gas potential is considerable and this has led to a renewed exploration drive by both established players and newcomers to the region. The potential for additional gas discoveries will ensure continued interest in the Gippsland Basin, with a particular advantage being the recent reform and deregulation of the gas industry.

Regional geology

The east–west-trending Gippsland Basin was formed as a consequence of Gondwana break-up (Rahmanian et al, 1990; Willcox et al, 1992, 2001; Norvick and Smith 2001; Norvick et al, 2001) and the basin evolution is recorded by several depositional sequences that are Early Cretaceous to Neogene in age.

Basin evolution

The Gippsland Basin’s architecture developed initially during the Early Cretaceous rifting between Antarctica and Australia and consisted of a primary depocentre – the Central Deep – which is flanked by structurally higher platforms and terraces to the north and south. The basin per se is defined as a series of major fault systems, namely the Rosedale and Lake Wellington fault systems on the northern margin and the Darriman and Foster fault systems on the southern margin (Figure 2). The Central Deep contains most of the major oil and gas fields; this region is characterised by rapidly increasing water depths in the east, where depths in excess of 3000 m occur in the Bass Canyon (Hill et al, 1998). The eastern limit of the basin is defined by the East Gippsland Rise, a prominent north-northeast-striking ‘basement’ high (Megallaa, 1993; Moore and Wong, 2002). The western onshore limit of the basin is traditionally placed at the Mornington High, but is actually represented by outcrops of Early Cretaceous Strzelecki Group sediments (Hocking, 1988).

The Strzelecki Group (Albian–Aptian) rifting event created a series of graben and half-graben of limited geographic extent. Subsequently, a period of uplift and erosion occurred between 100 and 95 Ma. This event produced a new basin configuration and may have provided the accommodation space for large volumes of basement-derived sediments. Renewed crustal extension during the Late Cretaceous (Turonian), associated with the rapid rifting along the Southern Margin and extension in the Tasman Sea, established the Central Deep as the primary depocentre. Terrigenous sedimentation in the Gippsland Basin continued until the late Santonian, when the first marine incursion is recorded in the eastern part of the basin (Partridge, 1999).

Rift-related extensional tectonism continued into the Early Eocene, with the formation of a pervasive set of northwest–southeast-trending normal faults. By the Middle Eocene, a period of low-strain compressional tectonism began to affect the Gippsland Basin and resulted in the formation of a series of northeast to east-northeast-trending anticlines. This event may have been due to intra-plate stress effects, perhaps associated with changes in the sea-floor spreading rate along the Southern Margin rift system. 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, formed as a result of this inversional tectonism. Minor inversion episodes continued well into the Neogene, forming a number of smaller anticlines and traps.

Post-rift depositional architectures and settings became dominant in the Gippsland Basin from the Early Oligocene, with the deposition of the basal unit of the Seaspray Group, the Lakes Entrance Formation. These onlapping, marly sediments provide the principal regional sealing unit 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 of the generated hydrocarbons) in the basin occurring in the Neogene.

The deposition of relatively thick Cainozoic sequences, and the attendant late loading of the source rocks, means that even traps that have developed during the Neogene can be charged with economic quantities of hydrocarbons.


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Stratigraphy and depositional history

Three broad stratigraphic successions are recognised in the Gippsland Basin, based upon lithological variations (Figure 4). The Strzelecki Group, a thick sequence of non-marine, volcanoclastic-rich sediments, the Latrobe Group, a sequence of marine and non-marine siliciclastics that host all of the known hydrocarbon occurrences in the offshore, and the Seaspray Group, a carbonate-dominated sequence that provides both the basal regional seal to the top-Latrobe Group oil and gas accumulations and the critical loading for the generation of hydrocarbons.

Strzelecki Group
The Albian–Aptian Strzelecki Group was deposited during low-strain syn-rift tectonism and unconformably overlies Palaeozoic igneous and folded sedimentary rocks. The group consists of interbedded lithic, volcanoclastic sandstones, mudstones, as well as minor coals and was deposited in a non-marine environment dominated by a fluvial depositional regime. Affinities with the Otway Group in the Otway Basin (Duddy, 1994) exist, and the sequence has some source rock potential, especially for relatively dry gas generation. The total thickness of the Strzelecki Group is poorly defined, but it is likely to exceed 3,000 m in parts of the basin.

Latrobe Group
The stratigraphic subdivision of the hydrocarbon-bearing Latrobe Group sediments is of key relevance for explorers. Four subgroups have been discriminated, each of which is bounded by basin-wide unconformities and consists of formations that are distinguished according to the main depositional facies assemblages.

Emperor Subgroup
The Emperor Subgroup is exclusively Turonian in age and has only been intersected around the basin margins in the vicinity of the bounding faults of the Northern and Southern terraces. Seismic data suggest that a thick section of the subgroup exists below depths of 4 to 6 km in the Central Deep (Bernecker et al, 2001). The Otway Unconformity, which separates the subgroup from the underlying Strzelecki Group, developed in response to uplift along the basin margins.

The Emperor Subgroup is dominated by lacustrine sediments of which the Kipper Shale represents the fine-grained material that accumulated in the evolving rift-valley. Within the rift-valley, one or more deep lakes emerged to form a large lacustrine depocentre (Marshall and Partridge, 1986; Marshall, 1989; Lowry and Longley, 1991). This palaeolake, or lakes, presumably occupied most of the Turonian rift-valley and received detrital sediments from the basin margins. The Kersop Arkose, a coarse-grained feldspathic sandstone, represents the earliest erosion of uplifted granites at the southern basin margin. The unit has been defined in both Moray 1 (type section) in the south and also in Admiral 1, northeast of the Kipper gas field. These intersections provide evidence that the Turonian basin margin was defined by the Lake Wellington Fault Zone to the north and the Foster Fault Zone to the south. The Admiral Formation is characterised by quartz-dominated lithic arenites that were derived from Palaeozoic sedimentary and metamorphic terrains, as well as from newly uplifted Early Cretaceous sediments. The Curlip Formation consists of sandstones and conglomerates that are interbedded with thin shales and minor coals. The formation overlies and interfingers with the Kipper Shale and the formation top is represented by the basin-wide Longtom Unconformity that terminates the Emperor Subgroup deposition. This unconformity was previously erroneously merged into the Seahorse Unconformity at the top of the Golden Beach Subgroup. Accordingly, numerous well sections were incorrectly assigned to the former Golden Beach Group. The hiatus between the Emperor and Golden Beach subgroups separates freshwater lacustrine sediments from non-marine and marine sediments and correlates with the opening of the adjacent Tasman Sea.

Golden Beach Subgroup
Two formations are distinguished in the Golden Beach Subgroup, the marine Anemone Formation and the fluvial/paralic Chimaera Formation. The Anemone Formation consists predominantly of mudstones (shales) and fine-grained siliciclastics that represent shallow to open marine deposition that prevailed in the eastern part of the basin. The marine Golden Beach Subgroup has been intersected in Archer 1, Anemone 1, Angler 1 and Pisces 1. The Chimaera Formation is a non-marine succession that consists of coarse-grained alluvial/fluvial sediments, as well as fine-grained floodplain deposits that include some coals. The formation has been intersected, and occasionally fully penetrated, in wells near the Rosedale Fault System but is missing on the Northern Platform and Northern Terrace. In the southern part of the basin, the Chimaera Formation is only known from Omeo 1, 2 and Perch 1. The Golden Beach Subgroup is essentially confined to the Central Deep, which reflects tectonic movement along the basin margins where conglomerates accumulated. Finer material was transported by fluvial systems that continued to migrate across a gradually widening lower coastal plain and terminated as deltaic bodies in the shallow sea. This alternation between marine and non-marine influence persisted throughout the remainder of the Latrobe Group and had significant control on the distribution of petroleum system elements. The subgroup also contains several volcanic horizons that, although undated, are almost certainly Campanian in age. These volcanics, most prominently developed in the Kipper Field and in the Basker/Manta/Gummy area, terminate the Golden Beach Subgroup and signal another depositional hiatus represented by the Seahorse Unconformity.


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Halibut Subgroup
The time gap recorded by the Seahorse Unconformity is longest in Golden Beach West 1, where the upper F. longus biozone directly overlies N. senectus sediments. Closer to the Rosedale Fault System, F. longus sediments overlie the Campanian volcanics (Bernecker and Partridge, 2001). The Halibut Subgroup hosts the bulk of the hydrocarbons in the Gippsland Basin and comprises five formations that are distinguished according to dominant depositional facies regimes and document the changes from non-marine to marine environments in a west–east or onshore–offshore direction. The Barracouta Formation, which represents upper coastal plain deposition is characterised by fluvial sediments and contains only minor coal. The Volador and Kingfish formations comprise the typical lower coastal plain coal-rich sediments and are separated by the Kate Shale, a marine unit recognised at the Cretaceous/Palaeogene boundary across the basin. The Mackerel Formation consists of near-shore marine sandstones, commonly typified by excellent reservoir qualities, with intercalated marine shales.

Sea-level fall in the Early Eocene, driven by mild basin inversion, initiated a period of major canyon cutting during which parts of the lower coastal plain and the shelf were eroded. The array of submarine channels that developed has added a considerable complexity to seismic mapping, given that the major channels cut down hundreds of metres into the underlying strata. During subsequent transgression, the channels were filled with marine sediments (eg, Flounder Formation), which led to the generation of potential stratigraphic hydrocarbon traps (Johnstone et al, 2001). The Marlin Unconformity highlights the major erosional event associated with channel incision and terminated deposition of the Halibut Subgroup.

Cobia Subgroup
The Middle Eocene to Early Oligocene Cobia Subgroup comprises the coal-bearing Burong Formation (lower coastal plain facies) and the shallow to open marine Gurnard Formation, a condensed section composed of fine- to medium-grained glauconitic siliciclastics. The Gurnard Formation is the reservoir unit in the Patricia/Baleen gas field and consists of fine- to medium-grained clastics. In most other wells the formation is mud-dominated and characterised by low porosity and permeability, although the formation is not considered an effective seal. Included in the subgroup is the Turrum Formation that consists of mid-Eocene marine channel-fill sediments. Deposition of the Cobia Subgroup ceased during the Early Oligocene as a consequence of a marked decline in sediment supply. Large areas of the central basin were left with starved or condensed sections which led to the development of what is traditionally known as the ‘Latrobe Unconformity’ (A. Partridge, in: Purcell, 1999). On seismic sections, this surface is commonly interpreted as a time-line, even though the biostratigraphic data clearly indicates that the Latrobe Unconformity should be considered a composite of several, separate erosional events (Partridge, 1999, 2003).

Seaspray Group
The Seaspray Group consists of calcareous sediments that unconformably overlie the siliciclastics of the Latrobe Group. Subsequent to a change in ocean circulation along the southern Australian margin, accumulation of marls and limestones began in the Middle Eocene in the Eucla Basin, extended to the Otway Basin during the Late Eocene and reached the Gippsland Basin during the Early Oligocene (Holdgate and Gallagher, 1997). Since then, cool-water carbonate production resulted in progradation of the shelf edge. From an exploration perspective, the Seaspray Group is both the primary regional seal (the Lakes Entrance Formation) to the oil and gas accumulations hosted in the top-Latrobe Group and the key sequence that loads and matures the source rocks. Only sparse data on its lithological character and physical properties are available and although the carbonates appear to be monotonous on wireline logs, the Seaspray Group in the offshore can be subdivided into four units (Bernecker et al, 1997) or formations (Partridge, 1999) according to lithological composition, depositional facies and log-signature.

In the context of this report, the conventional subdivision into the basal mud-rich, marly, slightly fossiliferous Lakes Entrance Formation and the carbonate-dominated Gippsland Limestone Formation is used. It should be noted that a different subdivision applies to the onshore Seaspray Group (Holdgate and Gallagher, 1997; Partridge, 1999). The boundary between the two formations in the offshore is not well-defined and is based on a subtle increase in carbonate content. However, over large parts of the basin, a seismic reflector has been identified at the top of the Lakes Entrance Formation, known as the ‘Mid-Miocene Marker’. Above this horizon, an interval of anomalous seismic velocity, the ‘High Velocity Zone’, produces distinctive two-way time pull-ups, which, in the past, had enormous effects on the correct mapping of target zones in the Latrobe Group (Feary and Loutit, 1998).

The seismic velocity anomalies are related to a complex system of Mid-Miocene channels that eroded up to 300 m into a sequence of calcareous sediments. These interfingering channels, which are very well imaged on seismic sections, are filled with generally coarser and more porous materials, are characterised by higher velocities than the underlying carbonates, and also show considerable lateral velocity gradients (Bernecker et al, 1997; Holdgate et al, 2000). Diagenetic processes also influence the seismic velocities, especially the preferential cementation of channel bases (Wong and Bernecker, 2001).

The modern shelf edge of the basin is located near a line that connects the Archer/Anemone discoveries with the Blackback and Basker/Manta/Gummy areas. The slope gradient is <6º, but increases rapidly along the Bass Canyon, which has deeply eroded into older sequences; erosion has reached the sediments of the Golden Beach Subgroup east of the Gippsland Rise (Marshall, 1990).


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Petroleum systems

Despite its relatively small areal extent, the Gippsland Basin is densely populated with 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; to date only four discoveries (Archer/Anemone, Angler, Blackback and Gudgeon) have been made in the eastern deeper water area (Figure 1). 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. The reasons for this may partly be due to the initial focus on top-Latrobe Group plays, which has resulted in numerous discoveries in sediments of the N. asperus and P. asperopolus biozones (Figure 4). Given that the Latrobe Group is thickest in the Central Deep, where prospective horizons are located below 3500 mSS (approx. 2.5 seconds TWT), it is not surprising that less is known about the prospectivity of the older sediments.

Petroleum systems elements

The identification of all the required components of petroleum systems in the Gippsland Basin is the subject of ongoing work and is not a simple task, especially given that many of the system’s elements are located at great depth.

Source

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 (Kerogen Type II/III) are widely distributed throughout the Latrobe Group and generally exhibit high total organic carbon (TOC) values (>2.0%), high Rock-Eval pyrolysis yields, and moderate to high hydrogen indices (>250 mg hydrocarbons/gTOC), suggesting that they have the potential to generate both oil and gas. The richest Latrobe Group source rocks (mainly humic to mixed type) occur within lower coastal plain and coal swamp facies. Well correlations show that much of the T. lilliei biozone 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 with 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 concentrations that generally exceed 10% (Petrofina, 1993).

A recent study of condensate recovered from the Archer/Anemone discovery suggests that source rock potential may also exist within marine sediments (Gorter, 2001).

The results of work in progress at GeoScience Victoria (O’Brien and Bernecker, in preparation) also suggests that the Strzelecki Group sediments within the onshore and offshore Gippsland Basin have the potential to generate significant quantities of gas. Overall, the Strzelecki Group appears to have a broadly similar source rock quality to its temporal equivalent, the proven working Eumeralla Formation source system in the Otway Basin. This work indicates that the gas in the Gippsland Basin fields, such as Trifon, Gangel and Seaspray onshore and Sole offshore, was probably generated within the Strzelecki Group. If confirmed, these results mean that traps either remote from the mature Central Deep source system, or located in Latrobe migration shadows, can still be charged with gas, providing that a local, mature Strzelecki source system is present.

Reservoirs

Marine near-shore barrier and shoreface sandstones are traditionally regarded as the best reservoirs in the basin. The most productive of these were drilled at or near the top-Latrobe Group level and are commonly referred to as the ‘top-Latrobe coarse clastics reservoirs’. This is an unfortunate misnomer, 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 that are characteristic for fluvial/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 plenty of examples for good quality reservoirs in deltaic sandstones, as well as in fluvial and submarine channels.

In contrast to the Latrobe Group, the identification of permeable reservoirs within the Strzelecki Group has proven elusive, though primary porosities can be high. Unless an improved model for the prediction of permeability within the Strzelecki-aged sands can be developed, such targets are inherently high-risk.


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Seal

For the top-Latrobe Group reservoirs, a basin-wide, high quality regional seal is provided by the marls of the Early Oligocene Lakes Entrance Formation. The thickness of this seal varies considerably and ranges from approximately 100 m to over 300 m in deeper water parts of the basin. 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 volumes 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 and other effective seals are formed by several distinct volcanic horizons of Campanian to Paleocene age (eg, as at the Kipper Field). The Kipper Shale exceeds thicknesses of 500 m, whereas the volcanics are often less than 50 m thick, though they are known to exceed 100 m at the Kipper field.

Traps

At the level of the basin-wide Latrobe Unconformity, the basin is dominated by a series of northeasterly-trending anticlines and synclines. Along the anticlinal trends, four-way dip closures have developed and form the traps for the major fields within the basin. It is interpreted that these anticlines formed during the inversion of deeper Early Cretaceous graben and half-graben that were initially filled with the volcanoclastic-dominated sediments of the Strzelecki Group. As tectonic regimes changed, these structural lines of weakness have been variably reactivated. The same northeast-trends of the anticlines and underlying graben are present in the onshore, where Early Cretaceous rocks are exposed within both the Strzelecki and Otway ranges.

Maturity and migration

Numerous studies of the thermal history of the basin – and specifically the modelling of the hydrocarbon generation and migration histories – have been carried out by exploration companies, but the results of these investigations remain largely unpublished. It has been suggested that the main period of hydrocarbon generation and expulsion was initiated in the Miocene, as a result of increased sedimentary loading of the Oligocene and younger carbonate sequences. Some workers (Duddy et al, 1997) have proposed that hydrocarbon generation and migration is at a currently at peak. Given that traps in the top-Latrobe Group were formed as a result of the assorted Neogene compressional events, the relative timing of trap formation and reservoir charging was ideal. This ‘late charge’ scenario does not apply to the deeper Latrobe Group, however. The Late Cretaceous depocentres underwent an early phase of generation and migration – in about the Late Paleocene to Early Eocene. At this time, the regional Lakes Entrance seal had not been deposited and thus by necessity, any trapping would have had to have involved intra-Latrobe Group sealing units and early-formed traps. Just how much of this early generated hydrocarbon inventory was in fact ever trapped remains problematical.

Play types

The two principal types of petroleum plays are present on both the northern margin and in the Central Deep; these are Top-Latrobe plays, and the intra-Latrobe/Golden Beach plays. The elements associated with these plays are as follows:


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