Otway Basin Regional Geology

The Otway Basin is a northwest-trending passive margin rift basin that extends from southeastern South Australia to a boundary with the contiguous Sorell Basin west of King Island (Figure 1). The basin is filled with Upper Jurassic to Holocene sediments and covers an area of 150 000 km², 80% of which lies offshore. The Otway Basin is one of a series of basins (including the Bight, Otway, Sorell, Bass and Gippsland basins) that formed during the break-up of Gondwana and the separation of Antarctica and Australia (Willcox and Stagg, 1990; Stagg and Reading, 2007; Blevin and Cathro, 2008; Direen et al, 2012). The western, northern and eastern basin boundaries are defined by the preserved limits of the uppermost Jurassic–Lower Cretaceous Otway Group sediments, while its southern boundary is delimited by the southernmost extent of Cenozoic sediments in the Hunter Sub-basin. The basin contains a siliciclastic and carbonate sedimentary succession that accumulated within two major depocentres. The “Inner Otway Basin”, which occupies onshore and shelfal areas, is characterised by a thick Lower Cretaceous sedimentary succession. Farther offshore, the area basinward of a large fault system in part mapped as the Tartwaup–Mussel Fault Zone (the region referred to herein as the “deepwater Otway Basin”) are the Late Cretaceous depocentres of the Morum, Nelson and Hunter sub-basins, and the Discovery Bay High (Totterdell et al, 2014). The Torquay Sub-basin, a largely offshore depocentre, is situated in the northeastern part of the basin and contains a Lower Cretaceous succession similar to that elsewhere in the basin, overlain by a thin, post-rift Upper Cretaceous succession that has affinities with the Upper Cretaceous sediments in the Bass Basin (Trupp et al, 1994; Blevin and Cathro, 2008; Totterdell et al, 2014).

The Otway Basin is an important gas producing region with discoveries onshore and in shallow water offshore areas approximately 170–220 km west-southwest of Melbourne, the State Capital of Victoria, delivering gas to the southeastern Australian energy market (Figure 1). The greater Melbourne region represents a large domestic gas market and is supported by major petroleum refineries. Portland, on the western Victorian coast, is a deep-water port suited to offshore operations and is serviced by an excellent road and rail network.

Petroleum discoveries have not yet been made in the relatively underexplored deep water part of the basin or within the Torquay sub-basin; hence the Morum, Nelson, Hunter and Torquay sub-basins and the Discovery Bay High are classified as lightly explored provinces (Totterdell et al, 2014).

Wells, fields and infrastructure in the region are shown in Figure 1, stratigraphy in Figure 2, and regional seismic character in Figure 3. The location of permits and the names of their operators are given in Figure 4 and the location of Commonwealth Marine Reserves and key ecological features are shown in Figure 5.

The Otway Basin is one of a series of basins that developed along the southern margin of Australia during the Middle Jurassic to Cenozoic breakup of eastern Gondwana, and together they comprise the Southern Rift System. The margin evolved through repeated episodes of extension and thermal subsidence leading up to, and following, the commencement of seafloor spreading between Australia and Antarctica. Breakup took place diachronously along the margin, starting in the west at ~83 Ma and concluding in the east at 34 Ma. In general, breakup was not accompanied by significant magmatism and the margin is classified as magma-poor. Key references that discuss the geology and tectonic evolution of the southern margin include: Stagg et al (1990), Willcox and Stagg (1990), Exon et al (1997), Totterdell et al (2000), Norvick and Smith (2001), Hill and Moore (2001), Teasdale et al (2003), Totterdell and Bradshaw (2004), Krassay et al (2004), and Blevin and Cathro (2008).

The Otway Basin overlies deformed Proterozoic and Paleozoic rocks of the Delamerian and Lachlan fold belts, which appear to have influenced the location and orientation of later basin-forming structures (Miller et al, 2002; Moore, 2002; Bernecker and Moore, 2003; Gibson et al, 2012). The complex structural and depositional history of the basin also reflects its location in the transition from an orthogonal–obliquely rifted continental margin in the west to a transform continental margin to the southeast (Totterdell et al, 2012).

With the onset of the major rifting phase in the Late Jurassic, several east-northeast-trending extensional depocentres formed and developed into the Robe, Colac and Gellibrand troughs in the onshore part of the basin. Older parts of the Portland Trough and the Torquay Sub-Basin may also have been initiated during this extensional phase (Trupp et al, 1994; Perincek and Cockshell, 1995). The Penola Trough and most of the Portland Trough were formed by southeasterly transtension between the original rifts, as extension continued. The easternmost portion of the offshore Voluta Trough may represent a continuation of these structures (Figure 1).

Renewed rifting in the Late Cretaceous was driven by a change in crustal extension direction from north–south to northeast–southwest. This created a structural style distinctly different from that developed by the earlier rifting. In the offshore, where Late Cretaceous rifting was concentrated, the resulting structures overprinted those of the initial rift phase. Most of the major structural features, including the Tartwaup–Mussel Fault System, Avoca–Sorell Fault System, Voluta Trough, Mussel Platform, Prawn Platform and Shipwreck Trough (Figure 1), were formed or reactivated by Late Cretaceous rifting. In some areas such as the Shipwreck Trough and Mussel Platform in the eastern part of the basin, sinistral strike-slip motion resulted in the development of transpressional structures with both extensional and compressional components. These are tightly folded, north-trending anticlinal structures, which are particularly well developed in the Shipwreck Trough.

The main structural feature within the Torquay Sub-basin is the east-northeast-trending Nerita Trough. The trough is characterised by thick Otway Group growth wedges (Crayfish and Eumeralla supersequences of Krassay et al, 2004; Figure 2). A period of contractional deformation affected much of the Otway Basin in the Cenomanian and resulted in inversion on Early Cretaceous faults, uplift of the Otway Ranges and erosion of much of the Albian–middle Campanian in the Torquay Sub-basin. The sub-basin is increasingly deformed to the west, culminating in the uplifted Otway Ranges (Trupp et al, 1994). The Late Cretaceous extension seen in the rest of the Otway Basin is limited to minor northwest–southeast-oriented faults on the Snail Terrace to the south of the main depocentre, and minor growth against the western bounding fault system (Cooper and Hill, 1997; Blevin and Cathro, 2008). The sub-basin was affected by a series of compressional events during the Oligocene and Miocene–Pliocene, which resulted in the formation of several large inversion anticlines, and uplift and erosion (Blevin and Cathro, 2008; Holford et al, 2011a).

The deep water Otway Basin consists of two main depocentres—the Morum and Nelson sub-basins. Separated by the Discovery Bay High, the depocentres are flanked on their basinward side by the Hunter Sub-basin (Figure 1; Totterdell et al, 2014). The inboard boundary of the deep water Otway Basin approximately coincides with a large fault system (in part mapped as the Tartwaup–Mussel Fault Zone; Figure 1) and a corresponding hinge zone. Basinward, the Upper Cretaceous succession thickens dramatically.

The westernmost element of the deep water Otway Basin is the Morum Sub-basin. For the purposes of this description, the Morum Sub-basin includes the narrow, highly faulted Beachport Sub-basin of Moore et al (2000), that links the Otway Basin with the Ceduna Sub-basin of the Bight Basin. The narrow, neck-like nature of this part of the basin may reflect its position adjacent to a transform segment of the continent-ocean boundary. The Morum Sub-basin contains at least 5 s TWT (~8 km) of Cretaceous sediments overlain by a thin Cenozoic succession. The sub-basin is characterised by intense faulting that affects the entire Cretaceous succession (Moore et al, 2000). The faults are typically high-angle, particularly in the inboard fault zone that underlies the upper continental slope. Lower-angle listric faults are common farther basinward.

The Morum Sub-basin is separated from the thick section in the Nelson Sub-basin to the east by the Discovery Bay High (Moore et al, 2000), a complex structural high across which the Cretaceous succession thins to about 2.5 s TWT (~4 km) and the Cenozoic section is thin or absent. This part of the basin is referred to by some authors as the Bridgewater High or Arch (e.g. Reid et al, 2001; Krassay et al, 2004). The Cretaceous section on the Discovery Bay High is of relatively uniform thickness, and only mildly deformed, suggesting this area underwent only moderate subsidence during the Cretaceous (Moore et al, 2000).

The Nelson Sub-basin, like the Morum Sub-basin, contains up to 5 s TWT (~8 km) of Cretaceous sediments overlain by a thin Cenozoic succession. However, both the structural style and sedimentary architecture are very different to that seen in the Morum Sub-basin (Figure 3). The inboard boundary of the sub-basin is marked by the broad Tartwaup–Mussel Fault Zone, across which the Lower Cretaceous section is offset basinward by about 4 km (Moore et al, 2000). The basal section, interpreted to comprise the Lower Cretaceous Crayfish and Eumeralla supersequences, is intensely faulted, although fault offsets are generally small. In comparison, the thick, overlying Upper Cretaceous succession is much less affected by faulting. Late Cretaceous faulting is concentrated in the Tartwaup–Mussel Fault Zone, with faults becoming more widely spaced farther basinward. Structural control on deposition is evident in the basal Upper Cretaceous succession. The overlying Cretaceous section comprises a thick progradational succession that is only mildly structured. This section onlaps an outer basement high that is interpreted to represent exhumed sub-continental lithospheric mantle (Totterdell et al, 2012). The Nelson Sub-basin is contiguous with the Sorell Basin to the southeast.

Outboard, in water depths of 3300–5400 m, the Morum and Nelson sub-basins are flanked by the Hunter Sub-basin. The Hunter Sub-basin is contiguous with the Recherche Sub-basin of the Bight Basin to the west and contains a thin Cretaceous and Cenozoic succession. The outer part of the sub-basin is interpreted to overlie highly extended continental crust and rocks of the ocean–continent transition (Totterdell et al, 2012; Moore et al, 2000). The Hunter Sub-basin is considered to have insufficient sedimentary section (generally less than 1 s TWT) to be prospective for hydrocarbons and will not be considered further in this discussion.

For detailed descriptions of the sedimentary history and stratigraphy of the Otway Basin, the reader is referred to publications by Parker (1995), Lavin (1997), Geary and Reid (1998), Boyd and Gallagher (2001), Constantine (2001), Partridge (2001) and Krassay et al (2004).

The Otway Basin fill comprises five distinct and regionally mappable basin phases (Figure 2; Krassay et al, 2004; Stacey et al, 2013):

• Early Cretaceous extension and subsidence (Crayfish and Eumeralla supersequences)
• Late Cretaceous extension (Shipwreck Supersequence)
• Late Cretaceous subsidence/extension (Sherbrook Supersequence)
• Cenozoic subsidence/extension (Wangerrip Supersequence)
• Cenozoic subsidence and inversion (Nirranda, Heytesbury and Whalers Bluff supersequences)

The oldest rift-fill sediments in the Otway Basin are of latest Jurassic–Early Cretaceous age (Figure 2). During that time, the locus of rifting and deposition was in the onshore parts of the basin where a series of initially distinct, west to northwest-trending extensional depocentres formed. These depocentres would eventually expand substantially into the Robe, Colac and Gellibrand troughs (Krassay et al, 2004). In excess of 5000 m of fluvio-lacustrine sediments of the Crayfish and Eumeralla supersequences (equivalent to the Otway Group) filled these depocentres. The lacustrine sediments and interbedded flow basalts of the Casterton Formation are overlain by the predominantly fluvial sediments of the Pretty Hill Formation, which are, in turn, overlain by lower energy fluvial and lacustrine sediments of the Laira Formation. The overlying Katnook Sandstone represents the return to higher energy fluvial deposition. Studies of apatite fission track (AFT) data and vitrinite reflectance (VR) data from wells in the basin suggest that it experienced regionally elevated palaeotemperatures (50–60°C/km) in the Early Cretaceous (Foster and Gleadow, 1992; Duddy, 1994; O'Brien et al, 1994; Cooper and Hill, 1997; Mitchell, 1997). Interpretation of seismic data suggests that a thin, extensional Lower Cretaceous succession is also present in the deep water Otway Basin (Figure 3). In the eastern Nelson Sub-basin, deposition during this time was strongly influenced by the north–south oriented Avoca–Sorell fault system.

A period of compression and structural inversion affected most of the Otway Basin during the Cenomanian (Norvick and Smith, 2001; Krassay et al, 2004), resulting in kilometre-scale uplift and exhumation in some areas of the basin (e.g. Otway Ranges and the Cape Otway–King Island High; Holford et al, 2011b), and non-deposition or erosion of much of the Cenomanian succession across most of the basin. Driven by uplift and erosion, heat-flow and the associated geothermal gradient decreased sharply in the early Late Cretaceous. Due to limited seismic data and poor well control, the impact of this compressional event in the deep water Otway Basin is less clear.

Bernecker et al (2004) proposed that the Cenomanian uplift of the Otway Ranges resulted in isolation of the Torquay Sub-basin from the rest of the Otway Basin. Thus, when deposition resumed in the Campanian, the sub-basin was effectively a northwest extension of the Bass Basin (Trupp et al, 1994; Bernecker et al, 2004). The lower coastal plain sandstones, siltstones and coals of the Campanian–lower Eocene Eastern View Formation that cover much of the Bass Basin and provide the source of hydrocarbons in that basin, were also deposited across the Torquay Sub-basin. The succession is generally thin (<200 m) but thickens over the Lower Cretaceous half graben. The Eastern View Formation is unconformably overlain by marine shelfal sediments of the middle Eocene–upper Oligocene Demons Bluff Group, which includes the basal transgressive sands of the Boonah Formation and the potential seal facies of the Anglesea Formation. The Demons Bluff Group is overlain by shallow marine carbonates of the upper Oligocene–Miocene Torquay Group.

In the rest of the Otway Basin, extension recommenced in the Late Cretaceous and at least 5000 m of sediments were deposited in the Shipwreck Trough. The main locus of deposition moved to the south, basinward of the Tartwaup–Mussel Fault Zone and equivalent faults farther west (Reid et al, 2001; Krassay et al, 2004). A series of northwest-trending depocentres developed beneath the present day outer shelf and slope in the Morum and Nelson sub-basins; the inboard, fault-controlled depocentre is commonly referred to as the Voluta Trough (e.g. Reid et al, 2001). Deposition throughout the Late Cretaceous was dominated by the fluvio-lacustrine, deltaic and marine sediments of the Shipwreck and Sherbrook supersequences (equivalent to the Sherbrook Group; Krassay et al, 2004; Figure 2).

Initial deposition of the Shipwreck Supersequence, particularly in the Nelson Sub-basin, appears to have been strongly fault controlled, with that control diminishing through time. In hydrocarbon producing areas of the Otway Basin, the Waarre and Flaxman formations, and the “Thylacine Sandstone Member” of the Belfast Mudstone are economically important reservoirs. The Sherbrook Supersequence consists of a thick, basinward-thickening progradational succession of coastal plain, deltaic and marine sediments up to 5 km thick. There is evidence of localised fault control on deposition, particularly around the Tartwaup–Mussel Fault Zone (Figure 3), and further basinward where listric growth faults are observed in seismic data.

The Late Cretaceous culminated in the commencement of breakup in the Otway Basin at around 65 Ma (Krassay et al, 2004). Moderate structuring and regional uplift accompanied break-up along this part of the margin and resulted in the development of the Late Maastrichtian Unconformity, which separates pre-rift and post-rift sediments. Post-rift (latest Maastrichtian to Holocene) sediments were deposited along the continental shelf in a divergent, passive margin setting, as Antarctica separated and drifted further away from Australia with concomitant opening of the Southern Ocean. The post-rift succession is made up of progradational coastal plain–open marine siliciclastic and carbonate sediments. Krassay et al (2004) categorised these sediments into three distinct supersequences that are separated by major unconformities representing different stages of passive margin development—the Wangerrip, Nirranda and Heytesbury supersequences (and their equivalent groups). In South Australia, these groups are classified as belonging to the Gambier Basin, known previously as the Gambier Embayment of the Otway Basin (Smith et al, 1995). In the deep water Otway, a thin succession of deep water equivalents to the Wangerrip, Nirranda and Heytesbury supersequences overlies the Sherbrook Supersequence (Figure 3).

Towards the end of the Maastrichtian, the first major transgression of the incipient Southern Ocean deposited the Massacre Shale of the Wangerrip Group (Partridge, 1999). This was followed by the creation of shallow marine to coastal depositional environments in which the Pebble Point Formation accumulated. Strongly progradational Paleocene to early Eocene sediments belonging to the Pember Mudstone (which is partly equivalent to, and partly succeeded by the Dilwyn Formation) were also deposited at this time (Arditto, 1995). All three formations are time equivalent to terrestrial sediments of the lower Eastern View Coal Measures that are restricted to the Torquay Sub-basin and the Colac Trough. The overlying Nirranda Group comprises prograding nearshore to offshore marine clastics of the basal Mepunga Formation that grade upwards into increasingly open marine carbonates of the Narrawaturk Marl. Both formations are coeval with the proximal Demons Bluff Formation and Eastern View Coal Measures recognised onshore in the northeastern part of the Otway Basin and Torquay Sub-basin (Abele et al, 1976; Blake, 1980; Tickell, 1991).

Hydrocarbon discoveries on the Australian southern margin are assigned to the Austral Petroleum Supersystem (Bradshaw, 1993; Summons et al, 2002; Edwards et al, 1999), in which three subsystems are recognised:

• Austral 1: Upper Jurassic to lowest Cretaceous fluvio-lacustrine shales (Crayfish Supersequence);
• Austral 2: Lower Cretaceous fluvial and coaly facies (Crayfish and Eumeralla supersequences); and
• Austral 3: Upper Cretaceous to lowest Cenozoic fluvio-deltaic facies (Shipwreck and Sherbrook supersequences).

O’Brien et al (2009) mapped the peak hydrocarbon generation fairways for the three petroleum systems in the Otway Basin and concluded that the principal control on the distribution of significant hydrocarbon accumulations in the basin is proximity to actively generating source kitchens. This is related to poor fault seal in the basin, so that development of hydrocarbon accumulations is reliant on the charge rate exceeding the leakage rate, complicated by relatively complex and tortuous migration pathways.

While many discoveries have been made in the inboard basin, only six petroleum exploration wells have been drilled in the remainder of the offshore parts of the basin—three in the deep water sub-basins (Morum 1, Amrit 1 and Somerset 1) and three in the offshore Torquay Sub-basin (Nerita 1, Snail 1 and Wild Dog 1; Figure 1). All of these wells were plugged and abandoned as dry holes. Austral 2 source rocks are modelled as being overmature across much of the Late Cretaceous depocentre in the deep water parts of the basin (O’Brien et al, 2009). However, the presence of a thick, dominantly marine Upper Cretaceous succession, and geochemical indications suggesting the influence of Austral 3-sourced hydrocarbons in outboard wells (O’Brien et al, 2009), provide some support for the concept that active petroleum systems are present in the deep water parts of the basin.

Source rocks

In the Otway Basin, the source rocks of the Austral 1 Petroleum System consist of non-marine, Upper Jurassic to Lower Cretaceous fluvio-lacustrine and lacustrine shales deposited in half graben (Casterton Formation and Crayfish Subgroup). Edwards et al (1999) grouped liquid hydrocarbons sourced by Austral 1 source rocks into four oil families, based on isotopic and biomarker signatures, and interpreted the depositional environments of the source rocks. The Austral 1 Petroleum System is recognised primarily in the Penola and Robe troughs as the source for: oil and bitumen in Crayfish 1A and Zema 1 (Family 1); condensates and oil in Wynn 1 and Sawpit 1, respectively (Family 2); condensates in Haselgrove 1, 2 and Haselgrove South 1, 2 (Family 3); and, gas and minor condensate in Troas 1 (Family 4).

With the exception of the Penola and Robe troughs, the vast majority of hydrocarbon discoveries in the Otway Basin belong to the Austral 2 Petroleum System, which consists of Lower Cretaceous (Albian-Aptian) source rocks charging the overlying basal Upper Cretaceous Waarre siliciclastic reservoir unit (Edwards et al, 1999; Boreham et al, 2004; O'Brien et al., 2009). These include the onshore fields in the Port Campbell Embayment and all offshore gas fields in the greater Shipwreck Trough area (Mehin and Link, 1994; Foster and Hodgson, 1995; Luxton et al, 1995). Source intervals comprise coals and carbonaceous shales within two coal measure sequences in the Eumeralla Formation, one of Aptian age near the base of the unit and the other of early Albian age.

The Sherbrook and basal Wangerrip group potential source rocks of the Austral 3 Petroleum System have not been definitively linked to any hydrocarbons in the Otway Basin (Totterdell et al, 2014), but most of the wells drilled in the basin have been located either on inner shelfal areas or onshore where the Sherbrook Group has not reached sufficient thermal maturity for significant hydrocarbon generation to have occurred. O’Brien et al (2009) reported that gas discoveries in wells drilled on the outer shelf adjacent to the Tartwaup–Mussel Fault Zone (La Bella, Geographe and Thylacine) are significantly wetter than discoveries on the inner shelf, where the Austral 2 system provides the sole hydrocarbon charge. Migration of Austral 3-sourced wet gas from the deep water basin up the Tartwaup–Mussel Fault Zone was suggested by O’Brien et al (2009) as a possible mechanism to explain this difference. The only oil thought to be attributed to the Austral 3 Petroleum System derived from the Pebble Point Formation in Wilson 1, located in the Victorian onshore part of the basin (Lavin, 1998). However, the Wilson 1 oil stain has since been reinterpreted as a drilling contaminant rather than in-place or migrated hydrocarbons (Boreham et al, 2004; O’Brien et al, 2009; Goldie Divko, 2015). The Turonian Waarre Formation contains both marginal marine and coastal plain sediments that can be regarded as viable source rocks, provided they are sufficiently deeply buried. Further basinward, these units are likely to comprise prodelta and open marine facies, which may have greater potential for containing high-quality source rocks, especially as studies by O'Brien et al (2009) suggest that the Turonian section in the deeper offshore would lie within the hydrocarbon maturity window. The Cenomanian–Turonian and Coniacian–Santonian were times of global anoxia and source rock accumulation (Oceanic Anoxic Events (OAE) II and III; Arthur et al, 1990; Jenkyns, 2010), which further enhances the potential for the presence of good-quality Austral 3 source rocks in distal marine facies in the deep water basin (Gallagher et al, 2005; O’Brien et al, 2009). The dredging of Cenomanian–Turonian potential source rocks with excellent liquids potential from the Ceduna Sub-basin of the Bight Basin further to the west (Totterdell et al, 2008), provides support for this hypothesis. In addition, O’Brien et al (2009) identified organic enrichment in Turonian rocks in wells located along the outer margin of the basin, near the Tartwaup–Mussel Fault Zone. Those results support the interpretation that the basal parts of the Sherbrook Group became increasingly rich in organic matter basinward, as marine conditions became more prevalent in the Late Cretaceous.

The nature of potential source rocks basinward of the Tartwaup–Mussel Fault Zone in the Otway Basin is not well understood; however interpretation of seismic data indicates that the Lower and Upper Cretaceous depositional sequences that contain Austral 2 and 3 source rocks elsewhere in the basin (Boreham et al, 2004), are also likely to be present in the deep water Otway Basin (Totterdell et al, 2014). Seismic interpretations indicate that Lower Cretaceous sequences thin basinward into the deep water Otway Basin; conversely, the Upper Cretaceous Shipwreck and Sherbrook supersequences thicken considerably basinward of the controlling Late Cretaceous faults systems (Figure 3).

Given the thickness of the Upper Cretaceous succession, potential Austral 2 source rocks (coaly sediments of the Eumeralla Supersequence) are modelled to be overmature across much of the deep water basin (Reid et al, 2001; O’Brien et al, 2009). Consequently, exploration success in the deep water basin is likely to be dependent on the presence of Turonian or younger (Austral 3) source rocks in the Shipwreck and Sherbrook supersequences (O’Brien et al, 2009). A possible exception to this is in the innermost part of the Morum Sub-basin, where the Lower Cretaceous succession is not as deeply buried and is modelled to have source potential (Duddy et al, 2003). In this region, the basinward-thickening Upper Cretaceous succession is interpreted to overlie potential Aptian–Albian source rocks that are postulated to include, not only the coaly source rocks of the Eumeralla Supersequence, but also organic-rich oil-prone marine sediments (Boult et al, 2006).

In the Torquay Sub-basin, the best potential source rocks are the Upper Jurassic to lowest Cretaceous Casterton Formation and Crayfish Supersequence (Austral 1; Edwards et al, 1999; Boreham et al, 2004) and the Lower Cretaceous Crayfish and Eumeralla supersequences (Austral 2; Edwards et al, 1999; Boreham et al, 2004). Although the Eastern View Formation provides the source for hydrocarbons in the Bass Basin (Blevin et al, 2005; Boreham et al, 2003), in the Torquay Sub-basin, the unit is thermally immature and not capable of generating hydrocarbons.

Reservoirs and seals

The Pretty Hill Formation (part of the Crayfish Subgroup) is the major play fairway in the South Australian part of the Otway Basin and is the producing unit in the Katnook, Ladbroke Grove, Haselgrove and Haselgrove South gas fields. In Victoria, the Pretty Hill Formation has good reservoir characteristics at shallow to moderate depths of burial (1000–2300 m), with measured porosity ranging from 13.2–32.0% (average 20.7%), and permeability of 390 mD (Mehin and Constantine, 1999). The reservoir potential of the unit below depths of approximately 2300 m is uncertain due to a lack of well penetrations. However, reservoir data from gas fields in the Penola Trough, onshore South Australia, suggest that porosity and permeability within the Pretty Hill Formation may well be quite high, given that the gas zones in these fields (between 2500 and 2800 m) have effective average core porosity of 10–18% and permeability of 0.6–549 mD (Parker, 1992).

Vertical and cross-fault sealing of the Penola Trough gas reservoirs in South Australia is provided by the Laira Formation (Parker, 1992; Lovibond et al, 1995). In Victoria, by contrast, the sealing unit is likely to be the Eumeralla Formation, since the Laira Formation is absent, except in a few wells located near the Victorian-South Australian border (Mehin and Constantine, 1999).

The Turonian Waarre Formation (Figure 2) is the major regional reservoir unit in the Victorian part of the Otway Basin. Producible gas has been encountered in sixteen onshore fields in the Port Campbell area. In the offshore Shipwreck Trough, the Waarre Formation hosts gas accumulations at Minerva, La Bella, Geographe and Thylacine. The Flaxman Formation and a sandy facies (“Thylacine Sandstone Member”; Cliff et al, 2004) at the base of the Belfast Mudstone are also significant exploration targets. In the Shipwreck Trough, marine sandstones in the basal part of the Flaxman Formation contain gas and constitute part of the total gas reservoir section for the Minerva and La Bella fields (Geary and Reid, 1998).

In the shelfal areas of the Otway Basin, including at the Port Campbell and Shipwreck Trough gas fields, the most widely distributed sealing facies is the marine claystone Belfast Mudstone, which provides a reliable regional top seal for reservoirs within the Waarre and Flaxman formations. In addition, shales within the Flaxman Formation may act as intraformational seals. Both units are regionally developed and are thickest in the offshore part of the basin.

The Campanian–Maastrichtian Paaratte Formation has been intersected by many wells in South Australia and is known to contain good quality reservoir intervals. The Paaratte Formation and Timboon Sandstone are also characterised by intraformational mudstones that have good sealing capacity, and the Paleocene Pebble Point Formation is sealed by the seaward-thickening Pember Mudstone. Potential sealing units within the Wangerrip Group include the basal Massacre Shale, basal mudstone units of the Dilwyn Formation, and mudstones in the Mepunga Formation.

Although the Sherbrook Group remains untested in terms of mature source rocks, all other petroleum systems elements appear to be present. However, the extent to which these reservoir facies are developed in the deep water Otway Basin is not known. In the deep water Otway Basin, the Upper Cretaceous succession is predicted to contain fine-grained prodelta and marine facies (Krassay et al, 2004), which could provide good quality seals. Only ongoing exploration, especially in the deeper parts of the basin, will shed light on the viability of this petroleum system. Two wells drilled in the vicinity of the shelf break (Amrit 1 and Hill 1) targeted the Paaratte Formation and verified the presence of good quality reservoir facies. An overlying seal facies in mudstones coeval with the more proximal Timboon Sandstone was also found in Amrit 1 (Subramanian, 2004, 2005). Petrophysical analyses of samples from Amrit 1 indicated 42.5 m of net sand with an average porosity of 16.2% was present.

In the Torquay Sub-basin, the reservoir properties of the Eocene Boonah Formation and the Upper Cretaceous–Eocene Eastern View Formation were found to be fair to excellent, while reservoir potential for two deeper Cretaceous units (the Pretty Hill Formation in the Crayfish Supersequence and the Eumeralla Supersequence) is also predicted (Bernecker et al, 2004). These potential reservoir units are all likely to have corresponding seals. The Boonah Formation is sealed by the regionally extensive Anglesea Formation, the Pretty Hill Formation is sealed by the Eumeralla Formation and intra-formational seals are likely within the Eastern View Formation and Eumeralla Formation.

Timing of generation

Burial history modelling indicates the Eumeralla Formation has a two-stage hydrocarbon generation history consisting of an initial Early Cretaceous phase of hydrocarbon expulsion followed by a lesser Cenozoic expulsion phase (Duddy, 1994, 1997; Mehin and Link, 1997b). Early Cretaceous expulsion was associated with the initial rifting event, when the geothermal gradient was approximately 50–70°C/km (Mehin and Link, 1997a; Mitchell, 1997). This event would have resulted in significant hydrocarbon generation from the Casterton Formation, Crayfish Subgroup and basal Eumeralla Formation, peaking at the end of the Early Cretaceous.

During the Late Cretaceous, hydrocarbon expulsion from the Casterton Formation (Crayfish Subgroup) and base Eumeralla Formation ceased after the regional geothermal gradient dropped from 50–70°C/km to 30°C/km (Duddy, 1997; Mitchell, 1997). Further hydrocarbon generation did not recommence until the Eumeralla Formation experienced burial temperatures greater than those attained at the end of the Early Cretaceous. Duddy (1997) and Mehin and Link (1997b) believe this occurred in the Paleogene with peak generation occurring in areas where the Eumeralla Formation is overlain by about 2000 m of Upper Cretaceous sediments and 1000–2000 m of Paleogene sediments.

Significant sediment loading took place in the deep water Otway Basin during the Late Cretaceous (Shipwreck and Sherbrook supersequences). O’Brien et al (2009) suggest that in most of the Nelson Sub-basin, both the Austral 2 and basal Austral 3 source rock intervals had undergone complete organic matter transformation, and had generated and expelled hydrocarbons by 82 Ma. Given the amount of Late Cretaceous structuring in the basin, particularly prior to breakup in the latest Maastrichtian, preservation of these early-generated hydrocarbons could be problematic. O’Brien et al (2009) also reported that in a narrow zone around the Tartwaup–Mussel Fault Zone, where the Upper Cretaceous succession is not as thick, much of the Sherbrook Group is currently at peak maturity, which enhances the petroleum prospectivity of this zone.

In the Morum Sub-basin, modelling by Duddy et al (2003) suggests that generation from Austral 2 (Eumeralla) source rocks ceased at about 45 Ma, and that migration, which commenced in the Late Cretaceous, continues to the present day.

In the Torquay Sub-basin, Trupp et al (1994) suggested that Casterton Formation source rocks would be marginally oil mature on the Snail Terrace, but overmature for oil and gas generation in the deepest parts of the sub-basin, having expelled all hydrocarbons by 90 Ma. The only traps available during the main phase of expulsion would be within the Crayfish section, which they considered to be below the reservoir floor. In addition, timing of generation (101 Ma) relative to the Cenomanian deformation event (95–90 Ma) would not appear to favour preservation of accumulations. Trupp et al (1994) also suggested that Eumeralla Formation source rocks are currently mature in the main depocentre. However, recent modelling by Holford et al (2010) suggests that maximum post-depositional temperatures for the Otway Group in Nerita 1 were reached in the Early Cretaceous. They reported that the combined effects of deeper burial (by an additional 1200 m) and elevated heat flow during the Early Cretaceous resulted in hydrocarbon generation from Lower Cretaceous source rocks prior to the 100–90 Ma uplift and erosion.

Play types

Sandstones within the Shipwreck Supersequence (Sherbrook Group; Waarre and Flaxman formations) sealed by the Belfast Mudstone and charged by Austral 2 source rocks are the most successful exploration targets inboard of the Tartwaup–Mussel Fault Zone. All of the producing fields and a majority of the discoveries are from the Waarre reservoir. The principal structural traps involve closure associated with faulted anticlines and tilted fault blocks. Regional seal is provided by the Belfast Mudstone while the Flaxman Formation exhibits local sealing capability. The Eumeralla Formation is expected to be gas generative across most of the region. The potential for oil generation from lower Sherbrook Group source rocks is inferred to be the highest in the Voluta and Portland troughs. Recent petroleum geochemical studies suggest that in the offshore, mature Turonian source rocks may be capable of generating liquid hydrocarbons if it can be demonstrated that these shales are marine in origin (O’Brien et al, 2009).

In the western Otway Basin, Turonian–Santonian slope fan sediments provide a valid exploration target in addition to the Waarre/Flaxman play. Rapid deepening and steepening of the shelf to the southwest of the Tartwaup Hinge Zone, combined with high eustatic sea levels, created a deep water depositional environment over much of the Otway Basin. Post break-up uplift in the hinterland provided large volumes of clastic material that bypassed the relatively stable platform of the Tartwaup Hinge Zone to the northeast. Lower delta plain and marginal marine conditions suitable for the formation of oil-prone source rocks within the Waarre and Flaxman formations are most likely to be found in rapidly subsiding troughs, such as those located southwest of the Tartwaup Hinge Zone. Slope-fan deposits, overlying a thick, coal-bearing sequence of the Waarre Formation, have been identified on seismic data in the South Australian part of the basin.

Another regionally well developed play type is associated with tilted fault blocks that contain Paaratte Formation sediments. These fault blocks rely on both intraformational and cross-fault seal for trap integrity. In proximal locations, trap seal is the main exploration risk associated with this play. In more distal areas, where the unit interfingers with the Belfast Mudstone, the risk of seal failure is reduced. Rollovers associated with faulted anticlines developed on the hanging wall of listric faults may provide independent four-way dip closures. The generally coarsening-upwards, quartz sandstones display excellent reservoir characteristics. Although this play has yet to be validated by a hydrocarbon discovery, only one offshore well (Discovery Bay 1) has targeted this play. Downthrown fault blocks, with juxtaposition of Paaratte Formation reservoirs against shaly sequences from the same unit, or Belfast Formation mudstones, may also constitute valid traps. The potential for fault seal is expected to increase in a basinward direction.

While there is potential for plays charged by early-generated, Austral 2-sourced hydrocarbons in the inboard parts of the deep water Otway Basin, preservation of such accumulations is considered problematic. O’Brien et al (2009) proposed that the best opportunities for preservation of early-generated hydrocarbons were in fault-independent anticlines with four-way dip closure, and in fault-dependent plays on faults with low dip and east–west strike, rather than northwest–southeast.

In the deep water Otway Basin, rapid sediment loading in the Late Cretaceous resulted in Austral 2 source rocks undergoing complete organic matter transformation by 82 Ma (O’Brien et al, 2009). Therefore, plays in much of the deep water Otway Basin are likely to be reliant on charge from unproven Austral 3 source rocks (Geary and Reid, 1998; Reid et al, 2001; O’Brien et al, 2009) charging Paaratte Formation equivalent sandstones with top and cross-fault seal provided by distal marine mudstones. The most promising exploration targets in the deep water Otway Basin lie in faulted anticlines and tilted fault blocks immediately outboard of the Tartwaup–Mussel Fault Zone. Amrit 1 targeted an inboard intra-Paaratte play sourced from the Belfast Mudstone. While the well confirmed the presence of reservoir quality sands and overlying seal facies (Subramanian, 2005), significant occurrences of hydrocarbons were not encountered and the play remains unproven. Minor hydrocarbon indications in the upper part of the Paaratte Formation could be interpreted as providing some evidence for the presence of an active petroleum system, but raise doubt over the volumes of generated hydrocarbons (Subramanian, 2005).

In the Morum Sub-basin, Duddy et al (2003) suggested that migration from Eumeralla source rocks continues to the present day and therefore there is potential for accumulations in suitable trapped Upper Cretaceous reservoirs.

Play types within the Torquay Sub-basin consist of: Miocene anticlines, similar to those in the Gippsland Basin, with an Eocene reservoir sealed by the Anglesea Formation; Oligocene inversion anticlines also with an Eocene reservoir; Early Cretaceous fault blocks and faulted anticlines; potential Pretty Hill Formation and Eumeralla Supersequence reservoirs sealed by Eumeralla Formation shales both laterally and vertically; onlaps onto basement highs, and; potential Pretty Hill Formation or basal Eumeralla Formation reservoirs that onlap basement in the eastern portion of the Torquay Sub-basin and along the Snail Terrace (Trupp et al, 1994; Bernecker et al, 2004).

Exploration in the region dates back as far as 1892, when coastal bitumen strandings led to the drilling of an exploration well in the South Australian part of the Otway Basin at Kingston. Early drilling was based on the theory that coorongite, (subsequently found to be a surface algal deposit) originated from underground oil seepages. Commercial CO₂ was discovered in Caroline 1 in 1968, but it was not until 1987 that the first commercial gas discovery was made at Katnook. This was followed by the discovery of the Ladbroke Grove Field in 1989. In 2007, the appraisal of the Jacaranda Ridge Field significantly upgraded the northern part of the Penola Trough as a wet gas–condensate play. The lack of early success may be attributed to poor quality seismic data prior to the early 1980s, and a poor understanding of structural and stratigraphic relationships in the Robe and Penola troughs. Good quality modern seismic coverage now exists over the offshore and most of the onshore parts of the basin and stratigraphic relationships are better understood.

The first wells in the Victorian part of the Otway Basin were drilled in the 1920s to 1940s in the Anglesea and Torquay areas (Sprigg, 1986). These wells were relatively shallow (<500 m) and only penetrated Cenozoic sediments. In 1959, Port Campbell 1 was drilled into Upper Cretaceous sediments and intersected the first hydrocarbon column in the basin. Drilled by the Frome-Broken Hill consortium, it flowed at a rate of 4.2 MMcf/d (118 931 m3/d) from Waarre Formation sandstones.

In 1966, Esso and Shell farmed into the Otway Basin and, with Frome-Broken Hill, drilled 22 wells in both Victoria and South Australia. Hoping to find an analogue for the Gippsland Basin, their efforts were largely unrewarded as only minor gas shows were recorded in Pecten 1A—a well located on the Mussel Platform in the eastern part of the Otway Basin. The major companies had abandoned the Otway Basin by 1976, discouraged by the lack of commercial oil or gas discoveries.

After a period of only limited drilling and seismic acquisition in the region, Beach Petroleum discovered gas in Waarre Formation sandstones in North Paaratte 1, located only 3 km northeast of Port Campbell 1. Encouraged by this gas discovery onshore, offshore release areas were offered and petroleum exploration permits were awarded to Esso, Phillips and Ultramar, though no new discoveries were made. In contrast, Beach Petroleum made additional small onshore gas discoveries within the Upper Cretaceous Waarre Formation in 1981 at Grumby 1 and Wallaby Creek 1.

In 1987, gas fields in the Port Campbell area went into production, supplying the regional centres of Portland and Warrnambool. In the early 1990s, BHP Petroleum Pty Ltd (BHP) discovered gas in two wells drilled on the Mussel Platform on the flanks of the Shipwreck Trough—Minerva 1 (1993) and La Bella 1 (1994)—as well as drilling two dry holes. After drilling an additional three wells that only encountered minor gas shows, BHP relinquished its exploration permits in 1997, but obtained retention leases over the Minerva and La Bella fields.

Only three wells have been drilled in the deep water Otway Basin. Morum 1 was drilled in the Morum Sub-basin in 1975, and the Voluta Trough of the Nelson Sub-basin was tested by Amrit 1 in 2004 and by Somerset 1 in 2009; all wells were dry. The oldest unit penetrated in the deep water Otway Basin is the Turonian Waarre Formation, which was reached in Morum 1 (Esso Australia, 1975). All of these wells are located on the edge of the continental shelf (Figure 1). The continental slope and deep water areas remain relatively unexplored.

Similarly, the Torquay Sub-basin has seen only moderate levels of exploration activity, and only three wells have been drilled in the offshore parts of the sub-basin (Figure 1). The best quality seismic data is available over the Snail Terrace. Exploration in the sub-basin commenced in the 1960s, when Shell drilled the Nerita 1 well (Shell Development, 1967). In the early 1970s, Hematite acquired seismic data and drilled the Snail 1 well (Hodgson and Mellins, 1973). The Bureau of Mineral Resources (BMR; now Geoscience Australia) also acquired several regional seismic lines in 1982. During the late 1980s to early 1990s, Shell undertook an exploration campaign in the basin that included the acquisition of gravity, magnetic and seismic data, and culminated in the drilling of Wild Dog 1 (Trupp et al, 1993). A permit covering much of the Torquay Sub-basin was granted to Trident Energy in 2005. In 2011, Loyz Energy farmed-in to the permit and in 2013, acquired a 3D seismic survey to the east of Wild Dog 1. The joint venture partners have identified numerous leads that include an untested structural play in the Lower Cretaceous Pretty Hill Formation (Rogers, 2013).

There was a strong resurgence in exploration activity in the Otway Basin from 1999 to 2005, which was driven by a combination of factors, including changes in the gas market and technological advances. A major exploration program by a Woodside Energy Ltd joint venture, utilising state-of-the-art 3D seismic technology, resulted in the large (approximately 1.3 Tcf [36.8 Gm3] GIP combined) Geographe and Thylacine gas discoveries. In the onshore, a Santos Limited joint venture exploration program, again using state-of-the-art 3D seismic acquisition technology, resulted in the discovery of three new gas fields. In 2002, another commercial offshore gas discovery was made by Strike Oil with the Casino 1 well, drilled by Santos Limited approximately 20 km southwest of the Minerva field on the western flank of the Shipwreck Trough. The Casino gas field holds an estimated recoverable reserve of 280 Bcf (7.9 km3) and was brought into production in 2006. In 2005, Santos Limited made an offshore gas discovery during the drilling of Henry 1. Also in 2005, Woodside discovered the Halladale and Blackwatch gas fields about 4 km offshore in the Shipwreck Trough, with Origin Energy subsequently acquiring Woodside’s interest in these fields as part of their development strategy. In 2008, gas shows were encountered at Netherby 1 and Pecten East 1 but exploration has had limited success since that time. In 2012, Thistle 1 was drilled by Origin Energy to the north of the Thylacine/Geographe gas fields but no hydrocarbons were encountered. Onshore, three exploration wells were drilled in South Australia in 2013–2014—one targeting a conventional petroleum play (Sawpit 2) and two targeting unconventional plays (Jolly 1 and Bungaloo 1).

During the last decade, drilling has largely focused on the appraisal and development of known accumulations. Origin Energy appraised the Halladale field with the drilling of Halladale 2 ST1 in 2014 (Origin Energy Limited, 2015). Origin Energy also drilled the Speculant 1 exploration well in the Victorian part of the inner Otway Basin which resulted in a gas discovery (Origin Energy Limited, 2014), which they followed with the Speculant 2 appraisal well in 2015 (Origin Energy Limited, 2015).

Recent offshore seismic surveys include Origin Energy’s Astrolabe 3D and WHL Energy’s La Bella 3D carried out in 2013 and Origin Energy’s Enterprise 3D and 3D Oil’s Flanagan 3D completed in late 2014.

Also recently, Geoscience Australia conducted an onshore unconventional resource assessment for the Otway Basin, using a probabilistic volumetric assessment method to assess the potential for unconventional gas and liquids resources, including shale and tight gas and liquids The interim resource assessment report is currently available (Geoscience Australia, 2017), and the full report is planned for release during 2017.

Production from the Minerva gas field commenced in 2004 via two subsea wells drilled in shallow waters tied back to an onshore gas plant. During the third quarter of 2016, Minerva produced 0.4 PJ of sales gas and 1140 bbls (181.3 kl) of condensate (Santos Limited, 2016).

In 2007, the Otway Gas Project commenced production of gas, condensate and LPG from the Thylacine field in Tasmanian waters. In 2013, the Geographe field, 15 km north of Thylacine (Figure 1), also commenced production (Origin Energy Limited, 2013). The Otway Gas Project also includes assessment of production viability for the Blackwatch and Halladale gas fields that overlap Victorian and Commonwealth waters immediately to the north of the Pecten field.

The Casino gas field was brought into production in 2006 and holds an estimated recoverable reserve of 280 Bcf (7.9 km³). The success of the Casino Gas project facilitated development of the Henry, Martha and Pecten discoveries, allowing production of gas from these fields via the existing Casino infrastructure to the onshore Iona production facility. Production from the Casino hub was 2.5 PJ of sales gas and 1120 bbls (178 kl) of condensate for the third quarter ending September, 2016 (Santos Limited, 2016). Production from the Netherby 1 DW1 and Henry 2 wells in the Henry gas field commenced in 2010, with a combined initial production of 13 000 bbl (2067 kl) of condensate and 11 000 MMscf (311.5 MMm³) of gas. The gas from the Pecten complex will also be linked to the Henry gas field infrastructure for future production.

Origin Energy’s Halladale/Speculant gas project came online in August 2016. The project involved a new 33 km pipeline connecting the Halladale and Speculant well sites to the Otway Gas Plant, and is expected to boost production at the plant by up to 80 TJ/day from the 2017 financial year onwards (Origin Energy, 2016)

No production is currently occurring in the Torquay or deep water sub-basins.

This section provides an overview of the environmental characteristic of the Acreage Release areas and the general setting of the region overlying the Otway Basin, together with information focused on the environmental geoscience characteristics of individual Acreage Release blocks

The Otway Shelf is positioned at the northern margin of the Southern Ocean and at the western margin of Bass Strait. The seabed is composed of sandy sediments with rocky limestone or basaltic reefs present, which are remnant fragments formed by the eroding of an ancient coastline (Bird, 1993). The lithologies present on the shelf continue onshore.

Warrnambool and Port Campbell are the closest communities, which rely on fishing and tourism. Nine Commonwealth and Victorian Fisheries operate in the area.

Commonwealth Marine Reserves (CMR) and Victorian Marine National Parks are both present on the Otway Shelf (Figure 5): These include the Apollo CMR and Twelve Apostles Marine National Park (MNP). The wreck of the Loch Ard and sea stacks that make up the Twelve Apostles both lie within the MNP.

Climate of the region

The region is characterised by a cool temperate climate. Precipitation occurs throughout the year, and there are few temperature extremes. Mean minimum and maximum temperatures are 7.5°C and 21.6°C, respectively, for the period 1864–2016. Mean annual rainfall over a 151 year period at Cape Otway Lighthouse (http://www.bom.gov.au/) is 894.2 mm. The region is at the edge of a known climate change hotspot (Oliver, 2013; Hobday and Hartog, 2016).

Oceanic Regime

The region has cool temperate waters with complex oceanography due to subpolar influences from the south, subtropical influences from the Leeuwin Current along the Western Australian Coast and Great Australian Bight (Commonwealth of Australia, 2015), as well as the influence of Bass Strait immediately to the East. Nutrient-rich upwelling occurs along the shelf, offshore Bonney coast, and to the west of the area (Robe, South Australia, to Portland, Victoria) between November and April (IMCRA, 2006; Butler et al, 2002) and may also be linked to strong storm events throughout the year (Blackman et al, 1987). Mean surface water temperatures range between 14°C and 18°C. Water temperatures are 2–3°C lower than adjacent bioregions due to the cooling effect of upwelling (IMCRA, 2006; Parks Victoria, 2006). The Otway coast is a high wave-energy coastline, constantly impacted by southwesterly swells generated in the Southern Ocean (Barton et al, 2012). Mean annual wave heights of 2.7 m recorded on the coastline cause significant erosion of sea cliffs and pillars (Bird, 1993). Tides are microtidal (0.8 m to 1.2 m) (Parks Victoria, 2003).

Seabed environments: regional overview

The Otway Continental Shelf broadly has shelf-edge parallel distribution of surficial sediment facies, with two main sediment facies present. The inner shelf is dominated by hard substrate and palimpsest quartz, bivalve and bryozoan gravels. The mid-shelf is dominated by bryozoan sand (Boreen et al, 1993; Harris et al, 2000).

The Otway Basin is part of the Southeast Marine Bioregion which extends from the far south coast of New South Wales to Kangaroo Island. This region hosts high levels of biodiversity and endemism, particularly regarding macroalgae (Womersley, 1990), and possibly represents one of the most diverse marine floral assemblages in the world (Commonwealth of Australia, 2015). At a regional scale, habitats include kelp forests, temperate seagrass meadows, and rocky reefs, as well as extensive soft sediment ecosystems. These marine habitats support a diverse range of temperate marine plants, invertebrates, fishes, and larger marine animals such as whales, dolphins and seals. Humpback whales, seabirds and other threatened animals can migrate through this region on their way to breeding grounds, and other species such as blue whales may use this region as a feeding ground (Gill et al, 2011). At the smaller regional scale of provincial bioregions (IMCRA, 2006), the Otway Basin is included in the Western Bass Strait Shelf Transition, which is an area of overlap and means it does not have fauna, flora or ocean conditions distinct from adjacent areas (Commonwealth of Australia, 2015).

Recent geological history

The morphology of the Otway Shelf has been shaped by tectonic uplift that has resulted in cliffed, coastal margins composed of mid-Cenozoic limestones (Bird, 1993), and further east, the Otway Ranges. Coastal landforms present include the ‘Twelve Apostles’. These sea stacks and the adjacent cliff coasts have dominantly been shaped by nearshore processes and eustatic changes in sea level since the separation of Australia and Antarctica.

At present, the cliffed coasts of the Otway Shelf are predominantly under destructive stresses from ocean swell waves produced during Southern Ocean storms, and provide sediment to the shelf (Porter-Smith et al, 2004). The documented Quaternary sedimentary record and geomorphology of the Otway Shelf are similar to that of a tropical carbonate platform with Holocene and relict sediment overlying Cenozoic and older carbonate sedimentary rocks. However, here, the Quaternary record is essentially palimpsest, with little recent sedimentation taking place.

Offshore reef patches, remnants of shore platforms, are common on the inner to mid-shelf (Bird, 1993) and extend beyond the limits of coastal waters (Holmes et al, 2007). Remnants of drowned relict Cenozoic limestone stacks, 6 km offshore in 50 m water depths have recently been mapped (Brezore et al, 2016).

Commonwealth Marine Reserves

Apollo Commonwealth Marine Reserve

The Apollo Commonwealth Marine Reserve represents the continental shelf that extends from South Australia to the west of Tasmania. The cool waters of the reserve are less than 50 m deep near Cape Otway. The reserve includes the Otway Depression, a 100 m deep undersea valley joining Bass Basin to the open ocean. This valley was an outlet channel for the ancient Bass Lake and mainland river systems, during the last ice age.

The waters of the reserve are exposed to large swell waves generated from the south-west, as well as strong tidal flows. The sea floor has many rocky reef patches interspersed with areas of sediment and, in places, has rich, benthic fauna dominated by sponges.

Seabirds, dolphins, seals and White Sharks forage in the reserve, and Blue Whales migrate through Bass Strait.

Conservation Values: Ecosystems, habitats and communities associated with:

• the Western Bass Strait Shelf
• the Bass Strait Shelf Province
• and associated with the following seafloor features, deep/hole/valley and shelf.

The reserve is zoned Multiple Use Zone IUCN Category VI.  Management plans for the Southeast Commonwealth Marine Reserves Network are in place. Mining operations, including exploration, are allowed.

Victorian Marine Parks

Twelve Apostles Marine National Park

The iconic cliffs and pillars of the Twelve Apostles are protected by the Twelve Apostles Marine National Park. The park runs along 17 km of coastline in coastal waters, adjacent to Release Area V17-3. Arches, canyons, fissures, gutters and deep sloping reefs support kelp forests, sponge gardens, habitat for seabirds, seals, lobsters, reef fish and sea spiders. Marine mammals visit the area and Little Penguins nest in the caves below the Twelve Apostles. The park is managed for ecosystem protection and recreation. All forms of extraction are prohibited in the park (Parks Victoria, 2006).

Fisheries

Fishing effort varies spatiotemporally in the region based on fishing restrictions, stock status and environmental conditions (Larcombe et al, 2001). The following fisheries occur in the Otway Basin area:

• Scallop Fishery. The Victorian zone is between the high tide mark, excluding bays and inlets, out 20 nm (http://agriculture.vic.gov.au/fisheries/commercial-fishing/scallop). The Commonwealth zone is between the Victorian and Tasmanian fisheries that lie within 20 nm of their respective coasts (http://www.afma.gov.au/fisheries/bass-strait-central-zone-scallop-fishery/). The fishing season runs from 1 April to 31 December.
• Eastern Tuna and Billfish Commonwealth Fishery operates in the Australian Fishing Zone and adjacent high seas. The season runs for 12 months (http://www.afma.gov.au/fisheries/eastern-tuna-and-billfish-fishery-page).
• Small Pelagic Commonwealth Fishery, western sub-area. The season runs for 12 months (http://www.afma.gov.au/fisheries/small-pelagic-fishery/).
• Southern and Eastern Scalefish and Shark Fishery, Commonwealth Southeast Trawl Sector and Commonwealth Scalefish Hook Sector. The season runs 12 months (http://www.afma.gov.au/fisheries/southern-eastern-scalefish-shark-fishery/
• Southern Bluefin Tuna Commonwealth Fishery. The season runs for 12 months (http://www.afma.gov.au/fisheries/southern-bluefin-tuna-fishery/).
• Southern Squid Jig Commonwealth Fishery. The season runs for 12 months (http://www.afma.gov.au/fisheries/southern-squid-jig-fishery).
• Giant Crab Victorian Fishery, Western Zone. Closed seasons for Females, 1 June to 15 November; for Males, 15 September to 15 November (http://agriculture.vic.gov.au/fisheries/commercial-fishing/giant-crab).
• Rock Lobster Victorian Fishery, Western Zone. Closed seasons for Females, 1 June to 15 November; for Males 15 September to 15 November (http://agriculture.vic.gov.au/fisheries/commercial-fishing/rock-lobster).
• Wrasse Victorian Fishery, Extends to 20 nm from coastline (http://agriculture.vic.gov.au/fisheries/commercial-fishing/wrasse).

Information resources

AFMA Commonwealth Fisheries: http://www.afma.gov.au/fisheries/

Apollo Commonwealth Marine Reserve: https://www.environment.gov.au/topics/marine/marine-reserves/south-east/apollo

National Conservation Values Atlas: http://www.environment.gov.au/webgis-framework/apps/ncva/ncva.jsf

Twelve Apostles Marine National Park (Victoria): http://parkweb.vic.gov.au/explore/parks/twelve-apostles-marine-national-park

Victorian Commercial Fisheries: http://agriculture.vic.gov.au/fisheries/commercial-fishing

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