Ideally when combining legacy 3D seismic surveys, differences in acquisition parameters warrant full pre-stack reprocessing from field data. However, there are occasions where this is not possible due to time, financial or data access constraints; a valuable alternative is post-stack merging and enhancement of existing migrations. This case was to produce a regularised and seamless 3D dataset of the highest possible quality, for the offshore Otway Basin, within 2 months. The input migrated volumes varied by data extent, migration methodology, angle range and grid orientation. Fourteen input volumes totalling 8092 km2 were post-stack merged and processed to produce a continuous and consistent volume, enabling more efficient and effective interpretation of the region. The surveys were regularised onto a common grid, optimised for structural trends, prior to survey matching. A mis-tie analysis algorithm, applied over a time window optimised for interpretation of key events, was used to derive corrections for timing, phase and amplitude, using a reference. This was followed by time-variant spectral and amplitude matching to improve continuity between volumes. Additional enhancements including noise removal and lateral amplitude scaling were also applied. The final merged volume offers significant uplift over the inputs, providing better imaging of structure and events and dramatically improving the efficiency and quality of interpretation. This enables rapid reconnaissance of the area by explorers.

The inboard areas of the Otway Basin, particularly the Shipwreck Trough, are well explored and a petroleum-producing province. However, outboard in water depths greater than 500m, the basin is underexplored with distant well control and sparse 2D reflection seismic data coverage. The presence of a successful petroleum province onshore and in shallow waters raises the question as to whether these plays may extend further outboard into the deep-water areas. In the deep-water area, structural complexity and poor imaging of events in the legacy seismic data have resulted in interpretation uncertainty and consequentially a high-risk profile for explorers. The 2020 Otway Basin seismic program acquired over 7000-line km of 2D reflection seismic data across the deep-water Otway Basin. In addition, over 10000km of legacy 2D seismic data were reprocessed to improve the tie between the inboard wells and the new seismic grid. This new dataset provides the first clear insight into the structural and stratigraphic framework of this frontier area, including better imaging of the sedimentary section and the lower crust, increased structural resolution and improved calibration of the outboard seismic reflectors via ties to the inboard wells. Interpretation of the new data has led to an improved assessment of the structural elements and the extension of regional supersequences into the deep-water areas. These refinements have been used as input into petroleum systems modelling work and will provide a foundation for future work to understand petroleum prospectivity, including the distribution of source, reservoir and seal facies.

The northern Houtman Sub-basin is an under-explored region of Australia’s western continental margin. It is located at the transition between the non-volcanic margin of the northern Perth Basin and the volcanic province of the Wallaby Plateau, and lies adjacent to the Wallaby-Zenith Transform Margin. In 2014-15, Geoscience Australia acquired new 2D seismic data (GA-349) across the northern Houtman Sub-basin to assess its hydrocarbon prospectivity. This study integrated interpretation of the recently acquired GA-349 survey, with Geoscience Australia’s existing regional interpretation of the Houtman and Abrolhos sub-basins, to develop a 2D structural and stratigraphic interpretation for the study area. As there are no wells in the northern Houtman sub-basin, the age and lithologies of the mapped sequences were derived from regional mapping, stratal relationships and seismic facies. The new data clearly images a large depocentre, including a much thicker Paleozoic section (up to 13 km) than previously recognised. Extending the length of the inboard part of northern sub-basin are a series of large half-graben (7-10 km thick), interpreted to have formed as a result of Permian rifting. Overlying these half-graben, and separated by an unconformity, is a thick succession (up to 6 km) interpreted to represent a subsequent late Permian to Early Jurassic phase of the thermal subsidence. A second phase of rifting started in the Early Jurassic and culminated in Early Cretaceous breakup. The sedimentary succession deposited during this phase of rifting is highly faulted and heavily intruded in the outboard part of the basin, adjacent to the Wallaby Saddle, where intrusive and extrusive complexes are clearly imaged on the seismic. In contrast to the southern part of the Houtman Sub-basin, which experienced rapid passive margin subsidence and regional tilting after the Valanginian breakup, the northern sub-basin remained mostly exposed sub-aerially until the Aptian while the Wallaby Zenith Fracture Zone continued to develop.

The northern Houtman Sub-basin is an under-explored region of Australia’s western continental margin. It is located at the transition between the non-volcanic margin of the northern Perth Basin and the volcanic province of the Wallaby Plateau and lies adjacent to the Wallaby-Zenith Transform Margin. In 2014, Geoscience Australia acquired new 2D seismic data (GA-349, 3455 km) across the northern Houtman Sub-basin to assess its hydrocarbon prospectivity. Previous studies of the Houtman Sub-basin indicated that en-echelon basin bounding N-NW trending faults are associated with the Permian half graben complex, however, it was not known if this structural style continued into the northern area of the Houtman Sub-basin. This study integrated interpretation of the recently acquired survey, with regional interpretation of the Houtman Sub-basin. This was further supported by well data and geophysical modelling and a regional 2D structural and stratigraphic interpretation developed. Structural mapping was done for the basement, Early Triassic (Woodada Formation) and Early Jurassic (Eneabba Formation). The basement structure of the northern Houtman Sub-basin is controlled by a series of large en-echelon NW-SE trending SW dipping faults, some of which have a throw of more than 10 km. These basement-involved faults control a series of Permian half graben separated by transfer zones and fault ramps. This basement architecture is similar to the inboard part of the southern Houtman Sub-basin, however the structures are larger. The Early Triassic and Early Jurassic faults trend NW-SE similar to the basement-involved faults, however major faults within the Jurassic succession lie about 50 km to the west of the Permian faults. Interpretation of the northern Houtman Sub-basin reveals a structurally complex basin containing a wide range of structural and stratigraphic traps at several stratigraphic levels. Potential plays have been identified in the upper Permian, Triassic and Jurassic successions. They include large stratigraphic plays in the Upper Permian/Lower Triassic, rollover anticlines within the Lower Triassic and Jurassic, and fault propagation folds and fault block plays in the Jurassic.

The Southern Platform of the Gippsland Basin of southeastern Australia contains a mixed carbonate-elastic succession deposited on the outer continental shelf in water depths of 50-200 m. Seismic geometry indicates the presence of likely carbonate build-ups formed in deeper water near the north-eastern edge of the Southern Platform by bryozoan mounds which pass to the northeast into distal bottom set deposits in shelf edge clinoforms. Mass Transport Complexes (MTCs) developed along the paleo-shelf edge and basin bounding faults through repeated failure from the Late Oligocene to the Mid Miocene. Two distinct Mass Transport Complexes are present. The Sailfish MTC affects a zone 7 km wide along the paleo-shelf edge in the SE of the area and features slumped paleo-shelf masses with listric faulting and toe thrusts in places. Some inversion of slump-related structures indicates continued movement after an initial failure event. The Devilfish MTC is up to 32 km wide and consists of a zone of extension which passes downslope into a broad zone of compressional structures which die out downslope without the development of a clear emergent slump mass or a terminal structure. Stratigraphic relationships suggest that it formed progressively by creep from the Late Oligocene to the Late Miocene. The difference in deformation styles between the two MTCs can be explained by proximity to major basin forming faults. The Devilfish MTC formed where the paleo-shelf edge sat adjacent to an underlying fault which juxtaposes deeper basin fill sediments against basement. This geometry provided abundant pore water to weaken the overlying sediments which failed under differential loading imposed by shelf edge build ups to form the MTC, possibly triggered by repeated earthquakes. Devilfish MTC differs from mass transport deposit described in the literature in comprising an extensional headwall zone and a main body affected by compressional structures which then die out downslope, probably because of thickening of the section and a return to normal porewater pressures basin-ward. This type of MTC could be termed "Frontally Diffuse" in contrast to the recognised Frontally Emergent and Frontally Confined MTC terminations.

During the Late Cretaceous, the eastern Australian margin rifted to form the Lord Howe Rise continental ribbon. To understand the history of this region since rifting we use reflection seismic data collected in 2016 onboard R/V Kairei. We focus on processing and interpreting a regional ~900-km-long east-west oriented seismic reflection profile at 27.2°S. The seismic data were processed through pre-stack depth migration and interpretation shows the structure and evolution of this margin. The profile covers the oceanic Tasman Basin through the continental Lord Howe Rise. Sediment-filled depressions are found within the Tasman Basin and likely relate to early transform faulting with later deposition. The Lord Howe Rise is largely made up of syn-rift and post-rift sedimentary sequences in multiple structurally controlled basins. Two additional features are found between these regions, the Dampier Ridge and the Middleton Basin. The Dampier Ridge has a sharp, probably transform, boundary against the eastern edge of the Tasman Basin. Within the ridge are multiple rift basins up to 3 km deep that are comparable in size and structure to those found on the Lord Howe Rise. Between the Dampier Ridge and the Tasman Basin is the Middleton Basin which contains well-stratified sediments that are up to ~3.5 km thick. Stratal relationships indicate that the Middleton Basin formed during a post-rift event with large amounts of subsidence. Deep reflections beneath this basin reveal mantle at a shallow depth. The results have important implications for the evolution of the margin from initial rifting, opening of the Tasman Basin, and subsequent deformational processes. SCG71-01 JpGU-AGU Joint Meeting 2017

New 2D seismic data acquired by Geoscience Australia in the northern Houtman Sub-basin of the Perth Basin provides important information on the prospectivity of this frontier area. To date, lack of quality seismic data and limited geological understanding have led to the perception that the hydrocarbon potential of the area is very low. However, interpretation of newly collected data suggests that the northern Houtman depocentre contains up to 15 km of pre-breakup sediments comprised of Permian, Triassic and Jurassic successions, which potentially contain multiple source rock, reservoir and seal intervals. The Permian syn-rift succession is confined to a series of large half-graben that are controlled by basement-involved faults separating the Houtman depocentre from the Bernier Platform. This succession is up to 10 km thick and is mapped throughout the inboard part of the new seismic grid. A prominent unconformity at the top of the Permian syn-rift sequence is overlain by a thick (up to 1800 m) and regionally extensive seismic sequence interpreted as the Lower Triassic Kockatea Shale. The thickness of the overlying Triassic succession ranges from approximately 1 km in the inboard part of the basin to up to 5 km further outboard. The Jurassic succession is thickest (up to 4 km) in the outboard part of the basin and is interpreted to contain sequences corresponding to the Cattamarra, Cadda and Yarragadee formations. Our study integrates new results from regional mapping, geophysical modelling and petroleum systems analysis, which enables a more accurate prospectivity assessment of this frontier basin.

New 2D seismic data, acquired by Geoscience Australia in the northern Houtman Sub-basin of the Perth Basin, provides important information on the prospectivity of this frontier area. To date, lack of quality seismic data and limited geological understanding led to the perception that the hydrocarbon potential of the area is very low. However, interpretation of newly collected data suggests that the northern Houtman depocentre contains up to 15 km of pre-breakup sediments composed of Permian, Triassic and Jurassic successions, which potentially contain multiple source rock, reservoir and seal intervals. The Permian syn-rift succession is confined to a series of large half-graben that are controlled by basement-involved faults separating the Houtman depocentre from the Bernier Platform. This succession is up to 10 km thick and is mapped throughout the inboard part of the new seismic grid. A prominent unconformity at the top of the Permian syn-rift sequence is overlain by a thick (up to 1800 m) and regionally extensive seismic sequence interpreted as the Lower Triassic Kockatea Shale. The thickness of the overlying Triassic succession ranges from about 1 km in the inboard part of the basin to up to 5 km further outboard. The Jurassic succession is thickest (up to 4 km) in the outboard part of the basin and is interpreted to contain sequences corresponding to the Cattamarra, Cadda and Yarragadee formations. Our study integrates new results from regional mapping, geophysical modelling and petroleum systems analysis, which enables a more accurate prospectivity assessment of this frontier basin.

Interpretation of newly acquired seismic data in the northern Houtman Sub-basin (Perth Basin) suggests the region contains potential source rocks similar to those in the producing Abrolhos Sub-basin. The regionally extensive late Permian–Early Triassic Kockatea Shale has the potential to contain the oil-prone Hovea Member source interval. Large Permian syn-rift half-graben, up to 10 km thick, are likely to contain a range of gas-prone source rocks. Further potential source rocks may be found in the Jurassic–Early Cretaceous succession, including the Cattamarra Coal Measures, Cadda shales and mixed sources within the Yarragadee Formation. This study investigated the possible maturity and charge history of these different source rocks. A regional pseudo-3D petroleum systems model was constructed using new seismic interpretations. Heat flow was modelled using crustal structure and possible basement composition determined from potential field modelling, and subsidence analysis was used to investigate lithospheric extension through time. The model was calibrated using temperature and maturity data from nine wells in the Houtman and Abrolhos sub-basins. Source rock properties are assigned based on an extensive review of total organic carbon, Rock Eval and kinetic data for the offshore northern Perth Basin. Petroleum systems analysis results show that Permian, Triassic and Early Jurassic source rocks may have generated large cumulative volumes of hydrocarbons across the northern Houtman Sub-basin, whereas the Middle Jurassic–Cretaceous sources remain largely immature. However, the timing of hydrocarbon generation and expulsion with respect to trap formation and structural reactivation is critical for the successful development and preservation of hydrocarbon accumulations.

PreviousNext You have accessInternational Conference and Exhibition, Melbourne, Australia 13-16 September 2015A Geochemical Overview of Gippsland Basin Hydrocarbon AccumulationsAuthors: Dianne S. Edwards*Manzur AhmedTom BerneckerChristopher J. BorehamJunhong ChenSe GongLouise Goldie-DivkoJohn GorterLisa HallRobert P. LangfordCameron MitchellHerbert VolkDianne S. Edwards* Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Manzur Ahmed Energy Flagship, CSIRO, Sydney, New South Wales, Australia.Search for more papers by this author, Tom Bernecker Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Christopher J. Boreham Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Junhong Chen Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Se Gong Energy Flagship, CSIRO, Sydney, New South Wales, Australia.Search for more papers by this author, Louise Goldie-Divko Earth Resources, Geological Survey of Victoria, Melbourne, Victoria, Australia.Search for more papers by this author, John Gorter Exploration & Production Division, ENI, Milan, Italy.Search for more papers by this author, Lisa Hall Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Robert P. Langford Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Cameron Mitchell Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, and Herbert Volk Energy Flagship, CSIRO, Sydney, New South Wales, Australia.Search for more papers by this authorhttps://doi.org/10.1190/ice2015-2210785 SectionsAbout ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract In the 50 years since the first commercial discovery in 1965 at Barracouta-1, and 46 years since production commenced from the Barracouta field, a total of 16.5 TCF of gas, 4026 MMbbl of oil, 385 MMbbl of condensate and 752 MMbbl of LPG have been found in the Gippsland Basin (Estimated Ultimate Recovery, as at the end of 2012). Despite these extensive resources, all from Cretaceous–Paleogene Latrobe Group reservoirs, there are questions regarding the operating petroleum systems, contributing source rock units, and the migration pathways between source and reservoir. Resolution of these uncertainties is essential to improve our understanding of the remaining prospectivity and for creating new exploration opportunities, particularly in the eastern, less explored part of the basin, but also for mitigating risk for the potential sequestration of carbon dioxide along the southern and western flanks. Geochemical fingerprinting of reservoir fluids has identified that the oil and gas originate from multiple sources. The most pervasive hydrocarbon charge into the largely produced fields overlying the Central Deep has a terrestrial source affinity, originating from lower coastal plain facies (Kingfish, Halibut, Mackerel), yet the oils cannot be correlated using source-related biomarker parameters to source rocks either within the Halibut Subgroup (F. longus biozone) at Volador-1, one of the deepest penetrations of the Upper Cretaceous section, or to older sections, penetrated on the flanks of the basin. However, within the underlying Santonian–Campanian Golden Beach Subgroup an oil-source correlation has been established between the Anemone-1A oil and the marginal marine Anemone Formation (N. senectus biozone) at Anemone-1/1A and Archer-1. A similar correlation is indicated for the Angler-1 condensate to the Chimaera Formation (T. lilliei biozone) in the deepest section at Volador-1 and Hermes-1. In the Longtom field, gas reservoired within the Turonian Emperor Subgroup, potentially has a source from either the lacustrine Kipper Shale or the Albian portion of the Strzelecki Group. The molecular and carbon isotopic signatures of oil and gas from the onshore Wombat field are most similar to hydrocarbons sourced from the Aptian–Albian Eumeralla Formation in the Otway Basin, also implicating a Strzelecki source in the Gippsland Basin. These results imply that sediments older than the Paleocene are significant sources of petroleum within the basin. Keywords: Gippsland Basin, geochemical, hydrocarbonPermalink: https://doi.org/10.1190/ice2015-2210785FiguresReferencesRelatedDetailsCited byThe story of Esso Australia’s push to explore the frontier Gippsland Basin with the ultra-deep water Sculpin-1 exploration well13 May 2022 | The APPEA Journal, Vol. 62, No. 2 International Conference and Exhibition, Melbourne, Australia 13-16 September 2015ISSN (online):2159-6832Copyright: 2015 Pages: 564 publication data© 2015 Published in electronic format with permission by the Society of Exploration Geophysicists and the American Association of Petroleum GeologistsPublisher:Society of Exploration Geophysicists HistoryPublished Online: 16 Sep 2015 CITATION INFORMATION Dianne S. Edwards*, Manzur Ahmed, Tom Bernecker, Christopher J. Boreham, Junhong Chen, Se Gong, Louise Goldie-Divko, John Gorter, Lisa Hall, Robert P. Langford, Cameron Mitchell, and Herbert Volk, (2015), "A Geochemical Overview of Gippsland Basin Hydrocarbon Accumulations," SEG Global Meeting Abstracts : 281-281. https://doi.org/10.1190/ice2015-2210785 Plain-Language Summary KeywordsGippsland BasingeochemicalhydrocarbonLoading ...

Palaeogeographical reconstructions of the Australian and Antarctic margins based on matching basement structures are commonly difficult to reconcile with those derived from ocean-floor magnetic anomalies and plate vectors. Following identification of a previously unmapped crustal-scale structure in the southern part of the early Palaeozoic Delamerian Orogen (Coorong Shear Zone), a more tightly constrained plate reconstruction for these margins is proposed. This reconstruction places the Coorong Shear Zone opposite the Mertz Shear Zone in Antarctica and lends itself to a revised interpretation of continental rifting along Australia’s southern margin in which rift basin architecture, margin segmentation and the formation of ocean-floor fracture zones are all linked to pre-existing basement structure and the reactivation of a few deep-rooted crustal structures inherited from the Delamerian Orogeny in particular. Reactivation of the Coorong Shear Zone and other basement structures (Avoca–Sorell Fault Zone) during the earlier stages of rifting was accompanied by the partitioning of extensional strain and formation of late Jurassic–Early Cretaceous normal faults and half-graben in the Bight and Otway basins with opposing NE–SW and NW–SE structural trends. Previously, the Mertz Shear Zone has been correlated with the Proterozoic Kalinjala Mylonite Zone in the Gawler Craton but this positions Australia 300–400 km too far east relative to Antarctica prior to breakup and fails to secure an equally satisfactory match in both basement geology and the superimposed extension-related structures.

The frontier deepwater Otway and Sorell basins lie offshore of southwestern Victoria and western Tasmania at the eastern end of Australia’s Southern Rift System. The basins developed during rifting and continental separation between Australia and Antarctica from the Cretaceous to Cenozoic. The complex structural and depositional history of the basins reflects their location in the transition from an orthogonal–obliquely rifted continental margin (western–central Otway Basin) to a transform continental margin (southern Sorell Basin). Despite good 2D seismic data coverage, these basins remain relatively untested and their prospectivity poorly understood. The deepwater (> 500 m) section of the Otway Basin has been tested by two wells, of which Somerset–1 recorded minor gas shows. Three wells have been drilled in the Sorell Basin, where minor oil shows were recorded near the base of Cape Sorell–1. As part of the federal government-funded Offshore Energy Security Program, Geoscience Australia has acquired new aeromagnetic data and used open file seismic datasets to carry out an integrated regional study of the deepwater Otway and Sorell basins. Structural interpretation of the new aeromagnetic data and potential field modelling provide new insights into the basement architecture and tectonic history, and highlights the role of pre-existing structural fabric in controlling the evolution of the basins. Regional scale mapping of key sequence stratigraphic surfaces across the basins, integration of the regional structural analysis, and petroleum systems modelling have resulted in a clearer understanding of the tectonostratigraphic evolution and petroleum prospectivity of this complex basin system.

Summary The deepwater Otway and Sorell basins developed during the breakup of Gondwana when Australia rifted from Antarctica. Regional 2D and 3D gravity modelling in conjunction with seismic and geological interpretation has led to an improved understanding of basement architecture in the study area. 2D gravity modelling along selected seismic lines reveals a N-S crustal-scale lineament extending to the Moho. A distinct density contrast of 0.16 t/m3 (i.e., between 3.05 t/m3 and 2.91 t/m3) across the structure points to significant lithological changes at middle to lower crustal depths, interpreted here to reflect a change from dominantly mafic to felsic lower crust. This structure is interpreted to be inherited from a pre-existing basement structure and supports the hypothesis that the evolution of the Sorell Basin was influenced by this basement structure. The 2D models also infer the presence of mafic under-plating in the lower-crust. The computed 3D gravitational response derived from interpreted seismic data correlates moderately well to the observed gravity interpretation and (a) implies consistency between the seismic and gravity response of the interpreted model, and (b) delineates the basement topography and identifies possible depocentres. The independently-derived depth to magnetic basement map supports the 3D forward gravity modelling results.

Summary Basement architecture off western Tasmania is a legacy of late Neoproterozoic-Cambrian subduction-related processes, ocean basin closure and multiple accretionary events, culminating in formation of the Delamerian-Ross and western Lachlan Orogens. Structures associated with these fold belts were subsequently reactivated during late Mesozoic-Cenozoic Gondwana breakup and the separation of Australia from Antarctica, strongly influencing the pattern and geometry of offshore rifting, including formation of an ocean-continent transform boundary off western Tasmania. Seismic reflection profiles combined with recently acquired high resolution aeromagnetic data permit this boundary and its associated reactivated basement structures (Avoca-Sorell Fault system) to be mapped in greater detail than has hitherto been possible and point to a transform margin dominated by steeply outward-dipping structures and deep sedimentary basins similar to other transform margin ocean-continent boundaries. These include the highly prospective Côte d’Ivore-Ghana region off the west African coast. Basement highs and rotated pre-rift crustal blocks adjacent to the west Tasmanian transform margin incorporate significant volumes of granite as well as a lower crust of probable Mesoproterozoic age that is locally juxtaposed against lower Paleozoic sequences intruded and/or floored by basaltic and ultramafic material. Aeromagnetic anomalies sourced from these basement rocks change orientation from NW- to NE-trending across the Avoca-Sorell Fault system and can be traced laterally into regions of known onshore basement geology, highlighting both the tectonic significance of this structure and its origins during lower Paleozoic deformation accompanying the Delamerian-Ross Orogeny.

The geology and petroleum potential of the western Tasmanian offshore basins is poorly understood. As part of a strategy to improve the understanding of these basins, aeromagnetic data was acquired by Geoscience Australia and Mineral Resources Tasmania under a National Geoscience Agreement and partly funded by the Commonwealth Government?s Offshore Energy Security Program. The survey acquired 141,234 line km of high quality data with a line spacing of 800 m across the Bass, southern Otway and Sorell basins and Torquay Sub-basin (Figure 1). The aim of this survey was to acquire new aeromagnetic data to help delineate the structural architecture of the basins and underlying basement and the distribution of igneous rocks. The data fill a gap in the existing aeromagnetic coverage between Tasmania and mainland Australia and provide fresh insights into basement structure and its control on basin architecture and sedimentation patterns during the breakup of Gondwana and separation of Australia from Antarctica.