The Mesozoic Beagle Sub-basin is in the Northern Carnarvon Basin, offshore Western Australia. Oil discovered at Nebo 1 in 1993 highlights an active petroleum system. The central Beagle Sub-basin, this study's focus, has a north-south trending horst-graben architecture. Detailed mapping of the 1529 km2 Beagle Multi-client 3D seismic survey gave insight into its geological history. The Rhaetian to Valanginian syn-rift succession comprises fluvio-deltaic and marine sediments deposited during low rates of crustal extension. During post-rift thermal subsidence, sediments onlapped eroded and tilted fault blocks formed during the syn-rift phase. Consequently, the Early Cretaceous regional seal is absent in the central study area. Overlying sedimentary successions are dominated by a prograding carbonate wedge. Potential source, reservoir and seal facies are present from the Triassic to earliest Cretaceous. 1D burial history modelling indicates that in Nebo 1, potential source rocks from the Middle Jurassic to Early Cretaceous became oil mature after the emplacement of the regional seal. At Manaslu 1, these sediments are immature. Potential source rocks are currently at maximum burial depth and thermal maximum. Trap integrity in the pre and syn-rift succession could be jeopardized by fault reactivation, however post-rift traps may be preserved. Potential plays include compaction folds over tilted horst blocks, anticlines, basin-floor fans and intra-formational traps. Hydrocarbons could use deep faults to migrate into Early Cretaceous plays. Younger sediments lack migration pathways so are unlikely to host significant hydrocarbons. Poor quality source rocks and reservoirs, and poor source rock distribution may also contribute to disappointing exploration results.

This study assesses the petroleum potential of the Paleo–Mesoproterozoic Birrindudu Basin in the northwestern Northern Territory, which is one of several Proterozoic basins in northern Australia with the potential to host conventional and unconventional petroleum accumulations. Historical source rock geochemistry, porosity, and permeability data from the Birrindudu Basin are collated and interpreted; in addition, new fluid geochemistry is interpreted within the context of the greater McArthur Basin. The limited data available indicate that at least four formations have good or excellent present-day organic richness (>2 wt% TOC), and several sandstone and carbonate reservoirs have good porosity data. The calculated brittleness index of a number of organic-rich shales suggests that several are likely to be favourable for fracture stimulation and therefore might constitute good unconventional hydrocarbon targets. Four continent-scale petroleum supersystems are identified, two of which are described for the first time. These supersystems are an important tool in understanding the petroleum potential in frontier basins with limited data. Additionally, a number of basin-scale petroleum systems are potentially present within the basin successions; 14 possible conventional systems and 9 possible unconventional systems are documented. Petroleum play concepts are also described to assist with assessing the potential for conventional and unconventional hydrocarbon resources. The ultimate aim is to identify areas that can be targeting for precompetitive geoscience data acquisition, so as to reduce the exploration search space. Presented at Annual Geoscience Exploration Seminar (AGES) April 2021 (p115 - p130)

The under-explored deepwater Otway and Sorell basins lie offshore of southwestern Victoria and western Tasmania in water depths of 100-4,500 m. The basins developed during rifting and continental separation between Australia and Antarctica from the Cretaceous to Cenozoic and contain up to 10 km of sediments. Significant changes in basin architecture and depositional history from west to east reflect the transition from a divergent rifted continental margin to a transform continental margin. The basins are adjacent to hydrocarbon-producing areas of the Otway Basin, but despite good 2D seismic data coverage, they remain relatively untested and their prospectivity is 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 within the Upper Cretaceous section. Three wells have been drilled in the Sorell Basin, where minor oil and gas indications were recorded in Maastrichtian rocks near the base of Cape Sorell 1. Building on previous GA basin studies and using an integrated approach, new aeromagnetic data, open-file potential field, seismic and exploration well data have been used to develop new interpretations of basement structure and sedimentary basin architecture. Analysis of potential field data, integrated with interpretation of 2D seismic data, has shown that reactivated north-south Paleozoic structures, particularly the Avoca-Sorell Fault System, control the transition from extension through transtension to a dominantly strike-slip tectonic regime along this part of the southern margin. Depocentres to the west of this structure are large and deep in contrast to the narrow elongate depocentres to its east. Regional-scale mapping of key sequence stratigraphic surfaces across the basins has resulted in the identification of distinct basin phases. Three periods of upper crustal extension can be identified. In the north, one phase of extension in the Early Cretaceous and two in the Late Cretaceous can be mapped. However, to the south, the Late Cretaceous extensional phase extends into the Paleocene, reflecting the diachronous break-up history. Extension was followed by thermal subsidence, and during the Eocene-Oligocene the basin was affected by several periods of compression, resulting in inversion and uplift. The new seismic interpretation shows that depositional sequences hosting active petroleum systems in the producing areas of the Otway Basin are also likely to be present in the southern Otway and Sorell basins. Petroleum systems modelling suggests that if the equivalent petroleum systems elements are present, then they are mature for oil and gas generation, with generation and expulsion occurring mainly in the Late Cretaceous in the southern Otway and northern Sorell basins and during the Paleocene in the Strahan Sub-basin (southern Sorell Basin). The integration of sequence stratigraphic interpretation of seismic data, regional structural analysis and petroleum systems modelling has resulted in a clearer understanding of the tectonostratigraphic evolution of this complex basin system. The results of this study provide new insights into the geological controls on the development of the basins and their petroleum prospectivity.

Geoscience Australia has recently completed a marine survey in the offshore northern Perth Basin, off Western Australia (Jones et al., 2011b; Jones, 2011c, Upton and Jones, 2011). One of the principal aims of the survey was the collection of evidence for natural hydrocarbon seepage. The survey formed part of a regional reassessment of the basin's petroleum prospectivity in support of frontier exploration acreage Release Area W11-18. This reassessment was initiated under the Australian Government's Offshore Energy Security Program and formed part of Geoscience Australia's continuing efforts to identify a new offshore petroleum province. The offshore northern Perth Basin was identified as a basin with new frontier opportunities. New data demonstrated that proven onshore-nearshore petroleum system is also effective and widespread in the offshore (Jones et al., 2011a). Evidence for a Jurassic petroleum system was also demonstrated in the Release Area W11-18 (Jones et al., 2011a). The marine survey results provide additional support for the presence of an active petroleum system in the northern Perth Basin.

In this study detailed mapping of seismic data from the 1529 km2 Beagle multi-client 3D seismic survey was undertaken to provide a better understanding of the geological history of the central Beagle Sub-basin. Situated in the Northern Carnarvon Basin, oil discovered at Nebo 1 in 1993 indicated the presence of at least one active petroleum system. The central part of the sub-basin has a N-trending horst-graben architecture. Two rifting events from the Hettangian to Sinemurian and the Callovian to Oxfordian were identified. A series of tilted fault blocks formed by the rifting events were locally eroded and progressively draped and buried by post-rift thermal subsidence sedimentation. Mapping indicated the Post-rift I Lower Cretaceous Muderong Shale regional seal is anomalously thin or absent in the intra-horst graben area. Burial history 1D modelling indicates that at Nebo 1, the most rospective potential source rocks within the Middle-Upper Jurassic section where in the early oil window; however, if present within the Beagle and Cossigny trough depocentres, these sediments would have entered the oil window prior to the deposition of the Muderong Shale regional seal. Upper Jurassic shales provide seal for the oil pool intersected in Nebo 1. The Tertiary section is dominated by a prograding carbonate wedge which has driven a second phase of thermal maturation observed in the Paleogene (Nebo 1) and Miocene (Manaslu 1). Potential source rocks are currently at their maximum depth of burial and maximum thermal maturity. Modest inversion on some faults prior to the Early Cretaceous has created traps and if source rocks retain generative potential, favourable traps could be now actively receiving hydrocarbon charge. Potential plays include compaction folds over tilted horst blocks, drape and small inversion induced anticlines, basin-floor fans and intra-formational traps. Deep faults may act as conduits for hydrocarbons migrating from mature potential source rocks into Jurassic to Cretaceous plays. Younger sediments appear to lack access to migration pathways provided by deeper faults.

Introduction: As part of the Offshore Energy Security Program (2007-2011), Geoscience Australia (GA) undertook an integrated regional study of the deepwater Otway and Sorell basins to improve the understanding of the geology and petroleum prospectivity of the region. The under-explored deepwater Otway and Sorell basins lie offshore of southwestern Victoria and western Tasmania in water depths of 100-4,500 m. The basins developed during rifting and continental separation between Australia and Antarctica from the Cretaceous to Cenozoic and contain up to 10 km of sediment. Significant changes in basin architecture and depositional history from west to east reflect the transition from a divergent rifted continental margin to a transform continental margin. The basins are adjacent to hydrocarbon-producing areas of the Otway Basin, but despite good 2D seismic data coverage, they 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. Structural framework: Using an integrated approach, new aeromagnetic data, open-file potential field, seismic and exploration well data were used to develop new interpretations of basement structure and basin architecture. This analysis has shown that reactivated north-south Paleozoic structures, particularly the Avoca-Sorell Fault System, controlled the transition from extension through transtension to a dominantly strike-slip tectonic regime along this part of the southern margin. Depocentres to the west of this structure are large and deep in contrast to the narrow elongate depocentres to its east. ...

Release Area W11-18 is a very large block over the offshore northern Perth Basin, covering parts of the Abrolhos, Houtman and Vlaming sub-basins and the Beagle and Turtle Dove ridges. Geoscience Australia (GA) has assessed the petroleum prospectivity of this area as part of the Australian Government's Offshore Energy Security Program. This assessment includes the first published synthesis of data from fourteen new field wildcat wells drilled in this part of the basin since the Cliff Head-1 discovery (2001), and the interpretation of new regional 2D seismic data acquired during GA survey 310 (2008-2009). A refined tectono-stratigraphic model for the offshore basin provides insights into basin evolution and prospectivity. Oil has been produced since 2006 from the Cliff Head oil field in WA-31-L, which is directly adjacent to Release Area W11-18. Three petroleum discoveries are included within the Release Area, with oil and gas in Dunsborough-1, and gas in Frankland-1 and Perseverance-1. These accumulations are reservoired in Permian sandstones and have primarily been sourced from the Hovea Member of the Kockatea Shale, which has also sourced the majority of producing oil and gas fields of the onshore Perth Basin. New seismic data show Permo-Triassic strata that are stratigraphic equivalents of the productive onshore and nearshore Perth Basin petroleum system, also occur within Permian half-graben in the outer Abrolhos and Houtman sub-basins. Source rock, oil stain and fluid inclusion sampling from this interval suggest that the proven onshore-nearshore petroleum system is also effective and widespread in the offshore. There is also evidence for an active Jurassic petroleum system within the Release Area. The Release Area offers a range of plays in a variety of water depths, predominantly less than 200 m, and is highly prospective for oil and gas.

A geological investigation, directed mainly towards the assessment of oil potentialities of the Basin, was commenced in 1948 by the Bureau of Mineral Resources, Geology and Geophysics when a small geological party carried out a reconnaissance of the Minilya River area. Since then up to seven geologists of the Bureau under the direction of M. A. Condon have been mapping the area in some detail each year in order to determine the stratigraphical sequence and its variations, regional structure, and the anticlinal structures and their extent. In addition to the regional mapping the two largest anticlines were mapped in detail. Geophysical work (gravity and seismic) has been carried out by the Geophysical section of the Bureau (see Record 1954/44). More recently, Seismograph Services Ltd. carried out a seismic survey for West Australian Petroleum Pty. Ltd. - mainly for the purpose of checking on the location of its first deep test, which is now being drilled on the Rough Range Anticline with some encouraging results to date. Palaeontological, petrographical and chemical examinations of specimens collected in the field are still continuing by specialists of the Bureau and outside.

Exploration for Unconventional Hydrocarbons in Australia reached a new milestone when Beach Energy announced the first successful flow test of a shale gas target in the Cooper Basin. Significant exploration activity is being seen in the Amadeus, Pedirka and Georgina basins and Beetaloo Sub-basin, while little is known of the potential of many other Central Australian basins. The globally acknowledged large resource potential of coal seam gas, shale and tight gas on the continent in addition to low sovereign risk has put Australia firmly on the radar of many local and international exploration companies. Over the next 12 months Geoscience Australia in collaboration with its counterparts in the State and Territory resource and energy departments will undertake an initial assessment of Australia's unconventional hydrocarbon resource potential. Capitalising on decades of high quality geological data held by the Commonwealth and the States and Territories, the programme aims to compile these data using nationally consistent assessment methodologies that ultimately provide robust figures in an internationally accepted standard. The immediate goal is to provide a first-pass, high level estimate of the likely resource volumes, which will be reported in the second edition of the Australian Energy Resource Assessment (published by RET). The longer term work program aims to assess Australia's onshore basins in terms of their resource potential and provide pre-competitive data to industry. To achieve this, several geological techniques will be applied including, but not limited to, geochemical screening, mapping of source rock occurrences and their distributions as well as physical rock property studies.

Exploration for Unconventional Hydrocarbons in Australia reached a new milestone when Beach Energy announced the first successful flow test of a shale gas target in the Cooper Basin. The ever expanding coal seam gas industry on Australia's east coast in addition to the large resource potential of shale and tight gas in Australia's eastern basins has put Australia firmly on the radar of many local and international exploration companies. Over the next 12 months Geoscience Australia in collaboration with its counterparts in the State and Territory resource and energy departments will begin an assessment of Australia's coal seam gas, shale gas and oil and tight gas resource potential. Capitalising on decades of high quality geological data held by the Commonwealth and the States and Territories, the aim of this collaboration is to develop nationally consistent assessment methodologies and provide robust national resource estimates in an internationally accepted standard. Overall, the programme aims to answer the 'where' and 'how much' questions for government, as well as provide this new industry with pre-competitive data and tools for comparing exploration opportunities. The immediate goal is to provide a first-pass, high level estimate of the likely resource volumes, which will be reported in the second edition of the Australian Energy Resource Assessment (published by RET). The longer term work program aims to assess Australia's onshore basins in terms of their resource potential and provide pre-competitive data to industry. To achieve this, several geological techniques will be applied including, but not limited to, geochemical screening, mapping of source rock occurrences and their distributions as well as physical rock property studies.