The 2012 Australian offshore acreage release includes exploration areas in four southern margin basins. Three large Release Areas in the frontier Ceduna Sub-basin lie adjacent to four exploration permits granted in 2011. The petroleum prospectivity of the Ceduna Sub-basin is controlled by the distribution of Upper Cretaceous marine and deltaic facies and a structural framework established by Cenomanian growth faulting. These Release Areas offer a range of plays charged by Cretaceous marine and coaly source rocks and Jurassic lacustrine sediments. In the westernmost part of the gas-producing Otway Basin, a large Release Area offers numerous opportunities to test existing and new play concepts in underexplored areas beyond the continental shelf. Gas and oil shows in the eastern part of the Release Area confirm the presence of at least two working petroleum systems. In the eastern Otway Basin, several Release Areas are offered in shallow water on the eastern flank of the highly prospective Shipwreck Trough and provide untested targets along the eastern basin margin southward into Tasmanian waters. To the south, a large Release Area in the frontier Sorell Basin provides the opportunity to explore a range of untested targets in depocentres that formed along the western Tasmanian transform continental margin. Two Release Areas offer exploration potential in the under-explored eastern deepwater part of the Gippsland Basin. Geological control is provided by several successful wells indicating the presence of both gas and liquids in the northern area, while the southern area represents the remaining frontier of the basin.

Overview of the Deep Crustal Seismic surveys conducted by Geoscience Australia and funded through the Onshore Energy Security Program since it's commencement in 2006 to September 2009.

2012 Acreage Release information pack

Legacy product - no abstract available

Legacy product - no abstract available

Extended abstract version of short abstract accepted for conference presentation GEOCAT# 73701

The Beagle Sub-basin is a Mesozoic rift basin in the Northern Carnarvon Basin. Oil discovered at Nebo-1 highlights an active petroleum system. 3D seismic interpretation identified pre, syn and post-rift megasequences. Pre-rift fluvio-deltaic and marine sediments were deposited during a thermal sag phase of the Westralian Super Basin. Low rates of extension (Rhaetian to Oxfordian) deposited fluvio-deltaic and marine sediments. During early post-rift thermal subsidence, sediments onlapped and eroded tilted fault blocks formed during the syn-rift phase. Consequently the regional seal (Early Cretaceous Muderong Shale) is absent in the centre. Subsequent successions are dominated by a prograding carbonate wedge showing evidence of erosion from tectonic and eustatic sea level change. 1D burial history modeling of Nebo-1 and Manaslu-1 show that all source rocks are currently at their maximum depths of burial. Sediments to the Late Cretaceous are in the early maturity window for both wells. The Middle Jurassic Legendre Formation reaches mid maturity in Nebo-1. Source, reservoir and seals are present throughout the Triassic to earliest Cretaceous, however, the absence of the regional seal in the central sub-basin reduces exploration targets. The lack of significant inversion increases the likelihood of maintaining trap integrity. Potential plays include compaction folds over tilted horst blocks, roll over and possible inversion anticlines, basin floor fans and intra-formational traps within fluvio-deltaic deposits. Late Cretaceous and younger sediments are unlikely to host significant hydrocarbons due to lack of migration pathways. Source rocks are of adequate maturity and deep faults act as pathways for hydrocarbon migration.

We measured the light absorption properties of two naturally occurring Australian hydrocarbon oils, a Gippsland light crude oil and a North West Shelf light condensate. Using these results in conjunction with estimated sensor environmental noise thresholds, the theoretical minimum limit of detectability of each oil type (as a function of oil thickness) was calculated for both the hyperspectral HYMAP and multispectral Quickbird sensors. The Gippsland crude oil is discernable at layer thickness of 20 micro metres or more in the Quickbird green channel. The HYMAP sensor was found to be theoretically capable of detecting a layer of Gippsland crude oil with a thickness of 10 micro metres in approximately six sensor channels. By contrast, the North West Shelf light condensate was not able to be detected by either sensor for any thickness up to 200 icro metres. Optical remote sensing is therefore not applicable for detecting diagnostic absorption features associated with this light condensate oil type, which is considered representative for the prospective Australian Northwest Shelf area. We conclude that oil type is critical to the applicability of optical remote sensing for natural oil slick detection and identification. We recommend that a sensor- and oil-specific sensitivity study should be conducted prior to applying optical remote sensors for oil exploration. The oil optical properties were obtained using two different laboratory methods, a reflectance-based approach and transmittance-based approach. The reflectance-based approach was relatively complex to implement, but was chosen in order to replicate as closely as possible real world remote sensing measurement conditions of an oil film on water. The transmittance-based approach, based upon standard laboratory spectrophotometric measurements was found to generate results in good agreement with the reflectance-based approach. Therefore, for future oil- and sensor-specific sensitivity studies, we recommend the relatively accessible transmittance-based approach, which is detailed in this paper.

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.

Legacy product - no abstract available