Legacy product - no abstract available

The Early Cretaceous Gage Sandstone and South Perth Shale formations are a prospective reservoir-seal pair in the Vlaming Sub-basin. Plays include post-breakup pinch-outs in the Gage Sandstone with the South Perth Shale forming top seal. The Gage reservoir has porosities of 18-25% and permeabilities of 1-1340 mD. It was deposited in palaeotopographic lows of the Valanginian breakup unconformity and is the lowstand component of the thick deltaic South Perth (SP) Supersequence. To characterise the reservoir-seal pair, a detailed sequence stratigraphic analysis was conducted by integrating 2D seismic interpretation, well log analysis and new biostratigraphic data. Palaeogeographic reconstructions for the SP Supersequence were derived from mapping higher-order prograding packages and establishing changes in sea level and sediment supply. Higher resolution Gage reservoir reconstructions were based on seismic facies mapping. The Gage reservoir forms part of a sand-rich submarine fan system similar to model proposed by Richards et al (1998). It ranges from canyon confined inner fan deposits to middle fan deposits on a basin plain. Directions of sediment supply are complex, with major sediment contributions from a northern and southern canyon adjacent to the Badaminna Fault Zone. The characteristics of the SP Supersequence differ markedly between the northern and southern parts of the sub-basin due to variations in palaeotopography and sediment supply. Palaeogeographic reconstructions reveal a series of regressions and transgressions leading to infilling of the palaeo-depression. Palaeogeographic reconstructions for the SP Supersequence portray a complex early post-rift depositional history in the central Vlaming Sub-basin. The developed approach is applicable for detailed studies of other sedimentary basins. APPEA

Legacy product - no abstract available

Legacy product - no abstract available

Legacy product - no abstract available

Legacy product - no abstract available

The Early Cretaceous Gage Sandstone and South Perth Shale formations are one of the most prospective reservoir-seal pairs in the Vlaming Sub-basin. Plays include post-breakup pinch-outs with the South Perth Shale forming a top seal. The Gage reservoir has porosities of 23-30% and permeabilities of 200-1800 mD and was deposited in palaeotopographic lows of the Valanginian breakup unconformity. This is overlain by the thick deltaic South Perth (SP) Supersequence. To characterise the reservoir-seal pair, a detailed sequence stratigraphic analysis was conducted by integrating 2D seismic interpretation, well log analysis and new biostratigraphic data. The palaeogeographic reconstructions for the Gage reservoir are based predominantly on the seismic facies mapping, whereas SP Sequence reconstructions are derived from mapping higher-order prograding sequences and establishing changes in sea level and sediment supply. The Gage reservoir forms part of a sand-rich submarine fan system and was deposited in water depths of > 400 m. It ranges from confined canyon fill to fan deposits on a basin plain. Directions of sediment supply are complex, with major sediment contributions from a northern and southern canyon adjacent to the Badaminna Fault Zone. The characteristics of the SP Supersequence differ markedly between the northern and southern parts of the sub-basin due to variations in palaeotopography and sediment supply. Palaeogeographic reconstructions reveal a series of regressions and transgressions leading to infilling of the palaeo-depression. Seven palaeogeographic reconstructions for the SP Supersequence portray a complex early post-rift depositional history in the central Vlaming Sub-basin. The developed approach could be applicable for detailed studies of other sedimentary basins

This study undertook geochemical and isotopic analyses on a wide selection of oil stains from the Thorntonia Limestone, Arthur Creek Formation and the Arrinthrunga Formation and its lower Hagen Member in order to define geochemical inter-relationships between the oils, characterize their source facies and to determine the extent of post-emplacement alteration. Oil stains were collected from BHD-4 and -9, Elkedra-2 and -7A, Hacking-1, MacIntyre-1, M13 PD, NTGS99/1, Owen-2, Randall-1 and Ross-1 over a depth range from 91 to 1065 m and were analysed for bulk, molecular (biomarkers) and carbon isotopic compositions. Gas chromatograph of the saturated hydrocarbon fraction clearly showed biodegradation as the main alteration process in the shallow reservoirs. Unaltered oil stains show a dominance of medium weight n-alkanes with a maximum at n-C15. Biodegradation results in a progressive loss of the lighter hydrocarbons and an accompanying shift in n-alkane maximum to C27, to finally a complete loss of n-alkanes and a large unresolved complex mixture (UCM). The absence of 25-norhopanes suggests a mild level of biodegradation. The low ratio of saturated hydrocarbons/aromatic hydrocarbons (<1, down to 0.42) compared to high ratios (up to 4.35) for oils with abundant lower molecular weight n-alkanes is consistent with biodegradation. However, low ratios are also seen for otherwise pristine oils, suggesting a complex charge history of initial biodegraded and subsequent re-charge with n-alkane-laden oil. The level of biodegradation is not too severe as to overtly affect the distribution of the biomarkers C19 - C26 tricyclic terpanes, C24 tetracyclic terpane, C27 - C35 hopanes, C30 triterpane (gammacerane) and C27- C29 desmethylsteranes, enabling their use in oil-oil correlation and definition of oil populations. To clarify the inter-relationships among the Georgina Basin oil stains multivariate statistical analysis was used involving a wide range of biomarker ratios that are source-specific and environmental indicators. Resulting oil populations showed a strong correlation with their reservoir unit across the basin, suggesting juxtaposition of source and reservoir within the same stratigraphic unit. Oil-source correlation based on biomarker, bulk carbon isotopes of saturated and aromatic hydrocarbons and n-alkane-specific carbon isotopes identified Thorntonia(!), Arthur Creek(!) and Hagen(.) Petroleum Systems. The latter petroleum system is characterised by relatively high gammacerane, indicating an evaporitic depositional environment. Alternatively, an evaporatic organic facies from an Arthur Creek Formation source may have sourced the Hagen Member oil stains, considering that other oil stains reservoired within the Arrinthrunga Formation show a close affinity with oil stains from the Arthur Creek(!) Petroleum System, suggesting an inter-formational Arthur Creek-Hagen Petroleum System at Elkedra-2. An Arthur Creek-Hagen(!) petroleum system is evident at Elkedra-7A while there is a mixed Thorntonia Limestone and Arthur Creek source contribute to the oil stain at Ross-1.

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Previously undated post Devonian sediments are shown by plant macro- and microfossils to be Early Cretaceous, and thus part of the Eromanga Basin. Modern landscape in the northern Barrier Ranges results from differential erosion following post-Early Cretaceous deformation that folded these and underlying rocks, most probably in response to reverse movements on faults at the western margin of the Bancannia Trough.