Legacy product - no abstract available

Legacy product - no abstract available

Legacy product - no abstract available

Surprisingly few natural hydrocarbon seeps have been identified in Australia's offshore basins despite studies spanning thirty years. Initial studies of natural hydrocarbon seepage around the Australian margin were generally based around the geochemical analysis of stranded bitumens, water column geochemical `sniffer' sampling, synthetic aperture radar or airborne laser fluorsensor. Later studies involved the integration of these remote sensing and geochemical techniques with mutli-channel and shallow seismic. A review of these earlier studies indicates that many seepage interpretations need to be re-evaluated and that previous data sets, when set in a global context, often represent normal background hydrocarbon levels. Relatively few sites of proven natural hydrocarbon seepage in Australia's offshore sedimentary basins can be reconciled with the dominantly passive margin setting and low recent sedimentation rates, which are not favourable for high rates of seepage, and difficulties in proving seepage on high energy, shallow carbonate shelves, where seabed features may be rapidly reworked and modern marine signatures are overprinted on authigenic seep carbonates. Active thermogenic methane seepage on the Yampi Shelf, the only proven documented occurrence in Australia, is driven by deposition of a thick Late Tertiary carbonate succession and Late Miocene tectonic reactivation. Therefore, to increase the success of detecting and correctly interpreting natural hydrocarbon seepage, data need to be analysed and integrated within the context of the local geological setting, and with an understanding of what is observed globally.

Legacy product - no abstract available

Legacy product - no abstract available

B.M.R. Maclean No. 1 was a fully cored stratigraphic hole drilled on the eastern margin of the Clarence-Moreton Basin near Evans Head. It reached a total depth of 664.8 m and intersected 590.05 m of Marburg Formation overlying 74.75 m of Ripley Road Sandstone. The lower 42.60 m of the Marburg Formation correlates with the Calamia Member recognised by Etheridge & others (1985). The sequence is mostly multistorey fluvial channel sandstone with only a small proportion of fine grained facies so that potential hydrocarbon source rocks are rare. Porous sandstone is also rare, though parts of the Calamia Member and the Ripley Road Sandstone may be porous and permeable.

Exploration in the offshore northern Carnarvon Basin during the last two decades has resulted in a number of major oil and gas discoveries. Recent discoveries in the Dampier (di Toro, 1994; Delfos, 1994), Exmouth (Bauer et al., 1994; Lawry & Carter, 1994; Mitchelmore & Smith, 1994) and Barrow (Beacher et al., 1994; Sit et al., 1994) sub-basins ensure that exploration activity is likely to remain high in these areas for the near future. However, some of these discoveries have been small fields or individual wells with residual oil columns, indicating that still greater quantities of hydrocarbons have escaped from the traps. Recent work on oil-filled fluid inclusions (Lisk & Eadington, 1994) indicates that the loss of hydrocarbons from pre-Cretaceous reservoirs and traps occurred during the past 20 million years, beginning in the Miocene. These hydrocarbons may have been lost, but could potentially have been trapped in younger Cretaceous and Tertiary reservoirs. The Carnarvon Cretaceousflertiary Tie study proposes to address this issue by collecting and interpreting a regional high-resolution seismic survey, within the broad structural and tectonic framework provided by the Continental Margins Program Northwest Shelf Project. The main objectives are: 1) construction of a regional, sequence-based chronostratigraphic framework for the Cretaceous and Tertiary within which the occurrence and distribution of potential seal and reservoir facies may be analyzed and predicted; 2) assessment of the post-Valanginian fault reactivation history of the northern Carnarvon Basin and the implications for: (a) the migration of hydrocarbons from pre-Cretaceous traps and (b) the integrity of potential Cretaceous and Tertiary seals; 3) determination of the probability of secondary migration and entrapment of hydrocarbons within Cretaceous and Tertiary strata. Approximately 4240 krn of high-resolution seismic data has been proposed for acquisition by AGSO's RV Rig Seismic. The data set will comprise 23 seismic lines tying 107 wells in the Exrnouth, Barrow, Dampier and Beagle Sub-basins. These data will tie with and complement the deep-seismic grid previously acquired by AGSO in the Carnarvon Basin. The seismic survey will be acquired using the latest high-resolution seismic technology. Data will be recorded using bubble-free GI air guns and with the following parameters: 3000m streamer; 12.5m group interval, 18.75m shot interval, recording frequency bandwidth of 4- 180Hz; 2ms sample interval; 5.5 second record length; and 80-fold CDP multiplicity. The program layout includes 5 strike lines linking the Exrnouth, Barrow, Dampier and Beagle subbasins and 18 dip lines orthogonal to the principal Mesozoic sub-basin fault systems.

The critical success factors which control hydrocarbon prospectivity in the Otway Basin have been investigated using petroleum systems approaches. Greater than 99% of the hydrocarbon inventory within the Victorian Otway Basin has been sourced from Austral 2 (Albian-Aptian) source rocks and these accumulations are typically located either within, or within approximately 3,000 m of source rock kitchens which are at peak thermal maturity at present day. Importantly, the zones of greatest prospectivity are located where these source rocks have been actively generating and expelling hydrocarbons throughout the Late Tertiary, primarily as a result of sediment loading associated with progradation of the Heytesbury shelfal carbonates. This peak generation window occurs at an average depth of approximately 2,500-3,500 m 'sub-mud' across much of the basin, which has allowed prospective hydrocarbon fairways to be mapped out, thereby highlighting areas of greatest prospectivity. It is believed that the spatial proximity of the actively generating source rocks to the accumulations is due to several factors, which includes overall poor fault seal in the basin (success cases occur where charge rate exceeds leakage rate) and relatively complex and tortuous migration fairways (which means that large volumes of hydrocarbons are only focussed and migrate for relatively short distances). etc

Legacy product - no abstract available