Chiefly charts and maps, includes explanatory notes

The northern Pedirka Basin in the Northern Territory is sparsely explored compared with its southern counterpart in South Australia. Only seven wells and 2500 km of seismic data occur over a prospective area of 73,000 km2. In this basin three petroleum systems have potential related to important source intervals in the basal Jurassic (Poolowanna Formation), Triassic (Peera Peera Formation) and Early Permian (Purni Formation). They are variably developed in three prospective depocentres, the Eringa Trough, the Madigan Trough and the northern Poolowanna Trough. New basin modelling techniques indicate oil and gas expulsion responded to increasing early Late Cretaceous temperatures in part due to sediment loading (Winton Formation). Using a composite kinetic model, oil and gas expulsion from coal rich source rocks were largely coincident at this time when source rocks entered the wet gas maturation window. The Purni Formation coals provide the richest source rocks and equate to the lower Patchawarra Formation in the Cooper Basin. Widespread well intersections indicate that glacial outwash sandstones at the base of the Purni Formation, herein referred to as the Tirrawarra Sandstone, have regional extent and are an important exploration target as well as providing a direct correlation with the prolific Patchawarra/ Tirrawarra petroleum system found in the Cooper Basin. An integrated investigation into the hydrocarbon charge and migration history of Colson-1 was carried out using CSIRO Petroleum's OMI (Oil Migration Intervals), QGF (Quantitative Grain Fluorescence) and GOI (Grains with Oil Inclusions) technologies. In the basal Jurassic Poolowanna Formation between 1984 and 2054 mRT, elevated QGF intensities, evidence of oil inclusions and abundant fluorescencing material trapped in quartz grains and low displacement pressure measurements collectively indicate the presence of palaeo-oil and gas accumulation over this 70 m interval. This is consistent with the current oil show indications such as staining, cut fluorescence, mud gas and surface solvent extraction within this reservoir interval. Multiple hydrocarbon migration pathways are also indicated in sandstones of the lower Algebuckina Sandstone, basal Poolowanna Formation and Tirrawarra Sandstone. This is a significant upgrade in hydrocarbon prospectivity, given previous perceptions of relatively poor quality and largely immature source rocks in the Basin. Conventional structural targets are numerous but the timing of hydrocarbon expulsion dictates that those with an ?older? drape and compaction component will be more prospective than those dominated by Tertiary reactivation which may have resulted in remigration or leakage. Preference should also apply to those structures adjacent to generative source ?kitchens? on relatively short migration pathways. Early formed Tirrawarra Sandstone and Poolowanna Formation stratigraphic traps are also attractive targets. Cyclic sedimentation in the Poolowanna Formation results in two upward fining cycles which compartmentalise the sequence into two reservoir ? seal configurations. Basal fluvial sandstone reservoirs grade upwards into topset shale/ coal lithologies which form effective semi-regional seals. Onlap of the basal cycle onto the Late Triassic unconformity offers opportunities for stratigraphic entrapment.

The Bight Basin contains a thick, prospective Jurassic-Cretaceous sedimentary section. Recent work by both Geoscience Australia and the petroleum exploration industry has increased our understanding of the structural and stratigraphic development, and the range of opportunities available in this frontier basin. The presence of thick deltaic units and indications of active petroleum systems further enhance its prospectivity. Although the basin is being tested by new drilling it remains one of the least explored passive margins in the world, and will require much more exploration to fully assess its potential.

AGSO's 1995-96 Petrel Sub-basin Study was undertaken within AGSO's Marine, Petroleum and Sedimentary Resources Division (MPSR) as part of MPSR's North West Shelf Project. The study was aimed at understanding the stratigraphic and structural development of the basin as a framework for more effective and efficient resource exploration. Specifically, the study aimed to: - define the nature of the major basement elements underlying the Petrel Sub-basin and their influence on the development of the basin through time, - determine the nature and age of the events that have controlled the initiation, distribution and tectonic evolution of the basin; - define the nature and age of the basin fill, and the processes that have controlled its deposition and deformation; and, importantly, - determine the factors controlling the development and distribution of the basin's petroleum systems and occurrences.

The Ceduna Sub-basin of the Bight Basin is a frontier region containing only one exploration well. Therefore, our assessment of the distribution of potential source rocks in the area is based on an understanding of the regional sequence stratigraphic framework and the potential petroleum systems present, along with the regionsal palaeogeography, and geochemical data from onshore and the adjacent Duntroon Basin. Studies carried out by AGSO over the past three years suggest that the thick Cretaceous succession in the Ceduna Sub-basin contains a range of fluvio-lacustrine, deltaic and marine source rocks that have the potential to generate liquid hydrocarbons.

Coalbed methane (CBM) is emerging as an important energy resource in Australia. CBM is one of the products of coalification - the process by which peat is transformed into coal during progressive burial. The initial product is biogenic gas, thermogenic gas is produced with increasing pressure and temperature and further biogenic gas may be produced after burial has ceased if the coal becomes exposed to an active groundwater system containing methanogenic bacteria. The storage of CBM within a coalbed reservoir is complex, being a mixture of free gas, dissolved gas and absorbed gas. A number of gas and coal properties govern how much and how fast a coal seam will give up its methane, but the most economically productive seams are naturally fractured or are stimulated to induce and increase fracturing. Unlike conventional gas reservoirs, the continuous production of water from a coalbed reservoir results in a corresponding progressive increase in gas production (up to a certain limit). CBM production in Australia commenced in 1996 and most of Australias coal basins are now covered by production, exploration or application licences. The Cooper Basin contains a huge volume of coal that is recognised to be the source of much of the conventionally trapped gas. No attempt has been made to explore the basin for CBM due to the generally held belief that the coals are too deep. The Weena Trough has been identified as one area in the Cooper Basin in which the Permian coals may be at depths that are economic to exploit. Two wells drilled in the period 1968-70 encountered net coal thicknesses of more than 40m with individual seams up to 18 metres. The fact that elsewhere these coals are known to be the source of much of the basins conventionally trapped gas, combined with the advances made in understanding the nature of CBM generation, storage and production, makes the Weena Trough an ideal target for evaluation

From 9 July to 4 August and 15 September to 14 October 1988, the BMRresearch vessel Rig Seismic conducted two cruises in the region of theSouth Perth Basin (Plate 1). The aims and objectives of the cruise were: (1) to develop an updated structural and stratigraphic frameworkfor the Perth Basin. (2) to collect a regional seismic grid to tie industry wells andprevious seismic surveys, in order to produce a comprehensiveassessment of the hydrocarbon potential of the South PerthBasin. (3) sample the continental slope for stratigraphic control, sourcerock potential and palaeoceanography. (4) develop models of basin evolution, particularly for small,deep sub-basins (e.g. Vlaming Sub-basin).

This record describes digital data compilation product, where several individual items are grouped for delivery on single CD-ROM. Content and number of items included in the compilation package can vary, depending on size of the individual items. The contents of this CD-ROM are as follows: Catalog # Title 33928 AGSO marine survey 176 direct hydrocarbon detection north-west Australia : Yampi Shelf, southern Vulcan Sub-Basin and Sahul Platform (July/September 1996) : operational report & data compendium (Record 2000/42) 31523 AGSO Marine Survey 207 direct hydrocarbon detection NW Australia:Northern Carnarvon Basin; Yampi Shelf; Southern Bonaparte Basin (September/October 1998)Record 1999/51 37047 Vulcan Sub-basin - environmental analyses 37020 Vulcan Sub-basin - hydrocarbon show analyses 25307 Vulcan Sub Basin well composites 35980 Bonaparte Basin - natural gas analyses

No abstract available

Petroleum exploration in the Arafura Basin has been restricted to the Goulburn Graben, a dominant central feature within the basin. The graben is over 350 km long and up to 70 km wide, containing a highly deformed sedimentary fill of up to 10 km. To date a total of nine wells have been drilled in the region which test a variety of structural and stratigraphic play types. No commercial discoveries have been made. The most significant drilling result is an oil and gas show in Arafura-1. A review of drilling results has identified a number of exploration risks in the basin: 1) poor quality reservoirs in the Palaeozoic and/or restricted fluid movement; 2) hydrocarbon charge and timing of events; and 3) breach of structure. Most of these issues are related to a Triassic contractional event that caused uplift and erosion. Despite these risks, significant petroleum potential remains for the Arafura Basin as a whole. Firstly the identified risk factors may not apply to the undrilled northern part of the basin, which is the basin depocentre. Secondly, there is strong evidence for viable petroleum systems with source, reservoir and seal rocks present in the sedimentary succession. Evidence for active source rocks is provided by numerous hydrocarbon indications in the wells, including oil shows and bitumen in Arafura-1 and Goulburn-1. Analysis of these shows indicates a probable Cambrian source and there is evidence of significant vertical migration of fluids, with Cambrian oil signatures throughout the Palaeozoic sections. With high quality reservoirs (>20% porosity) and a regional seal, potential exists for accumulations within the overlying Money Shoal Basin. Given the limited petroleum exploration in the Arafura Basin, there remains considerable untested potential in both the Goulburn Graben and the unexplored northern region.