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  • This Record presents a summary of an analysis of 21 offshore Otway Basin wells (Appendix 1) based on data provided in open file Well Completion Reports (WCRs) and Geoscience Australia online databases. Additional data and interpretations are drawn from the large body of published material on the basin. Analysis was inhibited in some cases by the quantity of data in WCRs, specifically the paucity of maps provided in the interpretive sections. Fortunately, most well analyses appear to have a determination of the reason/s for failure that is reasonably clear even without maps. The end product is primarily focused on individual well results, specifically success and failure analysis. To put the wells in a geological perspective, the introduction outlines briefly the regional geologic setting, distilling the ideas of many workers through the basin's exploration history. The final section presents a petroleum systems focused summary of the main findings of the work. From this, critical risks have been identified and areas of higher or additional potential have been indicated.

  • The hydrocarbon and source rock evaluation given in this report summarises our present understanding of the geochemical factors which control petroleum occurrence in the Browse Basin. The aims of the present work are to describe the methods used in, and initial results of our characterisation (richness, quality and maturity) of the organic-rich rocks (ORR) within the Browse Basin stratigraphic section. In addition, an oil-source correlation involving biomarkers and stable carbon isotopes enables us to identify the contribution of the specific ORR's to migrated petroleum (oil stains) and reservoired hydrocarbons in the basin. One important task in effective source prediction is to place the ORR in a sequence stratigraphic context. Using the stratigraphic framework for the Browse Basin, combined with the known chronostratigraphy, we have chosen to analyse and interpret source rock potential within nine major intervals, BB1-BB3, BB4-BB5, BB6-BB7, BB8, BB9, BB10, BB11, BB12, and BB13-BB15 based on the most significant sequence boundaries within the Browse Basin succession.

  • APPEA 2000 joint paper to arrive at a better understanding of the petroleum systems active in the Northern Bonaparte Basin, geochemical data from oils and source rock-extracts were compiled and interpreted from over 20 wells in the area.

  • The molecular composition of fluid inclusion (FI) oils from Leander Reef-1, Houtman 1 and Gage Roads-2 provide evidence of the origin of palaeo-oil accumulations in the offshore Perth Basin. These data are complemented by compound specific isotope (CSI) profiles of n-alkanes for the Leander Reef-1 and Houtman-1 samples, which were acquired on purified n-alkane fractions gained by micro-fractionation of lean FI oil samples, showing the technical feasibility of this technique. The Leander Reef-1 FI oil from the top Carynginia Formation shares many biomarker similarities with oils from the Dongara and Yardarino oilfields, which have been correlated with the Early Triassic Kockatea Shale. However, the heavier isotopic values for the C15-C25 n-alkanes in the Leander Reef-1 FI oil indicate that it is a mixture, and suggest that the main part of this oil (~90%) was sourced from the more terrestrial and isotopically heavier Early Permian Carynginia Formation or Irwin River Coal Measures. This insight would have been precluded when looking at molecular evidence alone. The Houtman-1 FI oil from the top Cattamarra Coal Measures (Middle Jurassic) was sourced from a clay-rich, low sulphur source rock with a significant input of terrestrial organic matter, deposited under oxic to suboxic conditions. Biomarkers suggest sourcing from a more prokaryotic-dominated facies than for the other FI oils, possibly a saline lagoon. The Houtman-1 FI oil ?13C CSI data are similar to data acquired on the Walyering-2 oil. Possible lacustrine sources include the Early Jurassic Eneabba Formation or the Late Jurassic Yarragadee Formation. The low maturity Gage Roads-2 FI oil from the Carnac Formation (Early Cretaceous) was derived from a strongly terrestrial, non-marine source rock containing a high proportion of Araucariacean-type conifer organic matter. It has some geochemical differences to the presently reservoired oil in Gage Roads-1, and was probably sourced from the Early Cretaceous Parmelia Formation.

  • The Vulcan Sub-basin has been actively explored for over twenty years, with oil production from the Jabiru and Challis-Cassini fields, and the depleted Skua Field, all of which were sourced by the Upper Jurassic Lower Vulcan Formation within the Swan Graben. The need to discover other oil-prone petroleum systems led to this study focussing on oils that have a different composition to those of the aforementioned oils. Geochemical analyses (bulk and compound-specific isotopes, GC and GC-MS of saturated and aromatic hydrocarbons) have characterised the Vulcan Sub-basin oils and condensates into three families (Fig 1); a marine oil family (with some terrigenous influence) comprising Jabiru, Challis, Skua, Talbot and Tenacious; a terrestrially-influenced oil family comprising Maret, Montara, Padthaway and Bilyara which have more varied geochemistry; and, a family of condensates from Tahbilk, Swan and Eclipse. The composition of these condensates is more reflective of reservoir alteration effects (such as leakage and gas flushing) than the type of organic matter in their source rocks. The terrestrially-influenced oil family is located in the southernmost part of the Vulcan Sub-basin and in the northern Browse Basin, most probably having being source from the Lower-Middle Jurassic Plover Formation. The Plover Formation contains liquid-prone source rocks within the Skua Trough, albeit immature for hydrocarbon generation. Similar source rocks are believed to occur beneath the Swan and Paqualin grabens since oils with mixed composition are found at Puffin, Pituri and Oliver.

  • The 50 major Australian source rock units can be grouped according to age into 15 intervals comprising Late Neoproterozoic, Middle Early Ordovician, late Early Ordovician, Middle to Late Devonian, Early Carboniferous, Early to early Late Permian, late Late Permian, Early to Middle Triassic, Early to Middle Jurassic, Middle to Late Jurassic, Late Jurassic, latest Jurassic to Early Cretaceous, Early Cretaceous, Late Cretaceous, latest Cretaceous to Eocene. Only marine source rocks are known older than Permian, while both marine and nonmarine source rocks are known from Permian and younger intervals. As expected, the marine source rocks are more common where there is a greater degree of continental inundation, while nonmarine source rocks are present only when the continent was at higher palaeolatitudes and when there was at least a moderate amount of continental inundation.

  • Launched in 2003, the Geoscience Australia National Petroleum Wells Database web site http://www.ga.gov.au/oracle/apcrc has proven an extremely useful tool for petroleum explorers wishing to access scientific and well header data for Australian petroleum exploration wells. This web site provides access to comprehensive databases representing over 100 person years of data entry by geologists, geochemists, biostratigraphers and technical staff. The databases contain information that includes well header data, biostratigraphic picks, reservoir and facies data (porosities, permeabilities, hydrocarbon shows and depositional environments), organic geochemistry data (Rock-Eval pyrolysis, molecular and isotopic analyses), and organic petrological data (vitrinite reflectance, maceral analyses). A major revision of the web site will be released at APPEA 2006. The revised web site has many improved features in response to industry and government client needs. These features include: 1 Easy retrieval of Acreage Release data, 2 An improved map for spatial searching and display of data, 3 Ability to retrieve age restricted and isopach data for many data types in the database, 4 Query and produce multiple summary reports (including graphs) for wells, 5 Generation of multiple oil and gas reports for wells, 6 Links to scanned documentation, and 7 Improved graphical displays of data.

  • The geological debate about whether, and to what extent, humic coals have sourced oil is likely to continue for some time, despite some important advances in our knowledge of the processes involved. Both liptinites and perhydrous vitrinites have the potential to generate oil; the key problem is whether this oil can be expelled. Expulsion of hydrocarbons is best explained by activated diffusion of molecules to maceral boundaries and ultimately by cleats and fractures to coal seam boundaries. The relative timing of release of generated CO2 and CH4 could have considerable importance in promoting the expulsion of liquid hydrocarbons. The main reason for poor expulsion from coal is the adsorption of oil on the organic macromolecule, which may be overcome (1) if coals are thin and interbedded with clastic sediments, or (2) if the coals are very hydrogen rich and generate large quantities of oil. Review of the distribution of oil-prone coals in time and space reveals that most are Jurassic-Tertiary, with key examples from Australia, New Zealand and Indonesia. Regarding establishing oil-coal correlations, a complication is that the molecular geochemistry of coals is often very similar to that of the enclosing, fine-grained rocks containing terrestrial organic matter. One potential solution to this problem is the use of carbon and hydrogen isotopes of n-alkanes, which have recently been shown to be powerful discriminators of mudstone and coal sources in the Turpan Basin (China). There is a continuum from carbonaceous shales to pure coals, but the question as to which of these are effective oil sources is an extremely important issue, because volumetric calculations hinge on the result. Unambiguous evidence of expulsion from coals is limited. Bitumen-filled microfractures in sandstones interbedded with coals in offshore mid-Norway and in Scotland have been interpreted to be the migration routes of hydrocarbons from the coal seams towards the sandstones. In the San Juan Basin, USA, direct evidence for the primary migration of oil within coal is provided by the sub-economic quantities (10s to 100s of barrels per well) of light oil produced directly from coal beds of the Upper Cretaceous Fruitland Formation. The Gippsland Basin (Australia) is commonly cited as the outstanding example of a province dominated by oil from coal, but there is no literature that explicitly demonstrates that generation and expulsion has been from the coal seams and not the intervening carbonaceous mudstones. The best evidence for coals as source for oil in the Gippsland appears to be volumetric modelling, which indicates that it would have been impossible to generate the volume of oil discovered to date from the organic-rich shales alone. However, early reports that mid-Jurassic coals in mid-Norway were a major source of the reservoired oils, also based to a large extent on oil generation and expulsion modelling, have now been shown to be inaccurate by detailed biomarker, isotope, whole oil and pyrolysis studies. The most convincing commercial oil discoveries that can be correlated to coals are: (1) Taranaki Basin oils in New Zealand, where Late Cretaceous and Tertiary coals, shaly coals and carbonaceous mudstones are likely to have sourced oils in approximate proportion to their volumes and organic contents, and (2) the oils and condensates in the Harald, Amalie and Lulita oilfields (Danish North Sea) which are likely to have been sourced are least partially from mid-Jurassic coals. New oil-source correlation studies based on diterpane, triterpane and sterane distributions in the Bass Basin (Australia), which lies adjacent to the Gippsland Basin and contains sub-economic reserves of oil and gas, has shown that the Tertiary coals and not the associated shales are best correlated with the oils.

  • A study of the Strahan Sub-basin in particular, and the wider Sorell Basin in general, has revealed the likely presence of an active hydrocarbon generation, migration, leakage and seepage system along the West Tasmanian Margin (WTM). 2D basin modelling of seismic data has demonstrated that a previously identified, high-quality Maastrichtian source interval is unlikely to contribute significantly to hydrocarbon inventories in the region. However. an interpreted deeper Cretaceous source rock has been sufficiently mature to expel hydrocarbons over much of the sub-basin since the Early Tertiary. Combining the seismic mapping and modelling of this deeper source facies with the mapping of hydrocarbon leakage indicators such as gas chimneys and carbonate build-ups has shown that active, present day hydrocarbon leakage and seepage is restricted to fault arrays immediately to the north-west of, and up-dip from, a thermally mature, Cretaceous source system. These observations demonstrate that a deeper source system is working but do not reveal whether the source system is oil-, condensate- or gas-prone. In one area, strong seismic evidence for present day seepage at the seafloor was observed, with the likely formation of methane-derived authigenic carbonates located directly above seismically prominent chimneys. The fact that the faults up-dip from the mature source leak raises the issue of how much of the generated hydrocarbons have been preserved in this area. Interpretation of new Synthetic Aperture Radar (SAR) data revealed a very low density of natural oil slicks along the West Tasmanian margin. Moreover, no SAR seepage slicks were observed over the area of identified active seepage within the Strahan Sub-basin. This could suggest that the area is condensate- or gas-prone, though hydrocarbon analyses of the seafloor sediments suggest that thermogenic hydrocarbons, some of which are moderately geochemically wet, are present along the West Tasmanian margin. This apparent contradiction might be explained by the fact that the seepage is intermittent, that the SAR data were at the upper end or lower end of the weather compliance envelope, or that the amount of liquid hydrocarbons leaking is relatively small, and hence the resulting SAR seepage slicks are too small to map. Further work to discriminate between these alternatives, and combinations thereof, is necessary. In particular, we would recommend the sampling of the seafloor seeps identified in the Strahan Sub-basin as a priority, as the presence of oil within these sediments would immediately high-grade this area significantly. Fault seal is quite likely to be a major risk within the Strahan Sub-basin due to the apparent relatively unfavourable alignment of the faults and the regional NNW stress trajectories. If the faults have relatively steep dips, they are probably leaky, as evidenced by the presence of gas chimneys developed preferentially along these faults in areas where the source is mature. In general, more north-east to east-west trending fault blocks will be likely to have higher seal integrity, but if such targets cannot be identified, then NNW trending faulted traps with shallow-dipping bounding faults represent a more attractive target than those with steeper dips, as would stratigraphic traps.

  • At this scale 1cm on the map represents 1km on the ground. Each map covers a minimum area of 0.5 degrees longitude by 0.5 degrees latitude or about 54 kilometres by 54 kilometres. The contour interval is 20 metres. Many maps are supplemented by hill shading. These maps contain natural and constructed features including road and rail infrastructure, vegetation, hydrography, contours, localities and some administrative boundaries. Product Specifications Coverage: Australia is covered by more than 3000 x 1:100 000 scale maps, of which 1600 have been published as printed maps. Unpublished maps are available as compilations. Currency: Ranges from 1961 to 2009. Average 1997. Coordinates: Geographical and either AMG or MGA coordinates. Datum: AGD66, GDA94; AHD Projection: Universal Transverse Mercator UTM. Medium: Printed maps: Paper, flat and folded copies. Compilations: Paper or film, flat copies only.