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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.

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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.

The Bremer Sub-basin on the rifted southwestern continental margin of Australia is a frontier basin in which no wells have been drilled. The petroleum potential of such frontier basins is generally limited to theoretical assessments from seismic data and analogues. However, a series of submarine canyons have incised the Bremer Sub-basin, allowing geological sampling of the upper 2.5 km of the basin succession. Geochemical, petrographic and palaeontological analyses of 136 rock samples recovered from 30 dredge sites, integrated with interpretation from a regional seismic grid, indicate that the Bremer Sub-basin contains a succession of up to 7km of Jurassic to Tertiary age sediments containing the essential petroleum system elements (source, reservoir and seal) to generate and trap hydrocarbons. Source rock analyses indicate Early Cretaceous coaly and lacustrine organic facies have the best oil potential with hydrogen indices (HI) up to 370 mg hydrocarbons/g TOC. Similar fluvio-lacustrine organic facies are recognised sources for oil in the adjacent Perth and eastern Bight basins. Furthermore, the identification of late Early Cretaceous marine anoxic organic facies in the Bremer Sub-basin supports the concept of a local southern Australian margin origin for widespread coastal bitumens termed asphaltites. Berriasian to Hauterivian age strata within the Bremer Sub-basin have the greatest potential to reservoir hydrocarbons, where lacustrine mudstones overlie fluvial sandstones in anticlines and fault block traps. The largest anticline may be capable of trapping up to 500 million barrels of oil in-place (P50 estimate; 900 million barrels P10 estimate).

First paragraph of abstract: The importance of organic sulphur fixation in the preservation of organic matter in humic coal-forming environments is demonstrated in this thesis. The transgression of coal depositional systems by marine waters during their deposition and early diagenesis enables the production of reduced inorganic sulphur species by sulphate-reducing bacteria. The presence of these reactive sulphur species, in combination with the altered chemical and microbial regime, influences the preservation and petroleum potential of humic coal.

During ODP Leg 189, the JOIDES Resolution recovered about 4200 m of continuous core from four sites in sedimentary basins on continental crust off Tasmania. These sites, one off west Tasmania, two on the South Tasman Rise (STR), and one on the East Tasman Plateau (ETP) are 760-968 m deep and in water 2100-2700 m deep. No hydrocarbon accumulations were expected at these sites. The pre-Oligocene section is largely shallow-marine organic-rich mudstone, which seismic profiles indicate is the top of a Cretaceous-Eocene largely deltaic sequence thousands of metres thick. This siliciclastic sequence formed as Tasmania rifted from the surrounding parts of Gondwana. Sedimentation rates were relatively high until the late Eocene, when a condensed siltstone sequence formed as the Antarctic Circumpolar Current first swept the shelves of the separating land masses. From the earliest Oligocene, when Australia finally cleared Antarctica, deposition of several hundred metres of carbonate pelagic ooze and chalk predominated. Sedimentation no longer kept up with subsidence, and at most sites unconformities have removed much of the Oligocene. The cores, in conjunction with seismic profiles, provide information on tectonic and sedimentary history and petroleum potential. New data include evidence of high present-day thermal gradients; marginally mature organic matter less than 1000 m below sea bed, biogenic and probably thermogenic gas, and bitumen generation; and overall source rock potential. Tectonic histories vary, but all basins have sufficient sediment and thermal gradient to generate hydrocarbons. However, of the thick sequences interpreted as deltaic, only the upper shelf mudstones were drilled. TOC content decreased with time as the gulfs around Tasmania widened, and also eastward from the more restricted Australo-Antarctic Gulf into the less restricted early Tasman Sea. Although the thermal gradient is highest in the three western sites, the holes do not reach the petroleum window. Methane is biogenic in the younger sediments, but higher hydrocarbon gases at depth suggest a thermogenic component. In addition, Rock-Eval analyses of the oldest sediments suggest bitumen (S2 peak) and organic matter approaching maturity. Little stratigraphic section is missing, so past overburden was unlikely to exceed present. Whether there are reservoir rocks and suitable hydrocarbon traps remains unknown. On the existing evidence, west Tasmania and STR appear to be reasonably prospective for petroleum, and more prospective than ETP, and we present a speculative play concept for them.

A recent Geoscience Australia geological sampling survey in the Great Australian Bight has provided new evidence for the presence of potential oil-prone source rocks in the Bight Basin. Exploratory drilling in the Bight Basin has historically concentrated on the inboard margins of the basin. Apart from Woodside's Gnarlyknots-1A well, which was drilled in the Ceduna Sub-basin in 2003, only the more proximal parts of the Cretaceous depositional systems of the basin have ever been sampled by drilling. Previous Geoscience Australia work in the Bight Basin predicted the presence of potential source rock intervals at different stratigraphic levels, including mid-Cretaceous marine or marine-influenced sediments whose source rock character was predicted to improve farther basinward. The sampling survey targeted an area at the seaward edge of the Eyre Terrace where canyon formation, slumping and faulting has exposed this Albian-Santonian section. Samples recovered from this area include a suite of carbonaceous marine siltstones and mudstones. Preliminary organic geochemical analysis has shown that some samples of Late Cenomanian-Early Turonian age recovered from the Eyre Terrace have excellent source rock potential, with high organic carbon contents (2.1-6.2% TOC) and the potential to generate liquid hydrocarbons (HI values ranging from 274 to 479 mg hydrocarbons/gTOC). These are the best source rock results yet from the Bight Basin, and demonstrate that targeting the right part of the depositional system is vital for understanding hydrocarbon source potential. 2D petroleum systems modelling of two transects from the Ceduna Sub-basin using source-specific multi-component kinetic parameters, suggests that generation and expulsion from the Late Cenomanian-Early Turonian potential source rock occurred during the mid-Campanian to Recent, resulting in potentially significant accumulations of both liquid and gaseous hydrocarbons within overlying sandstones of the Turonian-Santonian Tiger and/or latest Santonian-Maastrichtian Hammerhead supersequences.