Restricted on advice from A. Barrett

2002 and 2003 may well prove to be pivotal years for petroleum exploration in Australia as we endeavour to meet our twin imperatives of finding more oil and using gas. Long term gas supply contracts have been signed with China and a number of key oil discoveries have been made both on and offshore. Deep water wells will be drilled that have the potential to usher in another phase of major oil discovery akin to bonanza of the 1960s, when the first steps into the offshore resulted in billion barrel discoveries in Bass Strait. By the close of the first successful cycle of exploration in Australia (1960 to 1972) all currently producing basins were identified as petroliferous, the major play types had been established and over 60% of Australia?s current oil reserves found. The key drivers of this phase were the access to new basins opened up by the move to offshore exploration and the stimulus to further exploration provided by discovery success. The same drivers are apparent now. Recent discoveries in the Perth, Carnarvon, Otway and Browse basins provide strong indications that a significant new cycle of exploration success is already underway. In many cases these finds represent the largest fields yet found in the basin or at least the largest in the last thirty years. The usual discovery history trend of declining field sizes over time has been turned on its head - clearly demonstrating that many of Australia?s currently producing basins still have a long way to run and encouraging further exploration efforts. Perhaps of even more importance to Australia?s long term liquids self sufficiency is the current deepwater drilling campaign which is stepping out beyond former geographic limits. The first wells in major Mesozoic depocentres on the outer margin of the North west Shelf and in the Great Australian Bight are being drilled with the potential to establish entirely new petroleum provinces.

Introduction Australia has a thriving oil and gas industry with expanding infrastructure and many exploration opportunities. Geologically the country has the potential for large oil and gas discoveries within extensive sedimentary basins. Australia is also one of the world leaders in providing open-file geological data at a low cost, and an open Acreage Release process with competitive taxation regimes. Politically, Australia is very stable with a very high standard of living and a long-standing democratic culture based on the rights of the individual and the rule of the law. There is a free market philosophy which welcomes foreign investment - Australia has no mandatory local equity requirements and has no government owned oil companies. Government facilitation of investment includes fast-tracking of approvals processes for major projects. This CD provides some basic Australian data including: Oil and Gas Resources of Australia 2002 The Oil and Gas Resources of Australia 2002 (link to Pdf ) publication is the definitive reference on exploration, development and production of Australia's petroleum resources. It covers exploration, reserves, undiscovered resources,development, coal-bed methane resources, production, crude oil and shale oil and supporting information and statistics. An estimate of Australia's undiscovered oil and gas potential and a review of geological sequestration of carbon dioxide in Australia is also included. Australian Research and Promotional Material The Australian Research and Promotional Material section includes selected scientific publications on Australia and CO2 Sequestration. Promotional pamphlets are also included outlining geological products available from Geoscience Australia and contacts for obtaining these products. Research and Promotional material is grouped into regions: 1. Regional Australian Studies 2. North West Shelf 3. Australian Southern Margins 4. Carbon Dioxide Sequestration 5. Geoscience Australia Online Databases Demonstration The Geoscience Australia Petroleum Databases Demonstration is in PDF format and contains instructions on how to use Geoscience Australia's web-based Petroleum Databases located at: www.ga.gov.au/oracle/apcrc/ The Petroluem Databases, available through the Geoscience Australia website, contain open-file data and include: the Australian Geological Provinces Database, the Petroleum Information Management System (PIMS) GIS, the National Petroleum Wells Database and the National Geoscience GIS. Relevant Government and Industry Web Links Including: 1- Key Government Links for Offshore Acreage 2- Key Government Links for Onshore Acreage 3- Industry Links

Genetic relationships, identified using a combination of molecular and isotopic (carbon and hydrogen) compositions, have been found between natural gases, oils, oil stains, bitumens and potential source rocks in the onshore and offshore Otway Basin. The gas-gas, gas-oil and oil-source correlations herein challenge the validity of some previously accepted oil families and re-enforces the strong compartmentalisation of petroleum systems in the Otway Basin. Previous geochemical studies in the Otway Basin, mainly focussed on the oils and oil stains, have established that the Otway Basin hosts the most diverse array of petroleum systems within Australia. Up to five different oil families have previously been identified. These oils are sourced from a wide range of depositional environments from fresh to saline lacustrine, fluvio-lacustrine to peat swamp and marine, with suspected effective source rock ages from Late Jurassic to Late Cretaceous. Such depositional settings are consistent with the progressive development of source rocks facies intimately linked to basin development from initial rifting to thermal sag. It is now concluded that there is no indigenous representation of the saline lacustrine oil population in the Otway Basin. The geochemical signal is attributed to downhole contamination from gilsonite; a solid bitumen from the Eocene Green River Formation, USA. Oils stains are thought to be a result of primary migration from mature source rocks into juxtaposed sands and are not a strong advocate for secondary oil migration fairways. The natural gases show a strong geochemical association with their respective oils, suggesting that both are generated together from the same source. Also the gases and oils and their effective source rocks have a strong stratigraphic and geographic relationship, indicating mainly short- to medium-range migration distances from source to trap. Gas and oil in the western Otway Basin are sourced from the fluvio-lacustrine Casterton Formation?Crayfish Group sediments while in the eastern Otway Basin the gas and oil from the Shipwreck Trough and its onshore extension are from the coaly Eumeralla Formation sediments. Gas and oil in the central Otway Basin have a mixed source but predominantly are of Eumeralla Formation source Multiple charge histories are also evident with the widespread influx of overmature, dry gas focused in the western Otway Basin and more recently magmatic CO2 influx. Successive natural gas charges have the potential to displace and/or alter the composition of the pre-existing reservoired gas and oil. In-reservoir biodegradation of oil is seen in the shallower reservoirs but this is not a significant risk in the Otway Basin since nearly all reservoired petroleum is below the temperature/depth limits for biologically sustainable life.

This study documents the natural gas compositions of accumulations on the Exmouth Plateau and adjacent Rankin Platform in the Carnarvon Basin, a proven super-giant gas province on the North West Shelf of offshore Western Australia. The Exmouth Plateau contains Australia's largest undeveloped gas resources. The primary reservoirs are the Middle Late Triassic Mungaroo Formation (Chrysaor, Dionysus, Geryon, Maenad, Orthrus and Urania discoveries), the Late Jurassic sands of the Dingo Claystone at Geryon and Io/Jansz, and the Early Cretaceous Barrow Group at Scarborough. The gas accumulations at Geryon, Io/Jansz, Maenad, Orthrus and Urania are dry, with condensate to gas ratios (CGRs) of about 3 bbls/MMscf, although they contain low proportions of wet gases (average 100*(C1/ C1-C5) = 93.4 %). These gases typically have low concentrations of carbon dioxide (CO2 <2.6 %). The gas at Scarborough is extremely dry (100*(C1/C1-C5) = 99.9 %), with low concentrations of carbon dioxide (CO2 = 0.4 %). The d13C isotopic value of methane is -42.3, signifying the bacterial alteration of a thermogenic gas (Boreham et al., 2001). Wet gas is produced from the Mungaroo Formation on the northern Rankin Platform, with some of the wettest gases occurring at Goodwyn (CGR = 143 bbls/MMscf) and Echo/Yodel (CGR = 235 bbls/MMscf). The Mungaroo reservoired gas is drier (CGR ~12 bbls/MMscf) in Gorgon, located on the southern Rankin Platform. The Gorgon and neighbouring West Tryal Rocks, Chrysaor and Dionysus accumulations have elevated carbon dioxide (CO2) contents with the concentration and isotopic enrichment of CO2 increasing from the shallower (CO2 = 8 %; d13C CO2 = -5) to the deeper (CO2 = 23 %; d13C CO2 = -3) reservoirs. The isotopically enriched CO2 may originate from either a magmatic source or from the thermal decomposition of limestones within the deeply buried Permian, Triassic and Early Jurassic sediments. Mixing of inorganic and organic CO2 could explain the concentration isotopic trend observed in these accumulations. Gas: gas correlations based on the carbon (d13C) and hydrogen (dD) isotopic compositions of individual hydrocarbons from methane to n-pentane (C1-C5) are shown in Figure 1. The Geryon 1, Jansz 1, Maenad 1A, Orthrus 1 and Urania 1 gases have similarly shaped d13C isotopic profiles that show little differentiation between ethane, propane and butane (Figure 1a). Such a flat isotopic profile is typical of a terrigenous gas source (James, 1990) and may indicate either different sources for the wet gases and methane or facies changes within the same source rock. The most likely primary source of the Exmouth Plateau hydrocarbon gases is the regressive fluvial deltaic Triassic Mungaroo Formation. The isotopic profiles of the Gorgon 3 and North Gorgon 6 (southern Rankin Platform) and Chrysaor 1 gases display an almost linear d13C n-alkane profile (Figure 1c) and imply a different source province from that of the other Exmouth Plateau gases, most probably from Triassic Jurassic sediments in the Barrow Sub-basin, as well as within the Rankin Platform. The carbon and hydrogen isotopic profiles of the Dionysus gas are most similar to the other Exmouth Plateau gases (Figure 1b, d); however, its high concentration of isotopically enriched CO2 is most similar to the gases from the Gorgon area, suggesting the mixing of multiple sources of gas from different depocentres into this accumulation.

Molecular and stable isotopic (carbon and hydrogen) analyses are being undertaken on fluid samples from offshore Australian gas accumulations, as part of a Geoscience Australia initiative to understand the origin, thermal maturity and degree of preservation of these economic resources. The geochemical data are available from Geoscience Australia's web site http://www.ga.gov.au/oracle/apcrc. Here, emphasis is placed upon documenting the natural gas compositions of the Exmouth Plateau and Exmouth Sub-basin (Fig. 1). It is apparent from the isotopic signatures of the non-combustible and combustible gases that several sources of gas are mixed within these accumulations, many of which have complex fill histories. These results were presented at the Combined National Conference of the Australian Organic Geochemists and the Natural Organic Matter Interest Group, Rottnest Island, Perth, WA, February 2006 (Edwards et al., 2006).

A range of geophysical indicators have been used to infer the presence of shallow gas in the Arafura Sea. The existence of shallow gas has been confirmed by the analysis of core material obtained during the survey. This sampled gas has a microbial origin related to decay of organic matter in Holocene mud-filled channels. However, geophysical data indicates that another source of gas exists in deeper parts of the sedimentary section and this gas appears to be migrating up from depth. Intense pockmark fields (~350/km2) are often developed above the mud-filled channels but they have also been recorded away from these channels. The development and density of the pockmark fields appears to be related to sea bed sediment type, microbial gas production within the mud-filled channels and supply of fluids from deeper within the sedimentary section. Correlation of sub-bottom profile data with conventional seismic data also indicates that there are links between deep first-order Proterozoic faults, second-order Jurassic faults and third-order faults to sea bed observed in sub-bottom profiles. The detailed sea bed mapping carried out during the survey has also shown correlations between habitat and biodiversity of various benthic fauna. Areas of high biodiversity and abundance generally correlated with harder substrates. In these areas, sea whips and fans, soft corals, hydroids, crinoids and octocorals were frequently identified, with sessile benthos extending up to ~50cm in height. The extensive areas of soft substrate commonly exhibited low-relief benthos which often covered less than 5% of the surface area. Such areas were also frequently noted for pockmark fields and the general uniformity of the environment.

This work is a baseline study used to underpin the role of bacteria in the alteration and mineralisation of CO2 during geological storage following its injection into depleted natural gas reservoirs. In doing so it is paramount to first understand and characterise natural deep-earth biological systems. Here we report the molecular and isotopic signatures of gas, oil and formation waters from the biodegraded Tubridgi gas field. The onshore Tubridgi gas field is thought to lie at the end of a fill-spill chain from the offshore major oil and gas accumulations in the southern Barrow Sub-basin. An initial oil column at Tubridgi has been subsequently displaced by later gas charges. The Tubridgi gas is very dry (%methane/%ethane ~ 1000). Methane is isotopically light (delta13C = -49.2) and is depleted in 13C by ~10 compared to non-biodegraded gases from the Barrow Sub-basin. This, together with an isotopically heavy CO2 (delat13C = +1.8; ~6 enriched in 13C compared to non-biodegraded gas), suggests a major biogenic methane input derived from anaerobic methanogenic bacteria. The carbon isotopic composition of ethane (delta13C = -27) is only slightly enriched in 13C compared to non-biodegraded gas. Much larger enrichments occur in the hydrogen isotopes of ethane (deltaD = +42; ~180 enriched in D compared to non-biodegraded gas), suggesting anaerobic biodegradation has completely removed the higher (C3-C5) wet gases. This is supported by the less severely biodegraded Barrow Sub-basin natural gases, which can show up to 17 and 225 enrichment in 13C and D of propane, respectively, compared to non-biodegraded Barrow gas. Interestingly, the strong biogenic methane input seen in the carbon isotopes is not expressed in the hydrogen isotopes of methane (deltaD = -177 ), which is similar to the non-biodegraded gas. The Tubridgi-2 residual biodegraded heavy oil has a low API gravity of 23.5o and is the most sulphur-rich oil (S= 1.14 %) of all Australian oils. The gas-chromatogram displays an unresolved complex mixture with no n-alkanes. The level of biodegradation is heavy with 25-norhopane being present but no alteration of the sterane distributions are observed. The biomarker distribution of the Tubridgi-2 oil implies derivation from Late Triassic Middle Jurassic calcareous-influenced source rock deposited in a sub-oxic marine environment. Organic material extracted from the Tubridgi formation waters associated with the biodegraded gases mainly reflect the biodegraded oil input since very little low molecular weight `organics' was detected. Thus, the neutral organic compounds extracted at pH 7 are dominated by a homologous series of C19-C30 n-alkanes, while organic compounds extracted from acidified (pH 1) waters include a homologous series of C8-C18 n-alkylmonocarboxylic acids. The mutual exclusion between carbon numbers of the n-alkanes and n-alkylcarboxylic acids suggests a precursor-product relationship mediated by bacteria. However, the major organic components in the "acid" fraction are unidentified N and O containing compounds, most likely metabolic by-products of the biological activity. Cell counting is in progress, which will give an independent measure of the diversity and activity of the biological community within the reservoir.

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