No abstract available

The Capel and Faust basins, located on the Lord Howe Rise in water depths between 1,300 m and 2,500 m, were the focus of a series of marine surveys by Geoscience Australia in 2006 and 2007. Their interpretation of high-fold 2D seismic reflection, gravity and magnetic, multi-beam bathymetry, sonobuoy refraction, heat flow and geological sample data suggested the basins have petroleum potential. Analysis of petroleum generation and migration, based on structural maps, lithological and other data supplied by Geoscience Australia, is the focus of this study. Basin models predict that most of the deeper depocentres in the Capel and Faust basins, mapped as containing Jurassic-aged pre-rift and Cretaceous-aged syn-rift source rocks, have the potential to expel oil and gas, and charge nearby syn-rift and post-rift reservoir formations from Cretaceous time to the present day. Multi-1D thermal and petroleum generation models predict: - Pre-rift (215 - 165 Ma) and Syn-rift 1 (130 - 100 Ma) megasequences within the deeper depocentres are within the oil or gas generation window; - Based on the expected presence of petroleum-generative coaly source rocks, total oil and gas expulsion from the major depocentres exceeds 5 MMbbl/km2 and 25 Bcf/km2 respectively from the Pre-rift source rocks, and 20 MMbbl/km2, and 300 Bcf/km2 respectively from the Syn-rift 1 source rocks. In terms of timing, 80% of total hydrocarbon expulsion is predicted by the end of the Eocene, with maximum expulsion taking place between the Late Cretaceous and the Late Eocene (c. 68-36 Ma); - A significant increase in paleo-water depth in late Cenozoic time has supressed further heating related to post-Eocene burial. However, modelling predicts post-Eocene expulsion of oil and gas may have been partly enhanced by post-rift magmatism. In this study total expelled oil and gas volumes are 'migrated across' mapped horizons to assess charge of and fill-spill relationships between structural traps. This map-based charge modelling assumes certain reservoir properties with no migration losses and predicts that: - Accumulations within potential reservoir facies, such as deltaic, shoreline and turbidite sandstones of the lower Post-rift unit (70 - 68 Ma) are dominantly gas with volumes generally about 5 to 9 Tcf at burial depths of 400 - 700 m; - Accumulations within similar sandstones of the upper Syn-rift 2 unit are mixed oil and gas (about 2 to 3 billion bbl oil and 10 Tcf gas) at burial depths of 400 - 800 m; - Similar accumulations are present in the lower Syn-rift 2 and Syn-rift 1 fluvial sands; - Most of the mapped structural traps are buried to relatively shallow depths and seal effectiveness for containment must therefore be a significant risk. Deeper structures and stratigraphic plays may further contribute to the petroleum potential in the basins. The model presented here illustrates the potential for petroleum charge of structural traps in the Capel and Faust basins and highlights the risks associated with source rock distribution and type, reservoir distribution and quality, and seal effectiveness. Volumetric and charge assessments could be further refined using higher density seismic data and appropriate rock property data for reservoir and seal rocks in combination with 3D modelling.

The Otway Basin is now emerging as a major commercial gas province in southeast Australia. Sub-commercial oil occurrences in the basin suggest a liquids potential that has yet to be thoroughly addressed through rigorous geochemical study. To achieve this there is a critical need for more detailed information on the spatial variations in petroleum potential, condensate:gas ratios, (CGR), gas:oil ratios (GOR) and maturation characteristics within potential source horizons to identify sources for the oil and gas. In the Otway Basin, previous regional source rock assessment has identified a range of Late Jurassic to Cretaceous lithostatigraphic units that can be considered as potential petroleum source rocks (Edwards et al., 1999). Furthermore, oil families are particularly well understood through detailed carbon isotope and biomarker studies (Edwards et al., 1999; unpublished studies by Geoscience Australia and GeoMark Research Inc). However, there is a lack of integration of source rock characteristics with gas and oil geochemistry, leading to the identification of the effective source rocks in the Otway Basin. Otway Basin Organic Geochemistry Study A new organic geochemistry study in the Otway Basin is examining the petroleum potential of selected source intervals and aims to identify effective source rocks through oil-source correlations. As part of Geoscience Australia?s regional analysis of the Otway Basin, the study involves the integration of the geochemistry and biostratigraphic data within a sequence stratigraphic framework. The Otway Basin Project is currently interpreting key offshore and onshore wells, and a regional grid of conventional and deep-seismic data. Together, this work aims to chronicle a time-series of source rock development in the Otway Basin. New and existing samples of potential source rocks were selected for analysis by reviewing well logs, geochemical plots and web-based geochemical profiles. A total of 169 sediments from 32 onshore and 15 offshore wells were selected for more detailed gas-oil-source correlation studies. New vitrinite reflectance and fluorescence (VRFTM) analyses based on the technique of Newman (1997) were also carried out on samples from four key offshore wells (Mussell-1, Troas-1, Trumpet-1 and Voluta-1). Kerogen-specific VRFTM analyses will help to constrain vitrinite reflectance-vs-depth profiles, which are critical for accurate burial history modelling, as well as providing the primary control on maturation. On-Line Access to Organic Geochemistry Data The primary resource for organic geochemical data for the Otway Basin Project is ORGCHEM, Geoscience Australia?s Oracle database. Open-file information in the ORGCHEM database is available to users on-line via the Geoscience Australia?s website (www.ga.gov.au/oracle/apcrc). The website enables users to build geochemical profiles of Rock Eval (S2, HI, PI and Tmax) and vitrinite reflectance (VR) data (Figure 1) for most offshore exploration wells. For example, after submitting an initial well query, the user can generate a downhole profile of geochemistry results by clicking the ?Graph? option under the ?OrgChem? header. Sample ages are automatically estimated using GA?s STRATDAT Oracle database (Figure 1). .

Legacy product - no abstract available

<p>The Browse Basin, situated in the offshore Northwest region of Australia, is part of a world class hydrocarbon province hosting vast reserves of gas and condensate (Le Poidevin et al., 2015). In addition, both non-biodegraded (Caswell) and biodegraded (Cornea and Gwydion) oil fields are present. The primary source of gas is thought to be a Lower-Middle Jurassic fluviodeltaic sequence whereas Upper Jurassic to Lower Cretaceous marine sequences are the most likely source of liquid hydrocarbons (Rollet et al., 2016). Complex fill histories, mixed marine and terrestrial biomarker signatures and, on the Yampi Shelf, the addition of biogenic methane, have made it difficult to understand the charge history of accumulations in the basin. <p>This study combines comprehensive two dimensional gas chromatography coupled to time-of-flight mass spectrometry (GCxGC-TOFMS) and compound specific isotope analyses (CSIA) of n-alkanes, aromatic hydrocarbons and diamondoids to identify numerous hydrocarbon contributions to the accumulations in the Browse Basin. The absolute concentrations, ratios and isotopic composition of diamondoids have been shown to be source-specific and highly resistant to both thermal maturity and biodegradation (e.g Dahl et al., 1999; Grice et al., 2000; Moldowan et al., 2015). Diamondoid analysis and quantitation was performed on GCxGC-TOFMS as it minimises interference of co-eluting compounds and allows whole oil injection, eliminating potential losses from sample preparation (Silva et al., 2013; Wang et al., 2013). <p>The non-biodegraded Caswell oils contained high diamondoid concentrations, well above diamondoid yields recovered from laboratory oil cracking experiments (Dahl et al., 1999; Fang et al., 2012), indicating the contribution of a high maturity fluid (wet gas - early dry gas). Contrastingly, typical biomarker parameters indicate that these fluids have been generated from a marine source rock within the oil window (methylphenanthrene index = 0.4). Thefore, by combining the information from routine biomarker analyses with quantitative diamondoid analysis, the Caswell accumulation can be demonstrated to consist of a mixture of hydrocarbons. Furthermore no gas was recovered from this field, which is in disagreement with the high diamondoid concentrations found in the fluids. This indicates that gas has escaped from the structure, leaving behind a hydrocarbon field that initially seems to consist of marine oil but actually contains a mixture of hydrocarbons. <p>Although the biodegraded oils displayed even higher diamondoid concentrations than the Caswell oils, a similar mixed hydrocarbon signature cannot be confirmed from quantitative diamondoid analysis as biodegradation increases the concentration of these compounds. However due to their high abundance, carbon isotopic composition of individial diamondoids could be measured in the biodegraded oils. The δC values of methyladamantanes in biodegraded oils become progressively more depleted with increasing biodegradation and the depletion is more pronounced for dimethyladamantane. As biogenic methane is isotopically depleted compared to thermogenic methane, these results suggest that alteration of adamantanes could have occurred during the biodegradation process. <p>Diamondoid concentrations and their stable isotopic signatures provide further insight into the multiple sources of hydrocarbons that are contained within the Browse Basin acumulations and furthermore provide insight into the formation and occurrence of diamondoids in biodegraded oil fields. <p>References <p>Dahl, J.E., Moldowan, J.M., Peters, K.E., Claypool, G.E., Rooney, M.A., Michael, G.E., Mello, M.R., Kohnen, M.L., 1999. Diamondoid hydrocarbons as indicators of natural oil cracking. Nature 399. <p>Fang, C., Xiong, Y., Liang, Q., Li, Y., 2012. Variation in abundance and distribution of diamondoids during oil cracking. Organic Geochemistry 47, 1-8. <p>Grice, K., Alexander, R., Kagi, R.I., 2000. Diamondoid hydrocarbon ratios as indicators of biodegradation in Australian crude oils. Organic Geochemistry 31, 67-73. <p>Le Poidevin, S.R., Kuske, T.J., Edwards, D.S., Temple, P.R., 2015. Australian Petroleum Accumulations Report 7 Browse Basin: Western Australia and Territory of Ashmore and Cartier Islands adjacent area, 2nd edition. Record 2015/10. Geoscience Australia, Canberra. <p>Moldowan, J.M.M., Dahl, J., Zinniker, D., Barbanti, S.M., 2015. Underutilized advanced geochemical technologies for oil and gas exploration and production-1 . The diamondoids. Journal of Petroleum Science and Engineering 126, 87-96. <p>Rollet, N., Grosjean, E., Edwards, D., Palu, T., Abbott, S., Totterdell, J., Lech, M.E., Khider, K., Hall, L., Oolov, C., Nguyen, D., Nicholson, C., Higgins, K. and Mclennen, S., 2016. New insights into the petroleum prospectivity of the Browse Basin: results of a multi-disciplinary study. The APPEA Journal, 483-494. <p>Silva, R.C., Silva, R.S.F., Castro, E.V.R. De, Peters, K.E., Azevedo, D.A., 2013. Extended diamondoid assessment in crude oil using comprehensive two-dimensional gas chromatography coupled to time-of-flight mass spectrometry. Fuel 112, 125-133. <p>Wang, G., Shi, S., Wang, P., Wang, T., 2013. Analysis of diamondoids in crude oils using comprehensive two-dimensional gas chromatography / time-of-flight mass spectrometry. Fuel 107, 706-714.

Few published studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. This paper presents strong geochemical evidence for coals being the source for the sub-economic oil accumulations in the Bass Basin. Oils in the Bass Basin form a single oil population. Biodegradation of Cormorant oil results in a separate oil family compared to Pelican and Yolla crudes. Oil-to-source correlation based on biomarkers and carbon isotopes shows that the Early Eocene to Palaeocene coals are effective source rocks in the Bass Basin. This is in contrast to previous work which favoured disseminated organic matter in claystone as the sole source (Miyazaki, 1995). Potential oil-prone source rocks in the Bass Basin are the early Tertiary coals, mainly concentrated in the Middle to Early Eocene succession. These coals have hydrogen indices (HI) up to 500 mg HC/gTOC) and are associated with disseminated organic matter in claystones that are mainly gas prone. Maturity is sufficient for oil and gas generation with vitrinite reflectance (VR) up to 1.8 % at base of Pelican-5. Igneous intrusions, mainly within Palaeocene, Oligocene and Miocene sediments, produce localised elevated maturity to 5 % VR. The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are: (i) the onset of oil generation at a VR of 0.65 % (2450m in Pelican-5); (ii) the onset of expulsion (primary migration) at a VR of 0.75 % (2700 to 3200m in Bass Basin; 2850m in Pelican-5); (iii) the main oil window between VR of 0.75 % and 0.95 % (2850-3300m in Pelican-5); and, (iv) the main gas window at VR >1.2 % (>3650m in Pelican-5).

Evolution of the Lord Howe Rise basin systems and underlying basement terrances were influenced by multiple periods of tectonism and volcanic activity spanning the Palaeozoic to Tertiary. The prospects for hydrocarbon accumulations are moderate to high in several basins of the LHR, with evidence such as amplitude anamalies, bottom-simulating reflectors and low-level seeps observed on seismic and remotedly sensed data. The economic viability of exploration and production in this rremote region has not been assessed.

Exploration for Unconventional Hydrocarbons in Australia reached a new milestone when Beach Energy announced the first successful flow test of a shale gas target in the Cooper Basin. The ever expanding coal seam gas industry on Australia's east coast in addition to the large resource potential of shale and tight gas in Australia's eastern basins has put Australia firmly on the radar of many local and international exploration companies. Over the next 12 months Geoscience Australia in collaboration with its counterparts in the State and Territory resource and energy departments will begin an assessment of Australia's coal seam gas, shale gas and oil and tight gas resource potential. Capitalising on decades of high quality geological data held by the Commonwealth and the States and Territories, the aim of this collaboration is to develop nationally consistent assessment methodologies and provide robust national resource estimates in an internationally accepted standard. Overall, the programme aims to answer the 'where' and 'how much' questions for government, as well as provide this new industry with pre-competitive data and tools for comparing exploration opportunities. The immediate goal is to provide a first-pass, high level estimate of the likely resource volumes, which will be reported in the second edition of the Australian Energy Resource Assessment (published by RET). The longer term work program aims to assess Australia's onshore basins in terms of their resource potential and provide pre-competitive data to industry. To achieve this, several geological techniques will be applied including, but not limited to, geochemical screening, mapping of source rock occurrences and their distributions as well as physical rock property studies.

Legacy product - no abstract available

The objectives of Project 121.19 were: To understand the deep crustal architecture, the structural reactivation processes and the mechanisms of hydrocarbon generation, migration and entrapment within the Vulcan Sub-Basin, Timor Sea. To achieve the aims of the project, two surveys (Vulcan I & II) were conducted between October and December 1990. This report summarises the results of the Vulcan Sub-Basin I Survey (Survey 97), which focussed on the high resolution seismic and geochemical component of Project 121.19 (i.e. the structural reactivation, hydrocarbon generation and migration theme). The Timor Sea program achieved most of its objectives. The seismic data should, when processed, allow a much better understanding of the nature of the fault reactivation processes in the area. In addition, strike lines run along the Londonderry High show that near-vertical faults appear to correspond with the position of transfer faults which have been inferred from our interpretation of BMR's Timor Sea aeromagnetic data. The geochemical program identified a number of significant hydrocarbon anomalies in the area. The anomalies fell predominantly into two groups. One group was located over, and to the north-east to south-east of the Skua Field, while the other group was associated with transfer faulting, and a major aeromagnetic high, on the edge of the Vulcan Sub-Basin, south-east of Montara 1.