Academic literature on the topic 'Seismic prospecting Australia'
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Journal articles on the topic "Seismic prospecting Australia"
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Young, D., R. Brockett, and J. Smart. "AUSTRALIA—SOVEREIGN RISK AND THE PETROLEUM INDUSTRY." APPEA Journal 45, no. 1 (2005): 191. http://dx.doi.org/10.1071/aj04017.
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Australia has rejoiced in its reputation for having low sovereign risk and corresponding rating, for decades. This reputation was bruised in the first decade after the High Court introduced Native Title into Australian law by the legislative response of the then Government, but has since recovered, and enjoys the world’s lowest country risk rating, and shares the worlds best sovereign risk rating with the USA. A number of government precipitated occurrences in recent times, however, raise the question: for how long can this continue?This paper tracks the long history of occasional broken resource commitments—for both petroleum and mining interests—by governments at both State and Federal level, and the policies which have driven these breaches. It also discusses the notorious recent cancellation of a resource lease by the Queensland Government, first by purporting to cancel the bauxite lease and, after legal action had commenced, by a special Act of Parliament to repeal a State Agreement Act. This has raised concerns in boardrooms around the world of the security of assets held in Australia on a retention, or care and maintenance basis.The paper also looks at the cancellation of the offshore prospecting rights held by WMC, with no compensation. This was a result of the concept that rights extinguished by the Commonwealth, with no gain to the Commonwealth or any other party do not constitute an acquisition of property, thereby denying access to the constitutional guarantee of ’just terms’ supposedly enshrined in the Australian Constitution where an acquisition has occurred.Some other examples are the prohibition on exploration in Queensland national parks last November. This cost some companies with existing tenures a lot of money as exploration permits were granted, but then permission to do seismic exploration refused (Victoria). Several losses of rights occurred as a result of the new Queensland Petroleum and Other Acts Amendment Act after investments have been made.Changes in fiscal policy can also impact on project viability, and some instances of this are considered.This paper also explores ways these risks can be minimised, and how and when compensation might be recovered.
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Alexander, E., and J. Morton. "SELECTING THE WINNING BID." APPEA Journal 42, no. 1 (2002): 523. http://dx.doi.org/10.1071/aj01029.
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Work program bidding is established as the favoured method of allocating petroleum exploration tenements in offshore Australian waters and most of onshore Australia. However, the selection of winning bids can be complicated by the ranking of 2D versus 3D seismic, seismic versus drilling, program timing issues etc. On occasion the selection of the winning bids has been contentious. This paper summarises the process developed by the Petroleum Group in South Australia to select the winning work program bids for prospective onshore blocks for which bids have been gazetted. No other Australian jurisdiction has yet publicly released their detailed bid assessment processes.Onshore acreage releases with work program bidding have been used in South Australia since the 1980s by Petroleum Group to:focus industry onto specific prospective areas of the State (e.g. the Cooper Basin post expiry of PELs 5 and 6 in 1999); maximise exploration commitments; and achieve competition policy.The South Australian Petroleum Act 2000 allows cash or work program bidding to be used depending on the acreage. Acreage releases are announced by Ministerial press release. Associated clear bid assessment criteria are published together with promotional material to aid applicants. The date and time for close of bidding are also established, usually allowing a 6–9 month acreage evaluation period, the timeframe depending on the volume of data involved, i.e. the exploration maturity of the area.Applications received as a result of a gazettal process (i.e. competing bids) are assessed by a process designed to ensure probity and to achieve the over-arching aim of the bidding process i.e. the suitability of the applicants proposed work program for evaluating the prospectivity of the licence area and discovering petroleum.A scoring system has been developed which establishes, for each bid what is effectively a risked net present value in well equivalents. In this system, guaranteed work scores higher than non-guaranteed work; early work scores higher than later work; wells with multiple targets are scored higher than single target wells; 2D and 3D seismic and other exploration activity is converted into well equivalents; and loading of the later, non-guaranteed years of work programs are heavily discounted.The scoring system may also take into account differences in the amount and density of exploration data and minor variations may be made to the system to take this into account. It is intended that details of the scoring system to be used in bid assessment will be published each time bids are sought to ensure transparency and a level playing field.Comparisons are made with acreage management philosophy and processes used by other regulatory regimes in Australia and internationally.
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Fainstein, Roberto, Juvêncio De Deus Correia do Rosário, Helio Casimiro Guterres, Rui Pena dos Reis, and Luis Teófilo da Costa. "Coastal and offshore provinces of Timor-Leste — Geophysics exploration and drilling." Leading Edge 39, no. 8 (August 2020): 543–50. http://dx.doi.org/10.1190/tle39080543.1.
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Regional geophysics research provides for prospect assessment of Timor-Leste, part of the Southeast Asia Archipelago in a region embracing the Banda Arc, Timor Island, and the northwest Australia Gondwana continental margin edge. Timor Island is a microcontinent with several distinct tectonic provinces that developed initially by rifting and drifting away from the Australian Plate. A compressive convergence began in the Miocene whereby the continental edge of the large craton collided with the microcontinent, forming a subduction zone under the island. The bulk of Timor Island consists of a complex mélange of Tertiary, Cretaceous, Jurassic, Triassic, Permian, and volcanic features over a basal Gondwana craton. Toward the north, the offshore consists of a Tertiary minibasin facing the Banda Arc Archipelago, with volcanics interspersed onshore with the basal Gondwana pre-Permian. A prominent central overthrust nappe of Jurassic and younger layers makes up the mountains of Timor-Leste, terminating south against an accretionary wedge formed by this ongoing collision of Timor and Australia. The northern coast of the island is part of the Indonesian back arc, whereas the southern littoral onshore plus shallow waters are part of the accretionary prism. Deepwater provinces embrace the Timor Trough and the slope of the Australian continental margin being the most prospective region of Timor-Leste. Overall crust and mantle tectonic structuring of Timor-Leste is interpreted from seismic and potential field data, focusing mostly on its southern offshore geology where hydrocarbon prospectivity has been established with interpretation of regional seismic data and analyses of gravity, magnetic, and earthquake data. Well data tied to seismic provides focal points for stratigraphic correlation. Although all the known producing hydrocarbon reservoirs of the offshore are Jurassic sands, interpretation of Permian and Triassic stratigraphy provides knowledge for future prospect drilling risk assessment, both onshore and offshore.
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Longley, Ian, and James Dirstein. "Prospectivity and play analysis in the frontier Great Australian Bight: the benefits of a public domain data system and the application of traditional and new technologies." APPEA Journal 56, no. 2 (2016): 579. http://dx.doi.org/10.1071/aj15085.
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The deep water portion of the Great Australian Bight remains an untested basin with the Gnarlyknots–1A well drilled in 2003 not penetrating deep enough to test the well's targets within the Upper Cretaceous Ceduna Delta section. If an anoxic marine shale source system, that is an effective source in many parts of West Africa, is present beneath the delta, then this could supply a material oil charge into the numerous fault block structures identified on seismic data. With eight wells due to be drilled in the next few years, this area will be one of the most active exploration frontier settings in the region. Since Australia has an open file system for technical data, the regional Flinders 2000 2D Marine seismic Interpretation report containing five regional Time structure maps is now in the public domain, as is the Gnarlyknots–1A well data and the raw seismic data from the Ceduna 3D survey acquired in 2012. These data were used to evaluate the untested Coniacian play interval with the construction of Reservoir Presence and quality, seal and charge relative probability maps made from various proxies that were then stacked to show areas of relative prospectivity. This traditional approach was supplemented by the an example showing pre-interpretation surfaces from the pre-Cenomanian portion of the 3D volume to help develop a better understanding of the potential prospectivity of deeper intervals not captured on the submitted open file maps. The workflow presented here suggests some parts of the Ceduna Sub Basin are significantly more prospective than others. Moreover, we demonstrate that even in frontier settings with minimal well data, pre-interpretation processing and simple play analysis together can be a useful and efficient approach for delivering significant insights into prospectivity. This workflow will ultimately promote more exploration thinking and activity in the future.
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Holford, Simon, Nick Schofield, Justin MacDonald, Ian Duddy, and Paul Green. "Seismic analysis of igneous systems in sedimentary basins and their impacts on hydrocarbon prospectivity: examples from the southern Australian margin." APPEA Journal 52, no. 1 (2012): 229. http://dx.doi.org/10.1071/aj11017.
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The increasing availability of 3D seismic data from sedimentary basins at volcanic and non-volcanic continental margins has provided fundamental new insights into both the storage and transport of magma in the continental crust. As global hydrocarbon exploration increasingly focuses on passive margin basins with evidence for past intrusive and extrusive igneous activity, constraining the distribution, timing and pathways of magmatism in these basins is essential to reduce exploration risk. Producing and prospective Australian passive margin basins where igneous systems have been identified include the Bight, Otway, Bass, Gippsland and Sorell basins of the southern margin. This paper reviews both the impacts of volcanic activity on sedimentary basin hydrocarbon prospectivity (e.g. advective heating, reservoir compartmentalisation and diagenesis), and the styles, distribution and timing of late Cretaceous–Recent extrusive and intrusive igneous activity along basins of the southern Australian margin, providing illustrative examples based on 2D and 3D seismic reflection data.
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Smith, Nicholas R. A., Anya M. Reading, Michael W. Asten, and Charles W. Funk. "Constraining depth to basement for mineral exploration using microtremor: A demonstration study from remote inland Australia." GEOPHYSICS 78, no. 5 (September 1, 2013): B227—B242. http://dx.doi.org/10.1190/geo2012-0449.1.
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We constrain the depth and seismic structure of stiff sediment cover overlying a prospective basement terrane using a passive seismic technique which uses surface wave energy from microtremor (also known as ambient seismic energy or seismic noise). This may be applied to mineral exploration under cover to decrease the inherent ambiguity in modeling potential field data for exploration targeting. We use data from arrays of portable broadband seismometers, processed using both the multimode spatially averaged coherency (MMSPAC) method and the horizontal to vertical spectral ratio (HVSR) method, to produce profiles of seismic velocity structure along a 12-km transect. We have developed field protocols to ensure consistent acquisition of high-quality data in near-mine and remote locations and a variety of ground conditions. A wavefield approaching the theoretical ideal for MMSPAC processing is created by combining the energy content of an off-road vehicle, driven around the seismometer array, and ambient sources. We found that this combination results in significantly higher-quality MMSPAC waveforms in comparison with that obtained using ambient energy alone. Under ideal conditions, a theoretical maximum depth of investigation of 600 m can be achieved with a hexagonal sensor array with 50-m radius and MMSPAC and HVSR. The modeling procedure we employ is sensitive to layer thicknesses of [Formula: see text]. A high-velocity layer in the sediment package reduces the sensitivity to deeper structure. This can limit the modeling of underlying layers but may be addressed by detailed analysis of the HVSR peaks. Microtremor recordings including off-road vehicle noise, combined with the MMSPAC and HVSR processing techniques, may therefore be used to constrain sediment structure and depth to basement in a cost-effective and efficient method that could contribute greatly to future mineral exploration under cover.
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Bendall, Malcolm, Clive Burrett, Paul Heath, Andrew Stacey, and Enzo Zappaterra. "Seeing through the dolerite-seismic imaging of petroleum systems, Tasmania, Australia." APPEA Journal 55, no. 1 (2015): 297. http://dx.doi.org/10.1071/aj14024.
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Prior to the onshore work of Empire Energy Corporation International (Empire) it was widely believed that the widespread sheets (>650 m thick) of Jurassic dolerite (diabase) would not only have destroyed the many potential petroleum source and reservoir rocks in the basin but would also absorb seismic energy and would be impossible to drill. By using innovative acquisition parameters, however, major and minor structures and formations can be identified on the 1,149 km of 2D Vibroseis. Four Vibroseis trucks were used with a frequency range of 6–140 Hz with full frequency sweeps close together, thereby achieving maximum input and return signal. Potential reservoir and source rocks may be seismically mapped within the Gondwanan Petroleum System (GPS) of the Carboniferous to Triassic Parmeener Supergroup in the Tasmania Basin. Evidence for a working GPS is from a seep of migrated, Tasmanite-sourced, heavy crude oil in fractured dolerite and an oil-bearing breached reservoir in Permian siliciclastics. Empire’s wells show that each dolerite sheet consists of several intrusive units and that contact metamorphism is usually restricted to within 70 m of the sheets’ lower margins. In places, there are two thick sheets, as on Bruny Island. One near-continuous 6,500 km2 sheet is mapped seismically across central Tasmania and is expected, along with widespread Permian mudstones, to have acted as an excellent regional seal. The highly irregular pre-Parmeener unconformity can be mapped across Tasmania and large anticlines (Bellevue and Thunderbolt prospects and Derwent Bridge Anticline) and probable reefs can be seismically mapped beneath this unconformity within the Ordovician Larapintine Petroleum System. Two independent calculations of mean undiscovered potential (or prospective) resources in structures defined so far by Empire’s seismic surveys are 596.9 MMBOE (millions of barrels of oil equivalent) and 668.8 MMBOE.
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Heath, A. M., A. L. Culver, and C. W. Luxton. "Gathering good seismic data from the Otway Basin." Exploration Geophysics 20, no. 2 (1989): 247. http://dx.doi.org/10.1071/eg989247.
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Cultus Petroleum N.L. began exploration in petroleum permit EPP 23 of the offshore Otway Basin in December 1987. The permit was sparsely explored, containing only 2 wells and poor quality seismic data. A regional study was made taking into account the shape of the basin and the characteristics of the major seismic sequences. A prospective trend was recognised, running roughly parallel to the present shelf edge of South Australia. A new seismic survey was orientated over this prospective trend. The parameters were designed to investigate the structural control of the prospects in the basin. To improve productivity during the survey, north-south lines had to be repositioned due to excessive swell noise on the cable. The new line locations were kept in accordance with the structural model. Field displays of the raw 240 channel data gave encouraging results. Processing results showed this survey to be the best quality in the area. An FK filter was designed on the full 240 channel records. Prior to wavelet processing, an instrument dephase was used to remove any influence of the recording system on the phase of the data. Close liaison was kept with the processing centre over the selection of stacking velocities and their relevance to the geological model. DMO was found to greatly improve the resolution of steeply dipping events and is now considered to be part of the standard processing sequence for Otway Basin data. Seismic data of a high enough quality for structural and stratigraphic interpretation can be obtained from this basin.
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Nguyen, Duy, Dianne S. Edwards, Merrie-Ellen Gunning, and George Bernardel. "The Northwest Offshore Otway Basin Well Folio." APPEA Journal 62, no. 2 (May 13, 2022): S461—S466. http://dx.doi.org/10.1071/aj21124.
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The Otway Basin is a northwest–southeast trending rift basin which spans from onshore Victoria and South Australia into the deep-water offshore. The prospective supersequences within the basin are largely of Cretaceous age that host three possible petroleum systems (Austral 1, 2 and 3). While there is production from onshore depocentres, and the inboard Shipwreck Trough, the majority of the offshore basin remains underexplored. Recent regional studies have highlighted the need for further work across the underexplored parts of the basin and here we focus on the offshore northwest Otway Basin, integrating reinterpreted historical well data, newly acquired and recently reprocessed seismic data. This new Well Folio consists of composite logs and supporting data, which includes interpreted lithologies, petrophysical analyses, the analysis of historic organic geochemistry and organic petrology. In addition, updated well markers are provided based on seismic interpretation and new biostratigraphy in key wells. This integrated study provides the basis for renewed prospectivity assessment in the northwest offshore portion of the Otway Basin.
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Warris, B. J. "THE HYDROCARBON POTENTIAL OF THE PALAEOZOIC BASINS OF WESTERN AUSTRALIA." APPEA Journal 33, no. 1 (1993): 123. http://dx.doi.org/10.1071/aj92010.
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There are four main Palaeozoic Basins in Western Australia; the Perth Basin (Permian only), the Carnarvon Basin (Ordovician-Permian), the Canning Basin (Ordovician-Permian) and the Bonaparte Basin (Cambrian-Permian).The Perth Basin is a proven petroleum province with commercially producing gas reserves from Permian strata in the Dongara, Woodada and Beharra Springs gas fields.The Palaeozoic of the Carnarvon Basin occurs in three main sub-basins, the Ashburton, Merlinleigh and Gascoyne Sub-basins. No commercial petroleum discoveries ahve been made in these basins.The Canning Basin can be divided into the southern Ordovician-Devonian province of the Willara and Kidson sub-basins and Wallal Embayment and Anketell Shelf, and the northern Devonian-Permian province of the Fitzroy and Gregory sub-basins. Commercial production from the Permo-Carboniferous Sundown, Lloyd, West Terrace, Boundary oilfields and from the Devonian Blina oilfield is present only in the Fitzroy sub-basins.The Bonaparte Basin contains Palaeozoic strata of Cambrian-Permian age but only the Devonian-Permian is considered prospective. Significant but currently non-producing gas discoveries have been made in the Permian of the Petrel and Tern offshore gas fields.Based on the current limited well control, the Palaeozoic basins of Western Australia contain excellent marine and non marine clastic reservoirs together with potential Upper Devonian and Lower Carboniferous reefs. The dominantly marine nature of the Palaeozoic provides thick marine shale seals for these reservoirs. Source rock data is very sparse but indicates excellent gas prone source rocks in the Early Permian and excellent—good oil prone source rocks in the Early Ordovician, Late Devonian, Early Carboniferous and Late Permian.Many large structures are present in these Palaeozoic basins. However, most of the existing wells were drilled either off structure due to insufficient and poor quality seismic or on structures formed during the Mesozoic which postdated primary hydrocarbon migration from the Palaeozoic source rocks.With modern seismic acquisition and processing techniques together with a better understanding of the stratigraphy, structural development and hydrocarbon migration, the Palaeozoic basins of Western Australia provide the explorer with a variety of high risk, high potential plays without the intense bidding competition currently present along the North West Shelf of Australia.
Dissertations / Theses on the topic "Seismic prospecting Australia"
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Dunne, Jarrod Craig. "Subcoal seismic exploration in the Gippsland Basin (Australia) /." Connect to thesis, 1996. http://eprints.unimelb.edu.au/archive/00000702.
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Carroll, Paul Geoffery. "Pre-Permian structure and prospectivity at Gidgealpa, South Australia /." Title page, contents and abstract only, 1990. http://web4.library.adelaide.edu.au/theses/09SM/09smc3195.pdf.
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Thesis (M. Sc.)--University of Adelaide, National Centre of Petroleum Geology & Geophysics, 1992.Vol. 2 consists of 30 col. & folded maps & charts. Includes five overlays in vol. 1. Includes bibliographical references (leaves 152-162).
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Carroll, Paul Geoffrey. "Pre-Permian structure and prospectivity at Gidgealpa, South Australia." Thesis, 1990. http://hdl.handle.net/2440/112765.
Full textBooks on the topic "Seismic prospecting Australia"
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1953-, Mory A. J., Blundell K. A. 1966-, and Geological Survey of Western Australia., eds. The geophysical interpretation of the Woodleigh impact structure, Southern Carnarvon Basin, Western Australia. Perth, W.A: Geological Survey of Western Australia, 2001.
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Collins, C. D. N. Seismic velocities in the crust and upper mantle of Australia. Canberra: Australian Govt. Pub. Service, 1988.
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Exon, N. F. Rig seismic research cruise 3: Offshore Otway Basin, southeastern Australia. Canberra: Australian Govt. Pub. Service, 1987.
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Colwell, James B. Rig seismic research cruise 13: Structure and stratigraphy of the northeast Gippsland Basin and southern New South Wales margin : initial report. Canberra: Australian Govt. Pub. Service, 1987.
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Colwell, James B. Rig seismic research cruise 13: Structure and stratigraphy of the northeast Gippsland Basin and southern New South Wales margin : initial report. Canberra: Australian Government Publishing Service, 1987.
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J, Evans B., and Minerals and Energy Research Institute of Western Australia., eds. The recognition and suppression of seismic multiples, offshore north-west shelf, Australia: Results of research carried out as MERIWA Project No 88 at Curtin University of Technology. East Perth, WA: Distributed bu MERIWA, 1990.
Find full textConference papers on the topic "Seismic prospecting Australia"
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Urosevic, M., S. Ziramov, and X. Moreau. "The First Experimental Seismic Investigation over Prospective Uranium Deposits at Mulga Rock, Western Australia." In Near Surface Geoscience 2016 - First Conference on Geophysics for Mineral Exploration and Mining. Netherlands: EAGE Publications BV, 2016. http://dx.doi.org/10.3997/2214-4609.201602128.
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Alexander, Elinor. "Natural hydrogen exploration in South Australia." In PESA Symposium Qld 2022. PESA, 2022. http://dx.doi.org/10.36404/putz2691.
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South Australia has taken the lead nationally in enabling exploration licences for natural hydrogen. On 11 February 2021 the Petroleum and Geothermal Energy Regulations 2013 were amended to declare hydrogen, hydrogen compounds and by-products from hydrogen production regulated substances under the Petroleum and Geothermal Energy Act 2000 (PGE Act). Companies are now able to apply to explore for natural hydrogen via a Petroleum Exploration Licence (PEL) and the transmission of hydrogen or compounds of hydrogen are now permissible under the transmission pipeline licencing provisions of the PGE Act. The maximum area of a PEL is 10,000 square kilometres so they provide a large acreage position for explorers. PEL applicants need to provide evidence of their technical and financial capacity as well as a 5-year work program which could include field sampling, geophysical surveys (e.g., aeromagnetics, gravity, seismic and MT) and exploration drilling to evaluate the prospectivity of the licence for natural hydrogen. Since February 2021, seven companies have lodged 35 applications for petroleum exploration licences (PELs), targeting natural hydrogen. The first of these licences (PEL 687) over Kangaroo Island and southern Yorke Peninsula was granted to Gold Hydrogen Pty Ltd on 22 July 2021. As well as issuing exploration licences, a key role of the South Australian Department for Energy and Mining is to provide easy access to comprehensive geoscientific data submitted by mineral and petroleum explorers and departmental geoscientists since the State was founded in 1836. Access to old 1920s and 1930s reports, together with modern geophysical and well data has underpinned the current interest in hydrogen exploration. Why the interest? 50-80% hydrogen content was measured in 1931 by the Mines Department in gas samples from wells on Kangaroo Island, Yorke Peninsula and the Otway Basin, potential evidence that the natural formation of hydrogen has occurred. Iron-rich cratons and uranium-rich basement (also a target for geothermal energy explorers) occur in the Archaean-Mesoproterozoic Gawler Craton, Curnamona and Musgrave provinces which are in places fractured and seismically active with deep-seated faults. Sedimentary cover ranges from Neoproterozoic-Recent in age, with thick clastic, carbonate and coal measure successions in hydrocarbon prospective basins and, in places, occurrences of mafic intrusives and extrusives, iron stones, salt and anhydrite which could also be potential sources of natural hydrogen.
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Ben Habel, Wael, and Siddharth Dubey. "Towards a Multidisciplinary Approach in Play Characterisation: An Integrated Case Study from Browse Basin, NW Shelf, Australia." In Offshore Technology Conference Asia. OTC, 2022. http://dx.doi.org/10.4043/31603-ms.
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Abstract Stratigraphic forward modeling (SFM) is an innovative approach to subsurface facies prediction at the basin scale that augments and overcomes some of the limitations of conventional seismic, well, and analog data. As a multidisciplinary approach to play characterization, SFM improves the efficiency of current workflows, which is important given the current downward pressure on capex in oil and gas companies. A 2D SFM study on data from Browse basin, NW Australia, was conducted to enhance the prediction of facies distribution and improve play characterization by integrating SFM with other disciplines. The work started with seismic interpretation and depth conversion. Then, a third to fourth-order sequence stratigraphy interpretation was performed to determine the main sequence boundaries, maximum flooding surfaces, and a relative sea-level curve. The sequence stratigraphy results were later used to infer some of the inputs and parameters of the SFM model. The model simulates the deposition of clastic and carbonates from the Turonian (Late Cretaceous) to the present day. The results from the model were used to validate some of the geological concepts and the seismic interpretation. In addition, the approach enabled the prediction of reservoir quality, reservoir distribution, the presence of the seal, and the quantification of erosion. A 2D petroleum system model (PSM) covering the area from the Yampi shelf to the Seringapatam sub-basin was built using seismic interpretation, regional tectonic information, source rock geochemistry, and paleo heat flow. The results from SFM were integrated into a 2D PSM by resampling facies and erosion properties for each of the finely subdivided layers. The high-resolution 2D PSM with refined facies was simulated in geological time to model the basin evolution and its impact on all elements and processes of the petroleum system of Browse basin, which have been validated with nearby fields. As a result of this integrated approach, the risk of charge and entrapment in prospective stratigraphic traps was better understood and quantified. In addition, this approach helped to increase yet-to-find (YTF) hydrocarbon resources by accurately predicting reservoir distribution and extent. The generation of a 2D SFM and its integration within a multidisciplinary approach to predict facies represents a novel addition to exploration workflows. Adopting such an approach can improve significantly on the understanding of hydrocarbon entrapment and further reduce exploration risks.