Relevant bibliographies by topics / Petrel sub-basin

Academic literature on the topic 'Petrel sub-basin'

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Published: 10 December 2022
Last updated: 28 January 2023

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Journal articles on the topic "Petrel sub-basin"

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McConachie, B. A., M. T. Bradshaw, and J. Bradshaw. "PETROLEUM SYSTEMS OF THE PETREL SUB-BASIN-AN INTEGRATED APPROACH TO BASIN ANALYSIS AND IDENTIFICATION OF HYDROCARBON EXPLORATION OPPORTUNITIES." APPEA Journal 36, no. 1 (1996): 248. http://dx.doi.org/10.1071/aj95014.

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A petroleum system evaluation of the Petrel Sub-basin in the Bonaparte Gulf, northwest Australia, suggests that the wells drilled in the area have not fully evaluated the petroleum potential. Some of the lowest risk plays in the basin have not been tested adequately or have not been assessed in probable economic fairways.Several important discoveries have highlighted the existence of at least three petroleum systems in the Petrel Sub-basin; Larapintine, Transitional and Gondwanan. Best known are the Gondwanan gas discoveries at Petrel, Tern and most recently Fishburn, where hydrocarbons are reservoired in Late Permian sandstones and are probably sourced from Permian deltaic sequences. Kurt her inshore, oil has been recovered from Carboniferous and Early Permian reservoirs at Turtle and Barnett. The source of the oil is considered to be Carboniferous anoxic marine shales of a distinct petroleum system transitional between the Gondwanan and Larapintine systems (Milligans Formation source rock and Late Carboniferous to Permian reservoirs). Onshore, there is a gas discovery at Gariinala-1 and significant oil shows in Ningbing-1, in Late Devonian Larapintine system rocks. Geochemical analysis of the oil shows it to be sourced from a carbonate marine source rock, different from the clastic derived oils obtained from Turtle and Barnett.Recent discoveries in the Timor Sea have provoked a re-assessment of the very similar, largely untested, Mesozoic, Westralian petroleum system in the outer part of the Petrel Sub-basin. The prospective Mesozoic play fairway occurs in the northern part of the Petrel Sub-basin, extending into Area B of the Zone of Cooperation.
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Johnstone, Rosie, and Linda Stalker. "The Petrel Sub-basin: a world-class CO." APPEA Journal 62, no. 1 (May 13, 2022): 263–80. http://dx.doi.org/10.1071/aj21092.

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In 2021, the Australian Government announced a round of offshore greenhouse gas acreage release, including an area where research by Shell/CSIRO in 2016/2017 indicated close to 1 Gt carbon dioxide storage potential within the Mesozoic sediments of the Sandpiper, Elang and Plover Formations of the Petrel Sub-basin. The joint Shell/CSIRO study assessed key containment issues (legacy wells, potentially conductive faults, top seal extent) and storage formation connectivity. To study containment risk, CSIRO assessed a single injection well scenario and concluded that injection of up to 20 MTPA would not create geomechanical failure. Based on these findings, a ~5000 km2 area of interest southeast of the Petrel Field was proposed as suitable for injection in the Plover/Elang formations. The Shell team constructed topographical dynamic models at five potential locations. Three further models were built to simulate a base case and two end-member scenarios: (1) high permeability (leak point risk) and (2) low-pressure dissipation (top seal risk). The study showed that the development of two injector wells at one of the locations could safely and conservatively store 149 Mt, injected over a period of 30 years. Similar capacity is expected at four out of the five locations identified within the investigated area. Expansion to >2 injection wells per location, additional injection into the Sandpiper Formation and expansion to the west of the initially mapped focus area all point to achievable gigatonne storage potential. The joint study significantly expanded the understanding of the storage capacity, with recommendations for further data acquisition in both greenhouse gas (GHG) permits (GHG21-1 and GHG21-2).
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Phillips, Laura, Paul Massara, and Kenneth McCormack. "Faster play-based exploration, Petrel Sub-basin, Australia." ASEG Extended Abstracts 2019, no. 1 (November 11, 2019): 1–4. http://dx.doi.org/10.1080/22020586.2019.12073046.

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Lemon, N. M., and C. R. Barnes. "SALT MIGRATION AND SUBTLE STRUCTURES: MODELLING OF THE PETREL SUB-BASIN, NORTHWEST AUSTRALIA." APPEA Journal 37, no. 1 (1997): 245. http://dx.doi.org/10.1071/aj96015.

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Salt diapirs have been well documented in the Petrel Sub-basin of the Bonaparte Basin, offshore northwestern Australia, indicating that mobile salt exists at depth. G raphi- cal manipulation of geometric shapes on paper and analogue sandbox modelling were used to investigate the nature of structures produced in the sub-basin. The models rely on assumptions about the shapes developed by the moving salt, the timing of the movement and use the principle of vertical shear to adjust the accommodation space created by simple subsidence. The slug-like shape of the mobile salt wedges was adapted from the shapes imaged in the Gulf of Mexico by recent 3D seismic surveys.A simple graphic model of lateral salt migration replicates structures seen on a seismic panel from the Petrel Sub-basin in which wedges of sediment prograde from the basin centre to the basin margin. A more complex graphical model accounts for simple basin subsidence and salt migration shows many of the unusual features seen along the AGSO regional seismic Line 100/03. A sandbox model replicated the same features, including the broad dome of the Petrel structure, the sharper anticline around Tern, the depocentre northeast of Petrel, the smaller depocentre to the southeast and a number of small step-like structures. All these features are unusual as the amplitude diminishes upwards and downwards with no apparent basement control.The striking similarity of the models to the structures imaged by seismic suggests that salt has moved laterally, largely confined within the original evaporite stratigraphic level, taking on a slug-like shape, with an enlarged head and thin tail.This work gives an alternative explanation to the development of structures previously ascribed to compression, although the role of compression is not entirely discounted. The involvement of salt in the formation of large, but subtle structures such as the Petrel gas field, implies a longer history for the structures with influence on hydrocarbon migration, entrapment and the distribution of reservoir facies.
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O'Brien, G. W., M. A. Etheridge, J. B. Willcox, M. Morse, P. Symonds, C. Norman, and D. J. Needham. "THE STRUCTURAL ARCHITECTURE OF THE TIMOR SEA, NORTH-WESTERN AUSTRALIA: IMPLICATIONS FOR BASIN DEVELOPMENT AND HYDROCARBON EXPLORATION." APPEA Journal 33, no. 1 (1993): 258. http://dx.doi.org/10.1071/aj92019.

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The initial rifting in the Timor Sea, north-western Australia, took place in the Late Devonian to Early Carboniferous, with the development of the NWtrending Petrel Sub-basin. This rift system was compartmentalised by NE-trending accommodation zones which divided the sub-basin into discrete segments. In each segment, a lower plate rift margin, characterised by large displacement, low angle extensional faults, lay opposite an upper plate, or ramp, rift margin, characterised by small displacement, high angle flexural faults. Switching in the 'polarity' of the rift system took place across major, NE-trending accommodation zones.Part of this rift system was overprinted in the Late Carboniferous to Early Permian by the Westralian Super-Basin rift system, which developed on a NE trend, orthogonal to that of the underlying Petrel Sub-basin. The entire Vulcan Sub-basin and Sahul Platform region developed as part of an upper plate rift margin, with the Vulcan Sub-basin probably forming initially as a small flexural feature in the inboard part of the upper plate rift margin. The rift margin consisted of a linked array of NW-trending accommodation zones and NE-trending normal faults; pre-existing, NW-, NE- and NS-trending ?Proterozoic fracture systems controlled, at least to some extent, the geometry of the rift system that developed. The island of Timor probably developed as a major intra-rift high, or possibly a marginal plateaux, at this time. Thermal subsidence phase sedimentation continued until the Late Triassic, resulting in the deposition of 10 to perhaps 14 km of relatively unstructured sediments.Three major reactivation events affected the Timor Sea during the Mesozoic. These were: compression in the Late Triassic to Early Jurassic, extension in the Late Callovian to Early Oxfordian (late Middle to early Late Jurassic) and compression in the Tithonian/Berriasian (Late Jurassic/Early Cretaceous). These events all reactivated the pre-existing ?Proterozoic/ Petrel Sub-basin/Westralian Super-Basin structural architecture in a variety of ways. In the Petrel Sub-basin, reactivation was localised almost exclusively over the lower plate rift margins, leading to the formation of anticlines and ultimately, salt diapirism.In the Vulcan Sub-basin, all of the significant hydrocarbon discoveries appear to be preferentially located either along, or at the intersection of, NW- and NS-trending fault sets with the NE/ENE-trending grain. This is probably because the intersections of these Proterozoic/Late Carboniferous-Early Permian fault sets respond in a particularly complex fashion to the varying Mesozoic stress directions. In a qualitative fashion, this observation does provide a number of largely untested exploration 'fairways' within the Vulcan Sub-basin.
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Edwards, D. S., R. E. Summons, J. M. Kennard, R. S. Nicoll, J. Bradshaw, M. Bradshaw, C. B. Foster, G. W. O'Brien, and J. E. Zumberge. "GEOCHEMICAL CHARACTERISTICS OF PALAEOZOIC PETROLEUM SYSTEMS IN NORTHWESTERN AUSTRALIA." APPEA Journal 37, no. 1 (1997): 351. http://dx.doi.org/10.1071/aj96022.

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Isotopic and biomarker analyses carried out on Cambrian to Permian oils and source rocks in the Arafura, Bonaparte (Petrel Sub-basin) and Canning Basins have been used to geochemically characterise five distinct petroleum systems within the Larapintine and Gondwanan Petroleum Supersystems. The Larapintine 1 Petroleum System is characterised by isotopically light, free hydrocarbons in the Arafura Basin (613Csat = −32 %o Arafura-1) which have been correlated to kerogens of similar isotopic signature within the Middle Cambrian Jigaimara Formation. The richness and maturity of these source rocks indicate that an effective Larapintine 1 Petroleum System may exist in the northern parts of the Arafura Basin. Larapintine 2 oils, with Gloeocapsomorpha prisca-type signatures, are found on the Barbwire- Dampier Terraces and Admiral Bay Fault Zone in the Canning Basin. These oils can be correlated to source rocks in the Lower Ordovician Goldwyer Formation on the Barbwire Terrace and the Bongabinni Formation in the Admiral Bay Fault Zone by their diagnostic odd- carbon-number preference in the C15—CJ9 n-alkanes. Larapintine 3 oils are derived from Upper Devonian marine carbonates in the Canning Basin and Petrel Sub- basin and have a diagnostic biomarker signature which includes a predominance of steranes relative to diasteranes and abundant gammacerane and 30- norhopanes, similar to those observed in the Upper Devonian Gogo and Pillara Formations. Larapintine 4 oils are derived from Lower Carboniferous marine, clay- rich mudstones in both the Petrel Sub-basin and Canning Basin. They are isotopically light (mean δ13C sat = −28 %o) and have a unique terpane signature which has been identified within the Milligans Formation. Gondwanan 1 Petroleum System hydrocarbons, represented here by the Petrel-4 condensate, have a heavy isotopic signature (δ13C sat = −24 %o) which, coupled with an abundance of the diasterane and diahopane biomarkers, indicates derivation from Permian deltaic source facies. Recognition of the diagnostic geochemical components of each Palaeozoic petroleum system has led to the identification of Permian-like isotopic signatres in some hydrocabon accumulations in the Timor Sea that were previously attributed to Mesozoic sources.
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Lemberger, Marcus, James Stockley, and Tim Gibbons. "Browse to Bonaparte stratigraphic evaluation." APPEA Journal 53, no. 2 (2013): 483. http://dx.doi.org/10.1071/aj12094.

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After an initial 2010 stratigraphic, depositional environment and facies determination study of 75 wells in the Browse Basin, TGS has pushed this high-resolution project north into the Bonaparte Basin area. The study incorporates a further 165 wells located across the Ashmore Platform, Vulcan Sub-basin, Londonderry High, Malita and Calder Grabens, Sahul and Flamingo synclines, Laminara and Flamingo highs, Sahul Platform, Troubadour Terrace, and offshore Petrel Sub-basin areas. This multi-basin project has combined all the selected relevant public data into one interpretation study and is delivered in an integrated environment—wells are standardised and sequences interpreted. Once depositional environment and facies are allocated, multi-element maps are produced showing how the basin environments change through time and structural evolution. Stratigraphic interpretation has determined 37 sequences and 32 associated facies maps. Both Browse Basin (140,000 km2) and Bonaparte Basin (270,000 km2) are relatively less explored and at different ages in their exploration life-cycle. Both have proved to be oil and gas bearing across numerous different stratigraphic ages with a wide range of trapping and reservoir methods. This study aims to further aid North West Shelf exploration by delineating, among other facets, the presence or otherwise of rocks with reservoir and seal potential and by identifying structural elements such as the Petrel Sub-basin salt diapirs. This regional well data stratigraphic approach has been used across all the UK and Norway continental shelf hydrocarbon provinces. TGS sees the Australian North West Shelf as a province where this approach will further assist sub-surface understanding, and hence exploration success.
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Owens, R., A. Kelman, K. Khider, T. Bernecker, and B. Bradshaw. "Late Permian–Early Triassic depositional history in the southern Bonaparte Basin: new biostratigraphic insights into reservoir heterogeneity." APPEA Journal 61, no. 2 (2021): 699. http://dx.doi.org/10.1071/aj20111.

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The upper Permian to Lower Triassic sedimentary succession in the southern Bonaparte Basin represents a marginal marine depositional system that hosts several gas accumulations. Of these, the Blacktip gas field has been in production since 2009, while additional gas resources are under consideration for development. The sedimentary succession extends across the Permian–Triassic stratigraphic boundary, and shows a change in lithofacies from the carbonate dominated Dombey Formation to the siliciclastic dominated Tern and Penguin formations. The timing, duration, distribution and depositional environments of these formations in the Petrel Sub-basin and Londonderry High is the focus of this study. The sedimentary succession extending from the Dombey to the Penguin formations is interpreted to represent marginal marine facies which accumulated during a long-lasting marine transgression that extended over previous coastal and alluvial plain sediments of the Cape Hay Formation. The overlying Mairmull Formation represents the transition to fully marine deposition in the Early Triassic. Regional scale well correlations and an assessment of biostratigraphic data indicate that marginal marine depositional systems were initiated outboard before the end-Permian extinction event, and migrated inboard at about the Permian–Triassic stratigraphic boundary. Marginal marine deposition across the southern Bonaparte Basin continued through the faunal and floral recovery phase as Triassic species became established. The depositional history of the basin is translated to a chronostratigraphic framework which has implications for predicting the character and distribution of petroleum system elements in the Petrel Sub-basin and Londonderry High.
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Hildick-Pytte, Margaret. "New play type, southern Bonaparte Basin-Petrel Sub-basin—WA-442-P and NT/P81 exploration permits." APPEA Journal 52, no. 1 (2012): 525. http://dx.doi.org/10.1071/aj11041.

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Recent investigation, including mapping re-processed seismic data, suggests there is deeper hydrocarbon potential in the WA-442-P and NT/P81 exploration permits beneath the Early Carboniferous Tanmurra Formation horizon. Earlier interpretation of the area showed tilted fault blocks commonly thought of as economic basement in the vicinity of the Turtle and Barnett oil fields and extending to the northwest to connect with the Berkley Platform. The deep-gas play type is structural and is believed to be two nested three-way dip anticlines developed against a large bounding fault to the northeast, with axial trends northwest to southeast, and axial plane curving towards the northeast for the deeper structure. This play type is believed to be associated with structural compression and movement along the master fault with incremental re-activation most recently during the Cainozoic as recorded in overlying sediments. The Nova Structure and the deeper Super Nova structure have closures of about 450 and 550 km2, respectively. The sediments beneath the Nova horizon are believed to be of Devonian Frasnian-Famennian age but have not been drilled offshore in the Southern Bonaparte Basin (Petrel Sub-basin). Earlier work suggests that there are two petroleum systems present in the southern Bonaparte Basin, a Larapintine source from Early Palaeozoic Devonian to Lower Carboniferous source rocks, and a transitional Larapintine/Gondwana system sourced from Lower Carboniferous to Permian source rocks. Hydrocarbon charge for the structures is most likely from the Larapintine source rock intervals or yet to be identified older intervals associated with the salt deposition during the Ordovician and Silurian. Independent estimates place close to 7 TCF (trillion cubic feet) of gas in the Nova Structure. New 3D seismic data acquisition is planned over the structures to better define the geology and ultimately delineate well locations.
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Bernecker, Tom. "The 2010 Australian offshore release for petroleum exploration." APPEA Journal 50, no. 1 (2010): 5. http://dx.doi.org/10.1071/aj09002.

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The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. In 2010, thirty-one areas in five offshore basins are being released for work program bidding. Closing dates for bid submissions are either six or twelve months after the release date—i.e. 11 November 2010 and 12 May 2011—depending on the exploration status in these areas and on data availability. The 2010 release areas are located in Commonwealth waters offshore Northern Territory, Western Australia and South Australia, comprising intensively explored areas close to existing production as well as new frontiers. The Westralian Superbasin along the North West Shelf continues to feature prominently, and is complimented by a new frontier area in offshore SW Australia (Mentelle Basin), as well as two areas in the Ceduna/Duntroon sub-basins in the eastern part of the Bight Basin. The Bonaparte Basin is represented by three areas in the Petrel Sub-basin and two areas in the Vulcan Sub-basin. Further southwest, four large areas are being released in the outer Roebuck Basin—a significantly under-explored region. This year, the Carnarvon Basin provides 16 release areas of which three are located in the Beagle Sub-basin, five in the Dampier Sub-basin, five in the Barrow Sub-basin, three on the Exmouth Plateau and three in the Exmouth Sub-basin. The largest singular release area covers much of the Mentelle Basin in offshore SW Australia, and two areas are available in the Ceduna and Duntroon sub-basins as part of South Australia’s easternmost section of the Bight Basin. The 2010 Offshore Acreage Release offers a wide variety of block sizes in shallow as well as deep water environments. Area selection has been undertaken in consultation with industry, the States and the Northern Territory. As part of Geoscience Australia’s Offshore Energy Security Program, new data has been acquired in offshore frontier regions parts of which are being published on the Mentelle Basin (Borissova et al, this volume).
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Dissertations / Theses on the topic "Petrel sub-basin"

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Barnes, Craig Ronald. "A seismic-based structural interpretation of the Petrel sub-basin, Bonaparte Gulf, Northern Australia /." Title page, contents and abstract only, 1994. http://web4.library.adelaide.edu.au/theses/09SB/09sbb261.pdf.

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Gibson-Poole, Catherine Mary. "Site characterisation for geological storage of carbon dioxide: examples of potential sites from the North West Shelf, Australia." Thesis, 2010. http://hdl.handle.net/2440/63078.

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Release of anthropogenic greenhouse gas emissions to the atmosphere is a concern for global warming. Thus, practical and economic solutions are being sought to combat this problem. One possible methodology for reducing emissions is the geological storage of carbon dioxide (CO₂). The subsurface behaviour of CO₂is influenced by many variables; therefore, accurate appraisal of a potential CO₂storage site requires detailed site characterisation. In particular, potential sites need to be evaluated geologically in terms of their injectivity, containment and capacity. Detailed site characterisation was undertaken for two possible sites for geological storage of CO₂, located offshore northwest Australia in the Petrel and Barrow sub-basins. The injection targets in the Petrel Sub-basin are the Jurassic Plover and Elang formations, locally sealed by the Frigate Formation, and the overlying Cretaceous Sandpiper Sandstone, regionally sealed by the Bathurst Island Group. The Plover/Elang formations are laterally extensive, fluvio–deltaic sandstones of fair to good reservoir quality, with likely excellent lateral and vertical connectivity. The Frigate Formation may not be an effective seal up-dip, but the overlying secondary reservoir (Sandpiper Sandstone) and thick regional seal (Bathurst Island Group) will ensure continued CO₂containment. The Jurassic–Cretaceous post-rift sediments are structurally simple and dip gently up towards the basin margins with no defined structural closures. Therefore, hydrodynamic, residual and solubility trapping beneath the regional seal will be the dominant storage mechanisms. The potential storage capacity is vast (> 10,000 Mt), highlighting why deep saline formations may provide a realistic solution to large-scale greenhouse gas emissions reduction. In the Barrow Sub-basin, the Cretaceous Flag Sandstone is the injection target, sealed by the Muderong Shale. The reservoir units are laterally extensive, amalgamated, basin floor fan sandstones with excellent reservoir quality. Hemipelagic shale drapes may locally restrict the vertical connectivity. The Muderong Shale has excellent seal capacity, with the potential to withhold a CO₂ column height of 565–790 m. The structural geometry is a large anticline and the trapping mechanisms are likely to a combination of stratigraphic, residual and solubility trapping along the axis of the anticline, as well as structural trapping within the anticlinal closure. A few large faults exist which could potentially be reactivated if injection pressures are not appropriately managed. The hydrodynamic flow has been altered by production induced pressure decline; however, the impact on the CO₂ migration pathway is likely to be insignificant due to the stronger buoyancy drive. The detailed geological characterisation process identified that both sites are suitable candidates for geological storage of CO₂. Geological storage of CO₂is technically feasible in a variety of different geological settings, as demonstrated by studies like these and CO₂storage projects already in operation. Key to the success of a CO₂storage project is an understanding of the stratigraphic architecture and reservoir heterogeneity. This will allow an optimal injection strategy to be devised to utilise the inherent geological characteristics of the site and maximise the benefits of injectivity, capacity and containment for efficient geological storage of CO₂.
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2010
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Book chapters on the topic "Petrel sub-basin"

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Chahal, Raman, and Saurabh Datta Gupta. "Reservoir Characterization of Carbonate Facies Towards Hydrocarbon Exploration in Jaisalmer Sub-basin, India." In Petro-physics and Rock Physics of Carbonate Reservoirs, 233–48. Singapore: Springer Singapore, 2019. http://dx.doi.org/10.1007/978-981-13-1211-3_17.

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BALDWIN, S., N. WHITE, and R. D. MÜLLER. "Resolving multiple rift phases by strain-rate inversion in the Petrel Sub-basin, northwest Australia." In Evolution and Dynamics of the Australian Plate. Geological Society of America, 2003. http://dx.doi.org/10.1130/0-8137-2372-8.245.

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Conference papers on the topic "Petrel sub-basin"

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Yielding, G., C. Consoli, and P. Boult. "Fault-seal Risk Analysis for CO2 Storage in the Petrel Sub-basin, NW Australia." In Fourth International Conference on Fault and Top Seals. Netherlands: EAGE Publications BV, 2015. http://dx.doi.org/10.3997/2214-4609.201414051.

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Dewhurst, D., Y. Zhang, P. Schaubs, and L. Stalker. "Impact of Fault Permeability on Geomechanical Models of CO2 Injection in the Petrel Sub-basin, Northern Australia." In Fifth International Conference on Fault and Top Seals. European Association of Geoscientists & Engineers, 2019. http://dx.doi.org/10.3997/2214-4609.201902334.

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Reports on the topic "Petrel sub-basin"

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Jones, L. E. A. Petrel Sub-basin Marine Survey (GA0335/SOL5463) : Sub Bottom Profiler Processing Report. Geoscience Australia, 2014. http://dx.doi.org/10.11636/record.2014.048.

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Nicholas, W. A., A. Carroll, K. Picard, L. Radke, J. Siwabessy, J. Chen, F. J. F. Howard, et al. Seabed environments, shallow sub-surface geology and connectivity, Petrel Sub-basin, Bonaparte Basin, Timor Sea: Interpretative report from marine survey GA0335/SOL5463. Geoscience Australia, 2015. http://dx.doi.org/10.11636/record.2015.024.

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Consoli, Christopher, Karen Higgins, Diane Jorgensen, Kamal Khider, David Lescinsky, Robbie Morris, and Victor Nguyen. Regional assessment of the CO2 storage potential of the Mesozoic succession in the Petrel Sub-basin, Northern Territory, Australia : summary report. Geoscience Australia, 2014. http://dx.doi.org/10.11636/record.2014.011.

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Leetaru, Hannes, Alan Brown, Donald Lee, Ozgur Senel, and Marcia Coueslan. CO{sub 2} Injectivity, Storage Capacity, Plume Size, and Reservoir and Seal Integrity of the Ordovician St. Peter Sandstone and the Cambrian Potosi Formation in the Illnois Basin. Office of Scientific and Technical Information (OSTI), May 2012. http://dx.doi.org/10.2172/1064414.

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