Journal articles on the topic 'Petrel sub-basin'
To see the other types of publications on this topic, follow the link: Petrel sub-basin.
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the top 28 journal articles for your research on the topic 'Petrel sub-basin.'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Browse journal articles on a wide variety of disciplines and organise your bibliography correctly.
1
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.
Full textAbstract:
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.
2
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.
Full textAbstract:
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).
3
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.
Full text
4
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.
Full textAbstract:
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.
5
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.
Full textAbstract:
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.
6
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.
Full textAbstract:
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.
7
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.
Full textAbstract:
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.
8
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.
Full textAbstract:
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.
9
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.
Full textAbstract:
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.
10
Bernecker, Tom. "The 2010 Australian offshore release for petroleum exploration." APPEA Journal 50, no. 1 (2010): 5. http://dx.doi.org/10.1071/aj09002.
Full textAbstract:
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).
11
Stalker, Linda, David Dewhurst, Yanhua Zhang, Peter Schaubs, Ben Clennell, Yohan Suhardiman, Andrew Maxwell, et al. "Evaluation of the Petrel Sub-basin as a northern Australia CO2 store: future decarbonisation hub?" APPEA Journal 60, no. 2 (2020): 765. http://dx.doi.org/10.1071/aj19180.
Full textAbstract:
The Northern Australia CO2 Store Project has extended investigations for safe, long-term containment of large volumes of CO2 (up to 100 million tonnes) to support liquefied natural gas and other industries in a decarbonised future. Most natural gas fields in the Petrel Sub-basin and the surrounding region have relatively high native CO2 content. This collaborative project improved storage characterisation, evaluated geomechanical risks and estimated engineering demands necessary to progress the concept to ‘prospect’ and ‘resource’. New data have significantly advanced the geological and structural understanding in the region, improving chrono- and litho-stratigraphic correlations, with new well ties across the basin. However, the re-mapping has thrown up new questions that require additional data (e.g. new stratigraphic wells, 3D seismic data) to address those knowledge gaps. Geomechanical modelling in the area has tested (to extreme levels) the potential impact of injection on faults in the area, further de-risking the likelihood of upward migration and leakage. The region could utilise an abundance of energy and feedstocks in the form of solar, natural gas, hydrogen and CO2 to become a future decarbonisation and industrial hub while managing major emissions with offshore CO2 storage.
12
Gorter, J. D., P. J. Jones, R. S. Nicoll, and C. J. Golding. "A REAPPRAISAL OF THE CARBONIFEROUS STRATIGRAPHY AND THE PETROLEUM POTENTIAL OF THE SOUTHEASTERN BONAPARTE BASIN (PETREL SUB-BASIN), NORTHWESTERN AUSTRALIA." APPEA Journal 45, no. 1 (2005): 275. http://dx.doi.org/10.1071/aj04024.
Full textAbstract:
A revision of the latest Tournaisian to Namurian stratigraphy of the Petrel Sub-basin is proposed following the recognition of a series of megasequences based on seismic profiles, well logs and new palaeontological information. In late Tn3c, turbidites of the Waggon Creek facies were overlain by a seal, the Milligans Formation (redefined) during the Chadian (V1a, V1b). A basal Arundian (V2a) regression, possibly driven by tectonics, deposited the Yow Creek Formation (new name) with incised valley fills. A basal Asbian (V3a) regression, deposited coarser grained clastics and limestones, the Utting Calcarenite (V3a), forming a possible local reservoir facies overlain by a regional seal, Kingfisher Shale (new name). An intra-Asbian (V3b) regression followed, possibly glaciogenic and/or tectonically driven, with the deposition of the Tanmurra Formation, dominantly coarse clastics, during the Asbian, forming reservoir facies with some source potential. Following a basal Brigantian unconformity, the Sandbar Sandstone (new name) formed a restricted ?aeolian facies, a potential local reservoir. An intra-Brigantian unconformity was followed by deposition of the carbonate Sunbird Formation (new name), generally a tight shelf edge carbonate (V3c), near Lacrosse–1 and Sunbird–1. A major basal Pendleian sea-level fall, probably glaciogenic, with major channel incision and erosion, was followed by Arnsbergian clastics with G. maculosa, the Arco Formation (new name) with basinal shales in clinoforms. The latest Arco Formation (earliest Pennsylvanian) was followed by a Late Namurian regression, and deposition of the Aquitaine Formation (new name), consisting of fluvio-deltaic siliciclastics, with minor marine influence, large scale channelling, potentially good reservoirs, and a regional upper shaly seal. This sequence is unconformably overlain by the basal Kulshill Group, which marked the onset of major Gondwanan glaciation.
13
Bradshaw, Marita. "Review of the 2008 offshore petroleum exploration release areas." APPEA Journal 48, no. 1 (2008): 359. http://dx.doi.org/10.1071/aj07025.
Full textAbstract:
Each year the Australian Government releases new offshore opportunities for petroleum exploration. Thirty-five new exploration areas located across five of Australia’s offshore sedimentary basins are offered in the 2008 Release. All the areas are available through a work program bidding system with closing dates for bids at six and 12 months from the date of release. Acreage in the first round closes on 9 October 2008 and includes the more explored areas. The second closing round on 9 April 2009 comprises acreage located in less well explored and frontier regions. The 2008 exploration areas are in Commonwealth waters offshore of Western Australia and the Northern Territory, and in the Territory of the Ashmore and Cartier Islands adjacent area. The 2008 Release focusses on the North West Shelf, as well as offering two new exploration areas in the Vlaming Sub-basin in the offshore Perth Basin. Seven of the new release areas are located in Australia’s major hydrocarbon producing province, the Carnarvon Basin. They include a shallow water area in the western Barrow Sub-basin and another on the Rankin Platform, three areas in deeper water in the Exmouth Sub-basin and two on the deepwater Exmouth Plateau. Six areas are available for bidding in the Browse Basin and another five in the Bedout Sub-basin of the Roebuck Basin. In the Bonaparte Basin, the 15 Release areas are located in shallow water and represent a range of geological settings, including the Vulcan and Petrel sub-basins, Ashmore Platform and Londonderry High. The 2008 Offshore Petroleum Exploration Release of 35 areas in five basins covers a wide range in size, water depth and exploration maturity to provide investment opportunities suited to both small and large explorers. The Release areas are selected from nominations from industry, the States and Territory, and Geoscience Australia. The focus of the 2008 Release is on the North West Shelf where there is strong industry interest in the producing Carnarvon and Bonaparte basins and in the Browse Basin, the home of super-giant gas fields under active consideration for development. Also included in the 2008 Release is the Bedout Sub-basin, in the Roebuck Basin, located on the central North West Shelf, between the hotly contested Carnarvon and Browse basins. In addition, the Release show-cases the southern Vlaming Sub-basin, Perth Basin, where recent studies by Geoscience Australia provide a new understanding of petroleum potential (Nicholson et al, this volume).
14
Bernecker, Thomas. "Review of the 2009 offshore petroleum exploration release areas." APPEA Journal 49, no. 1 (2009): 465. http://dx.doi.org/10.1071/aj08031.
Full textAbstract:
The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. This year, 31 areas plus two special 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. 3 December 2009 and 29 April 2010), depending on the exploration status in these areas is and on data availability. The 2009 release areas are located in Commonwealth waters offshore Northern Territory, Western Australia, South Australia and Victoria, comprising intensively explored areas close to existing production as well as new frontiers. As usual, the North West Shelf features very prominently and is complimented by new areas along the southern margin, including frontier exploration areas in the Ceduna Sub-basin (Bight Basin) and the Otway Basin. The Bonaparte Basin is represented by one release area in the Malita Graben, while five areas are available in the Southern Browse Basin in an under-explored area of the basin. A total of 14 areas are being released in the Carnarvon Basin, with eight areas located in the Dampier Sub-basin, three small blocks in the Rankin Platform and three large blocks on the Northern Exmouth Plateau (these are considered a deep water frontier). In the south, six large areas are on offer in the Ceduna Sub-basin and five areas of varying sizes are being released in the Otway Basin, including a deep water frontier offshore Victoria. The special release areas are located in the Petrel Sub-basin, Bonaparte Basin offshore Northern Territory, and encompass the Turtle/Barnett oil discoveries. The 2009 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 Territory. This year’s acreage release caters for the whole gamut of exploration companies given that many areas are close to existing infrastructure while others are located in frontier offshore regions. As part of Geoscience Australia’s Offshore Energy Security Program, new data has been acquired in offshore frontier regions and have yielded encouraging insights into the hydrocarbon prospectivity of the Ceduna-Sub-basin.
15
Goncharov, Alexey, Clive Collins, Peter Petkovic, Tanya Fomin, Vitaliy Pilipenko, Barry Drummond, and Chao-Shing Lee. "Ocean-bottom seismograph and conventional reflection surveys in the Petrel Sub-Basin: an integrated seismic study." Exploration Geophysics 29, no. 3-4 (September 1998): 384–90. http://dx.doi.org/10.1071/eg998384.
Full text
16
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.
Full textAbstract:
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.
17
Baxter, K. "The role of small-scale extensional faulting in the evolution of basin geometries. An example from the late Palaeozoic Petrel Sub-basin, northwest Australia." Tectonophysics 287, no. 1-4 (March 1998): 21–41. http://dx.doi.org/10.1016/s0040-1951(98)80059-0.
Full text
18
Nicholas, W. A., S. L. Nichol, F. J. F. Howard, K. Picard, H. Dulfer, L. C. Radke, A. G. Carroll, M. Tran, and P. J. W. Siwabessy. "Pockmark development in the Petrel Sub-basin, Timor Sea, Northern Australia: Seabed habitat mapping in support of CO2 storage assessments." Continental Shelf Research 83 (July 2014): 129–42. http://dx.doi.org/10.1016/j.csr.2014.02.016.
Full text
19
Owens, R., A. Kelman, K. Khider, J. Iwanec, and T. Bernecker. "Addressing exploration uncertainties in the southern Bonaparte Basin: enhanced stratigraphic control and post drill analysis for upper Permian plays." APPEA Journal 62, no. 2 (May 13, 2022): S474—S479. http://dx.doi.org/10.1071/aj21122.
Full textAbstract:
The upper Permian to lower Triassic sedimentary succession in the southern Bonaparte Basin represents an extensive marginal marine depositional system that hosts several gas accumulations, including the Blacktip gas field that has been in production since 2009. Development of additional identified gas resources has been hampered by reservoir heterogeneity, as highlighted by preliminary results from a post drill analysis of wells in the study area that identify reservoir effectiveness as a key exploration risk. The sedimentary succession that extends across the Permian–Triassic stratigraphic boundary was deposited during a prolonged marine transgression and shows a transition in lithofacies from the carbonate-dominated Dombey Formation to the siliciclastic-dominated Tern and Penguin formations. Recent improvements in chronostratigraphic calibration of Australian biostratigraphic schemes, spanning the late Permian and early Triassic, inform our review of available palynological data, and re-interpretation and infill sampling of well data. The results provide a better-resolved, consistent and up-to-date stratigraphic scheme, allowing an improved understanding of the timing, duration and distribution of depositional environments of the upper Permian to lower Triassic sediments across the Petrel Sub-basin and Londonderry High.
20
Rozlovska, S. Ye, О. P. Vergunenko, B. B. Hablovskyi, and М. V. Shtogryn. "Possibilities of attrtribute analysis of seismic data to clarify the structural features of geological section." Oil and Gas Power Engineering, no. 1(35) (June 29, 2021): 16–24. http://dx.doi.org/10.31471/1993-9868-2021-1(35)-16-24.
Full textAbstract:
Seismic attributes are used for qualitative estimation of changes in the wave field performed within the analysis of seismic response characteristics. Related changes can be associated with sedimentation characteristics and structural features of the geological section. Subject of the study is Kovalivka field in the northern pre-flank zone of the western part of Dnieper-Donets basin. The aim of the study was to specify geological structure of the sub-salt Devonian sediments by means of attribute analysis of the wave field dynamic characteristics. It should be mentioned that Devonian sediments in Dnieper-Donets depression are very poorly studied by seismic and well drilling. New attempts to study Devonian formation here were caused by obtained inflows from similar Devonian reservoirs in Prypiat depression and by finding new prospects within the investigated area. The results of old seismic data re-processing have been analyzed as well as recent seismic and well data. Basing on the obtained data, the attribute analysis has been conducted and madden a prognosis of the geological section by wave field dynamic characteristics using Petrel software (Sсhlumberger). Due to performed interpretation procedures, we have specified location of faults, stratigraphic boundaries and distribution of sub-salt Devonian sediments. Also, we predicted a zone of development sub-salt carbonate sediments with possible a rifogenic origin. Significant increase of a total thickness of sub-salt formation and presence of quite thick relatively pure low-density organogenic carbonate sediments take place in Kovalivka field. It significantly increases the prospect potential of the area.
21
Nooralddin, Amel, Medhat Nasser, and Aboosh Al-hadidy. "Facies Analysis and Paleoenvironmental Assessment of the Upper Campanian Hartha Formation in Y and J Fields Northwestern Zagros Basin, Iraq." Iraqi Geological Journal 54, no. 2F (December 31, 2021): 36–47. http://dx.doi.org/10.46717/igj.54.2f.4ms-2021-12-21.
Full textAbstract:
The Upper Campanian Hartha Formation represents potential Cretaceous hydrocarbon-bearing reservoir rocks across the Y and J oilfields northwestern Zagros Basin, northern Iraq. The study objective is depositional environment which affects reservoir properties by tool, lithofacies, core, thin section, and logs, using petrel (V.2016) and strat software, facies distribution, grains, and diagenetic processes control and enhance reservoir properties which can plan platform production and minimize risks in choosing production wells location at two fields scale The current study is concerned with lithofacies and microfacies of the Hartha Formation within two fields in northern Iraq. Several subsurface well-log data, core, and cutting samples have been used in order to prepare thin sections that were subjected to sedimentological (lithofacies, and grain-size) examination. The petrography investigation revealed five rock-units including Hr. 1, 2, 3, 4, and 5, the thickness of 89 m in the Y-A field and increasing to up to 140 m in the J-B field might be due to erosion or tectonic uplift of the topography in Y subbasin. Which is locally sub-basin within study fields western banks of Tigris river as gentle slope ramp depositional condition with Spectrum microfacies from lime-mudstone to packstone texture with rudest and benthic debris enhances by diagenesis, dolomitization, dissolution moldic porosity, fracture; dolostone is more effective in the upper section of the formation in A than B Wells. Many factors, such as cementation, compaction, and pore-filling autogenic minerals, decrease reservoir quality, and their effects are similar in wells A and B.
22
Molyneux, Stephen, Jeff Goodall, Roisin McGee, George Mills, and Birgitta Hartung-Kagi. "Observations on the Lower Triassic petroleum prospectivity of the offshore Carnarvon and Roebuck basins." APPEA Journal 56, no. 1 (2016): 173. http://dx.doi.org/10.1071/aj15014.
Full textAbstract:
Why are the only commercial hydrocarbon discoveries in Lower Triassic and Permian sediments of the western margin of Australia restricted to the Perth Basin and the Petrel Sub-basin? Recent regional analysis by Carnarvon Petroleum has sought to address some key questions about the Lower Triassic Locker Shale and Upper Permian Chinty and Kennedy formations petroleum systems along the shallow water margin of the Carnarvon and offshore Canning (Roebuck/Bedout) basins. This paper aims to address the following questions:Source: Is there evidence in the wells drilled to date of a working petroleum system tied to the Locker Shale or other pre-Jurassic source rocks? Reservoir: What is the palaeogeography and sedimentology of the stratigraphic units and what are the implications for the petroleum systems?The authors believed that a fresh look at the Lower Triassic to Upper Permian petroleum prospectivity of the North West Shelf would be beneficial, and key observations arising from the regional study undertaken are highlighted:Few wells along a 2,000 km area have drilled into Lower Triassic Locker Shale or older stratigraphy. Several of these wells have been geochemically and isotopically typed to potentially non Jurassic source rocks. The basal Triassic Hovea Member of the Kockatea Shale in the Perth Basin is a proven commercial oil source rock and a Hovea Member Equivalent has been identified through palynology and a distinctive sapropelic/algal kerogen facies in nearly 16 wells that penetrate the full Lower Triassic interval on the North West Shelf. Samples from the Upper Permian, the Hovea Member Equivalent and the Locker Shale have been analysed isotopically indicating –28, –34 and –30 delta C13 averages, respectively. Lower Triassic and Upper Permian reservoirs are often high net to gross sands with up to 1,000 mD permeability and around 20% porosity. Depositional processes are varied, from Locker Shale submarine canyon systems to a mixed carbonate clastic marine coastline/shelf of the Upper Permian Chinty and Kennedy formations.
23
Keep, Myra, Anna Bishop, and Ian Longley. "Neogene wrench reactivation of the Barcoo Sub-basin, northwest Australia: implications for Neogene tectonics of the northern Australian margin." Petroleum Geoscience 6, no. 3 (September 2000): 211–20. http://dx.doi.org/10.1144/petgeo.6.3.211.
Full text
24
Johnstone, Rosie. "Concurrent 21. Presentation for: The Petrel Sub-basin: a world-class CO." APPEA Journal 62, no. 4 (June 3, 2022). http://dx.doi.org/10.1071/aj21374.
Full textAbstract:
Presented on Thursday 19 May: Session 21 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). To access the presentation click the link on the right. To read the full paper click here
25
MAUNG, TUN U, Petroleum Resources B. "Abstract: Petroleum Potential and Results of Exploration in the Offshore Petrel Sub-Basin, Bonaparte Basin, Northwestern Australia." AAPG Bulletin 82 (1998). http://dx.doi.org/10.1306/00aa8f4e-1730-11d7-8645000102c1865d.
Full text
26
J. E. Blevin, J. B. Colwell, J. M. "Definition of Basin Phases in the Petrel Sub-basin (Australia): Implications for the Development of Palaeozoic Petroleum Systems: ABSTRACT." AAPG Bulletin 80 (1996). http://dx.doi.org/10.1306/64eda564-1724-11d7-8645000102c1865d.
Full text
27
Owens, R. "Geoscience Poster G10: Addressing exploration uncertainties in the southern Bonaparte Basin: enhanced stratigraphic control and post drill analysis for upper Permian plays." APPEA Journal 62, no. 4 (June 3, 2022). http://dx.doi.org/10.1071/aj21406.
Full textAbstract:
Poster G10 The upper Permian to lower Triassic sedimentary succession in the southern Bonaparte Basin represents an extensive marginal marine depositional system that hosts several gas accumulations, including the Blacktip gas field that has been in production since 2009. Development of additional identified gas resources has been hampered by reservoir heterogeneity, as highlighted by preliminary results from a post drill analysis of wells in the study area that identify reservoir effectiveness as a key exploration risk. The sedimentary succession that extends across the Permian–Triassic stratigraphic boundary was deposited during a prolonged marine transgression and shows a transition in lithofacies from the carbonate-dominated Dombey Formation to the siliciclastic-dominated Tern and Penguin formations. Recent improvements in chronostratigraphic calibration of Australian biostratigraphic schemes, spanning the late Permian and early Triassic, inform our review of available palynological data, and re-interpretation and infill sampling of well data. The results provide a better-resolved, consistent and up-to-date stratigraphic scheme, allowing an improved understanding of the timing, duration and distribution of depositional environments of the upper Permian to lower Triassic sediments across the Petrel Sub-basin and Londonderry High. To access the poster click the link on the right. To read the full paper click here
28
G. W. O'Brien, J. Blevin, P. Gunn,. "The Petrel Sub-Basin System, Timor Sea, Australia: Rift Architecture and Its Control on Structuring Within the Tertiary Sequence, Timor Sea: ABSTRACT." AAPG Bulletin 79 (1995). http://dx.doi.org/10.1306/7834f015-1721-11d7-8645000102c1865d.
Full text