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1
Newell, N. A. "WATER WASHING IN THE NORTHERN BONAPARTE BASIN." APPEA Journal 39, no. 1 (1999): 227. http://dx.doi.org/10.1071/aj98014.
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The discovery of 11 oil fields and one gas field in the Northern Bonaparte Basin since 1994 has established a new petroleum province. The prolific yield of the Middle to Upper Jurassic source rocks is demonstrated not only by the volumes of reservoired hydrocarbons, principally in the Plover and Elang formations, but by the long residual columns beneath a number of the fields, and in some dry structures. An important aspect of the continuing exploration in the basin is, therefore, to identify prospects where as much as possible of the hydrocarbon column is preserved. While the integrity of fault seals has, until now, been the primary focus in this regard, this paper proposes water washing as the principal mechanism for depletion of hydrocarbon accumulations within the Northern Bonaparte Basin.That such a process might have operated was indicated initially by the observation that, while the oils in the basin are so light that they are almost condensates, they are also extremely low in volatile content or, in other words, undersaturated. This phenomenon strongly suggests selective removal of compounds. The identification of this process as water washing was based on the relationship between the light aromatic content of the oils, and their gas-oil ratios (GOR) and bubble-points. Within the oils characterised by very low GORs, highly soluble light aromatics, such as benzene and toluene, are almost completely absent, whereas under conditions of evaporative fractionation by fault leakage these compounds tend to be enriched in the residual oil. The fact that methane, ethane and propane are also highly soluble, and have therefore also been removed, accounts for the low volatility of the oils. The lightness of the original hydrocarbons has probably disguised the process of water washing, as only the very soluble components have been removed.The volume loss, under reservoir conditions, resulting from the depletion of a Northern Bonaparte Basin oil accumulation by water washing has been calculated to be in the order of 70%. The volume loss of degrading a gas/condensate accumulation to a low GOR oil is around 90%. These volumetric losses are consistent with the dimensions of many of the residual columns observed in traps in the area.Regionally, the degree of water washing increases to the northwest, with fields such as Laminaria and Buffalo having the lowest light aromatic content. Offset pressure data from reservoirs indicates a present-day water flow from the northwest. This flow can be accounted for by the dewatering of sediments overthrust by the island of Timor over the last seven million years.Compositional variation of light molecular weight compounds, within some fields, may also be attributable to water washing, with reservoir heterogeneity hindering the diffusion and homogenisation of hydrocarbons through the fields. These compositional variations strongly indicate that water washing is occurring at the present-day, and consequently may be of value in reservoir production studies. Hydrocarbons recovered from the Darwin Formation, which is not in communication with the Elang/Plover aquifer, exhibit little or no evidence of water washing.The proposal that water washing can remove significant volumes of hydrocarbons from traps does not appear to have been previously documented. It constitutes a significant advance in our understanding of exploration risk in the Northern Bonaparte Basin by demonstrating that small isolated closures or deep crests within regional highs carry a significant risk of being underfilled. Moreover, column height within prospects may be estimated by calculating volume losses from fields 'along strike' in regard to the degree of water washing.A strong incentive to explore for an alternative play type is provided by the recognition of non-degraded oil within traps not in communication with the Elang/Plover aquifer.
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Gorter, John, Robert S. Nicoll, Ian Metcalfe, Robbert Willink, and Darren Ferdinando. "The Permian–Triassic boundary in Western Australia: evidence from the Bonaparte and Northern Perth basins—exploration implications." APPEA Journal 49, no. 1 (2009): 311. http://dx.doi.org/10.1071/aj08020.
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Several sedimentary basins in Western Australia contain petroleum reservoirs of Late Permian or older age that are overlain by thick shaly sequences (400–2,000 m) that have been assigned an Early Triassic age. The age of the base of the Triassic shales has been, and continues to be, contentious with strata being variously ascribed to the latest Permian (Changhsingian Stage) or wholly in the earliest Triassic (Induan Stage). In the Perth Basin the Permian-Triassic boundary appears to be located somewhere in the Hovea Member of the Kockatea Shale. In the Bonaparte Basin, the boundary would appear to be either in the uppermost Penguin Formation or at the boundary between the Penguin and Mairmull formations. The uncertainty of the boundary placement relates to the interpretation of the sedimentological, biostratigraphic and geochemical record in individual sections and basins. Major problems relate to the recognition, or even the presence of unconformities, complications related to the presence of reworked sediments and paleontological material (both conodonts and spore-pollen) and to the significance of geochemical shifts. The age of the basal Kockatea Shale (northern Perth Basin) and the basal Mt Goodwin Sub-group (Bonaparte Basin) is reassessed using palaeontological data, augmented by carbon isotopic measurements and geochemical analyses, supported by wireline log correlations and seismic profiles. The stratigraphy of the latest Permian to Early Triassic succession in the Bonaparte Basin is also revised, as is the nomenclature for the Early Triassic Arranoo Member of the Kockatea Shale in the northern Perth Basin. The Mt Goodwin Sub-group (new rank) is composed of the latest Permian Penguin Formation overlain by the Early Triassic Mairmull, Ascalon and Fishburn formations (all new).
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Gorter, J. D., and J. M. Davies. "UPPER PERMIAN CARBONATE RESERVOIRS OF THE NORTH WEST SHELF AND NORTHERN PERTH BASIN, AUSTRALIA." APPEA Journal 39, no. 1 (1999): 343. http://dx.doi.org/10.1071/aj98019.
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The Perth, Carnarvon, Browse, and Bonaparte basins contain Permian shallowmarine carbonates. Interbedded with clastic oil and gas reservoirs in the northern Perth Basin (Wagina Formation), and gas reservoirs in the Bonaparte Basin (Cape Hay and Tern formations), these carbonates also have the potential to contain significant hydrocarbon reservoirs. Limestone porosity may be related to the primary depositional fabric, or secondary processes such as dolomitisation, karstification, and fracturing. However, in the Upper Permian interval of the North West Shelf and northern Perth Basin, where there are no indications of significant preserved primary porosity in the limestones, all known permeable zones are associated with secondary porosity. Fractured Permian carbonates have the greatest reservoir potential in the Timor Sea. Tests of fractured Pearce Formation limestones in Kelp Deep–1 produced significant quantities of gas, and a test of fractured Dombey Formation limestone in Osprey–1 flowed significant quantities of water and associated gas. Minor fracture porosity was associated with gas shows in dolomitic limestones in Fennel–1 in the Carnarvon Basin, and fractures enhance the reservoir in the Woodada Field in the northern Perth Basin. Karst formation at sub-aerial unconformities can lead to the development of secondary porosity and caverns, as in the Carnarvon Basin around Dillson–1. Minor karst is also developed at the top Dombey Formation unconformity surface in the Timor Sea region.
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Gorter, John, Robert Nicoll, Andrea Caudullo, Robyn Purcell, and Kon Kostas. "Latest Permian (Changhsingian) to Early Triassic (Induan-Olenekian) of the Mt Goodwin Sub-group at Blacktip gas field, southeastern Bonaparte Basin, Australia." APPEA Journal 50, no. 1 (2010): 203. http://dx.doi.org/10.1071/aj09013.
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Gas was discovered in intra-Mt Goodwin Sub-group sandstones (Ascalon Formation) of the southeastern Bonaparte Basin in Blacktip–1 in 2001 from a zone characterised by a discrete seismic amplitude anomaly. This integrated study uses wireline logs, cores, cuttings, palynology, micropaleontology and geochemical analyses to determine the depositional environment of the Mt Goodwin Sub-group reservoirs and the source rock potential of this large, latest Permian (Changhsingian) to Early Triassic (Induan Olenekian) section of the Bonaparte Basin in northern Australia. Specific outcomes include a better understanding of the Early Triassic reservoir sandstone depositional environment and recognition of marker horizons on electric logs and seismic profiles, resulting in a more consistent regional interpretive framework for the uppermost Permian (Changhsingian) and Early Triassic (Induan Olenekian), in the Bonaparte Basin.
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Whibley, Mike, and Ted Jacobson. "EXPLORATION IN THE NORTHERN BONAPARTE BASIN, TIMOR SEA - WA-199-P." APPEA Journal 30, no. 1 (1990): 7. http://dx.doi.org/10.1071/aj89001.
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Permit WA-199-P, located in the Northern Bonaparte Basin, has undergone an intensive exploration phase from its award on 22 October 1985, which has resulted in the acquisition of 6250 km of 2D seismic and 1558 km of 3D seismic together with the drilling of seven exploration wells. Significant oil shows were recorded in six of these wells.The major play type investigated to date within the permit consists of Jurassic tilted horst and fault blocks. Potential reservoirs comprising medium to coarse grained sandstones of the Jurassic Plover Formation and, to a lesser extent, the Late Jurassic to Early Cretaceous Flamingo Group, are sealed by massive claystones of the Cretaceous Bathurst Island Group. Numerous oil shows have been encountered by drilling within these two reservoirs; however, drilling results from the Avocet-Eider structure indicate that Late Miocene-Recent fault reactivation often breaches the lateral seal of the fault- dependent structures causing leakage of hydrocarbons up the fault.Source extract-oil correlations and maturation studies indicate that the most likely oil sources comprise thermally mature marine claystones of the Flamingo Group and Plover Formation, developed within the Sahul Syncline to the east of WA-199-P. The main period of oil migration was probably Miocene or younger. A number of play types remain untested. These consist of Permian, Intra-Triassic and top Cretaceous fault blocks, as well as fault-independent closures, downdip fault closures and stratigraphic wedge outs of Maastrichtian sand reservoirs, and submarine fan sands developed within the basal Flamingo Group.
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McLennan, Jeanette M., John S. Rasidi, Richard L. Holmes, and Greg C. Smith. "THE GEOLOGY AND PETROLEUM POTENTIAL OF THE WESTERN ARAFURA SEA." APPEA Journal 30, no. 1 (1990): 91. http://dx.doi.org/10.1071/aj89005.
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The northern Bonaparte Basin and the Arafura-Money Shoal Basins lie along Australia's offshore northern margin and offer significantly different exploration prospects resulting from their differing tectonic and burial histories. The Arafura Basin is dominated by a deep, faulted and folded, NW-SE orientated Palaeozoic graben overlain by the relatively flat-lying Jurassic-Tertiary Money Shoal Basin. The north-eastern Bonaparte Basin is dominated by the deep NE-SW orientated Malita Graben with mainly Jurassic to Recent basin-fill.A variety of potential structural and stratigraphic traps occur in the region especially associated with the grabens. They include tilted or horst fault blocks and large compressional, drape and rollover anticlines. Some inversion and possibly interference anticlines result from late Cenozoic collision between the Australian plate and Timor and the Banda Arc.In the Arafura-Money Shoal Basins, good petroleum source rocks occur in the Cambrian, Carboniferous and Jurassic-Cretaceous sequences although maturation is biassed towards early graben development. Jurassic-Neocomian sandstones have the best reservoir potential, Carboniferous clastics offer moderate prospects, and Palaeozoic carbonates require porosity enhancement.The Malita Graben probably contains good potential Jurassic source rocks which commenced generation in the Late Cretaceous. Deep burial in the graben has decreased porosity of the Jurassic-Neocomian sandstones significantly but potential reservoirs may occur on the shallower flanks.The region is sparsely explored and no commercial discoveries exist. However, oil and gas indications are common in a variety of Palaeozoic and Mesozoic sequences and structural settings. These provide sufficient encouragement for a new round of exploration.
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Preston, J. C., and D. S. Edwards. "THE PETROLEUM GEOCHEMISTRY OF OILS AND SOURCE ROCKS FROM THE NORTHERN BONAPARTE BASIN, OFFSHORE NORTHERN AUSTRALIA." APPEA Journal 40, no. 1 (2000): 257. http://dx.doi.org/10.1071/aj99014.
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Geochemical data from oils and source rock extracts have been used to delineate the active petroleum systems of the Northern Bonaparte Basin. The study area comprises the northeastern portion of the Territory of Ashmore and Cartier Islands, and the western part of the Zone of Co-operation Area A, and is specifically concerned with the wells located on and between the Laminaria and Flamingo highs. The oils and condensates from this region can be divided into two distinct chemical groups which correspond with the reservoir types, namely, a smaller group recovered from fracture porosity within the Early Cretaceous Darwin Formation, and a larger group reservoired in sandstones of the Middle-to-Late Jurassic Plover and Elang formations. The oils recovered from the Darwin Formation have a marine source affinity and correlate with sediment extracts from the underlying Early Cretaceous Echuca Shoals Formation. The Elang/ Plover-reservoired oils, which include all the commercial accumulations, were divided into two end-member families; the first includes the relatively land-plant- influenced oils from the northwestern part of the area (e.g. Laminaria, Corallina, Buffalo and Jahal fields), the second includes the relatively marine-influenced oils to the southeast (e.g. Bayu-Undan fields). Another oil family comprises the geographically and geochemically intermediate oils of the Elang and Kakatua fields and adjacent areas. While none of the oils can be uniquely correlated with a single source unit, they show geochemical similarities with Middle-to-Late Jurassic source rock extracts. Organic-rich rocks within the Plover and Elang formations are the major source of hydrocarbons for this area. The range in geochemistry of the Elang/Plover-reservoired oils may arise from facies variation within these sediments, but is more probably due to the localised additional input of hydrocarbons generated from thermally mature organic-rich claystone seals that overlie the Elang reservoir in catchment areas and traps; i.e. from the Frigate Formation for the northwestern oil family and from the Flamingo Group for the southeastern oil family. The short-range migration patterns dictated by the structural complexity of the basin are reflected in the closeness with which variations in the geochemical character of the accumulated liquids track variations in the character of source-seal lithologies. The length of migration pathways can, therefore, be inferred from the similarity or otherwise of source-seal characters with those of the hydrocarbon accumulations themselves. The resulting observations may challenge existing ideas concerning migration patterns, hydrocarbon prospectivity and prospect risking within the Northern Bonaparte Basin.
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Young, Ian F., Michael J. Raymondi, Phil Wolter, Donna M. Mayo, and Spencer Quam. "Seismic Reprocessing Contributes to Development Success at the Elang Field, Northern Bonaparte Basin." Exploration Geophysics 32, no. 3-4 (September 2001): 297–306. http://dx.doi.org/10.1071/eg01297.
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Palmer, Derecke. "Seismic Reprocessing Contributes to Development Success at the Elang Field, Northern Bonaparte Basin." Exploration Geophysics 32, no. 3-4 (September 2001): 307–14. http://dx.doi.org/10.1071/eg01307.
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Young, Ian F., Wolter Phil, Michael J. Raymondi, Donna M. Mayo, and Spencer Quam. "Seismic reprocessing contributes to development success at the Elang Field, Northern Bonaparte Basin." ASEG Extended Abstracts 2001, no. 1 (December 2001): 1–7. http://dx.doi.org/10.1071/aseg2001ab152.
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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.
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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.
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Jules, Rakotondravoavy, Jiaren Ye, and Qiang Cao. "Geological Conditions and Hydrocarbon Accumulation Processes in the Sahul Platform, Northern Bonaparte Basin, Australia." International Journal of Geosciences 07, no. 06 (2016): 792–827. http://dx.doi.org/10.4236/ijg.2016.76061.
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Mclntyre, C. L., and P. J. Stickland. "SEQUENCE STRATIGRAPHY AND HYDROCARBON PROSPECTIVITY OF THE CAMPANIAN TO EOCENE SUCCESSION, NORTHERN BONAPARTE BASIN, AUSTRALIA." APPEA Journal 38, no. 1 (1998): 313. http://dx.doi.org/10.1071/aj97015.
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The Campanian to Eocene succession of the Northern Bonaparte Basin contains a number of siliciclastic reservoirs which provide alternative targets to the Callovian structural plays that have dominated exploration to date. The succession is part of the Passive Margin Megasequence which extends from the Aptian to the Pliocene, and is traditionally subdivided into the Turnstone, Johnson and Grebe Formations.Prograding deltaics of the Turnstone Formation swamped an incipient Early-Campanian carbonate ramp following a second-order sequence-boundary. Five third-order sequences are recognised within the Turnstone Formation, each dominated by Lowstand (shelf-margin wedge) and Highstand Systems Tract components. A coeval basinal carbonate system resulted in the deposition of marls and lutites distal of the clastic deltaics. In the Early Paleocene, drowning of the clastic system led to the establishment of a productive carbonate ramp. Rare lowstand siliciclastic reservoirs are developed within carbonate-dominated prograding complexes, as incised valley-fill, and possibly within prominent slope canyons. In the Late Paleocene, a third-order transgression drowned the carbonate system. The Early Eocene Grebe sandstones were then deposited as a second-order lowstand package upon a prominent sequence-boundary. Subsequent flooding of the siliciclastic system resulted in the re-establishment of the prograding carbonate ramp system.The morphology of the passive-margin was strongly influenced by the interplay between sediment-supply and subsidence. The predominantly ramp-like geometry of the margin promoted the development of numerous shallow-marine lowstand reservoirs. The hydrocarbon prospectivity of each of these reservoirs is primarily controlled by the magnitude of the subsequent flooding events: Only the largest transgressions resulted in sufficient reduction of depositional energy to isolate the lowstand siliciclastics.Vertical migration remains the critical risk for all passive margin plays, as the reservoirs are separated from the Late Jurassic and Early Cretaceous source kitchens by up to one kilometre of claystone dominated sequences. None-the-less, the widespread occurrence of shallow hydrocarbon shows in the greater Bonaparte Basin indicates that Neogene faulting does provide locally valid migration pathways into post-rift reservoirs.
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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.
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Boreham, Christopher J., Dianne S. Edwards, Robert J. Poreda, Thomas H. Darrah, Ron Zhu, Emmanuelle Grosjean, Philip Main, Kathryn Waltenberg, and Paul A. Henson. "Helium in the Australian liquefied natural gas economy." APPEA Journal 58, no. 1 (2018): 209. http://dx.doi.org/10.1071/aj17049.
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Australia is about to become the premier global exporter of liquefied natural gas (LNG), bringing increased opportunities for helium extraction. Processing of natural gas to LNG necessitates the exclusion and disposal of non-hydrocarbon components, principally carbon dioxide and nitrogen. Minor to trace hydrogen, helium and higher noble gases in the LNG feed-in gas become concentrated with nitrogen in the non-condensable LNG tail gas. Helium is commercially extracted worldwide from this LNG tail gas. Australia has one helium plant in Darwin where gas (containing 0.1% He) from the Bayu-Undan accumulation in the Bonaparte Basin is processed for LNG and the tail gas, enriched in helium (3%), is the feedstock for helium extraction. With current and proposed LNG facilities across Australia, it is timely to determine whether the development of other accumulations offers similar potential. Geoscience Australia has obtained helium contents in ~800 Australian natural gases covering all hydrocarbon-producing sedimentary basins. Additionally, the origin of helium has been investigated using the integration of helium, neon and argon isotopes, as well as the stable carbon (13C/12C) isotopes of carbon dioxide and hydrocarbon gases and isotopes (15N/14N) of nitrogen. With no apparent loss of helium and nitrogen throughout the LNG industrial process, together with the estimated remaining resources of gas accumulations, a helium volumetric seriatim results in the Greater Sunrise (Bonaparte Basin) > Ichthys (Browse Basin) > Goodwyn–North Rankin (Northern Carnarvon Basin) accumulations having considerably more untapped economic value in helium extraction than the commercial Bayu-Undan LNG development.
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Bernecker, Thomas, Dianne Edwards, Tehani Kuske, Bridgette Lewis, and Tegan Smith. "Prospectivity of the 2014 offshore acreage release areas for petroleum exploration." APPEA Journal 54, no. 1 (2014): 383. http://dx.doi.org/10.1071/aj13040.
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The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. Industry nominations provided guidance for the selection of gazettal areas, and in 2014 all 30 areas are supported by such nominations. The release areas are located across various offshore hydrocarbon provinces ranging from mature basins with ongoing oil and gas production to exploration frontiers. Work program bids are invited for two rounds closing on 2 October 2014 and 2 April 2015, while the closing date for four cash bid areas is 5 February 2015. Twenty-nine of the 2014 Release Areas are located along Australia’s northern margin within the Westralian Superbasin, which encompasses the rift-basins that extend from the Northern Carnarvon Basin to the Bonaparte Basin. Evolution during Gondwana break-up established a series of petroleum systems, many of which have been successfully explored, while others remain untapped. Only one area was nominated and approved for release on Australia’s southern margin. The 220 graticular blocks cover almost the entire Eyre Sub-basin of the Bight Basin. In the context of the recent commencement of large-scale exploration programs in the Ceduna and Duntroon sub-basins, this release area provides additional opportunities to explore an offshore frontier. Geoscience Australia’s new long-term petroleum program supports industry activities by engaging in petroleum geological studies that are aimed at the establishment of margin to basin-scale structural frameworks and comprehensive assessments of Australian source rocks underpinning all hydrocarbon prospectivity studies.
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Blevin, J. E. "EXPLORATION HIGHLIGHTS FOR 2006." APPEA Journal 47, no. 2 (2007): 631. http://dx.doi.org/10.1071/aj06056.
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Key business indicators show an upward trend in exploration activity in Australia during 2006. The year was marked by fluctuating high oil prices, a strong uptake of acreage in most basins, and increased levels of drilling activity and seismic acquisition. Market demand for product, production infrastructure and the fruition of several development projects have pushed the level of exploration activity in both offshore and onshore basins. Despite this trend and the spread of tenements, almost all petroleum discoveries made during 2006 were located within 15 km of existing (but often undeveloped) fields.The Carnarvon Basin continued to be the focus of most offshore exploration activity during 2006, with the highest levels of 3D seismic acquisition and exploration/appraisal/development drilling in the country. Discoveries in the Carnarvon Basin also covered the broadest range of water depths—extending from the oil and gas discoveries made by Apache on the inboard margin of the Barrow Subbasin, to the deepwater gas discoveries at Clio–1 and Chandon–1 by Chevron. Several large gas discoveries were made in the Carnarvon and Bonaparte basins and provide significant tie-back opportunities to existing and planned infrastructure. The Bonaparte Basin also saw significantly increased levels of 2D and 3D seismic acquisition during 2006. Onshore, the Cooper/Eromanga basins continued to experience the highest level of drilling activity and seismic acquisition, while maintaining an overall high drilling success rate. For the first time in many years, data acquisition also occurred in frontier basins like the Daly (Northern Territory), Darling (New South Wales), Tasmanian (Tasmania) and Faust/Capel basins (Lord Howe Rise region).Coal seam methane (CSM) exploration maintained a strong performance in 2006, particularly in Queensland, while South Australia, Queensland and Victoria continue to lead the way with large tracts of acreage gazetted for geothermal energy exploration.
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Bernecker, Thomas, Steve Abbott, George Bernardel, Megan Lech, Ryan Owens, Tegan Smith, and Jennifer Totterdell. "The 2017 offshore acreage release areas: petroleum geological overview." APPEA Journal 57, no. 2 (2017): 304. http://dx.doi.org/10.1071/aj16029.
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In 2017, 21 new offshore petroleum exploration areas have been released. The majority of the areas are located along the North West Shelf spanning the Westralian Superbasin from the Bonaparte Basin in the north-east to the Northern Carnarvon Basin in the south-west. New areas have been released in offshore south-eastern Australia with new opportunities provided in the Otway, Bass and Gippsland basins. Two large areas in the northern Perth Basin, an offshore frontier, complete the 2017 Acreage Release. All Release Areas are supported by industry nominations and one new cash bid area has been offered in the Dampier Sub-basin. Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available as part of the agency’s regional petroleum geological studies. A new regional 2D seismic survey was acquired in the Houtman Sub-basin of the Perth Basin, forming the basis of the latest prospectivity study carried out by Geoscience Australia. The results of the study are presented in the technical program of the 2017 APPEA conference. A wealth of seismic and well data, submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGSSA) are made available through the National Offshore Petroleum Information Management System (NOPIMS). Additional datasets are accessible through Geoscience Australia’s data repository.
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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.
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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).
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Cockbain, A. E. "THE NORTH WEST SHELF." APPEA Journal 29, no. 1 (1989): 529. http://dx.doi.org/10.1071/aj88040.
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The region of the North West Shelf dealt with in this paper is underlain by three of the four basins which make up the Westralian Superbasin. The Bonaparte Basin lies outside the scope of this paper; the other basins are the Browse Basin, the offshore Canning Basin, here named the Western Canning Basin, and the offshore Carnarvon Basin, here called the Northern Carnarvon Basin. Sediments belonging to ten depositional sequences (Pz5, Mzl to Mz5, and Czl to Cz4) are present in the basins, the oldest being of Late Carboniferous and Permian age (Pz5).Deposition commenced in rift (interior fracture) basins under fluvial/deltaic conditions in the Late Permian/Early Triassic (Mzl), when the North West Shelf was part of Gondwana. Continental breakup took place in the Middle Jurassic (breakup unconformity between Mz2 and Mz3), and marine conditions prevailed over the Westralian Superbasin thereafter, with deposition taking place in a marginal sag setting. Siliciclastic sediments gave place to carbonates in the Late Cretaceous (Mz5) as the Indian Ocean grew larger.Parts of the area have been under permit since 1946, and to date some 227 exploration wells have been drilled. The most intensive exploration has taken place in the Northern Carnarvon Basin (191 wells), followed by the Browse Basin (20 wells), and Western Canning Basin (16 wells). Thirty- four economic and potentially economic discoveries have been made. The main target reservoirs are Triassic, Jurassic and Cretaceous, and the regional seals are Triassic and Cretaceous. The fields are of two types: pre- breakup unconformity (mainly tilted horst blocks), and post- breakup unconformity (usually four- way dip closures). Of the five producing fields, the North Rankin Gas Field is a pre- breakup field, while the four oil fields (Barrow, Harriet, South Pepper and North Herald) are all post- breakup.
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Bernecker, Thomas, Tehani Kuske, Bridgette Lewis, and Tegan Smith. "The hydrocarbon potential of the 2015 Offshore Acreage Release Areas for petroleum exploration." APPEA Journal 55, no. 1 (2015): 71. http://dx.doi.org/10.1071/aj14007.
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The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. These areas are located across various offshore hydrocarbon provinces ranging from mature basins with ongoing oil and gas production to exploration frontiers. A total of 23 areas are released for work-program bidding and six areas for cash bidding (Fig. 1). The two work-program bidding rounds will remain open until 29 October 2015 and 21 April 2016, respectively, while cash bid submissions will close on 4 February 2016. The 2015 Release Areas are located in 13 distinct geological provinces across eight basins and all were supported by industry nominations. Six areas are located in the Bonaparte Basin, two of which are cash bid areas over the Turtle/Barnett oil accumulations. In the Browse Basin, three areas in the Caswell Sub-basin and one area on the Yampi Shelf are released. In support of recent exploration activities and success, one large area has been gazetted in the central Roebuck Basin. The Northern Carnarvon Basin offering comprises 11 areas on the Exmouth Plateau and in the Dampier Sub-basin, including four for cash bidding. This year, the usual predominance of North West Shelf Release Areas is counterbalanced by seven large areas in the Bight, Otway, Sorell and Gippsland basins. This includes one area in the Ceduna Sub-basin, three areas in the deepwater Otway Basin, one area in the northern Sorell Basin and two areas in the southeastern Gippsland Basin. The nominations received for these areas highlights the industry’s interest in evaluating the hydrocarbon potential of Australia’s underexplored southern margin. Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available as part of the agency’s regional petroleum geological studies.
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Gorter, J. D., and A. Y. Glikson. "Fohn lamproite and a possible Late Eocene — pre‐Miocene diatreme field, Northern Bonaparte Basin, Timor Sea." Australian Journal of Earth Sciences 49, no. 5 (October 2002): 847–68. http://dx.doi.org/10.1046/j.1440-0952.2002.00957.x.
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Bernecker, Thomas, Ryan Owens, Andrew Kelman, and Kamal Khider. "Geological overview of the 2021 offshore acreage release areas." APPEA Journal 61, no. 2 (2021): 294. http://dx.doi.org/10.1071/aj20113.
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In 2021, a total of 21 areas were released for offshore petroleum exploration. They are located in the Bonaparte Basin, Browse Basin, Northern Carnarvon Basin, Otway Basin, Sorell Basin and Gippsland Basin. Despite COVID-19 negatively impacting the industry, participation in the acreage release nomination process was again robust. However, as has been the case in recent years, industry interest is focussed on those areas that are close to existing discoveries and related infrastructure. In tune with the Australian government’s resource development strategy, the areas being offered for exploration are likely to supply extra volumes of natural gas, both for export to Southeast Asian markets and domestically to meet the forecasted shortage in supply to eastern Australia. According to the 2019 implementation of a modified release process, only one period for work program bidding has been scheduled. The closing date for all submissions is Thursday, 3 March 2022. Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available in the context of the agency’s regional petroleum geological studies. As part of a multidisciplinary study, new data, including regional seismic and petroleum systems modelling, for the Otway Basin are now available. Also, a stratigraphic/sedimentological review of the upper Permian to Early Triassic succession in the southern Bonaparte Basin has been completed, the results of which are being presented at this APPEA conference. Large seismic and well data sets, submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGSSA), are made available through the National Offshore Petroleum Information Management System (NOPIMS). Additional data and petroleum-related information can be accessed through Geoscience Australia’s data repository.
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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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Bourget, J., R. B. Ainsworth, G. Backé, and M. Keep. "Tectonic evolution of the northern Bonaparte Basin: impact on continental shelf architecture and sediment distribution during the Pleistocene." Australian Journal of Earth Sciences 59, no. 6 (August 2012): 877–97. http://dx.doi.org/10.1080/08120099.2012.674555.
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Bernecker, Thomas. "A petroleum geological overview of the 2013 offshore acreage release for petroleum exploration." APPEA Journal 53, no. 1 (2013): 69. http://dx.doi.org/10.1071/aj12007.
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The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. The previous two releases were characterised by several large, gazetted areas in underexplored regions, a trend that is maintained this year with several frontier areas comprising more than 100 graticular blocks on offer. The recent uptake of new exploration permits in the Bight Basin, the offshore North Perth Basin, and the Roebuck Basin indicates a continuing strong industry interest in offshore frontier exploration. A total of 31 areas in 13 geological provinces are formally released in 2013, and work program bids are invited for two rounds closing on 21 November 2013, and 22 May 2014. Area gazettal was, again, well supported by industry nominations. The areas on offer are represented by an even mix of shallow and deepwater areas, as well as by areas close and distant to previous discoveries and producing fields. The Northern Carnarvon, Browse, and Bonaparte basins dominate new exploration opportunities in the 2013 release, while only four areas were gazetted in the North Perth, Otway, and Gippsland basins. These also deserve attention as they have exploration potential in underexplored parts of the basins and offer opportunities to test new play concepts. Data coverage varies from being excellent in more mature areas to sparse in underexplored areas such as the North Perth Basin. The Australian Government continues to assist offshore exploration activities by providing free access to a wealth of open-file geological and geophysical data.
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Wiyatno, Oki Fimansyah, M. Syamsu Rosid, and Humbang Purba. "Mapping the Distribution and Characterization of Sandstone Reservoir Using Simultaneous Inversion Method in “OA” Field at Northern Bonaparte Basin." Journal of Physics: Conference Series 1351 (November 2019): 012045. http://dx.doi.org/10.1088/1742-6596/1351/1/012045.
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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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Abbassi, Soumaya, Rolando di Primio, Brian Horsfield, Dianne S. Edwards, Herbert Volk, Zahie Anka, and Simon C. George. "On the filling and leakage of petroleum from traps in the Laminaria High region of the northern Bonaparte Basin, Australia." Marine and Petroleum Geology 59 (January 2015): 91–113. http://dx.doi.org/10.1016/j.marpetgeo.2014.07.030.
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Bernecker, Thomas, George Bernardel, Claire Orlov, and Nadège Rollet. "Petroleum geology of the 2018 offshore acreage release areas." APPEA Journal 58, no. 2 (2018): 437. http://dx.doi.org/10.1071/aj17056.
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A total of 21 areas were released in 2018 for offshore petroleum exploration. They are located in the Bonaparte, Browse, Northern Carnarvon, Bight, Otway and Gippsland basins. All release areas were supported by industry nominations, indicating that interest in exploring Australia’s offshore basins remains strong, despite the significant decrease in the number of exploration wells drilled in recent years. Sixteen areas are being released under the work program bidding system with two rounds, one closing on 18 October 2018 and the other on 21 March 2019. Five areas are being released for cash bidding and include the producible La Bella gas accumulation in the Otway Basin. Prequalification for participation in the cash-bid auction closes on 4 October 2018 with the auction scheduled for 7 February 2019. Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available as part of the agency’s regional petroleum geological studies. The regional evaluation of the petroleum systems in the Browse Basin has been completed and work continues on assessing the distribution of Early Triassic source rocks and related petroleum occurrences across the North West Shelf. A wealth of seismic and well data, submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006, are made available through the National Offshore Petroleum Information Management System. Additional datasets are accessible through Geoscience Australia’s data repository.
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George, S. C., H. Volk, T. E. Ruble, and M. P. Brincat. "EVIDENCE FOR A NEW OIL FAMILY IN THE NANCAR TROUGH AREA, TIMOR SEA." APPEA Journal 42, no. 1 (2002): 387. http://dx.doi.org/10.1071/aj01021.
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Geochemical evidence is presented for a previously unrecognised oil generative source rock in the Nancar Trough area. This source rock supplements the middle to late Jurassic source rocks, which have previously been shown to have generated most of the oils in the northern Bonaparte Basin and the Vulcan Sub-basin. Fluids with a strong contribution from this new source rock, defined here as the Nancar oil family, have an unusually high abundance of mid-chain substituted monomethylalkanes. In comparison, oils from the Vulcan Sub-basin contain mostly terminally substituted monomethylalkanes and the overall abundance is much lower. Oils from the Laminaria High and some from the northern Vulcan Sub-Basin show intermediate characteristics and may be co-sourced. Evidence from the analysis of fluid inclusion oils was important in establishing the presence of the new oil family because interference from drilling mud contaminants could be excluded. The detailed geochemistry of Ludmilla–1 fluid inclusion oil suggests the source rock for the Nancar oil family was deposited in a marine environment under sub-oxic conditions with limited sulphur content, a low contribution of terrestrial organic matter and a high contribution of organic matter from bacterial activity. Since monomethylalkanes are typical biomarkers of cyanobacteria, the source rock that gave rise to the new oil family may be rich in cyanobacterial organic matter. Further studies on sediment extracts are needed to establish an explicit oil-source rock correlation and to identify the stratigraphic location/palaeo-environment of the source rock. Such information will be valuable in determining the prospectivity of the large and relatively unexplored province draining the Nancar Trough kitchen.
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Jules, Rakotondravoavy, Ye Jia Ren, and Cao Qiang. "Thermal History and Potential of Hydrocarbon Generated from Jurassic to Early Cretaceous Source Rocks in the Malita Graben, Northern Bonaparte Basin, Australia." International Journal of Geosciences 06, no. 08 (2015): 894–916. http://dx.doi.org/10.4236/ijg.2015.68073.
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Jules, Rakotondravoavy, Jiaren Ye, and Qiang Cao. "Evaluation of Hydrocarbon Generated and Expelled from the Jurassic to Early Cretaceous Source Rocks in the Lynedoch Field, Northern Bonaparte Basin, Australia." International Journal of Geosciences 07, no. 04 (2016): 584–97. http://dx.doi.org/10.4236/ijg.2016.74045.
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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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Nóbrega, PFA, JAB Aguiar, and JEC Figueira. "First records of Charadrius semipalmatus, Bonaparte 1825 (Charadriidae) and Gelochelidon nilotica Gmelin 1789 (Sternidae) in the State of Minas Gerais, Brazil." Brazilian Journal of Biology 75, no. 2 (May 2015): 451–54. http://dx.doi.org/10.1590/1519-6984.17013.
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Around forty bird species habitually reproduce in the Northern Hemisphere during summer, and migrate to the Southern Hemisphere during northern winter. These migrating birds fly together in large or small groups until they have reached the Caribbean, Central American, or Brazilian shores. Charadrius semipalmatus, Bonaparte 1825, is one of these migrating species that uses resting and feeding areas along eastern and western coasts of North and South America, with several records for the Brazilian coast, and very few for the inland country. On November 24, 2011, an individual of this species was observed on the banks of one of the lakes that compose a complex of about 40 temporary lakes within the Karst of Lagoa Santa Environmental Protection Area. On October 29 and 30, 2012 a single individual of Gelochelidon nilotica, Gmelin 1789, was also observed in Sumidouro State Park. We suggest that these specimens have used the Atlantic Ocean migration route, following the São Francisco River Basin, until the karst area. Although highly impacted, the temporary lakes within the Karst of Lagoa Santa still harbor a significant number of bird species, and serve as resting and feeding places for migratory or errant species that are still eliciting new records.
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Whittam, D. B., M. S. Norvick, and C. L. Mclntyre. "MESOZOIC AND CAINOZOIC TECTONOSTRATIGRAPHY OF WESTERN ZOCA AND ADJACENT AREAS." APPEA Journal 36, no. 1 (1996): 209. http://dx.doi.org/10.1071/aj95012.
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Increased exploration activity in Area A of the Timor Gap Zone of Cooperation between Australia and Indonesia (ZOCA) has created the need for revision of the existing stratigraphic framework of the region. A chronostratigraphic approach to the analysis of the Mesozoic and Cainozoic succession of Western ZOCA provides a framework for improved stratigraphic prediction. The framework is based on the identification of depositional sequences by the integration of seismic and well data. Genetically related depositional sequences have been grouped into seven 'megasequences' which reflect distinct stages in the tectonic development of the basin.The Mesozoic and Cainozoic succession in the Northern Bonaparte Basin was deposited in a marginal sag basin that was affected by Triassic to Lower Cretaceous extension related to continental separation along the northwest margin of Australia. Four stages are seen in the evolution of the basin since the end of the Permian. Relative tectonic quiescence during the Triassic preceded two cycles of extension related to continental separation during the Jurassic to Earliest Cretaceous. Continental separation was followed by the development of a Cretaceous/Tertiary passive margin and a subsequent phase of tectonism related to the Miocene/Pliocene collision of the Indo-Australian and Eurasian plates. A tentative correlation has been made between the megasequence framework of Western ZOCA and the geological succession exposed on Timor Island.The framework forms the basis for a system of common stratigraphic nomenclature for the Timor Gap. The model also assists in understanding the tectono-strati-graphic evolution of the basin and is a foundation for the development of new play concepts that will support continuing exploration activity in the area.
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Summons, R. E., C. J. Boreham, C. B. Foster, A. P. Murray, and J. D. Gorter. "CHEMOSTRATIGRAPHY AND THE COMPOSITION OF OILS IN THE PERTH BASIN, WESTERN AUSTRALIA." APPEA Journal 35, no. 1 (1995): 613. http://dx.doi.org/10.1071/aj94037.
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The known global secular change in the distribution of carbon isotopes between the Palaeozoic and Mesozoic is the basis of a new oil-source correlation tool. The carbon isotopic signatures of n-alkanes, in combination with information about the distributions of diagnostic biomarkers have been used to classify Perth Basin oils according to the age of the source. These data confirm that most of the oil in the northern Perth Basin originates from the basal section of the Kockatea Shale.Oils exclusively from Triassic sources are isotopically light with n-alkane 813C values near −34%o PDB. Jurassic oil from Gage Roads-1 is isotopically heavy (~24%o) and is also distinctive in its relatively high content of conifer-derived aromatic hydrocarbons. Condensates from Jurassic source intervals in the Dandaragan Trough are isotopically heterogeneous with n-alkane 813C values between −25%o and −29%o. The Whicher Range-1 condensate, of apparent Permian origin, is isotopically heavy with n-alkane 5l3C values near −25%o. The isotopic data provide information about variation in sedimentary facies and possible multiple sources that is not evident from the biomarker signatures. All the Jurassic oils have significant amounts of bicadinanes, resin-derived biomarkers until recently attributed exclusively to tropical angiosperms.A strong excursion in the isotopic signature of organic carbon is present in core at 2,293 m in the Woodada-2 borehole and occurs with no obvious lithological change. Similar isotope shifts are known to mark the Permian-Triassic boundary globally and have been previously recognised in the Bonaparte, Bowen, Canning, Carnarvon and tentatively in the southern Perth basins. The excursion in Woodada-2 is abrupt and suggests a significant time break in sedimentation. However, diagnostic Permian palynoflora or fauna have not been detected below 2,293 m in the Woodada-2 core, and hence, the assignment of a Permian-Triassic contact cannot be made unequivocally with the existing data.
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van Merwyk, A. M., and A. L. Disney. "ENVIRONMENTAL UPDATE 2004." APPEA Journal 45, no. 2 (2005): 157. http://dx.doi.org/10.1071/aj04069.
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This paper presents the highlights of development activity of 2004 for the petroleum industry within Australia. In the face of declining oil production within Australia there were few new oil field developments in 2004 (Exeter- Mutineer; Jingemia). The start up of liquids stripping at Bayu-Undan in the Timor Sea and other gas/condensate fields such as Apache’s Linda, however, helped to arrest the declining trend. The first oil fields that define a new oil province in the Exmouth Sub-basin were the subject of extensive appraisal programs and Woodside gave the green light for start of the A$1.48 billion Enfield development.The story for natural gas in 2004 is somewhat more buoyant with several developments in domestic supply around Australia, including coal seam methane (CSM) production on-stream on the east coast. The national pipeline grid extended with the opening of the A$500 million SEAgas pipeline between Port Campbell and Adelaide. Minerva gas production followed at the end of the year, leading the way for the approval of gas developments at Thylacine- Geographe (A$1.1 billion) and Casino (A$200 million) in the Otway Basin. The Yolla gas production platform was installed on site in the Bass Basin. Apache and Santos signed an agreement to supply gas from John Brookes, offshore Carnarvon Basin, and Woodside looked to Blacktip, in the Bonaparte, to supply gas to the Northern Territory.2004 was a cornerstone year for LNG. A new carrier was delivered to the NWS Joint Venture and gas flowed from the fourth LNG train for the first time. Deliveries under new contracts started to Japan and Korea and a major contract for supply was signed with China. Other potential LNG projects began significant appraisal programs at fields such as Scarborough on the NWS.
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Jewett, Kelsey, Anne-Claire Lorage, Said Amiribesheli, and Han Kee Tan. "Exploration in the southwest Malita Graben: initial results and remaining potential." APPEA Journal 53, no. 2 (2013): 428. http://dx.doi.org/10.1071/aj12039.
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In 2011, Total E&P Australia and Petronas Carigali drilled two exploration wells in permit WA-403-P in the northern Bonaparte Basin. Both wells targeted the Middle-Jurassic play of the Elang/Plover formations that have yielded all commercial discoveries in the area. Notably, the wells were drilled in a less-explored area near the axis of the basin, targeting reservoirs at or more than 4,000 m. Pre-drill, the critical risks were recognised as burial-related reservoir degradation and cross-fault leakage into Upper Jurassic to Lower Cretaceous sands. The first well, Durville-1, was drilled on a poorly imaged three-way dip closure to the south of the Flamingo High. A gas column with high CO2 content was encountered in thick, high net-to-gross sands of lowermost Berriasian age. Drilling was terminated before the Elang Formation was reached. The second well, Laperouse-1, was drilled on a well-imaged fault block near the southern margin of the Malita Graben. The structure was formed in the Late Jurassic and lacks recent fault activation; thus, it was anticipated that early hydrocarbon charge might protect the reservoir from severe diagenesis. Laperouse-1 encountered a thick succession of Tithonian to Berriasian water-bearing sand packages; it reached total depth in the Elang Formation. The WA-403-P drilling campaign has confirmed the presence of thick Cretaceous sandstone in the area, although significant discrepancies in reservoir quality are observed between Durville-1 and Laperouse-1.
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Charlton, T. R. "THE PETROLEUM POTENTIAL OF EAST TIMOR." APPEA Journal 42, no. 1 (2002): 351. http://dx.doi.org/10.1071/aj01019.
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The hydrocarbon prospectivity of East Timor is widely considered to be only moderate due to Timor island’s well-known tectonic complexity, but in the present study a much higher potential is interpreted, with structures capable of hosting giant hydrocarbon accumulations. High quality source rocks are found in restricted marine sequences of Upper Triassic-Jurassic age. The most likely reservoir target is shallow marine siliciclastics of Upper Triassic-Middle Jurassic age encountered in the Banli–1 well in West Timor, comparable to the Malita and Plover Formations of the northern Bonaparte Basin, and sealed by Middle Jurassic shales of the Wai Luli Formation. The Wai Luli Formation also forms a major structural décollement level which detaches shallow level structural complexity from a simpler structural régime beneath.The principal exploration targets are large, structurally simple inversion anticlines developed beneath the complex shallow-level fold and thrust/mélange terrain. Eroded-out examples of inversion anticlines, such as the Cribas, Aitutu and Bazol anticlines, are typically several tens of kilometres long and up to 10 km broad. Comparable structures in the subsurface of southern East Timor are interpreted north of Betano, and probably also near Suai, Beaco, Aliambata and Iliomar. Other potential targets include a possible non-inverted rollover anticline at Pualaca, stratigraphic and structural traps in the south coast syn/postorogenic basins, and possibly large structural domes beneath extensive Quaternary reef plateaux in the extreme east of the island.
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Soares, Rui, Steve Thompson, and Robert Smillie. "Rigless well intervention and trees on wire from a DPII vessel: a case study." APPEA Journal 50, no. 2 (2010): 744. http://dx.doi.org/10.1071/aj09108.
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Since the 2006 bidding rounds, exploration activity in both the Timor-Leste exclusive offshore area (TLEA) and joint petroleum development area (JPDA) has progressed steadily. Within the JPDA, exploration remains largely focussed in the Jurassic-age Plover and Elang Sandstone formations in the Flamingo Trough-Sahul Syncline region. Over 700 MMbbls of liquids and 4Tcf of gas have been discovered in this western region of the JPDA, including the 2008 Kitan oil field discovery by Eni, which is currently scheduled for production in 2011. Recent seismic survey activity within the JPDA by PSC holders Petronas and Oilex has resulted in the combined acquisition of 2,800 square kilometres of new 3D data. These surveys, together with on-going re-evaluation of existing well data by these companies, has helped further refine the knowledge of petroleum systems within the JPDA, in preparation for drilling campaigns scheduled for late 2009 and early 2010. Within the TLEA, multi-client seismic surveys undertaken in 2005, together with on-shore academic research, indicates that the prospective Mesozoic sequence of the Northern Bonaparte Basin underlies the Timor Trough, greatly enhancing the petroleum prospectivity of this region. Further detailed 2D and 3D seismic surveys in the TLEA have been recently completed by PSC holders Reliance Exploration and Eni. The first wells to be drilled in this deeper water frontier region are scheduled for 2010.
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Wheller, Dave, Grant Ellis, Yohan Suhardiman, Ryosuke Yokote, Doani Selvaggi, Giuseppe Maniscalco, and Joseph Derrij. "Discovery to development: a subsurface case history of the Kitan Oil Field, Timor Sea, Joint Petroleum Development Area, Timor-Leste and Australia." APPEA Journal 53, no. 2 (2013): 439. http://dx.doi.org/10.1071/aj12050.
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The Kitan oil field is located in the northern Bonaparte Basin in the Joint Petroleum Development Area, an area jointly administered by Timor-Leste and Australia. The Kitan structure is a Jurassic east-west trending tilted fault block. The Kitan–1 exploration well was drilled and successfully tested in early 2008. Kitan–2 appraisal well was drilled immediately after Kitan–1 and intersected the reservoir up-dip from Kitan–1 and confirmed the extension of the oil accumulation. The main oil-bearing section is in the shallow marine sandstone of the Middle Jurassic Laminaria Formation. It is divided into two reservoir zones: a blocky channelised sandstone (Unit–2) overlain by a dominantly finer-grained succession composed of coarsening-upwards para-sequences (Unit–1). Kitan oil field was declared a commercial discovery in April 2008 and a field development plan was submitted in May 2009 and approved in April 2010. Four development wells were drilled of which three were completed as producers, each employing an intelligent completion design to enable independent control and monitoring of the two reservoirunits. The three wells were tied back subsea via flexible flowlines and risers to the Glas Dowr FPSO. Oil production from the Kitan started in October 2011, about 3.5 years after the discovery of the field. The fast-track development of Kitan was achieved due to accelerated appraisal, prompt completion of studies, early commitment to long lead items, and excellent support from joint-venture partners and government.
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Brooks, D. M., A. K. Goody, J. B. O'Reilly, and K. L. McCarty. "BAYU/UNDAN GAS-CONDENSATE DISCOVERY: WESTERN TIMOR GAP ZONE OF COOPERATION, AREA A." APPEA Journal 36, no. 1 (1996): 142. http://dx.doi.org/10.1071/aj95009.
Full textAbstract:
The Bayu/Undan Gas-Condensate Field straddles the boundary between the ZOCA 91-12 and ZOCA 91-13 PSC areas, within the Timor Gap Zone of Cooperation Area A (ZOCA). The field is located approximately 450 km northwest of Darwin, NT, and 350 km east-southeast of Kupang, Timor. The closure is the culmination of the Flamingo High, a major structural element within the northern Bonaparte Basin. This structure has been viewed as having significant hydrocarbon potential since Flamingo-1 recovered gas from Berriasian sandstones in 1971.The discovery well, Bayu-1, was drilled by the ZOCA 91-13 contract operator, Phillips Petroleum Company ZOC, in early 1995. Bayu-1 intersected a gross 155m gas-condensate column within Middle Jurassic sandstones at a depth of 2,954.5 mSS. The ZOCA 91-12 joint venture then drilled Undan-1,10 km northwest of Bayu-1, on a separate culmination within the closure defined by the Bayu-1 gas-water contact. Undan-1 and subsequent wells have confirmed the existence of one large gas-condensate field, with a most likely areal extent of over 160 km2.The sandstone reservoir consists of late Oxfordian to Callovian shallow marine, deltaic to shoreface, coarsening upward parasequences, overlying Callovian to Bajocian marginal marine to coastal plain sediments. The trap is an east-west oriented horst block bounded by en-echelon normal faults to the north and south, with dip closure to the east and west. Seal is provided by Tithonian to Barremian marine claystones. A likely hydrocarbon source is contained within the Barremian to Callovian interval, some of which are mature for condensate and wet gas expulsion in the southern Sahul Syncline and Malita Graben.
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Young, I. F., T. M. Schmedje, and W. F. Muir. "THE ELANG OIL DISCOVERY ESTABLISHES NEW OIL PROVINCE IN THE EASTERN TIMOR SEA (TIMOR GAP ZONE OF COOPERATION)." APPEA Journal 35, no. 1 (1995): 44. http://dx.doi.org/10.1071/aj94003.
Full textAbstract:
The Elang-1 oil discovery in the Timor Gap Zone of Cooperation (ZOC) has established a new oil province in the eastern Timor Sea. The discovery well, completed in February 1994, recorded a flow of 5,800 BOPD (5,013 STBOPD) from marine sandstone of the Late Jurassic Montara beds. The oil is a light (56° API), undersaturated oil with a GOR of approximately 550 SCF/STB. Elang-1 was the first well drilled by the ZOCA 91-12 Joint Venture and only the fifth well in the ZOC since exploration of this frontier area resumed in 1992.The Elang Prospect, initially mapped by Petroz in the late 1970s on the basis of regional seismic data, was detailed by the 1992 Walet Seismic Survey. The prospect is the main crestal culmination on the Elang Trend, a prominent structural high to the north of the Flamingo High that was established during continental break-up in the Late Jurassic. The Elang Trend is bounded to the south by a series of en-echelon normal faults and connecting relay ramps and comprises a number of horst and tilted fault blocks.Elang-1 tested a near crestal culmination on the Elang Prospect and intersected a 76.5 m gross oil column below 3,006.5 m RT. At time of drilling this oil column was the thickest that had been encountered by any well in the Northern Bonaparte Basin. Good quality reservoir sandstone in six discrete bodies were intersected within the Montara beds. Core-measured porosity and permeability range up to 17 per cent and 2.2 Darcies within the oil column.Subsequent to the Elang discovery, the Joint Venture recorded a 402 km2 3D survey over the Elang Trend. Elang-2, an appraisal well spudded in September 1994 prior to receipt of the 3D data, established the lateral continuity of the Montara beds reservoirs. Flow rates of 6,080 BOPD (5,300 STBOPD) and 7,500 BOPD (5,970 STBOPD) from separate intervals have confirmed that high deliverabilities can be expected from individual sandstones. Further appraisal drilling is planned in the first half of 1995. This is expected to lead to commercial development of the field.
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Grahame, Jarrad, Emma Cairns, and Stephanie Roy. "Triassic paleogeography and petroleum systems of the North West Shelf, Australia: key insights from a new regional study." APPEA Journal 57, no. 2 (2017): 744. http://dx.doi.org/10.1071/aj16156.
Full textAbstract:
CGG Multi-Client & New Ventures, in collaboration with CGG Robertson, has undertaken a new comprehensive study of the Triassic paleogeography and petroleum systems of the North West Shelf (NWS) including the Northern Carnarvon, Roebuck, Browse and Bonaparte basins. The key objectives of the study were to enhance the understanding of the prospectivity of NWS Triassic petroleum systems, develop new paleogeography maps, establish evidence for Triassic marine-derived source rocks and investigate the prospectivity of Late Triassic carbonate reef complexes. The study comprises new biostratigraphic analyses, quantitative evaluation by scanning electron microscopy (QEMSCAN®) analyses, core logging, 1D and 2D modelling of key wells and seismic sections, plate reconstructed paleogeography and play mapping. Of key relevance to this study is the paleo-depositional framework and subsequent structuring of Triassic successions throughout the NWS basins in the context of petroleum system development.
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Hamid Fadul, Suliman Ahmed, Ye Jia Ren, Cao Qiang, and Liu Wenchao. "Formation Pressure Evolution in Lynedoch Fields, Northern Bonaparte Basin, Australia." Earth Science Research 1, no. 2 (June 19, 2012). http://dx.doi.org/10.5539/esr.v1n2p122.
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Preston, James C.1, Noel A. Newell2. "ABSTRACT: The origin and alteration of hydrocarbons in the Northern Bonaparte Basin, offshore Northern Australia." AAPG Bulletin 84 (2000). http://dx.doi.org/10.1306/a9674c6a-1738-11d7-8645000102c1865d.
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