Academic literature on the topic 'Northern Bonaparte Basin'

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.

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).

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.

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.

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.

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.

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.

Thesis (B. Sc.(Hons.))--University of Adelaide, National Centre for Petroleum Geology and Geophysics, 1996.
Volume 2 is boxed and consists of a large folded chart. Includes bibliographical references.

[Truncated abstract] The Northern Bonaparte Basin and adjacent Darwin Shelf form part of a major petroleum province on the northwestern margin of Australia. The middle to Late Cretaceous Bathurst Island Group consists of siliciclastic and pelagic carbonate strata that form the regional seal to underlying Upper Jurassic and Lower Cretaceous reservoir sandstones. The Bathurst Island Group has previously been subdivided into four stratigraphic sequences or ‘play intervals’ bound by regional disconformities in the Valanginian (KV horizon), Lower Aptian (KA horizon), upper Lower Cenomanian (KC horizon), Middle Campanian (KSC horizon), and at the CretaceousPaleocene boundary (T horizon). Correlation of these sedimentary packages and stratigraphic surfaces requires high-resolution calcareous microfossil biostratigraphy, while palaeobathymetric determinations based on benthonic foraminiferal assemblages are important for determining the subsidence history of the area and relative sea-level changes. This study presents the first detailed stratigraphic distributions, taxonomic lists and illustrations of foraminifera and calcareous nannofossils from the Bathurst Island Group of the Northern Bonaparte Basin and Darwin Shelf. A biostratigraphic framework has been constructed for the study area incorporating ‘standard’ (Tethyan) Cretaceous planktonic foraminiferal and calcareous nannofossil events where applicable, and integrating locally defined events where necessary. This framework allows Cretaceous strata to be correlated regionally across the study area and to the global chronostratigraphic scale. Correlation of the Northern Bonaparte Basin and Darwin Shelf strata to the Cretaceous Stages and international time scale is based on recent ties of nannofossil and foraminiferal events to macrofossil zones and palaeomagnetic polarity chrons at ratified and proposed Global Stratotype Sections and Points (GSSPs). Calcareous nannofossil events recorded in the study area that are critical for defining stage boundaries include the lowest occurrences of Prediscosphaera columnata, Micula decussata, Lithastrinus grillii, and Aspidolithus parcus parcus, and the highest occurrences of Helenea chiastia, Lithastrinus moratus, Aspidolithus parcus constrictus, and Eiffellithus eximius. Important planktonic foraminiferal events for correlation include the lowest occurrences of Rotalipora gr. globotruncanoides, and Dicarinella asymetrica, and the highest occurrences of Planomalina buxtorfi, Rotalipora cushmani, and Dicarinella asymetrica. During the middle to Late Cretaceous the Northern Bonaparte Basin and Darwin Shelf occupied mid-high palaeolatitudes between 35ºS to 45ºS. These palaeolatitudes are reflected in the transitional character of the planktonic microfossil assemblages, which combine elements of the low-latitude, warm-water Tethyan Province to the north and the cool-water high-latitude Austral Province to the south. ‘Standard’ Tethyan zonations are most applicable for uppermost AlbianMiddle Campanian strata because equator-to-pole temperature gradients were weakly developed, and global climate was warm and equable during this interval. These conditions resulted in broad latitudinal distributions for Tethyan marker species, and consequently most UC calcareous nannofossil zones and European-Mediterranean planktonic foraminiferal zones are recognised. In contrast, the EarlyLate Albian and the late Middle CampanianMaastrichtian were intervals of greater bioprovinciality and stronger palaeotemperature gradients. In these intervals application of the Tethyan zonations is more difficult, and a number of the Tethyan biostratigraphic markers are absent from the study area (e.g. Ticinella species in the Albian and Radotruncana calcarata in the Late Campanian). Cretaceous palaeobathymetric reconstruction of the study area is based on comparison of the foraminiferal assemblages with those of previous Cretaceous palaeobathymetric studies. Marginal marine assemblages consist solely of low diversity siliceous agglutinated foraminifera (e.g. Trochammina). Inner and middle neritic water depths (0-100 m) contain rare to common planktonic foraminifera (mainly globigerine forms), robertinids (e.g. Epistomina), siliceous agglutinates, lagenids, buliminids (e.g. Neobulimina), and rotaliids. The outer neritic zone (100-200 m water depth) contains abundant planktonic foraminifera (keeled and globigerine), calcareous agglutinates (e.g. Dorothia), and diverse lagenids, buliminids, and rotaliids. Upper-middle bathyal water depths (200-1000 m) are characterised by abundant planktonic foraminifera, common siliceous agglutinated taxa (e.g. Glomospira), rare to common Osangularia, and globular species of Gyroidinoides, Pullenia, and Paralabamina.