Petrel Sub-basin Research Articles

Review of the 2009 offshore petroleum exploration release areas

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.

A REAPPRAISAL OF THE CARBONIFEROUS STRATIGRAPHY AND THE PETROLEUM POTENTIAL OF THE SOUTHEASTERN BONAPARTE BASIN (PETREL SUB-BASIN), NORTHWESTERN AUSTRALIA

A revision of the latest Tournaisian to Namurian stratigraphy of the Petrel Sub-basin is proposed following the recognition of a series of megasequences based on seismic profiles, well logs and new palaeontological information. In late Tn3c, turbidites of the Waggon Creek facies were overlain by a seal, the Milligans Formation (redefined) during the Chadian (V1a, V1b). A basal Arundian (V2a) regression, possibly driven by tectonics, deposited the Yow Creek Formation (new name) with incised valley fills. A basal Asbian (V3a) regression, deposited coarser grained clastics and limestones, the Utting Calcarenite (V3a), forming a possible local reservoir facies overlain by a regional seal, Kingfisher Shale (new name). An intra-Asbian (V3b) regression followed, possibly glaciogenic and/or tectonically driven, with the deposition of the Tanmurra Formation, dominantly coarse clastics, during the Asbian, forming reservoir facies with some source potential. Following a basal Brigantian unconformity, the Sandbar Sandstone (new name) formed a restricted ?aeolian facies, a potential local reservoir. An intra-Brigantian unconformity was followed by deposition of the carbonate Sunbird Formation (new name), generally a tight shelf edge carbonate (V3c), near Lacrosse–1 and Sunbird–1. A major basal Pendleian sea-level fall, probably glaciogenic, with major channel incision and erosion, was followed by Arnsbergian clastics with G. maculosa, the Arco Formation (new name) with basinal shales in clinoforms. The latest Arco Formation (earliest Pennsylvanian) was followed by a Late Namurian regression, and deposition of the Aquitaine Formation (new name), consisting of fluvio-deltaic siliciclastics, with minor marine influence, large scale channelling, potentially good reservoirs, and a regional upper shaly seal. This sequence is unconformably overlain by the basal Kulshill Group, which marked the onset of major Gondwanan glaciation.

Seismic Migration in Near-Vertical and Wide-Angle Reflection and Refraction Studies: Towards a Unified Approach

Conventional deep reflection profiles usually image upper to middle crustal levels quite well. The ability of this methodology toimage the lower crust and transition to the mantle is often limited. We have made a step forward in developing a methodology forprocessing, interpreting and presenting near-vertical reflection, wide-angle reflection and refraction seismic data and velocityinformation derived from the three data sets within a unifiedapproach. The key elements of this approach are: pre-stack depthmigration of wide-angle reflection and refraction data; wave fieldanalysis of the refraction and wide-angle reflection data prior toand after depth migration; and unified analysis of seismic velocityinformation. For the finite-difference continuation of the wavefield we use a special oblique time-spatial grid. The time fieldcalculation is based upon a finite-difference approximation of theeikonal equation and the grid used in this task is curvilinear. Thecoordinate lines are based on ray paths and wave fronts in themedium. Such a grid is particularly effective at large offsets. Theoverall configuration of the oblique grid used for the downwardcontinuation of the time field is determined for the domain wherethe solution of the eikonal equation exists. The initial conditionsare defined by the recorded travel times. We demonstrate how thisapproach works on an example from the Petrel sub-basin, Australian North West Shelf, where conventional CDP (nearverticalreflection) data were supplemented by the wide-anglereflection and refraction data recorded by ocean-bottomseismographs. Depth migration of refraction/wide-angle seismicdata presents them in the same style as the conventional reflectiondata thus radically enhancing the seismic image of the lower crustwhere the CDP data lacks detail. Unlike previous studies in depthmigration of refraction/wide-angle data did, we have dealt withrefracting horizons in the deep crust. We have created seismicimages for three (conventionally only one image is formed)refractors including the Moho discontinuity. To achieve this, wehave processed the data recorded in the time-spatial zones wheredifferent seismic events interfere.

Ocean-bottom seismograph and conventional reflection surveys in the Petrel Sub-Basin: an integrated seismic study

The ocean-bottom seismograph (OBS) data recorded in the Petrel sub-basin with a 100 m shot interval were not spatially aliased with respect to prevailing velocities and frequencies. This enabled the utilisation of digital seismic processing techniques not normally used to process refraction and wide-angle data. F-k filtering was used to enhance signal/noise ratio at large (tens of km) offsets. Depth migration of wide-angle reflections utilised the interpretation of signal dynamics to supplement the travel times-based interpretation conventionally used for refraction and wide-angle data. The project provided valuable velocity information to better constrain the depth conversion of AGSO’s regional deep reflection profiles in the region. Prominent reflectivity seen in the conventional reflection data at two-way times (TWT) greater than 4 s does not correspond to any velocity increase imaged by refraction/wide-angle techniques. On the other hand, the most significant velocity increase, which occurs at the Moho, does not produce high-amplitude near-vertical reflections. Interval velocities estimated from the conventional reflection data at TWT greater than 2 sec appear to be up to 1 km/s lower than those derived from the OBS data. If the former are used to depth convert reflection data, then depth to seismic boundaries in the centre of the basin at TWT 6-9 s would be underestimated by up to 2 km. Seismic reflection and refraction techniques are complementary to each other, and both are required to fully interpret the data.

The role of small-scale extensional faulting in the evolution of basin geometries. An example from the late Palaeozoic Petrel Sub-basin, northwest Australia

During continental extension, the kinematic collapse of the hangingwall of major normal faults and the subsequent isostatic response imposes a strong control on the evolving basin geometry. The interaction of the flexural wavelength. and the magnitude and location of faults may allow the development of basin geometries which deviate from a classic half-graben style, particularly if some of this deformation is below the scale of observation (commonly seismic reflection data). In particular the development of a lateral partitioning between large- and small-scale faults within a basin may exert a significant control on the resulting basin geometry. Using the Petrel Sub-basin in northwest Australia as an example, it is demonstrated that an extensional basin geometry consisting of a classic half-graben can be overprinted by a significant ‘sag’ geometry which can be related to the lateral offset of sub-resolution faulting. This lateral partitioning and resulting basin geometry may also have an application to other extensional basins, particularly if a mechanism is present to allow this partitioning of fault styles to develop. In the Petrel Sub-basin this has been related to the presence of older basement features of the Halls Creek Mobile Zone beneath the axis of the basin. However, a comparison with physical models also suggests that this may be applicable to basins formed by oblique rifting (a component of which may also be present within the Petrel Sub-basin), particularly if this is imposed upon a weak zone or suture within the upper mantle.

Abstract: Petroleum Potential and Results of Exploration in the Offshore Petrel Sub-Basin, Bonaparte Basin, Northwestern Australia

Abstract: Petroleum Potential and Results of Exploration in the Offshore Petrel Sub-Basin, Bonaparte Basin, Northwestern Australia

GEOCHEMICAL CHARACTERISTICS OF PALAEOZOIC PETROLEUM SYSTEMS IN NORTHWESTERN AUSTRALIA

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.

SALT MIGRATION AND SUBTLE STRUCTURES: MODELLING OF THE PETREL SUB-BASIN, NORTHWEST AUSTRALIA.

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

Definition of Basin Phases in the Petrel Sub-basin (Australia): Implications for the Development of Palaeozoic Petroleum Systems: ABSTRACT

An study of the Petrel Sub-basin (Bonaparte Basin) on Australia`s northwest margin has identified seven main phases of basin development spanning the Early Cambrian to Tertiary. Each phase was initiated and terminated by distinct, primarily tectonic events that have controlled the structural and stratigraphic evolution of the basin and the development of petroleum systems. These phases include periods of major extension (Early Cambrian, Middle Devonian to early Carboniferous) and compression (Early Devonian, mid-Triassic), as well as rapid and slow subsidence phases in the Early to Late Carboniferous and Late Carboniferous to Triassic, respectively. Basin inversion in the mid-Triassic has been critical in controlling the development of broad anticlinal features that presently reservoir the large, but as yet undeveloped gas/condensate fields Petrel and Tern. An earlier period of minor compression during the late Carboniferous initiated limited movement of Paleozoic salt within the deeper basin, forming salt-cored, low amplitude anticlines in the predominantly carbonate Tanmurra Formation, a play which remains untested. In the southern Petrel Sub-basin, early phases of hydrocarbon generation and fluid migration associated with salt movement are poorly understood. Preliminary results of geochemical studies indicate that there are at least two oil families in Devonian and Carboniferous reservoirs. This suggestsmore » multiple source intervals within the deeper flanks of the basin, thus the understanding of sedimentation during early basin phases may be critical in evaluating petroleum systems.« less

PETROLEUM SYSTEMS OF THE PETREL SUB-BASIN-AN INTEGRATED APPROACH TO BASIN ANALYSIS AND IDENTIFICATION OF HYDROCARBON EXPLORATION OPPORTUNITIES

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.

THE STRUCTURAL ARCHITECTURE OF THE TIMOR SEA, NORTH-WESTERN AUSTRALIA: IMPLICATIONS FOR BASIN DEVELOPMENT AND HYDROCARBON EXPLORATION

The initial rifting in the Timor Sea, north-western Australia, took place in the Late Devonian to Early Carboniferous, with the development of the NWtrending Petrel Sub-basin. This rift system was compartmentalised by NE-trending accommodation zones which divided the sub-basin into discrete segments. In each segment, a lower plate rift margin, characterised by large displacement, low angle extensional faults, lay opposite an upper plate, or ramp, rift margin, characterised by small displacement, high angle flexural faults. Switching in the 'polarity' of the rift system took place across major, NE-trending accommodation zones.Part of this rift system was overprinted in the Late Carboniferous to Early Permian by the Westralian Super-Basin rift system, which developed on a NE trend, orthogonal to that of the underlying Petrel Sub-basin. The entire Vulcan Sub-basin and Sahul Platform region developed as part of an upper plate rift margin, with the Vulcan Sub-basin probably forming initially as a small flexural feature in the inboard part of the upper plate rift margin. The rift margin consisted of a linked array of NW-trending accommodation zones and NE-trending normal faults; pre-existing, NW-, NE- and NS-trending ?Proterozoic fracture systems controlled, at least to some extent, the geometry of the rift system that developed. The island of Timor probably developed as a major intra-rift high, or possibly a marginal plateaux, at this time. Thermal subsidence phase sedimentation continued until the Late Triassic, resulting in the deposition of 10 to perhaps 14 km of relatively unstructured sediments.Three major reactivation events affected the Timor Sea during the Mesozoic. These were: compression in the Late Triassic to Early Jurassic, extension in the Late Callovian to Early Oxfordian (late Middle to early Late Jurassic) and compression in the Tithonian/Berriasian (Late Jurassic/Early Cretaceous). These events all reactivated the pre-existing ?Proterozoic/ Petrel Sub-basin/Westralian Super-Basin structural architecture in a variety of ways. In the Petrel Sub-basin, reactivation was localised almost exclusively over the lower plate rift margins, leading to the formation of anticlines and ultimately, salt diapirism.In the Vulcan Sub-basin, all of the significant hydrocarbon discoveries appear to be preferentially located either along, or at the intersection of, NW- and NS-trending fault sets with the NE/ENE-trending grain. This is probably because the intersections of these Proterozoic/Late Carboniferous-Early Permian fault sets respond in a particularly complex fashion to the varying Mesozoic stress directions. In a qualitative fashion, this observation does provide a number of largely untested exploration 'fairways' within the Vulcan Sub-basin.

The Tern Gas Field case history

The Tern Gas Field is located 110 km offshore in the Petrel Sub-Basin of the Bonaparte Basin in northern Australia. The Tern structure was discovered in 1966 when the first seismic survey was recorded in the area. Subsequently, gas was encountered in the Late Permian sandstones of the Hyland Bay Formation when Tern 1 was drilled in 1971. Further seismic studies detailed the Tern structure and Tern 2 located 10 km south-east of the discovery well confirmed the existence of the gas field in 1982. The presence of an amplitude anomaly in the seismic response (bright spot) was recognised when a modern seismic survey was recorded in 1980. Since then, different seismic projects have enabled an accurate mapping of the field whilst the significance of the anomaly was investigated.