Vulcan Sub-basin Research Articles

Analysis of Petrophysical Parameter on Shaly Sand Reservoir by Comparing Conventional Method and Shaly Sand Method in Vulcan Subbasin, Northwest Australia

Vulcan Subbasin is an area with a lot of oil and gas exploration where is located in the Bonaparte Basin, Northwest Australia. There is some formation identified as sandstone reservoir with clay content which is usually called shaly sand based on the screening between resistivity log and density log. Clay content caused lower resistivity log readings so the shaly sand reservoir is considered as non-reservoir. To overcome this, a method besides the conventional method was applied to analyze the petrophysical parameters of shaly sand reservoir, it was shaly sand method. Petrophysical analysis is an analysis of rock physical parameters such as shale volume, porosity, and water saturation based on well log data. In this study, petrophysical analysis was carried out in the Vulcan Subbasin using 35 well log data, including gamma ray log, resistivity log, neutron log, and density log for the conventional method and shaly sand method involved Stieber equation and Thomas Stieber plot. The results obtained from this study are the comparison of petrophysical parameter values and pay summary between the conventional method and the shaly sand method, also its relation to the shale distribution type. By applying the shaly sand method, the average shale volume has decreased, the average porosity has increased, the average water saturation has increased, the average net to gross has increased, the average net thickness has increased, and the average net pay has increased. Changes in the average value were caused by laminated-dispersed shale distribution type which is influenced by diagenesis and the depositional environment of the formation.

Quantifying exhumation using compaction and vitrinite reflectance in the Southern Bonaparte Basin, North West Shelf, Australia

Rock fracture during exhumation can enhance hydrocarbon fluid migration through reservoir rocks but can also breach seal rocks and cause fluids to escape. Therefore, understanding the spatial and temporal distribution of exhumation within sedimentary basins can help optimize oil and gas systems targeting and help identify potential subsurface locations for CO2 storage. Structural, tectonic and stratigraphic studies suggest that the hydrocarbon-rich Bonaparte Basin of the Australian North West Shelf has undergone multiple episodes of exhumation since the Palaeozoic. However, the distribution of this exhumation and its correlation with the distribution of petroleum systems in the basin is not well established. In this work, we combine compaction and vitrinite reflectance analysis to estimate exhumation on selected boreholes, then model its temporal and spatial distribution within the southern Bonaparte Basin. The compaction and vitrinite reflectance analysis use porosity and paleotemperature data of sediments, respectively, to estimate the maximum burial depth of sediments and subsequently calculate exhumation. Our results indicate that the southern Bonaparte Basin went through an average of ∼1.9 km total exhumation from the Permian to the present with a maximum exhumation of ∼2.7 km in the Londonderry High. Vitrinite reflectance data suggest that sediments in the Ashmore Platform were subjected to heat from magmatic events. From the Permian to the Late Triassic, exhumation was confined within the Ashmore Platform (∼0.8 km) and Vulcan Sub-basin. Then from the Late Triassic to the present, exhumation shifted eastwards towards the Londonderry High and Petrel Sub-basin. The results show that the latest Cretaceous and Cenozoic tectonic events produced around 0.8 km of exhumation in the Londonderry High and 0.3 km in the Ashmore Platform. This exhumation likely impeded the formation of Mesozoic petroleum systems in the central Bonaparte Basin while preserving the older Paleozoic system whose hydrocarbons migrated towards traps in around the Londonderry High. Our results indicate porosity values between 20% and 25% for the Vulcan Sub-basin and the Ashmore Platform with little exhumation making them potential areas for CCS.

Elemental composition of dispersed vitrinite in marine Jurassic source rocks of the Vulcan Sub-basin, Australia: Implications for vitrinite reflectance suppression

The vast majority of petroleum exploration wells in the offshore basins of Western Australia bottom in Jurassic sedimentary rocks for which vitrinite reflectance results commonly appear to be anomalously low. Light element electron probe microanalysis (EPMA) of dispersed vitrinites in five samples of marine, Jurassic, potential source rocks from three petroleum exploration wells drilled in the Vulcan Sub-basin, Timor Sea, enables better understandings of this problem. The elemental abundance of carbon, oxygen, nitrogen, sulphur, aluminium and silicon were measured, and hydrogen content was calculated by difference. The EPMA method was validated by comparison of microprobe results for vitrinite in an Australian, Permian, medium volatile bituminous coal, with those determined by conventional elemental analysis according to the Australian ‘standard method’. Results on the Vulcan Sub-basin samples show that hydrogen contents of the Jurassic vitrinites are anomalously high, plotting as ‘type II’ ‘oil prone’ organic matter, on a van Krevelen-type diagram (atomic H/C vs O/C), a region normally associated with liptinite macerals. Implications of the EPMA results were investigated using fluorescence alteration of multiple macerals (FAMM) analyses, a laser-based technique that enables determination of the degree of vitrinite reflectance suppression. The elemental analyses, together with associated optical microscopy, confirm the occurrence of vitrinite having suppressed reflectance in marine Jurassic rocks of the Vulcan Sub-basin, which has important consequences for petroleum exploration if using vitrinite reflectance data in modelling thermal maturation and petroleum generation. In addition, the perhydrous vitrinites themselves may have considerably more petroleum generation potential than previously thought.

Salt in the Vulcan sub-basin, NW Australia: observations from high-quality 3D seismic data and implications for palaeogeography

The Vulcan sub-basin is one of the few places in Australia where tectonic features (i.e. diapirs) associated with a mobile substrate can be found. In this presentation one of these features, the Paqualin diapir, and its environs will be described and discussed using the new regional NOVAR MC3D prestack depth migrated seismic dataset. The extent of the NOVAR MC3D seismic dataset makes it possible, for the first time, to integrate the observation of c. 600m of interbedded halite and anhydrite in the Paqualin-1 well, local fault geometries indicative of the movement of a mobile layer and regional tectonic features consistent with the presence of a mobile substrate. In this presentation the observations will be integrated with global analogues, regional palaeogeographic interpretations to refine models for the origin and spatiotemporal distribution of mobile layers in the Vulcan sub-basin.

Integrated Design Assessment Optimizes Layout and Engineering of Timor Gas Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19391, “An Integration of Geology, Geohazards, Geophysics, and Geotechnics for Pre-FEED Site Layout and Engineering Design of an Offshore Gas Field in the Timor Sea,” by Pattarapong Chullabrahm, Korn Saranyasoontorn, and Maythus Svasti-Xuto, PTTEP, et al., prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. The complete paper presents an integration of geology, geohazards, geophysics, and geotechnical assessments for a design of an offshore gas production facility and an associated export pipeline. The gas field described in the paper is off the northwest coast of Australia in the Timor Sea at a water depth of approximately 130 m. Introduction The gas field is envisioned to include a subsea production system, a fixed central processing platform (CPP) for separation and treatment, and a floating storage and offloading (FSO) vessel for condensate. Processed gas will be transported by a new gas export pipeline (GEP) that connects the CPP with a tie-in point on an existing export pipeline. A schematic of the infield facilities is shown in Fig. 1. Regional Geology and Geohazards To understand the seabed geology, the associated geohazards, and their effect on the proposed development, an initial desktop study into the seabed and shallow subsurface geology was undertaken. The main output from the desktop study was a preliminary geological ground model that helped determine the most suitable geophysical and geotechnical survey techniques to obtain accurate information needed to model the ground conditions further in preparation for engineering design. Regional Geology. The field development lies within the Vulcan sub-basin of the Bonaparte Basin, which contains sediments to a depth of 15 km. The sub-basin is a southwest/northeast-trending extensional depocenter comprised of a series of fault bound horsts, grabens, and terraces and is active tectonically. The resulting deformation is dominated by extensional fault structures (e.g., normal faults). During the late Pliocene epoch and early Quaternary period, sedimentation of the Bonaparte Basin was dominated by shallow water carbonates in a tropical ramp setting, including the development of isolated, intrashelf carbonate buildups that are often referred to as pinnacles or shoals. Avoiding these steep-sided shoals is an objective in selecting a preferred pipeline route; however, acknowledgement of other, unmapped seabed features such as terraces, banks, and valleys must also be considered. The base-case GEP route, called the Southern Bypass route, has a length of approximately 347 km and is proposed to link the field to the tie-in point. A more-direct route between the field and the tie-in point could shorten this route significantly (up to 70 km). This provides an opportunity for a significant expense savings for GEP construction but only if a technically feasible route through a major subsea canyon—the Lambert Shelf Valley (LSV)—can be found. This canyon is up to 100 m deeper than the surrounding seabed and has steep-sided slopes ranging between 30 and 50°. Geohazards. The LSV has the potential to influence the proposed seabed infrastructure. The geohazards associated with this canyon have a direct effect on the GEP. The following geohazards required investigation: Slope instability Turbidity currents Hard ground Mobile bed forms Pockmarks and shallow gas Soft soils Liquefaction

PESA Australian exploration review 2019

Australia has continued its recent run of exploration success by yielding a series of impressive discoveries in 2019, despite a contraction in exploration activity. In 2019, Australian explorers were rewarded with six conventional onshore discoveries and three offshore discoveries, while only drilling 20 exploration wells. The exploration drilling highlights were the discoveries in the Vulcan Sub-basin (Bratwurst and Orchid) and the North Perth Basin (Beharra Springs Deep and West Erregulla). 2019 also saw successful appraisal drilling on the Dorado and Corvus discoveries as well as renewed exploration efforts in the Beetaloo Sub-basin unconventional plays. The exploration farm-in deals of note were Santos farming into Armour’s South Nicholson Basin acreage and Conoco farming into 3D Oil’s Otway Basin acreage. Australia is set for an exciting year of exploration with further drilling planned in the North Perth Basin and other high impact exploration wells on the North West Shelf. In a positive sign for future exploration, 13 new offshore permits were awarded with committed work programs or cash bids totalling AU$223 million. This is the first uptick in offshore permit awards since 2010.

A geological pressure model for the Browse Basin and the southern Vulcan Sub-Basin, NWS Australia

The results presented in this paper draws on a regional pressure analysis of the offshore areas of the Browse Basin and the southern Vulcan Sub-Basin.The presented study focuses on Late Permian to ...

Role of deep-sourced fluids on the initiation and growth of isolated carbonate build-ups

The relative role of the various mechanisms responsible for the formation of isolated carbonate build-ups occurring on the seafloor along continental margins is still uncertain. The interpretation of an extensive seismic dataset in the central Vulcan Sub-basin (NW Australia) allowed to evaluate the possible role of migration and seepage of deep-sourced fluids during the initial growth of isolated carbonate build-ups. The Neogene tectonic activity along the margin generated extensional fault systems that commonly displaced the seafloor, thus apparently creating a substratum to the initiation of various carbonate build-ups during the Pleistocene.

Marine seismic triple source case studies from the Asia–Pacific region

There has been a rapid uptake on the idea of using multiple sources in marine seismic data acquisition because of the additional flexibility the technique offers in survey design based not only on geophysical quality, but also for health, safety and environment (HSE) and efficiency. This paper examines three case studies conducted in Australia and Indonesia covering aspects of the advantages. An important consideration in survey design is efficiency, and multisource designs improve this by allowing wider spreads to be towed, so more data is acquired per vessel pass. In turn, HSE exposure is decreased by reducing survey times and by reducing the amount of in-sea equipment. The Trepang Survey carried out for Ophir Energy offshore West Papua was designed for efficiency, but the HSE aspect came to the fore when large amounts of floating debris (several hundred tree trunks) were found in the path of the survey vessel. By reducing the acquisition time, the risk the timber posed was minimised. The Cygnus survey in the Vulcan sub-basin is an example of where the multisource technique increased quality by improving the cross-line resolution and increasing fold without decreasing efficiency. Bianchi and Hockey were two surveys in the same area and, because the surveys were small, they were inefficient to acquire because much of the time was spent on line changes. The operator Quadrant used the fact that a triple-source design would allow for symmetrical bins to be acquired and joined the two small surveys together: effectively two sets of line change times were turned into acquisition time.

Salt diapir reactivation and normal faulting in an oblique extensional system, Vulcan Sub-basin, NW Australia

Oblique extension and salt diapirism have their own distinct mechanisms that control the geometry and kinematics of structures. In this study, we document a geological phenomenon from the Vulcan Sub-basin in NW Australia that combines these processes: a salt diapir reactivated in an oblique extensional system. Detailed structural analysis of this natural example, with a focus on normal fault systems, allows characterization of the oblique extensional system and investigation of how the pre-existing structural fabrics and salt diapir control deformation, and interact with each other under oblique extension. After comparison with forward modelling results and using constraints from geological evidence, our fault strike analysis indicates that the Neogene flexural extension orientation in the oblique extensional system is around 347°, revealing a perpendicular relationship between extension direction and fault strikes from the deformation zone. The salt diapir, reactivated during Neogene extension, strongly influences local structure in the oblique extensional system by altering fault strikes, stepping patterns, deformation zone width and fault density, indicative of a ‘stress–strain concentration’ effect of the salt diapir owing to its extremely low strength. These results provide valuable insights into the understanding of oblique extensional systems, the geomechanical role of salt during extension, and the Neogene tectonic evolution of NW Australia. Supplementary material : Dominant seismic frequency analysis, uninterpreted seismic profiles, additional structural and isochron maps, a 3D view of fault systems, and original measurements of the fault system are available at http://doi.org/10.6084/m9.figshare.c.3148321 .

Structural style in a young flexure-induced oblique extensional system, north-western Bonaparte Basin, Australia

In the north-western Bonaparte Basin (North West Shelf of Australia) Neogene to Recent flexure-induced extension superimposed obliquely over the Mesozoic rift structures. Thus, the area offers a good opportunity to investigate the dynamics and architecture of oblique extension fault systems. Analysis of basin-scale 2D and 3D seismic data along the Vulcan sub-basin shows that Neogene deformation produced a new set of extensional, en échelon faults, at places accompanied by the reactivation of the Mesozoic faults. The pre-existing Mesozoic structures strongly control the distribution of the Neogene-Recent deformation, both at regional and local scales. Main controls on the Neogene-Recent fault style, density and segmentation/linkage include: (1) the orientation of the underlying Mesozoic structures, (2) the obliqueness of the younger extension relative to the rift-inherited faults, and (3) the proximity to the Timor Trough. Three types of vertical relationships have been observed between Mesozoic and Neogene-Recent faults. Hard linkages seems to develop when both fault systems trend parallel, therefore increasing risks for trap integrity. It is suggested that the orientation of maximum horizontal stress (SHmax) relative to the Mesozoic faults, forming hydrocarbon traps, is critical for their potential seal/leak behaviour. Stratigraphic growth across the faults indicates that main fault activity occurred during the Plio-Pleistocene, which corresponds to the timing of tectonic loading on Timor Island and the development of lithospheric flexure. Synchronism of normal faulting with flexural bending suggests that extensional deformation on the descending Australian margin accompanied the formation of the Timor Trough.

Geochemical characterisation and predicted bulk chemical properties of petroleum generated from Jurassic and Cretaceous source rocks in the Vulcan Sub-basin, Bonaparte Basin, North West Shelf of Australia

A geochemical investigation was carried out on 61 core and cuttings samples from selected Mesozoic source rocks in the offshore Vulcan Sub-basin of the Bonaparte Basin, Australia. Rock-Eval pyrolysis data reveal that these source rock samples contain Type II, Type II/III and Type III kerogen, with variable potential for gas and liquid hydrocarbon generation. In the Vulcan Sub-basin, samples from the marine Lower Cretaceous Echuca Shoals Formation and Upper Jurassic–Lower Cretaceous upper Vulcan Formation have fair to moderate quality organic matter. The samples from these two formations are marginally mature, but where burial is sufficient to attain higher maturity, as in the Nancar Trough to the north of the Vulcan Sub-basin, these formations have potential to be additional sources for marine oil. Samples from the marine Middle–Upper Jurassic lower Vulcan and fluvio-deltaic Lower–Middle Jurassic Plover formations contain good to very good quality organic matter. Mixed oil- and gas-prone Type II/III kerogens in the lower Vulcan and Plover formations are mature for hydrocarbon generation and can be, depending on their location and depositional environment, source rocks for oil with terrigenous and/or marine geochemical signatures. Assuming a constant geological heating rate of 3.3°C/Ma, the onset of hydrocarbon generation (10% transformation ratio (TR)) from the Echuca Shoals and upper Vulcan formations occurs at 120°C compared to 120–160°C for the lower Vulcan and Plover formations. Generally, low gas/oil ratios (GORs), comparable to those measured in the natural accumulations, were reproduced at <50% TR for both shaley coals and shales of the lower Vulcan and Plover formations. Shales of the Echuca Shoals, Vulcan and Plover formations generate paraffinic–naphthenic–aromatic (PNA) oils. Compared to the shale samples, shaley coals from the Plover Formation are kinetically more refractory and their high hydrogen indices (>400mgHC/gTOC) suggest the potential for high-wax PNA oil generation, in addition to wet gas.

The Zeppelin 3D rocks the Vulcan sub-basin

In January 2012, the storm clouds of Tropical Cyclone Iggy were gathering over the Timor Sea as production of the 500km2 Zeppelin 3D seismic survey began in the Vulcan sub-basin permits AC/P 50 and AC/P 51. Despite the high seas and the adoption of a conventional approach towards acquisition, the Zeppelin 3D appears to have set a new benchmark for seismic data quality in the Vulcan sub-basin, which has traditionally been considered a 'difficult data area'. Reprocessing some of the overlapping legacy Onnia 3D seismic suggests that much of the imaging improvement stems from a similar approach to multiple suppression to that used successfully in other 'difficult' Australian basins. The combination of shallow water demultiple, SRME and gap deconvolution followed by a stratigraphically-controlled velocity analysis appears to account for much of the improvement. Shooting in the (dominant) dip direction also appears to have helped although had we applied 3D SRME this might have been rendered less important. Using the reprocessed Onnia 3D and the Zeppelin 3D, our seismic interpreters have been able to develop a detailed structural model which underpins the distribution of fault bend fold related prospectivity. Enhanced resolution enables sequence stratigraphy to be delineated and low-stand fan leads identified. Seismic amplitudes also provide strong indications of reservoir sand geometries although porefill indications are expected to remain difficult to resolve. A series of structures within 3 separate plays (Triassic, Jurassic and Cretaceous) define a significant increase in the assessed oil and gas volumetric potential thereby justifying the early investment in seismic.

Browse to Bonaparte stratigraphic evaluation

After an initial 2010 stratigraphic, depositional environment and facies determination study of 75 wells in the Browse Basin, TGS has pushed this high-resolution project north into the Bonaparte Basin area. The study incorporates a further 165 wells located across the Ashmore Platform, Vulcan Sub-basin, Londonderry High, Malita and Calder Grabens, Sahul and Flamingo synclines, Laminara and Flamingo highs, Sahul Platform, Troubadour Terrace, and offshore Petrel Sub-basin areas. This multi-basin project has combined all the selected relevant public data into one interpretation study and is delivered in an integrated environment—wells are standardised and sequences interpreted. Once depositional environment and facies are allocated, multi-element maps are produced showing how the basin environments change through time and structural evolution. Stratigraphic interpretation has determined 37 sequences and 32 associated facies maps. Both Browse Basin (140,000 km2) and Bonaparte Basin (270,000 km2) are relatively less explored and at different ages in their exploration life-cycle. Both have proved to be oil and gas bearing across numerous different stratigraphic ages with a wide range of trapping and reservoir methods. This study aims to further aid North West Shelf exploration by delineating, among other facets, the presence or otherwise of rocks with reservoir and seal potential and by identifying structural elements such as the Petrel Sub-basin salt diapirs. This regional well data stratigraphic approach has been used across all the UK and Norway continental shelf hydrocarbon provinces. TGS sees the Australian North West Shelf as a province where this approach will further assist sub-surface understanding, and hence exploration success.

The Vesta oil and gas field, Vulcan Sub-basin, Timor Sea, Australia

The Vesta oil and gas field is located in the Swan Graben of the Vulcan Sub-basin. The structure consists of a number of separate tilted fault blocks located on a northwest-trending accommodation zone that forms a high, separating the southeast-dipping half-graben of the Swan Graben North from the northwest-dipping half-graben of the Swan Graben South. Drilled in 2005, Vesta–1 intersected a 17 m thick oil-bearing slope-fan sandstone of the Late Jurassic Elm Sandstone in the Lower Vulcan Formation. Drill-stem testing flowed oil and gas and indicated that the reservoir is normally pressured surrounded above and below by over-pressured claystone. In 2007, Vesta–2 intersected gas-bearing sandstone in a separate fault compartment. Understanding the geometry of the hydrocarbon-bearing Elm Sandstone reservoir has proved a challenge due to the very poor 3D seismic imaging, the variable sandstone thickness and quality, and abundant evidence of thin steeply-dipping injected sandstones above and below the main reservoir sandstone. The Lower Vulcan and Upper Vulcan Formation claystone provides the vertical and lateral seal for the Elm Sandstone. This thick seal has protected the Vesta oil and gas accumulations from the effects of the Late Tertiary tectonism, which had a significant effect on the integrity of the palaeo-oil filled closures on the adjacent Eclipse Trend. Three phases of hydrocarbon charge of the Vesta structure have been identified with oil-source correlation indicating a Lower Vulcan Formation marine source. The source interval intersected in Vesta–1 is presently post-mature, with oil and gas generation associated with high heat flow in the Late Jurassic. Expulsion of hydrocarbons from the source was most likely compaction-driven, with gas expulsion in the Early Cretaceous, and oil expulsion much later with increasing hydrocarbon saturation.

Hydrocarbon-Derived Carbonate Cements of Subsurface Origin in the Vulcan Sub-Basin, Timor Sea

Localized carbonate cementation occurs in the Eocene Grebe Sandstone of the Vulcan Sub-basin, Timor Sea, Australia. The cements have been previously interpreted as originating from microbial methane oxidation and sulfate reduction in a shallow subsurface environment and were related to hydrocarbon leakage. Here we reassess these localized carbonate cements in the Grebe Sandstone, and reported new findings. Petrography shows that there are two facies of sands in the Grebe Sandstone: (1) cemented, mostly fine-grained sands; and (2) loose, often coarse-grained sands. In addition, two types of carbonate matrix occur in the Grebe Sandstone: (1) spars to microspars in calcareous, fine-grained sandstones; and (2) micritic to microsparry matrix associated with limestone grains. Stable carbon isotopic values reveal that only the cements associated with sandstones were probably hydrocarbon-derived, and the resultant mineral is mainly calcite. Petrographic attributes and Mn(superscript +2) and Co(superscript +2) compositions of these cements differ significantly from those of modern cold-seep carbonates at or near the sea floor. Moreover, the hydrocarbon-derived carbonate mineralization only occurs in the fine-grained sands, not in the coarse-grained sands. In other word, the cementation was not only dependent on hydrocarbon leakage but also on the lithofacies of the host rock. We propose that the extent of hydrocarbon-related cementation alone cannot be used to evaluate the trap integrity as has been previously suggested.

Structural styles in the Papuan Fold Belt, Papua New Guinea: constraints from analogue modelling

Abstract Cross sections, seismic data and centrifuge analogue modelling reveal the structural styles in the oil-producing areas of the Papuan Fold Belt. They include inverted basement faults, detachment faults in the Jurassic section 1–2 km beneath the Neocomian Toro Sandstone reservoir, and tight, overturned folds in the reservoir sequence with stretched and boudinaged forelimbs, cut by break-thrusts. Additional features include highly variable thicknesses in the Cretaceous Ieru Formation, the regional seal sequence, including through-going detachments that isolate the overlying thick Miocene Darai Limestone. Centrifuge analogue modelling of intact, plane-layered strata determined that the mechanical stratigraphy and the thickness of weak beds above the lower décollement horizon exert the greatest control on the structural style. Large-offset thrust faults were only produced in models with pre-cut faults, generating early inversion and then large ramp anticlines, similar to those in the Kutubu Oilfield, which has reserves of &gt;350 million barrels. It is suggested that the Kutubu Oilfield trend was underlain by a large normal fault and that, by analogy with the Vulcan Sub-basin, oil-rich source rocks may be confined to the hanging wall or north side of this fault. Oil would have been generated and expelled during thin-skinned deformation.

The 2010 Australian offshore release for petroleum exploration

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).

The effect of source and maturity on the stable isotopic compositions of individual hydrocarbons in sediments and crude oils from the Vulcan Sub-basin, Timor Sea, Northern Australia

Recent work has demonstrated the effect of maturation on the stable hydrogen isotopic compositions (δD) of individual sedimentary hydrocarbons ( n-alkanes, pristane and phytane) in a series of marine source rocks from the Perth Basin (Western Australia). There was an enrichment in deuterium (D) in the hydrocarbons with increasing maturity, attributed to isotopic exchange associated with thermal maturation. An initial, large (≈115‰) biologically derived difference between the δD values of n-alkanes and isoprenoids gradually decreased as pristane and phytane became enriched in D, while the n-alkanes generally remained at constant isotopic composition. This work has now been extended to include a series of Late Jurassic sediments from the lower Vulcan Formation of the Vulcan Sub-basin (Timor Sea, Northern Australia), where the δD values of n-alkanes and isoprenoids show similar trends to those observed for the Perth Basin. The enrichment in D in isoprenoids correlates strongly with traditional maturity parameters and is shown to be related to the epimerisation of pristane and phytane. Pristane and phytane extracted from a post-mature Paqualin-1 sediment are significantly enriched in D relative to the n-alkanes, indicating that D enrichment persists at very high maturity, more so for regular isoprenoids than n-alkanes. This supports the notion that hydrogen (H/D) exchange causes the observed shift in δD values, and not free radical hydrogen transfer. A mechanism is proposed which can account for both H/D exchange and epimerisation of pristane and phytane in the sedimentary environment. Pristane is enriched in D relative to phytane throughout the Vulcan Sub-basin sequences, attributed to a lower relative algal input to the isoprenoids, and indicating that they exchange hydrogen at similar rates during maturation. Crude oils and condensates from the sub-basin were also analysed to evaluate their source and thermal maturity and the results complement previous molecular and stable carbon isotopic analysis. The δD values of n-alkanes and regular isoprenoids largely support the previous classification of Vulcan Sub–basin crude oils and condensates into two groups: Group A, having a marine source affinity and Group B, a terrigenous source affinity. Some oils and condensates are suggested to be a mixture of sources A and B, or A and other as yet unknown sources. Tenacious-1 crude oil (formerly a Group A oil) contains n-alkanes with more positive δD values than other Group A oils and is suggested to have been mixed with another source of more mature hydrocarbons. The Group A crude oils and condensates show an upward inflection in the n-alkane δD profile from n-C 11 to n-C 15, which is suggested to represent an addition of D-enriched lower molecular weight n-alkanes from a more mature wet gas/condensate to an initial oil charge. The small differences between the δD values of the n-alkanes and regular isoprenoids in the crude oils and condensates indicate that significant H/D exchange has taken place, implying that the samples were generated from mature source rocks.

HYDROCARBON ENTRAPMENT IN TRIASSIC TO LATE JURASSIC RESERVOIRS IN THE TIMOR SEA, AUSTRALIA—NEW INSIGHTS

Abundant oil-filled fluid inclusions at quartz overgrowth/detrital quartz boundaries and in fractures cutting quartz grains are often used as the primary evidence of palaeo-oil columns in Triassic to Late Jurassic reservoirs in numerous wells in the Timor Sea. Based on fluid inclusion analysis of sandstone reservoirs in present oil columns, a Grains containing Oil Inclusions (GOI) value of 5% has been used as a threshold with values &gt;5% indicating palaeo-oil columns. However, values Other indications of palaeo-oil columns are evident below and/or within GOI-defined palaeo-oil columns: good to excellent direct and cut fluorescence on cuttings and/or core, elevated resistivity and reservoir diagenesis. In the case of oil shows these hydrocarbon indications have been discounted as indicating focussed oil migration below a palaeo-oil–water contact rather than indicating a palaeo-oil column.While GOI provides valuable data to support the interpretations of palaeo-oil columns, it provides a picture at one instance in the hydrocarbon entrapment history and therefore should not be used in isolation. Other hydrocarbon indications are equally valid evidence of oil entrapment at one or more different times in the hydrocarbon entrapment history, and should be used with GOI data to provide a comprehensive picture of the evolution of a hydrocarbon trap. Case histories from wells Crux–1, in the northern Browse Basin, and Oliver–1 and Eclipse–2, in the Vulcan Sub-basin of the Timor Sea, illustrate how an integrated picture of hydrocarbon entrapment history can be developed and demonstrate that structures in the Timor Sea have undergone more than one phase of oil entrapment and leakage, with each oil phase potentially from a different oil source.