bluuebunny/crossref_metadata_2025 huggingface dataset:
EXPLORING THE POTENTIAL FOR OIL GENERATION, MIGRATION AND ACCUMULATION IN CAPE SORELL–1, SORELL BASIN, OFFSHORE WEST TASMANIA
Authors: Boreham C.J. , Blevin J.E. , Duddy I. , Newman J. , Liu K. , Middleton H. M , Macphail M.K. , Cook A.C.
Published: August 2017

Given the underexplored nature of the Sorell Basin, offshore Tasmania, the reported presence of oil stains and shows in the Late Cretaceous sequence below 3,000 m in Cape Sorell–1 is seen as encouraging evidence of an effective petroleum system. To investigate the significance of these shows, an integrated palynological, geochemical and burial history analysis of Cape Sorell–1 has been undertaken. New data have been collected on palynology, potential source rocks (biomarker and chemical kinetics), oil migration indicators (quantitative grain fluorescence—QGF, and grains–with–oil– inclusions—GOI) and thermal history parameters (vitrinite reflectance—VR, vitrinite–inertinite reflectance and fluorescence—VRF® and apatite fission track analysis—AFTA®). A synthesis of these analyses has resulted in a model that suggests that the terrestrial organic–rich potential source rocks in Cape Sorell–1 are very labile for hydrocarbon generation and are presently at the initial phase of oil generation. The model also indicates that increasing hydrocarbon generation with time reflects a progressive increase in temperature reaching maximum temperatures at the present–day. According to the model, accelerated rate of oil generation from the Maastrichtian potential source rock interval at ~3,200 m in the lower Sherbrook Group Equivalent occurred at ~48 Ma and is in response to the maximum burial heating rate in the Early Eocene, during rapid deposition of the thick Wangerrip Group Equivalent. This heating event may have been related to gateway opening along the Otway coast and west Tasmanian margin. Although there was a declining heating rate since the Early Eocene, gas and oil may continue to be generated to the present–day at Cape Sorell–1.The low content of mobile oil below sealing facies higher in the section negates a pervasive oil migration phase sourced down–dip from the basin centre, or from older sedimentary sequences below TD in Cape Sorell–1. However, the possibility that Cape Sorell–1 is in a migration shadow cannot be excluded. The restricted areal extent of the depocentre associated with Cape Sorell–1, together with thin, isolated potential source beds at the well site, would indicate the major risk for hydrocarbon occurrences in the local region is limited source rock volume. However, seismic evidence suggests the possible presence of similar facies within the deeper syn–rift succession below TD at Cape Sorell–1. The labile nature of the organic matter would support oil generation and migration at maturities lower and depths shallower than traditionally viewed. This work provides evidence to support a possible oil play from terrestrial source rocks in the Sorell Basin, and may also provide useful insights into recent large offshore gas discoveries to the north in the adjacent Otway Basin.
THE JOHN BROOKES GAS DISCOVERY—AN EVOLVING STORY
Authors: Auld K. , Thomas B. , Goodall J. , Benson J.
Published: August 2017

John Brookes–1 was drilled as part of a work commitment for the WA-214-P Joint Venture in 1998 and discovered an 85 m gross dry gas column. The objective of the well was to test a structural closure at the base of the Muderong Shale regional seal on the Tryal Rocks anticline, up-dip from Tryal Rocks–1, drilled in 1970. Tryal Rocks–1, the 31st offshore well to be drilled within the Carnarvon Basin, WA, was initially considered a dry hole. However, a review of the well data in 1997–98 suggested that Tryal Rocks–1 might contain a hydrocarbon column. The mapping of the structure using initially 2D seismic data acquired post Tryal Rocks–1, then 3D data, indicated that Tryal Rocks–1 was drilled within closure, but off crest, and that significant closure existed up-dip. The John Brookes–1 location was selected to test this updip potential. The John Brookes–1 discovery confirmed the validity of the structural mapping. However, the unexpected nature of the reservoir, interpreted as a well developed turbiditic channel of Birdrong Sandstone age, changed the emphasis from purely structural to a play with structural/stratigraphic potential. An amalgamated turbidite complex model was invoked which infers that the John Brookes–1 reservoir represents a confined channel system cut into the underlying substrate. This model explains the results to date, with the John Brookes–1 gas reservoir being in direct continuity with the sandstones at Tryal Rocks–1. A review of the 3D seismic data across the field and seismic modelling support the stratigraphic model developed from the palynological interpretation.
DRILL CUTTINGS ANALYSIS—A NEW APPROACH TO RESERVOIR DESCRIPTION AND CHARACTERISATION; EXAMPLES FROM THE COOPER BASIN, AUSTRALIA
Authors: Tiainen S. , King H. , Cubitt C. , Karalaus E. , Prater T. , Willis B.
Published: August 2017

In the absence of conventional core data, drill cuttings provide a continuous, independent and relatively inexpensive data source. Data collected from this often under-utilised resource can be used to determine permeability, provide information on diagenesis, stratigraphy and sedimentology, locate natural fractures, discriminate between genuinely poor reservoir and under performing assets and assist with petrophysical characterisation. Data can also be acquired in real time at the wellsite.Drill cuttings analysis or rock typing is a visual method of semi-quantitatively describing rock and pore characteristics from drill cuttings. More specifically it partitions rocks into distinct permeability groups according to their petrophysical properties as observed under high-powered stereo microscope. Based on the observation of key visible attributes, the rocks are assigned to one of six rock types equivalent to the following permeability ranges; 1A (>100mD ambient), 1B (10-100 md ambient), 1C (1-10 mD ambient), 1D (0.5- 1 mD ambient), type II (0.5-0.07 mD ambient) and type III (One of the major strengths of rock typing is it can be used to provide an estimate of in-situ permeabilities. As rock type categories are related to ambient permeability classes an algorithm has been developed to take these ambient range estimates to single in-situ values for permeability and then taking into consideration the lithology in the sample, calculates a permeability height (kh) for the interval. The algorithm corrects for overburden, klinkenberg and relative permeability effects.A comparison of kh derived from rock typing with kh derived from production and test data indicates a strong correlation between the two datasets. Results indicate that the kh sources are consistently similar and fall within one third of an order of magnitude of each other. As both of these data sources are independently derived it suggests both are realistic derivations of the actual kh of the reservoir interval. Consequently, once calibrated to all data sources, rock typing is considered capable of providing a robust estimate of in-situ kh for a specified reservoir interval.
SEISMIC EXPRESSION OF ABNORMAL GEO-PRESSURE IN THE BARROW SUB-BASIN
Authors: Urosevic M. , Fu Li-Yun , Dodds K.J.
Published: August 2017

Drilling uncertainties related to abnormal geopressure are common in the Barrow and Dampier Sub-basins of the North West Shelf. These uncertainties contribute to increased drilling risk and costs. There have been a number of published studies in this area which have been directed towards understanding the mechanisms and modelling of the expected pressures. These studies, however, have been in general isolated and have concentrated on non-seismic related methods. This paper provides an empirical analysis of the seismic response in an area with known variation of overpressure, and critically is integrated with a comprehensive research effort looking at aspects of overpressure from a laboratory, empirical and theoretical perspective.The study was conducted using data taken from permit WA-25-P (P25) in the Barrow Sub-basin. These data included 3D surface seismic and VSP, well logs, mud weight and pressure data from the wells. The results of a mineralogical analysis conducted on core samples and basin-wide geological modelling studies were also incorporated into the study. The Muderong Shale, which comprises the principal seal in the area and is believed to be overpressured was selected as the prime target for the analysis. Initially we assess the potential of existing methods, such as velocitybased methods, for remote prediction of excessive pore pressure in the area P25. This is extended to amplitude related effects involving an analysis of reflectivity in the presence of a velocity transition zone over the overpressured interval. Finally the relationship of well data, VSP and surface seismic derived attributes is described.The available data in the P25 area was sparse and consequently we could not rely on statistical based associations. Current industry methods that rely on a limited number of calibration points suggest that the application of either velocity or AVO based methods may produce unreliable predictions of pore pressure. Ambiguities in inferring overpressure introduced by a variable mineral composition of shales and the presence of a strong velocity gradient, which distorts the wave shape, reduces the reliability of these methods.A detailed analysis using VSP data acquired in a highly overpressured well was found to be crucial for understanding the response of various seismic attributes to changes in effective stress. This enabled us to propose a new qualitative, but efficient approach for remote prediction of overpressure, particularly suited for underexplored areas such as P25. The applicability of the method, which uses single and combined seismic sequence and trace multi-attributes to predict overpressured zones, is demonstrated with the Venture-Carey 3D data recorded in the Barrow Sub-basin.
DETECTING OVERPRESSURE USING POROSITY-BASED TECHNIQUES IN THE CARNARVON BASIN, AUSTRALIA
Authors: Ruth P.J. van , Hillis R.R. , Swarbrick R.E.
Published: August 2017

Overpressure has been encountered in many wells drilled in the Carnarvon Basin. Sonic logs are used to estimate pore pressure in shales in the Carnarvon Basin using the Eaton and equivalent depth methods of estimating pore pressure from velocity data with reference to a normal compaction trend. The crux of pore pressure estimation from the sonic log lies in the determination of the normal compaction trend, i.e. the acoustic travel time (Δt)/depth (z) trend for normally pressured sediments. The normal compaction trend for shales in the Carnarvon Basin was established by fitting an Athy-type exponential relationship to edited sonic log data, and is:
Δt = 225 + 391exp(-0.00103z)
Vertical stress estimates are also needed for the Eaton and equivalent depth methods used herein. A vertical stress (σv) relationship was obtained by fitting a regression line to vertical stress estimates from the density log, and is:
σv = 0.0131 z1.0642
The Eaton and equivalent depth methods yield similar pressure estimates. However, the equivalent depth method can only be applied over a limited range of acoustic travel times, a limitation that does not apply to the Eaton method.
The pressure estimates from the Eaton method were compared to pressures measured by direct pressure tests in adjacent permeable units. There is a good correlation between Eaton and test pressures in normally pressured intervals in three wells and overpressured intervals in two wells. Eaton pressure estimates underestimate overpressured direct pressure measurements in four wells by up to 13 MPa. This is consistent with overpressure being generated (at least in part) by a fluid expansion mechanism or lateral transfer of overpressure. The Eaton pressures in one well are, on average, 11 MPa lower than hydrostatic pore pressure recorded in direct pressure measurements below the Muderong Shale. The sediments in this well appear to be overcompacted due to exhumation. Mud weights can be used as a proxy for pore pressure in shales where direct pressure measurements are not available in the adjacent sandstones. The Eaton pressure estimates are consistent with mud weight in the Gearle Siltstone and Muderong Shale in 4 of the 8 wells studied. The Eaton pressures are on average 10 Mpa in excess of mud weight in the Muderong Shale and Gearle Siltstone in three wells. It is unclear whether the predicted Eaton pressures in these three wells accurately reflect pore pressure (i.e. the mud weights do not accurately reflect pore pressure), or whether they are influenced by changes in shale mineralogy (because the gamma ray filter does not differentiate between shale mineralogy).
MANAGEMENT OF ENVIRONMENTAL AND STAKEHOLDER ISSUES FOR OFFSHORE EXPLORATION ACTIVITIES IN THE OTWAY BASIN
Authors: Colman J.G. , Grubisa A. , Millhouse R.S.
Published: August 2017

Woodside has been managing seismic acquisition and drilling operations as part of a gas exploration program in the offshore Otway Basin in southwest Victoria since July 1999. There are a number of sensitive and complex environmental and multiple-use issues facing companies undertaking exploration activities in these waters, including a seasonal aggregation of feeding blue whales, winter calving and breeding habitat for southern right whales and a productive rock lobster fishery. Recent changes to the legislative regime for environmental approvals of petroleum activities in Commonwealth waters has introduced further complications for operators in this area. Consequently, a key aspect of this exploration program has been the pro-active management of environmental and stakeholder issues.A comprehensive management strategy addressing these issues was developed for seismic acquisition and drilling operations, with the key objectives of ensuring regulatory compliance and facilitating a process where all stakeholders were fully informed about proposed activities. This process focussed on informing stakeholders of the potential impacts of seismic acquisition and drilling, and how Woodside intended to manage those impacts. This approach was driven by a desire for continuous improvement of performance, over and above compliance with all regulatory requirements. It also recognises the legitimacy of stakeholder risk through social, environmental and political values, and has had environmental and economic benefits for the project.Environmental benefits included early identification and assessment of potential environmental impacts resulting from the different phases of exploration, development of management strategies to control and mitigate these potential impacts, and improved environmental awareness across the project team, joint venture partners and external stakeholders. Prevention of delay or denial of regulatory approvals for exploration activities had significant economic benefits to Woodside and the joint venture partners. The development and implementation of a stakeholder involvement process, involving explorers, external affairs and environmental advisers, was an innovative approach that has application across other Woodside activities and the industry generally, particularly for projects in locations with a high level of environmental sensitivity, multiple-use and stakeholder concern.
STRUCTURAL EVOLUTION AND THERMAL MATURATION MODELLING OF THE BASS BASIN
Authors: Cummings A.M. , Hillis R.R. , Tingate P.R.
Published: August 2017

The Bass Basin forms part of the Southern Margin Rift System that developed as a result of the initial separation of Australia and Antarctica. The structural history of the Bass Basin differs from that of a classic extensional basin in that it was influenced by two major rifting events, one associated with the opening of the Southern Ocean (Southern Ocean Rifting) and the other with the opening of the Tasman Sea (Tasman Rifting). The structure and stratigraphy of the basin reflect the impact of both rifting events.A revised model for the structural development of the Bass Basin is proposed. Four important periods of structural development within the basin are:possible Barremian extension associated with the closing phases of Southern Ocean Rifting;Turonian to Campanian extension associated with Tasman Rifting;Campanian to Early Eocene transtensional (wrenchrelated) reactivation of Tasman rift structures, andMiddle Tertiary reactivation.Current geothermal gradients within the Bass Basin are high, ranging from 33°C/km (Pelican–2) to 65°C/km (Konkon–1). Comparison of maturity profiles based on one dimensional thermal modelling with measured maturity profiles indicates that the Late Cretaceous to Recent sequence is experiencing maximum temperatures. Uplift relating to Oligocene to Miocene reactivation is restricted to the northern region of the basin (e.g. Cormorant Trough). Oligocene-Miocene deformation within central and southern regions was restricted to strike-slip reactivation of deep-seated basement involved structures.Assuming constant heat flow based on present-day values, source-rich horizons from the L.balmei to M.diversus intervals within the central depocentre regions of the Cormorant, Yolla and Pelican Troughs appear to have entered the oil expulsion window after deposition of the regional sealing unit, the Demons Bluff Formation. These source- rich horizons continued to pass through the oil expulsion window during and after Oligocene-Miocene reactivation events.An understanding of early rift geometries and subsequent changes in basin architecture and thermal conditions is central to defining new play concepts in this comparatively under-explored basin.
TIMING CONSTRAINTS ON THE STRUCTURAL HISTORY OF THE WESTERN OTWAY BASIN AND IMPLICATIONS FOR HYDROCARBON PROSPECTIVITY AROUND THE MORUM HIGH, SOUTH AUSTRALIA
Authors: Duddy I.R. , Erout B. , Green P.F. , Crowhurst P.V. , Boult P.J.
Published: August 2017

Reconstructed thermal and structural histories derived from new AFTA Apatite Fission Track Analysis, vitrinite reflectance and (U-Th)/He apatite dating results from the Morum–1 well, Otway Basin, reveal that the Morum High is a mid-Tertiary inversion structure. Uplift and erosion commencing in the Late Paleocene to mid-Eocene (57–40 Ma) removed around 1,500 m of sedimentary section. The eroded section is attributed to the Paleocene- Eocene Wangerrip Group which is considered to have been deposited in a major depocentre in the vicinity of the present Morum High. This depocentre is interpreted to have been one of a number of transtensional basins developed at the margin of the Morum Sub-basin and adjacent to the Tartwaup Hinge Zone and Mussel Fault during the Early Tertiary. The Portland Trough in Victoria represents a similar depocentre in which over 1,500 m of Wangerrip Group section, mostly represented by deltaic sediments of the Early Eocene Dilwyn Formation, is still preserved.Quantification of the maximum paleotemperature profile in Morum–1 immediately prior to Late Paleocene to mid-Eocene inversion shows that the paleo-geothemal gradient at the time was between 21 and 31°C/km, similar to the present-day level of 29°C/km, demonstrating that there has been little change in basal heat flow since the Early Tertiary.Reconstruction of the thermal history at the Trumpet–1 location reveals no evidence for any periods of significant uplift and erosion, demonstrating the relative stability of this part of the Crayfish Platform since the Late Cretaceous.The thermal and burial histories at Morum–1 and Trumpet–1 have been used to calibrate a Temis2D hydrocarbon generation and migration model along seismic line 85-13, encompassing the Crayfish Platform, Morum High and Morum Sub-basin. The model shows the cessation of active hydrocarbon generation from Eumeralla Formation source rocks around the Morum High due to cooling at 45 Ma (within the range 57–40 Ma) resulting from uplift and erosion of a Wangerrip Group basin. There has been almost no hydrocarbon generation from the Eumeralla Formation beneath the Crayfish Platform.Migration of hydrocarbons generated from the Eumeralla Formation began in the Late Cretaceous in the Morum Sub-basin and is predicted to continue to the present day, with the potential for accumulations in suitably placed reservoirs within the Late Cretaceous package both within the Morum Sub-basin and at the southern margin of the Crayfish Platform.
MID TO LATE JURASSIC SHALLOW MARINE SEQUENCES OF THE EASTERN BARROW SUB-BASIN: THE ROLE OF LOW-STAND DEPOSITION IN NEW EXPLORATION CONCEPTS
Authors: Moss S. , Barr D. , Kneale R. , Clews P. , Cruse T.
Published: August 2017

Several wells drilled along the fault-terraced eastern margin of the Barrow Sub-basin of the Australian North West Shelf have shed light on the pattern of Callovian to Tithonian sedimentation in the area. Much of this section has historically been interpreted as a product of deep marine depositional environments.Sandstone reservoirs cored in Linda–1/ST1, Linda–2 (both Wanaea spectabilis b age) and Denver–1/ST1 (Rigaudella aemula age) exhibit coarsening-upward cycles typical of marine parasequences, and possess sharp, erosive lower contacts with underlying claystone. In the case of Denver–1/ST1, the sandstones are heavily bioturbated with a distinct shallow marine trace fossil assemblage. Burrows are less evident in the sandstones from the Linda wells, although several thin bioturbated horizons—also with shallow marine trace fossils—are encountered. Similar patterns of shallow marine deposition are observed in previously drilled wells within the study area, and evidence of pedogenesis is found in core from Georgette–1 (R. aemula age), suggesting that exposure occurred on some of the higher fault terraces during low-stand conditions in the Middle to Late Jurassic.Further to the west, deepwater submarine fan sediments, deposited during low-stands, have been recognised. A range of time equivalent low-stand deposits—which are spatially and genetically exclusive— therefore exists within the sub-basin. Indeed such a spectrum should be expected in complex and tectonically active areas such as the Jurassic Barrow Sub-basin.The recognition of shallow marine deposits in the area has major implications with respect to the location and geometry of reservoir sandstones. The low-stand shoreface model, as opposed to the deep marine turbidite model, leads to the prediction of sandstone deposition aligned roughly parallel—rather than perpendicular— to the palaeo-shoreline and the potential for deeperwater sandstones further downdip.
THE HYDROCARBON POTENTIAL OF EXPLORATION PERMITS WA-299-P AND WA-300-P, CARNARVON BASIN: A CASE STUDY
Authors: Partington M. , Aurisch K. , Clark W. , Newlands I. , Phelps S. , Senycia P. , Siffleet P. , Walker T.
Published: August 2017

Exploration permits WA-299-P and WA-300-P lie west of the North West Cape in a frontier part of the Carnarvon Basin where the largely Mesozoic Exmouth Sub-basin abuts against shallow Palaeozoic strata of the Gascoyne Platform. The only exploration well, within the permits, Pendock–1, penetrated a thin Valanginian Birdrong Sandstone unconformably overlying Carboniferous to Silurian units, so the Mesozoic hydrocarbon potential of the area is effectively untested.The structure of the area comprises a complex mosaic of NNE–SSW trending Early Palaeozoic extensional, listric growth faults, dissected by NW–SE trending Permian extension relay zones. Subsequent phases of Callovian– Oxfordian and Valanginian uplift, together with Late Cretaceous and Miocene inversion along the main fault zone, further complicate the structure. Several seismic events, some of which correlate with magnetic anomalies, are discordant with the local stratigraphy indicating a probable igneous origin.The primary targets are the Birdrong Sandstone and underlying Wogatti Formation, both of which host onshore oil accumulations at Rough Range and Parrot Hill–1. The retrogradational clastic shoreline facies of the Birdrong Sandstone is well known along the eastern edge of the Dampier–Barrow–Exmouth Sub-basins. The Wogatti Formation was deposited as a more restricted alluvial/ fluvial sheet sand facies, so far identified only in the onshore Cape Range area. Where the Jurassic is preserved, fluvial/alluvial channel sand facies of the Middle Jurassic Learmonth Formation, known onshore at Sandy Point–1, and Callovian nearshore sands, as observed in Unknown Hill–l, are expected to be important secondary targets.The most promising play types within the Southern Carnarvon Basin are dip and fault-dip closures at Birdrong/Wogatti level associated with Late Cretaceous reactivation of the main NE–SW listric faults, and accentuated by later Miocene compression. The most significant exploration risks are charge and the high risk of biodegradation of reservoired liquid hydrocarbons (critically linked to reservoir temperature).
A HYDROCARBON GENERATION MODEL FOR THE COOPER AND EROMANGA BASINS
Authors: Deighton I. , Draper J.J. , Hill A.J. , Boreham C.J.
Published: August 2017

The aim of the National Geoscience Mapping Accord Cooper-Eromanga Basins Project was to develop a quantitative petroleum generation model for the Cooper and Eromanga Basins by delineating basin fill, thermal history and generation potential of key stratigraphic intervals. Bio- and lithostratigraphic frameworks were developed that were uniform across state boundaries. Similarly cross-border seismic horizon maps were prepared for the C horizon (top Cadna-owie Formation), P horizon (top Patchawarra Formation) and Z horizon (base Eromanga/Cooper Basins). Derivative maps, such as isopach maps, were prepared from the seismic horizon maps.Burial geohistory plots were constructed using standard decompaction techniques, a fluctuating sea level and palaeo-waterdepths. Using terrestrial compaction and a palaeo-elevation for the Winton Formation, tectonic subsidence during the Winton Formation deposition and erosion is the same as the background Eromanga Basin trend—this differs significantly from previous studies which attributed apparently rapid deposition of the Winton Formation to basement subsidence. A dynamic topography model explains many of the features of basin history during the Cretaceous. Palaeo-temperature modelling showed a high heatflow peak from 90–85 Ma. The origin of this peak is unknown. There is also a peak over the last two–five million years.Expulsion maps were prepared for the source rock units studied. In preparing these maps the following assumptions were made:expulsion is proportional to maturity and source rock richness;maturity is proportional to peak temperature; andpeak temperature is proportional to palaeo-heatflow and palaeo-burial.The geohistory modelling involved 111 control points. The major expulsion is in the mid-Cretaceous with minor amounts in the late Tertiary. Maturity maps were prepared by draping seismic structure over maturity values at control points. Draping of maturity maps over expulsion values at the control points was used to produce expulsion maps. Hydrocarbon generation was calculated using a composite kerogen kinetic model. Volumes generated are theoretically large, up to 120 BBL m2 of kitchen area at Tirrawarra North. Maps were prepared for the Patchawarra and Toolachee Formations in the Cooper Basin and the Birkhead and Poolowanna Formations in the Eromanga Basins. In addition, maps were prepared for Tertiary expulsion. The Permian units represent the dominant source as Jurassic source rocks have only generated in the deepest parts of the Eromanga Basin.
RESERVOIR QUALITY, DIAGENESIS AND SEDIMENTOLOGY OF THE PALE AND SUBU SANDSTONES: RE-VISITING THE EASTERN PAPUAN BASIN, PAPUA NEW GUINEA
Authors: Barclay S.A. , Liu K. , Holland D.
Published: August 2017

Two shallow diamond drill holes (Subu–1 and Subu–2) continuously cored in August and September 2001 by InterOil Australia represent the first sub-surface penetrations of reservoir quality sandstones in the Eastern Papuan Basin of Papua New Guinea. These wells intersected two sedimentologically distinct thick quartz sandstones (>100 m). The upper sandstone unit is Campanian in age and is correlated with the Pale Sandstone, whereas the lower sandstone is of Turonian age and has not been reported previously, and is tentatively named as the Subu Sandstone in this paper.The core has been the subject of detailed reservoir quality and diagenetic study as part of a multi-disciplinary study conducted by CSIRO Petroleum. The results of the reservoir quality portion of this study form the basis of this report and demonstrate the following:There are two distinct depositional systems present with a lower sandy slope apron and basin floor fan system (Subu Sandstone) and a younger upper shoreface-shallow marine depositional system (Pale Sandstone).While the porosity and permeability data for subsurface samples (5 to 16% and 0.1 to 1000mD) are lower than previously reported by Boult and Carman (1990) for surface samples both the sandstone units demonstrate thick, good reservoir quality reservoir capable of holding significant volumes of hydrocarbons.Bitumen is present in the pore space through out the sandstones in both wells. The presence of biodegraded hydrocarbons demonstrates that liquid hydrocarbons have been generated in the basin and have either migrated through the Subu and Pale sandstone or have been reservoired in them.Associated with the bitumen is pyrite precipitated as an in-situ by-product of shallow biodegradation of the parent liquid hydrocarbon as indicated by sulphur isotope analysis.Diagenetic effects include compaction (the dominant control on reservoir quality), minor quartz cementation, minor secondary porosity generation, and in thin zones localised carbonate cementation.Despite their very different depositional settings and age difference the thin section petrology of the Pale and Subu sandstones are very similar. The subtle difference between them is textural (grain size, sorting) and detrital clay content. The Subu Sandstone is typically finer grained, displays a higher degree of sorting and has a higher detrital clay content than the Pale Sandstone.The character of these sandstones may have as much to do with provenance as with depositional environment and may indicate a separate quartz-rich depositional system sourcing sediment from the Australian craton independent of the Fly Platform Toro/Imburu systems.
THE EMERGENCE OF CORPORATE SOCIAL RESPONSIBILITY—ISSUES FOR THE AUSTRALIAN OIL AND GAS SECTOR
Authors: Keaney A.T.
Published: August 2017

Recent times have seen a rise in expectations in companies’ accountability as good corporate citizens. This trend has seen an increased emphasis on corporate governance and director liability. Further disclosure is now required and/or expected against a number of measures including environmental adherence, community activities and employee relations.At the same time companies are now subject to heightened shareholder activism as well as the growth of ethical investment funds which require companies to meet certain standards of corporate behaviour before they will invest.With the recent collapse of several major Australian companies and the consequent scrutiny of their corporate behaviour, and the revelation of instances of massive levels of corporate impropriety in the US, the above trend can be expected to grow. This paper discusses:the main platforms of corporate responsibility currently on the public agenda including:good corporate governance and director liability;environmental responsibility (sustainability rather than compliance); andother areas of social responsibility including treatment of employees and preservation of employee entitlements;the regulatory issues surrounding corporate responsibility, in particular under the Corporations Act;the risks and rewards of engaging in or ignoring this process. The risks might include potential director liability and public relations issues. The rewards may include access to additional public and private capital; andissues in this debate of particular relevance to the upstream oil and gas sector.
MIGRATION, LEAKAGE AND SEEPAGE CHARACTERISTICS OF THE OFFSHORE CANNING BASIN AND NORTHERN CARNARVON BASIN: IMPLICATIONS FOR HYDROCARBON PROSPECTIVITY
Authors: O’Brien G.W. , Cowley R. , Lawrence G. , Williams A.K. , Webster M. , Tingate P. , Burns S.
Published: August 2017

RadarSat and ERS Synthetic Aperture Radar (SAR) satellite data have been used for oil slick mapping as part of a systematic interpretative study of the offshore Canning Basin, as well as part of the northern Carnarvon Basin, extending from the inner shelf to the abyssal plain. These seepage data have been integrated with regional geological data, more than 12,000 km of reprocessed Airborne Laser Fluorosensor (ALF) survey data, seismic DHI indicators, water column geochemical sniffer data, potential field data, earthquake data and 2D Petromod basin modelling, to provide new insights into the region’s petroleum prospectivity and key exploration risk factors.From a prospectivity viewpoint, this study has highlighted several areas and processes. Firstly, it is clear that overpressure in the region is principally controlled by the thickness of the Tertiary carbonate wedge and we predict that overpressure may be present in parts of the deeper water Canning Basin. Secondly, the offshore Canning Basin contains a relatively low density of SAR-mapped oil slicks, though this appears to be due to a combination of factors, namely a paucity of vertical conduits for leakage, a predominantly condensate-prone charge and a small slick size.Significantly, several as-yet untested areas emerge from our observations. In the offshore Canning Basin, a 'window' exists in about 1,500–2,500 m of water, where the Triassic source rocks are particularly well placed for liquids generation. Morever, a large area in a radius some 20–80 km outboard of the Bedout High, also appears to have significant untested liquids potential, with respect to sourcing from the Triassic. The shallow section through this region contains a vast area with abundant seismically mapped gas chimneys and other seepage indicators, supporting the conclusions from the remote sensing and basin modelling of significant hydrocarbon charge in this region. Finally, the study indicates that liquids have been generated within the Palaeozoic section of the Bedout Sub-basin.
A RE-EVALUATION OF THE HYDROCARBON HABITAT OF THE NORTHERN PERTH BASIN
Authors: Thomas B.M. , Barber C.J.
Published: August 2017

Recent oil discoveries at Hovea, Cliff Head, Jingemia and Eremia have challenged the perception that the northern Perth Basin is largely gas prone and renewed interest in the identification of oil source rocks in the succession. A major geochemical reassessment of all units from the Middle Triassic to the base of the Permian shows that the principal oil prone source rocks are restricted to a discrete zone within the basal Kockatea Shale, the Sapropelic Interval of the Hovea Member (defined herein). The source zone, typically 10–40 m thick, is laterally continuous over much of the onshore northern Perth Basin. It immediately overlies the Permian-Triassic boundary and may form part of a global anoxic event. These are some of the best oil source rocks ever identified in Australia. A combination of diagnostic biomarkers and compound specific isotopic data consistently link the Hovea Member source rocks to all oils analysed from the northern Perth Basin. Gas prone source rocks are developed at several levels in the Permian, and particularly in the Irwin River Coal Measures. In most areas of the basin, oil charge from the Triassic is in direct competition with any gas generated from the Permian, as seen in the large Warradong Kitchen, southeast of the Dongara Field. This has resulted in a predominance of gas discoveries, often with a thin oil leg. The smaller but oil prone Jingemia Kitchen, southwest of Dongara, has sourced the recent oil discoveries at Hovea, Jingemia and Eremia. There is evidence that the Hovea Member source rocks are also widely distributed offshore in the Abrolhos Sub-basin where they appear to have sourced the Cliff Head oil discovery and strong oil shows in Morangie–1 and Livet–1, some 300 km northwest of Dongara.
THE INFLUENCE OF COMPOSITION, DIAGENESIS AND COMPACTION ON SEAL CAPACITY IN THE MUDERONG SHALE, CARNARVON BASIN
Authors: Kovack G.E. , Dewhurst D.N. , Raven M.D. , Kaldi J.G.
Published: August 2017

The Muderong Shale blankets most of the northern Carnarvon Basin and is the top seal to over 90% of all commercial discoveries. This study examines the influence that vertical effective stress, mineralogy and diagenesis have on regional variations of seal capacity. Throughout the basin, threshold pressures (determined from Mercury Injection Capillary Pressure (MICP) analyses), range from less than 1,000 psi (equivalent to ~100 m gas column) up to 10,000 psi (~1,000 m gas column). Because the Muderong Shale varies in thickness (5 m to >900 m) and burial depth (~0.5–3.5 km), effective stresses and temperatures also vary. Effective stress and temperature significantly control pore geometry at different depths through compaction and diagenesis. The data from this study show that shale grain size has no direct influence over seal threshold pressure except that finer-grained Muderong Shale (36–45% particles 2.5 km) along the Northern Alpha Arch and Rankin Platform, total illite content is only moderate.
LATE CRETACEOUS PONDED TURBIDITE SYSTEMS: A NEW STRATIGRAPHIC PLAY FAIRWAY IN THE BROWSE BASIN
Authors: Benson J.M. , Brealey S.J. , Luxton C.W. , Walshe P.F. , Tupper N.P.
Published: August 2017

Regional seismic and sequence stratigraphic analysis of the Browse Basin identified a new Late Cretaceous play fairway involving ponded turbidite systems deposited within confined basins. This work highlighted the potential for isolated sandstone reservoirs in the Middle Campanian sequence of the Caswell Sub-basin. Extensional faults were expected to provide vertical conduits for charge from underlying Early Cretaceous source rocks.The play concept was tested by the drilling of two exploration wells in 2001. The Carbine prospect was a potential stratigraphic trap involving deposition of turbidite sandstones within a localised basin set up by slumping in an intra-slope setting. Carbine–1 penetrated a 77 m thick section of high quality, 100% net-to-gross sandstone but failed to encounter hydrocarbons.A similar ponded turbidite model was invoked for the Marabou prospect although in this case the confined basin was controlled by pre-existing topography at the toe of the slope. The trapping mechanism for Marabou was largely stratigraphic although a small area of anticlinal closure was present. Marabou–1 penetrated 102 m of good quality sandstone with elevated gas readings over the uppermost 22 m. Borehole problems prevented the acquisition of wireline logs or testing but it appears likely that the well penetrated a sub-commercial hydrocarbon column restricted to the four-way dip closure.The well results confirmed the presence of ponded turbidite systems with excellent reservoir characteristics. Further work is required, however, to address the critical risks associated with hydrocarbon migration and updip seal. Nevertheless, ponded turbidite systems remain attractive exploration targets particularly in basins where updip seal is assisted by structuring and where the reservoirs are intercalated with prolific source rocks.
MODERN ANALOGUES FOR DRYLAND SANDY FLUVIAL-LACUSTRINE DELTAS AND TERMINAL SPLAY RESERVOIRS
Authors: Lang S.C. , Payenberg T.H.D. , Reilly M.R.W. , Hicks T. , Benson J. , Kassan J.
Published: August 2017

Ephemeral sandy fluvial-lacustrine deltas and terminal splays associated with dryland depositional environments are important reservoirs in many basins around the world, in both pericratonic and intracratonic settings (Triassic of Algeria; Triassic of the North Sea; and Pliocene of the Caspian Sea). Research on modern depositional analogues from dryland basins offers insights into these types of reservoirs. Australia’s modern Lake Eyre Basin, an arid to hyper-arid, low-accommodation intracratonic basin in central Australia, provides an ideal natural laboratory.This paper highlights field observations of modern, sand-prone, reservoir analogues from the Neales River and Umbum Creek, on the western fringe of Lake Eyre, including unique aerial observations of sedimentation from a rare flood event in an ephemeral fluvial system. These rivers flow irregularly in a dryland setting, but are prone to flash flooding and highly variable discharge that moves large volumes of sediment over a few hours or days. Although there are variations in sediment type and discharge, similarities exist with the key reservoir elements common to most modern and ancient dryland fluvial-lacustrine systems.Distinctive elements include fluvial point bar and associated overbank deposits, distributive avulsion channels and down-dip terminal splays, either on the floodplain or onto the playa lake fringe. The terminal splays are formed, where there is not a pre-existing standing body of water, during rapidly decelerating flows with high-flow regime, transitional to low-flow regime conditions. Typical structures include parallel lamination, convex-upward parallel lamination, climbing ripples and small-scale 2D and 3D dunes. Flow interference with in-channel and floodplain vegetation is an important sediment-trapping mechanism with reservoir quality implications. Aeolian deflation is also significant as it causes the removal of fine-grained sediments during dry periods. The main controls on sediment preservation include the overall low-accommodation setting and rare major lake-filling events controlled by flooding out-of-phase with flows down the western rivers. Depositional products are either high-net-to gross fluvial- terminal splay sheet sands or lower net-to-gross fluvial- terminal splay-lacustrine delta sand sheets or stringers.
MESOZOIC EVOLUTION OF THE GREATER TARANAKI BASIN AND IMPLICATIONS FOR PETROLEUM PROSPECTIVITY
Authors: Uruski C. , Baillie P.
Published: August 2017

A paradigm of New Zealand petroleum geology was that the oldest source rocks known in the region were of Cretaceous age, so any older sedimentary rocks were considered to be economic basement. Two major projects have revealed that this is not universally the case and that a Jurassic petroleum system should now be considered.Firstly, the Astrolabe 2D speculative survey, acquired by TGS-NOPEC in 2001, has revealed that a significant section underlies the traditional Cretaceous petroleum systems. Secondly, the Wakanui–1 well, drilled by Conoco, Inpex and Todd in 1999, which has recently become open-file, penetrated a Mid-Jurassic coal measure sequence.Jurassic rocks, including coal measure units, are known onshore in New Zealand, They are part of the Murihiku Supergroup, one of the basement terranes comprising the Permian to Cretaceous volcanic arc that forms the basement rocks of the present New Zealand landmass. Wherever they have been seen in outcrop, these rocks generally record low grade metamorphism and have been discounted as petroleum source rocks. Where rocks of the same age were deposited distal to the volcanic arc (and the effects of heat and pressure), however, they may form components of an effective petroleum system.The New Caledonia Basin, extending more than 2,000 km from Taranaki to New Caledonia, may have been the site of a Mesozoic back-arc basin. Jurassic coal measure successions and their equivalent marine units may be locally, or regionally important as source rocks. Implications of a Jurassic petroleum system for prospectivity of the region are investigated.
STRUCTURE AND HYDROCARBONS IN THE SHIPWRECK TROUGH, OTWAY BASIN: HALF-GRABEN GAS FIELDS ABUTTING A CONTINENTAL TRANSFORM
Authors: Palmowski D. , Hill K.C. , Hoffman N.
Published: August 2017

As part of a regional study of the evolution of the Otway Basin, the Investigator 3D seismic survey has been structurally analysed, using 11 extracted 2D sections and 3D interpretations of key horizons. South-southwest directed extension was widespread in the Turonian forming the Shipwreck Trough, coincident with uplift of the Otway Ranges to the northeast. The Turonian extension, at ~1.5 myrs, resulted in planar faults in the northeastern part of the Trough, but large half-graben above south-southwest dipping listric master faults in the southwest, both fault sets soling into an Early Cretaceous shale detachment. The half-graben propagated north from the Mussel-Tarpwaup Hinge-Zone by footwall collapse and accommodated deposition of reservoir rocks for the known hydrocarbon accumulations. The half-graben die out along strike to the east at tip-points against an accommodation zone that developed into a continental transform (the Shipwreck Fault).Santonian breakup in the Great Australian Bight coincided with considerable south-southwesterly extension in the Otway Basin juxtaposed against the failed Bassian rift across the Shipwreck Fault. Extension of ~1.21 km to the west of the Shipwreck Fault contrasts with ~0.42 km on the eastern side accommodated by ~0.79 km left-lateral displacement along the Shipwreck Fault. The Belfast Mudstone was deposited during this time, forming the regional seal for the known hydrocarbon accumulations.Limited slow extension during the Campanian to Early Eocene resulted in a further 0.33 km sinistral slip along the Shipwreck Fault. Late Early Eocene Breakup in the Otway Basin ended the transitional phase, terminating extensional and Shipwreck Fault offset. The breakup caused local uplift and ~1 km erosion of Wangerrip Group sediments. The post breakup phase is characterised by prograding sequences indicating progressive-regressive cycles.The Thylacine and La Bella gas fields occur in large tilted fault-blocks near the Hinge-Zone. These successful large structures lie along a longstanding High probably sourced from south of the Hinge-Zone. Key elements for a successful hydrocarbon play are deposition of the Turonian Waarre Formation sandstone reservoirs at rift onset and of a thick Belfast Mudstone seal during continuous Coniacian-Santonian extension. Footwall collapse north of the Hinge-Zone, bound by the deepwater Otway Basin and the continental transform, controlled the distribution of traps, regional seal and hydrocarbon maturation.