ORCID Profile
0000-0002-5222-7413
Current Organisation
University of Adelaide
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Publisher: American Association of Petroleum Geologists AAPG/Datapages
Date: 2009
DOI: 10.1306/08080808031
Publisher: CSIRO Publishing
Date: 2010
DOI: 10.1071/AJ09016
Abstract: The passive southern margin of the Australian continent, which formed following Cretaceous–Palaeogene separation from Antarctica, contains a rich record of Neogene–Recent compressional deformation and uplift. This deformation and uplift is manifested by reversal of displacement along syn-rift extensional faults, folding of mid–late Cenozoic post-rift sediments, and regional unconformities that can be traced for distances of up to 1,500 km along the margin. Palaeothermal data from onshore and offshore exploration wells indicate that erosion associated with deformation and uplift locally exceeds 1 km in the eastern Otway Basin. Both neotectonic palaeostress trends inferred from these structures and present-day stress orientations are consistent with northwest–southeast directed compression controlled to first-order by plate boundary forces. The critical role of the relative timing of trap formation and source rock maturation in controlling hydrocarbon prospectivity in the southern Australian margin is investigated by comparing two structures that formed during Neogene–Recent deformation in the Otway Basin: the Minerva and Nerita anticlines. While the Minerva Anticline hosts a major gas field (558 BCF GIP), the Nerita Anticline was found to be dry. A combination of apatite fission track analysis (AFTA), vitrinite reflectance (VR) and present-day temperature data show that all units intersected in Minerva–1 are presently at their maximum post-depositional temperatures, and are presently mature for hydrocarbon generation. In contrast, similar data collected from the preserved section at Nerita–1 indicate cooling from maximum post-depositional temperatures prior to formation of the Nerita Anticline in the late Miocene. Based on regional AFTA data, the underlying early Cretaceous source rocks probably reached maximum palaeotemperatures and ceased hydrocarbon generation during mid-Cretaceous uplift. These results indicate that areas of the southern margin that were deformed during the Neogene–Recent have the greatest potential to trap hydrocarbons where potential source rocks are presently at their maximum post-depositional temperatures.
Publisher: Informa UK Limited
Date: 02-2000
Publisher: Wiley
Date: 17-01-2014
DOI: 10.1111/BRE.12035
Publisher: CSIRO Publishing
Date: 2001
DOI: 10.1071/AJ00041
Abstract: The APCRC GEODISC research program has encountered many challenges looking for geological sequestration sites for CO2, but has also found some solutions. Challenges already faced have been in effectively searching databases, developing uniform terminology and evaluation methodology, establishing comparative quality assessment of Australia’s sequestration sites against each other and against those from overseas, improving our understanding of the injection and trapping properties of CO2 and predicting its effects on reservoirs/seals, and developing economic and reservoir models.Pilot research projects at the regional and site specific levels have been used to address these issues, as well as developing generic models, before building site specific models. Issues such as storage efficiency and the use of carbonates as CO2 sequesrationt reain challenges for the future.Preliminary conclusions reached from the regional study of Australia suggest that suitable deep saline formations will be widespread, have the largest sequestration volumes, and are likely to be the most economically attractive option currently available. In the future, some depleted oil and gas fields and enhanced coalbed methane production sites may also represent local high-volume options. It is considered unlikely that sequestration into voids/cavities or associated with enhanced oil recovery (EOR) will represent attractive options other than in exceptional circumstances. Despite these limitations, it is expected that many of Australia’s sedimentary basins will have excellent sequestration sites. The GEODISC program will provide an assessment of the critical factors required for success at each site.Several of the highest-ranking saline formations are currently undergoing site-specific study. Early indications are that the petrophysical data required for models of injection, migration, and trapping is of limited availability. Various methods are required to estimate the distribution and likely variability of these parameters across any site.These and other uncertainties in the distribution, quantity and quality of data required for predictive modelling necessitate an innovative and thorough approach to handling both risk and uncertainty. This will also be a challenge to be addressed during the GEODISC program.From the GEODISC work to date, it appears that it will be technically feasible to sequester large quantities of CO2 in geological formations in Australia for long periods of time. What is less clear is whether this can be done at a cost that would not impose an unreasonable economic burden on Australian industry. The future results for GEODISC will be highly relevant to answering this key question.
Publisher: Informa UK Limited
Date: 06-2003
DOI: 10.1071/EG03174
Publisher: CSIRO Publishing
Date: 2002
DOI: 10.1071/AJ01011
Abstract: Predictions of the likelihood of fault reactivation for five fault-bound prospects in the Timor Sea are made using the FAST (Fault Analysis Seal Technology) technique. Fault reactivation is believed to be the dominant cause of seal breach in the area. Calculations are made using a stress tensor appropriate for the area, a conservative fault-rock failure envelope and the structural geometries of each prospect. A depth-stress power relationship defines the vertical stress magnitude based on vertical stress profiles for 17 Timor Sea wells.Empirical evidence of hydrocarbon leakage at each trap is used to investigate the accuracy of the fault reactivation-based predictions of seal integrity. There is a good correlation between evidence of leakage and the risk of reactivation predicted using the FAST technique. Risk of reactivation is expressed as the pore pressure increase (ΔP) that would be required to induce failure. This study allows the fault reactivation predictions to be calibrated in terms of risk of seal breach. Low integrity traps are associated with ΔP values less than 10 MPa, moderate integrity traps correspond with values between 10 and 15 MPa and high integrity traps correspond with values greater than 15 MPa. Faults with dip magnitudes greater than 60° in the Timor Sea area are likely to have a high risk of reactivation and shear failure is the most likely mode of reactivation.
Publisher: CSIRO Publishing
Date: 2002
DOI: 10.1071/AJ01010
Abstract: The results of natural and laboratory-induced fault behaviour from wells in the Otway Basin are compared with s le material from a producing Carnarvon Basin field where rocks from a fault zone have been cored. Capillary pressure, microstructural and juxtaposition data obtained from these fault rocks indicate a capability to hold back gas columns in excess of 100 m, yet many fault closures are found to contain only palaeo-columns. Trap failure is usually attributed to reactivation of trap-bounding faults, often during Miocene-Recent times in these basins. Faults susceptible to reactivation can be predicted by geomechanical methods involving the determination of the in-situ stress field and the orientation and dip of faults with respect to that stress field. Failure envelopes of fault rocks have been determined to estimate reactivation potential in the present day in-situ stress field. This approach works well where fault rocks are weaker than the host reservoir sandstone, but may not be applicable where fault rocks are stronger. In fields where the latter is the case, intact hydrocarbon columns are present, irrespective of whether faults are optimally oriented for reactivation. This indicates that the assumptions of zero cohesive strength and constant friction coefficient for predicting the reactivation potential of fault rocks may not be completely reliable.
Publisher: Informa UK Limited
Date: 03-2006
DOI: 10.1071/EG06050
Publisher: Informa UK Limited
Date: 09-1998
DOI: 10.1071/EG998420
Publisher: Elsevier BV
Date: 2010
Publisher: Elsevier BV
Date: 07-2007
Publisher: Geological Society of London
Date: 30-08-2011
Publisher: Informa UK Limited
Date: 03-2000
DOI: 10.1071/EG00058
Publisher: Geological Society of London
Date: 2005
Publisher: American Geophysical Union (AGU)
Date: 16-10-2010
DOI: 10.1029/2009JB006997
Publisher: Geological Society of America
Date: 28-08-2009
DOI: 10.1130/B26481.1
Publisher: American Geophysical Union (AGU)
Date: 08-2009
DOI: 10.1029/2008TC002359
Publisher: American Geophysical Union (AGU)
Date: 04-1997
DOI: 10.1029/96TC02943
Publisher: Informa UK Limited
Date: 06-1995
DOI: 10.1071/EG995202
Publisher: Geological Society of London
Date: 27-02-2009
Publisher: Elsevier BV
Date: 2011
Publisher: CSIRO Publishing
Date: 2001
DOI: 10.1071/AJ00029
Abstract: A small, but significant fraction of wells drilled in the Northern Carnarvon Basin have encountered problems with overpressure: better pore pressure prediction would improve safety and economy for drilling operations. In the Northern Carnarvon Basin the occurrence of overpressure and likely mechanisms are under investigation as part of the Australian Petroleum Cooperative Research Centre (APCRC) Research Program on Pore Pressure Prediction. Previous workers have proposed a number of mechanisms as the main cause of overpressure including undercompaction, hydrocarbon generation, horizontal stress and clay reactions.A preliminary regional study was undertaken incorporating over 400 well completion reports which identified approximately 60 wells with mud weights greater than 1.25 S.G. A subset of these wells was investigated and more reliable but much scarcer pressure indicators such as kicks or direct pressure measurements were examined. Depth-pressure profiles of wells across the region are variable and commonly show pressure compartmentalisation. Using a range of indicators, it was observed that overpressured strata in the Barrow Subbasin:occur over a wide depth range (2,500 to 4,000+ mbsl) occur over a wide stratigraphic range (Late Triassic to Late Cretaceous) are not regionally limited by major structural boundaries are associated with sequences dominated by finegrained sediments with variable clay mineralogy and in depositionally, or structurally, isolated sandstones andmainly to the west of the Barrow and D ier Subbasins around the Alpha Arch and Rankin Trend, coinciding with thickest Tertiary deposition.Previous published work in the study area has tended to support hydrocarbon generation as the primary cause of overpressure, though more recent publications have emphasised compaction disequilibrium. The log response (DT, RHOB and NPHI) of overpressured clay-rich strata has been investigated to constrain the type of overpressure mechanism. A normal compaction trend has been derived for four stratigraphic groupings Muderong Shale, Barrow Group, Jurassic and Triassic. All overpressure occurrences were accompanied by an increase in sonic transit time. Not all wells have suitable log data for evaluation, but all stratigraphic groups show some evidence of elevated porosity associated with overpressure consistent with disequillibrium compaction as a dominant mechanism. Overpressures in the Barrow Group in Minden-1 and the Jurassic section within Zeepaard–1 do not have accompanying porosity anomalies suggesting a different overpressure mechanism model is needed.
Publisher: Elsevier BV
Date: 12-2003
Publisher: Geological Society of London
Date: 27-07-2021
DOI: 10.1144/JGS2020-250
Publisher: Geological Society of America
Date: 2003
Publisher: CSIRO Publishing
Date: 2012
DOI: 10.1071/AJ11033
Abstract: Previous in-situ stress studies across many of Australia’s petroleum basins demonstrate normal fault and strike-slip fault stress regimes, despite the sedimentary successions demonstrating evidence for widespread Miocene-to-Recent reverse faulting. Seismic and outcrop data demonstrate late Miocene-to-Recent reverse or reverse-oblique faulting in the Otway and Gippsland basins. In the Otway Basin, a series of approximately northeast to southwest trending anticlines related to reverse-reactivation of deep syn-rift normal faults, resulting in the deformation of Cenozoic post-rift sediments are observed. Numerous ex les of late Miocene-to-Recent reverse faulting in the offshore Gippsland Basin have also been observed, with contractional reactivation of previously normal faults during these times partially responsible for the formation of anticlinal hydrocarbon traps that host the Barracouta, Seahorse and Flying Fish hydrocarbon fields, adjacent to the Rosedale Fault System. A new method for interpreting leak-off test data demonstrates that the in-situ stress data from parts of the Otway and Gippsland basins can be reinterpreted to yield reverse fault stress regimes, consistent with the present-day tectonic setting of the basins. This reinterpretation has significant implications for petroleum exploration and development in the basins. In the Otway and Gippsland basins, wells drilled parallel to the orientation of the maximum horizontal stress (ÏH) represent the safest drilling directions for both borehole stability and fluid losses. Faults and fractures, striking northeast to southwest, previously believed to be at low risk of reactivation in a normal fault or strike-slip fault stress regime are now considered to be at high risk in the reinterpreted reverse fault stress regime.
Publisher: CSIRO Publishing
Date: 2010
DOI: 10.1071/AJ09030
Abstract: Petroleum generation, expulsion, migration and accumulation have been modelled in 3D at basin-scale for the Bass Basin, Tasmania. The petroleum systems model shows several source rocks of different ages have generated and expelled sufficient hydrocarbons to fill structures in the basin however, the lithologies and fault properties in the model result in generally limited migration after hydrocarbon expulsion started. Impermeable faults, together with several fine-gained sealing facies in the Lower and Middle Eastern View Group (EVG) have resulted in minor vertical hydrocarbon migration in the lower parts of the EVG. An exception occurs in the northeastern part of the basin, where strike-slip movement of suitably oriented faults during Miocene reactivation resulted in breaches in deeper accumulations and migration to upper reservoir sands and, in several cases, leakage through the regional seal. The Middle Eastern View Group source rocks have produced most of the gas in the basin. Oil appears to be largely limited to the Yolla Trough, related to the relatively high thermal maturation of Narimba Sequence source rocks. In general, most of the hydrocarbon expelled from the Otway Megasequence occurred prior to the regional seal being deposited however, modelling predicts it can contribute to the hydrocarbon inventory of the Cape Wickham Sub-basin. In particular, the modelling predicted an Otway sourced accumulation at the site of the recently drilled Rockhopper–1. In the Durroon Sub-basin in the Bark Trough, the Otway Megasequence is predicted to be the main source of accumulations. The modelling has provided detailed insights into migration in the existing plays and has allowed assessment of the reasons for previous exploration failures (e.g., a migration shadow at Toolka–1) and to suggest new locations with viable migration histories. Reservoir sands of the Upper EVG are only prospective in the Yolla and Cormorant troughs where charged by Early Eocene sources however, Miocene reactivation is a major exploration risk in this area.
Publisher: Informa UK Limited
Date: 03-1997
DOI: 10.1071/EG997080
Publisher: Wiley
Date: 17-01-2014
DOI: 10.1111/BRE.12052
Publisher: Geological Society of London
Date: 2005
Publisher: American Association of Petroleum Geologists AAPG/Datapages
Date: 2014
DOI: 10.1306/04011312111
Publisher: Geological Society of London
Date: 09-08-2012
DOI: 10.1144/SP367.12
Abstract: Delta–deepwater fold–thrust belts (DDWFTBs) develop over low-angle detachment faults which link extension to downslope contraction. Detachment faults have been examined in previous studies for the Amazon Fan, Niger, Nile, Angola, Baram and Bight Basin DDWFTBs. The driving mechanisms for the movement along the detachment remain uncertain, however. Previous authors have attributed the movement along detachment faults to high pore-fluid pressure, which reduces the effective normal stress acting on a fault surface thereby encouraging sliding along the fault. However, high pore-fluid pressure has not been directly confirmed in many of these faults due to a lack of well data in detachment surfaces. In this study, finite element modelling was used to test the effects of pore-fluid pressure, coefficient of friction, sediment rigidity and sediment wedge angle on sliding along the detachment. The modelling suggests that increased pore-fluid pressures and decreased coefficients of friction increase slip along a detachment. At hydrostatic pore-fluid pressures, sediment rigidity and sediment wedge angle have relatively little effect on the movement of the sediment wedge along the detachment. Modelling of these conditions using ABAQUS™ improves our understanding of the nature and mechanics of DDWFTBs and their underlying detachments.
Publisher: CSIRO Publishing
Date: 2008
DOI: 10.1071/AJ07014
Abstract: A study of porosity trends and reservoir quality of the Eastern View Group (EVG) of the Bass Basin has been undertaken. Previous exploration in the Bass Basin targeted the Upper EVG due to its stratigraphic equivalence to the hydrocarbon-rich Upper Latrobe Group in the Gippsland Basin. Although this exploration has proved that mature source rocks in the basin have generated and expelled hydrocarbons, the relative lack of hydrocarbon charge into the Upper EVG has previously been identified as a major exploration risk. If hydrocarbon generation is adequate, the lack of Upper EVG accumulations is probably related to limited vertical migration. Thus the reservoir quality of the most relatively charged Middle and Lower EVG is important in determining the basins’ prospectivity. Sonic log data were deemed to be the most appropriate to determine porosity for this study. Wyllie, Clemenceau, Hunt-Raymer and modified Hunt-Raymer equations were used to calculate porosity. The results from each method were compared with available core plug data and the best method (modified Hunt-Raymer) selected. The modified Hunt-Raymer derived porosity trends were examined both vertically and laterally in the basin. In some sandstone intervals an increase in porosity with depth was observed. Thicker sand bodies can exhibit average calculated porosity of approximately 20% even at depths greater than 3,000 m. Several sands in the Middle EVG show a localised increase in porosity with depth, which is attributed to the fining upwards (coarsening downwards) of fluvial channels. The presence of good reservoir sands in the Middle and Lower EVG closer to mature source rocks in the basin is very encouraging as it makes deeper exploration in the Bass Basin more attractive.
Publisher: Taylor & Francis
Date: 17-05-2007
Publisher: Geological Society of London
Date: 11-1997
Publisher: American Association of Petroleum Geologists AAPG/Datapages
Date: 2009
DOI: 10.1306/08080808016
Publisher: Geological Society of London
Date: 09-08-2012
DOI: 10.1144/SP367.10
Abstract: Delta–deepwater fold–thrust belts are linked systems of extension and compression. Margin-parallel maximum horizontal stresses (extension) on the delta top are generated by gravitational collapse of accumulating sediment, and drive downdip margin-normal maximum horizontal stresses (compression) in the deepwater fold–thrust belt (or delta toe). This maximum horizontal stress rotation has been observed in a number of delta systems. Maximum horizontal stress orientations, determined from 32 petroleum wells in the Gulf of Mexico, are broadly margin-parallel on the delta top with a mean orientation of 060 and a standard deviation of 49°. However, several orientations show up to 60° deflection from the regional margin-parallel orientation. Three-dimensional (3D) seismic data from the Gulf of Mexico delta top demonstrate the presence of salt diapirs piercing the overlying deltaic sediments. These salt diapirs are adjacent to wells (within 500 m) that demonstrate deflected stress orientations. The maximum horizontal stresses are deflected to become parallel to the interface between the salt and sediment. Two cases are presented that account for the alignment of maximum horizontal stresses parallel to this interface: (1) the contrast between geomechanical properties of the deltaic sediments and adjacent salt diapirs and (2) gravitational collapse of deltaic sediments down the flanks of salt diapirs.
Publisher: Elsevier BV
Date: 05-2011
Publisher: Geological Society of London
Date: 07-2004
Publisher: Springer Science and Business Media LLC
Date: 06-04-2017
Publisher: CSIRO Publishing
Date: 2002
DOI: 10.1071/AJ01032
Abstract: 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).
Publisher: Elsevier BV
Date: 07-1995
Publisher: Oxford University Press (OUP)
Date: 04-1987
Publisher: CSIRO Publishing
Date: 1997
DOI: 10.1071/AJ96032
Abstract: Theoretical fracture gradient relations are generally based on the assumption that the sedimentary sequence behaves elastically under conditions of lateral constraint. Hence the minimum horizontal stress (σhmin) is given by: where V is Poisson's ratio, σv is overburden stress, pp is pore pressure, and at is far -field tectonic stress. In driling practice, fracture initiation, or leak -off pressures, which are related to σhmin are most commonly predicted by the application of empirical stress /depth relations such as that proposed for offshore Western Australia by Vuckovic (1989): Leak -off pressure (psi) = 0.197D1145, where D is depth in feet. A modified form of the uniaxial elastic relation for the prediction of σhmin is proposed, such that: where the constants c and d are straight line regression constants derived from cross -plotting effective minimum horizontal stress and effective vertical stress. This relation, as opposed to previous empirical approaches to fracture gradient /σhmin determination, yields regression coefficients of physical significance: c represents the average Poisson's ratio term, v /(1 -v), and d represents an estimate of the tectonic (and inelastic) component of the minimum horizontal stress. This application of the modified fracture gradient relation, termed the effective stress cross -plot method, is tested successfully against published data from experimental wells in the East Texas Basin where independent estimates of Poisson's ratio are available. Leak -off pressures have been compiled from 61 wells in the Timor Sea. Leak -off pressures in the Timor Sea are somewhat lower than predicted by Vuckovic's (1989) stress /depth relation for offshore Western Australia, and a new, empirical stress /depth relation, which better fits the Timor Sea data is proposed: The effective stress cross -plot method is also applied to the Timor Sea data, yielding: Detailed pore pressure data were not available for the Timor Sea data -set and the effective stress cross -plot method does not fit the observed data any better than the new empirical stress /depth relation. However, the regression constants suggest an average Poisson's ratio of 0.26 and a relatively insignificant tectonic stress of 1 MPa for the Timor Sea.
Publisher: American Geophysical Union (AGU)
Date: 15-10-2000
DOI: 10.1029/2000GL011538
Publisher: American Geophysical Union (AGU)
Date: 15-10-2000
DOI: 10.1029/2000GL011537
Publisher: Elsevier BV
Date: 12-1996
Publisher: Geological Society of London
Date: 09-2000
Abstract: Knowledge of the in situ stress field of the Australian continent has increased greatly since compilation of the World Stress Map in 1992, principally by analysis of borehole breakouts and drilling-induced tensile fractures in petroleum wells. Stress orientations are variable across the Australian continent as a whole. However, within 15 of 16 in idual stress provinces defined in the Australian continent (of one to a few hundred kilometres scale), mean stress orientations are statistically significant. The stress provinces, and stress trajectory mapping, reveal that there are systematic, continental-scale rotations of stress orientation within Australia. Unlike many other continental areas, stress orientations do not parallel the direction of absolute plate motion. Nonetheless, the regional pattern of stress orientation is consistent with control by plate boundary forces, if the complex nature of the convergent northeastern boundary of the Indo-Australian plate, and stress focusing by collisional segments of the boundary, is recognized.
Publisher: CSIRO Publishing
Date: 2011
DOI: 10.1071/AJ10017
Abstract: There is growing recognition that many passive margins have undergone compressional deformation subsequent to continental breakup, including the southern Australian margin. This deformation commonly results in formation of domal anticlines with four-way dip closures that are attractive targets for hydrocarbon exploration, and many such structures host major hydrocarbon accumulations in the Otway and Gippsland basins however, the driving mechanisms behind formation of these structures are not completely understood. We compare the history of post-breakup compression in the Otway Basin of the southern Australian margin, with that of the Rockall-Faroe area of the northeast Atlantic margin, which has been far more extensively studied with the aim of establishing a better understanding of the genesis and prospectivity of such structures. Both margins have experienced protracted Mesozoic rifting histories culminating in final continental separation in the Eocene, followed by distinct phases of compressional deformation and trap formation. Whilst the structural style of the anticlines in both margins is similar (mainly fault-propagation folds formed during tectonic inversion), the number, litude, and length of the structures in the northeast Atlantic margin are much higher than the southern Australian margin. We propose that compressional structures at both margins formed due to far-field stresses related to plate boundaries, but the magnitude of these stresses in the northeast Atlantic margin is likely to have been higher, and the strength of the lithosphere lower. In the northeast Atlantic margin, the presence of Early Cenozoic basalt lava flows may have also contributed to an increase in pore-fluid pressure in the underlying sediment making pre-existing faults more prone to reactivation.
Publisher: Geological Society of America
Date: 2003
Publisher: Geological Society of London
Date: 08-2009
Publisher: Geological Society of America
Date: 07-2010
DOI: 10.1130/G30881.1
Publisher: Elsevier BV
Date: 02-2010
Publisher: Elsevier BV
Date: 2011
Publisher: Society of Economic Geologists
Date: 2014
DOI: 10.5382/SP.18.12
Publisher: Geological Society of America
Date: 2008
DOI: 10.1130/G24699A.1
Publisher: Geological Society of London
Date: 11-2017
DOI: 10.1144/JGS2017-076
Publisher: Informa UK Limited
Date: 09-2006
DOI: 10.1071/EG06215
Publisher: CSIRO Publishing
Date: 2010
DOI: 10.1071/AJ09029
Abstract: GeoScience Victoria and partners have undertaken the first detailed basin-wide study of the regional top seal in the Gippsland Basin. The Gippsland Basin is an attractive site for geological carbon storage (GCS) because of the close proximity to emission sources and the potential for large-scale storage projects. This top seal assessment involved the analysis of seal attributes (geometry, capacity and mineralogy) and empirical evidence for seal failure (soil gas geochemical anomalies, gas chimneys, hydrocarbon seepage and oil slicks). These datasets have been integrated to produce a qualitative evaluation of the containment potential for GCS, and also hydrocarbons, across the basin. Mineralogical analysis of the top seal has revealed that the Lakes Entrance Formation is principally a smectite-rich claystone. The geometry of the top seal is consistent with deposition in an early post-rift setting where marine sediments filled palaeo-topographic lows. The seal thickness and depth to seal base are greatest in the Central Deep and decrease toward the margins. There is a strong positive relationship between seal capacity column heights, seal thickness, depth to seal base and smectite content. At greater burial depths (below 700 m) and where smectite content is greater than 70%, seal capacity is increased (supportable column heights above 150 m). Natural hydrocarbon leakage and seepage onshore and offshore is correlated with fault distribution and areas of poor seal capacity. This study provides a framework for qualitatively evaluating seal potential at a basin scale. It has shown that the potential of the regional top seal over the Central Deep, Southern Terrace, central eastern Lake Wellington Depression and the southern to central near shore areas in the Seaspray Depression are most suitable for the containment of supercritical CO2. Further toward the margin of the regional seal in both onshore and offshore areas, containment of supercritical CO2 is less likely.
Publisher: SPE
Date: 20-10-2002
DOI: 10.2118/78226-MS
Abstract: A Mohr-Coulomb failure criterion is applied to estimate fluid pressures that may cause fault reactivation during the depletion of hydrocarbon reservoirs. The estimates incorporate the decline in total minimum horizontal stress that accompanies fluid pressure depletion in hydrocarbon reservoirs. Such pore pressure/stress coupling must be incorporated in predictions of depletion-induced failure because it significantly influences the fluid pressures at which faulting occurs. A new algorithm for failure incorporating the coupled decrease in pore pressure and stress is derived to calculate the fluid pressures that can cause slip on normal faults during ongoing production. The algorithm is applied to the Ekofisk reservoir, Norway, using various friction coefficients for chalk and incorporating the observation that the minimum horizontal stress decreased at 80% the rate of pore pressure depletion in the field. A friction coefficient of 0.6 yields realistic results when modelling the depletion period 1975 to 1990. A fluid pressure decrease from the initial 45 MPa to 38 MPa is required to activate optimally oriented faults with dip angles of approximately 60°. This fluid pressure level (38 MPa) was attained in 1978-1980 and marks the onset of significant subsidence in the Ekofisk field. Ongoing fluid pressure depletion from 38 MPa to the present level of approximately 25 MPa is sufficient for sliding on faults with dip angles of 48° to 73°. Preexisting fractures in the Ekofisk reservoir fall in this range, as they exhibit predominantly steep dip angles (65°). Slip events recorded during seismic monitoring that was conducted in 1994, are likely to represent the reactivation of such steeply dipping faults and possibly the formation of new fractures. The modelling technique presented for predicting induced reservoir and fault failure is an essential requirement for the long-term planning of hydrocarbon field depletion.
Publisher: Informa UK Limited
Date: 07-2007
Publisher: American Geophysical Union (AGU)
Date: 07-2002
DOI: 10.1029/2001JB000408
Publisher: Society of Petroleum Engineers (SPE)
Date: 06-1996
DOI: 10.2118/28176-PA
Abstract: Consideration of the stress field around an arbitrarily oriented borehole shows that in an extensional stress regime (σv σH& σh), wellbores parallel to the direction of minimum horizontal principal stress are the least prone to compressive shear failure (breakout). The most stable deviation angle (from the vertical) depends on the ratio of the horizontal principal stresses to the vertical stresses, and the higher the ratio σH/σV, the higher the deviation angle for minimizing breakout. In a strike-slip stress regime (σv & σH& σh), horizontal wells are the least prone to breakout, and the higher the ratio σH/σ v, the closer the drilling direction should be to the azimuth of σH. A new compressive shear failure criterion, which is a combination of the effective strength concept and the Drucker-Prager criterion, is proposed for quantifying the stresses at which borehole breakout occurs. The lowest mud weight, at and below which breakout will occur, can be predicted by combining this criterion with the stress field around an arbitrarily oriented borehole. The highest mud weight at and above which a tensional or hydraulic fracture is induced can be predicted by combining the tensile strength of the rocks of the wellbore wall with the stress field around an arbitrarily oriented borehole. For the in-situ stress environments considered, the optimally oriented inclined wellbore is less prone to breakout (i.e., allows a lower mud weight) and tensional or hydraulic fracture (i.e., supports a higher mud weight) than a vertical well.
Publisher: Elsevier BV
Date: 2011
Publisher: Elsevier BV
Date: 04-2005
Publisher: Informa UK Limited
Date: 09-1993
DOI: 10.1071/EG993567
Publisher: American Geophysical Union (AGU)
Date: 10-01-1998
DOI: 10.1029/97JB02381
Publisher: Geological Society of London
Date: 1995
Publisher: American Geophysical Union (AGU)
Date: 09-2008
DOI: 10.1029/2007JB005324
Publisher: Informa UK Limited
Date: 03-1997
DOI: 10.1071/EG997088
Publisher: Geological Society of America
Date: 2003
Publisher: Geological Society of London
Date: 07-1991
Publisher: Geological Society of London
Date: 2003
Publisher: Elsevier BV
Date: 07-2004
Publisher: Informa UK Limited
Date: 09-1993
DOI: 10.1071/EG993561
Publisher: Geological Society of London
Date: 2003
Publisher: Geological Society of London
Date: 21-06-2010
Publisher: Elsevier BV
Date: 12-1993
Publisher: SPE
Date: 04-11-1991
DOI: 10.2118/23015-MS
Abstract: Wellbore instability poses a significant problem for many wells drilled on the Northwest Shelf of Australia. With the discovery of the Wanaea and Cossack oilfields, research work has focused on an investigation involving the measurement of shale properties, analysis of operations and well logs and the application of this information to the analysis of wellbore stress and instability.
Publisher: Geological Society of London
Date: 2017
DOI: 10.1144/SP458.10
Publisher: Elsevier BV
Date: 06-1994
Publisher: Informa UK Limited
Date: 06-1992
DOI: 10.1071/EG992489
Publisher: Informa UK Limited
Date: 03-1999
DOI: 10.1071/EG999033
Publisher: Geological Society of London
Date: 2017
DOI: 10.1144/SP458.15
Publisher: Geological Society of London
Date: 09-08-2012
DOI: 10.1144/SP367.6
Abstract: The Ceduna Sub-basin is located within the Bight Basin on the Australian southern margin. Recent structural analysis using newly acquired two-dimensional (2D) and three-dimensional (3D) seismic data demonstrates two Late Cretaceous delta–deepwater fold–thrust belts (DDWFTBs), which are overlain by Cenozoic sediments. The present-day normal fault stress regime identified in the Bight Basin indicates that the maximum horizontal stress ( S Hmax ) is margin parallel Andersonain faulting theory therefore suggests the delta-top extensional faults are oriented favourably for reactivation. A breached hydrocarbon trap encountered in the Jerboa-1 well demonstrates this fault reactivation. Faults interpreted from 3D seismic data were modelled using the Poly3D © geomechanical code to determine the risk of reactivation. Results indicate delta-top extensional faults that dip 40–70° are at moderate–high risk of reactivation, while variations in the orientation of the fault planes results in an increased risk of reactivation. Two pulses of inversion are identified in the Ceduna Sub-basin and correlate with the onset of rifting and fault reactivation in the Santonian. We propose a ridge-push mechanism for this stress which selectively reactivates extensional faults on the delta-top, forming inversion anticlines that are prospective for hydrocarbon exploration.
Publisher: Informa UK Limited
Date: 12-2003
Publisher: Geological Society of America
Date: 2007
DOI: 10.1130/G23906A.1
Publisher: Geological Society of London
Date: 2005
DOI: 10.1144/0060551
Publisher: Oxford University Press (OUP)
Date: 09-05-2013
DOI: 10.1093/GJI/GGT139
Publisher: Informa UK Limited
Date: 07-2008
Publisher: Informa UK Limited
Date: 09-2004
DOI: 10.1071/EG04217
Publisher: CSIRO Publishing
Date: 2005
DOI: 10.1071/AJ04036
Abstract: Juxtaposition mapping of lithology onto the Ladbroke Grove Fault plane shows that the Pretty Hill Sandstone reservoir, which hosts a 90 m gas column, juxtaposes massive shale units in the hangingwall. Retention of the column at Ladbroke Grove can thus be attributed to favourable across-fault, reservoir-seal juxtaposition. The free water level (FWL) of the Ladbroke Grove column coincides with an abrupt change in strike of the fault from east–west to northwest–southeast. Fault re-activation risking using the FAST (Fault Analysis Seals Technology) technique indicates that the northwest–southeast striking segment of the fault is critically oriented within the in-situ stress field for reactivation, whereas the more east–west trending segment is associated with a relatively lower risk of fault re-activation. Hence recent slip along the northwest–southeast segment may have created permeable fracture networks along this part of the fault plane and thus limited the extent of the column to that bounded by the east–west trending fault segment. This hypothesis is supported by data on soil gases acquired across the fault which suggest that the fault is leaking CO2 across its northwest–southeast striking segment, but not across its east–west striking segment.The Pyrus Fault is not presently sealing by across-fault, reservoir-seal juxtaposition. The throw on the fault plane is sufficient to juxtapose the Katnook Sandstone in the hangingwall against the Pretty Hill Sandstone reservoir in the footwall, providing a sand-on-sand juxtaposition leak point at the structural apex of the trap. Fault re-activation along this fault is likely to have caused fracturing of any shale gouge veneer that may have been present along this sand-on-sand contact resulting in across-fault leakage of hydrocarbons into the Katnook Sandstone and leakage up the fault along permeable fracture networks. FAST predictions of fault re-activation show that the fault is critically oriented within the in-situ stress field for re-activation and soil gas measurements at the surface suggest the fault is leaking CO2.
Publisher: American Association of Petroleum Geologists AAPG/Datapages
Date: 03-2003
DOI: 10.1306/10100201135
Publisher: Elsevier BV
Date: 09-2010
Publisher: Geological Society of London
Date: 11-1994
Publisher: CSIRO Publishing
Date: 2011
DOI: 10.1071/AJ10028
Abstract: This paper reports the first evidence for significant overpressures in the Otway Basin, southern Australia, where most previous studies have assumed near-hydrostatic pore pressures. Overpressures are observed in the Upper Cretaceous Shipwreck supersequence in several wells in the Voluta Trough, such as Bridgewater Bay–1, Normanby–1 and Callister–1. One of these wells penetrated successions of Pliocene-Recent marine clastic sediments nearly 700 m thick that were deposited rapidly in submarine channels and that were probably carved during the late-Miocene to early-Pliocene. Wireline and drilling data suggest that overpressures present in Upper Cretaceous shales and sandstones in the Belfast Mudstone and Flaxman and Waarre formations developed either due to disequilibrium compaction—where there is no evidence of hydrocarbon generation and thick Pliocene stratigraphy is present—or due to fluid expansion where there is evidence of hydrocarbon generation and the Pliocene stratigraphy is thin to absent. The two key factors that may indicate abnormal pore pressures in Upper Cretaceous sediments in the central Otway Basin are the thickness of Pliocene stratigraphy and whether or not hydrocarbons are actively generating from source rocks.
Publisher: Geological Society of London
Date: 06-1992
Publisher: Geological Society of London
Date: 2003
Publisher: Geological Society of London
Date: 11-1993
Publisher: Cambridge University Press (CUP)
Date: 11-1996
Publisher: Informa UK Limited
Date: 10-1999
Publisher: Informa UK Limited
Date: 03-2000
DOI: 10.1071/EG00441
Publisher: Informa UK Limited
Date: 03-2000
DOI: 10.1071/EG00448
Publisher: Geological Society of London
Date: 1995
Publisher: Wiley
Date: 14-04-2003
Publisher: CSIRO Publishing
Date: 2002
DOI: 10.1071/AJ01067
Abstract: 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 C anian extension associated with Tasman Rifting C anian 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. ersus 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.
Publisher: Informa UK Limited
Date: 04-2005
Publisher: Informa UK Limited
Date: 06-1995
DOI: 10.1071/EG995412
Publisher: Elsevier BV
Date: 05-2017
Publisher: Geological Society of London
Date: 08-1999
Publisher: Elsevier BV
Date: 03-2006
Publisher: Elsevier BV
Date: 02-2010
Publisher: SPE
Date: 20-10-2002
DOI: 10.2118/78213-MS
Abstract: Fault sealing is one of the key factors controlling hydrocarbon accumulations and can be a significant influence on reservoir behavior during production. Fault seal is, therefore, a major exploration and production uncertainty that requires a rigid, systematic framework within which to quantify the geological risk of trapping hydrocarbons. One of the key uncertainties in this risking procedure is the breaching of structurally bound traps due to the formation of structural permeability networks. Considering a population of faults and fractures, those that are critically stressed are more prone to act as conduits for fluid transmission. Evaluation and mapping of fault seal breach through such networks involves integration of in-situ stress conditions, pore pressure, fault architecture and fault geomechanics. Geomechanical characterization of well-lithified fault rocks from the Otway Basin and the Northwest Shelf demonstrates that faults can exhibit significant cohesive strength and that fault reactivation and trap breach is influenced by the development of shear, tensile and mixed-mode fractures. The mechanics of the reactivation process are influenced by grain strength and fault morphology. Mercury injection capillary pressures of cataclastic faults indicate a seal capacity of 2400 psi. Following reactivation, seal capacity is reduced ∼95% due to the development of a highly connected fracture network. The tensile strength of such healed faults allows failure to occur by shear, tensile and mixed mode fracturing. These data suggest simple application of Byerlee's Law may not always be applicable when predicting reactivation induced fault seal failure. Consequently, geomechanical tools used to predict trap breach via reactivation that assume cohesionless frictional failure are likely to significantly underestimate seal reactivation risk. The impact of structurally risking traps using Byerlee and laboratory-derived fault data is demonstrated using the Fault Seal Risk Web approach. Application of geomechanical fault data results in a significant reappraisal of prospect structural risk due to consideration of fault healing.
Publisher: Elsevier BV
Date: 02-2010
Publisher: Geological Society of London
Date: 2008
DOI: 10.1144/SP306.4
Publisher: Geological Society of London
Date: 2008
DOI: 10.1144/SP306.3
Publisher: American Geophysical Union (AGU)
Date: 20-03-1992
DOI: 10.1029/91GL02949
Publisher: Geological Society of London
Date: 09-08-2012
DOI: 10.1144/SP367.7
Abstract: Parts of the Australian continent, including the Otway Basin of the southern Australian margin, exhibit unusually high levels of neotectonic deformation for a so-called stable continental region. The onset of deformation in the Otway Basin is marked by a regional Miocene–Pliocene unconformity and inversion and exhumation of the Cretaceous–Cenozoic basin fill by up to c . 1 km. While it is generally agreed that this deformation is controlled by a mildly compressional intraplate stress field generated by the interaction of distant plate-boundary forces, it is less clear whether the present-day record of deformation manifested by seismicity is representative of the longer-term geological record of deformation. We present estimates of strain rates in the eastern Otway Basin since 10 Ma based on seismic moment release, geological observations, exhumation measurements and structural restorations. Our results demonstrate significant temporal variation in bulk crustal strain rates, from a peak of c . 2×10 −16 s −1 in the Miocene–Pliocene to c . 1.09×10 −17 s −1 at the present day, and indicate that the observed exhumation can be accounted for solely by crustal shortening. The Miocene–Pliocene peak in tectonic activity, along with the orthogonal alignment of inverted post-Miocene structures to measured and predicted maximum horizontal stress orientations, validates the notion that plate-boundary forces are capable of generating mild but appreciable deformation and uplift within continental interiors.
Publisher: Geological Society of London
Date: 12-2001
Publisher: Geological Society of London
Date: 06-10-2015
DOI: 10.1144/JGS2015-048
Publisher: Geological Society of London
Date: 02-1998
Publisher: Geological Society of London
Date: 1995
Publisher: Geological Society of London
Date: 1995
Publisher: Informa UK Limited
Date: 07-2011
Publisher: Elsevier BV
Date: 12-1994
Publisher: Informa UK Limited
Date: 03-1991
DOI: 10.1071/EG991189
Publisher: CSIRO Publishing
Date: 2006
DOI: 10.1071/AJ05016
Abstract: There have been several studies, both published and unpublished, of the present-day state-of-stress of southeast Australia that address a variety of geomechanical issues related to the petroleum industry. This paper combines present-day stress data from those studies with new data to provide an overview of the present-day state-of-stress from the Otway Basin to the Gippsland Basin. This overview provides valuable baseline data for further geomechanical studies in southeast Australia and helps explain the regional controls on the state-of-stress in the area.Analysis of existing and new data from petroleum wells reveals broadly northwest–southeast oriented, maximum horizontal stress with an anticlockwise rotation of about 15° from the Otway Basin to the Gippsland Basin. A general increase in minimum horizontal stress magnitude from the Otway Basin towards the Gippsland Basin is also observed. The present-day state-of-stress has been interpreted as strike-slip in the South Australian (SA) Otway Basin, strike-slip trending towards reverse in the Victorian Otway Basin and borderline strike-slip/reverse in the Gippsland Basin. The present-day stress states and the orientation of the maximum horizontal stress are consistent with previously published earthquake focal mechanism solutions and the neotectonic record for the region. The consistency between measured present-day stress in the basement (from focal mechanism solutions) and the sedimentary basin cover (from petroleum well data) suggests a dominantly tectonic far-field control on the present-day stress distribution of southeast Australia. The rotation of the maximum horizontal stress and the increase in magnitude of the minimum horizontal stress from west to east across southeast Australia may be due to the relative proximity of the New Zealand segment of the plate boundary.
Publisher: Wiley
Date: 22-02-2010
Publisher: CSIRO Publishing
Date: 1999
DOI: 10.1071/AJ98004
Abstract: The dominant cause of overpressure in basins is rapid loading of fine-grained sediments in which incomplete dewatering leads to additional overburden load being supported partly by the pore fluids. The principal controls on the magnitude of overpressure created are permeability and compressibility of the fine-grained rocks, coupled with the loading or sedimentation rate. High magnitude overpressure requires rapid sedimentation and/or evolution of sediment permeability to nanoDarcy values at shallow depth. By contrast, most fluid expansion mechanisms can be shown to be ineffective at generating large magnitude overpressure at realistic basin conditions. Only gas generation (either directly from kerogen or by oil to gas cracking) has the potential to create large magnitude overpressure, and only if the connected reservoir volume is very restricted.The origin of overpressure in the North West Shelf, especially the Northern Carnarvon Basin has previously been suggested to be due to petroleum generation, principally because the top of overpressure is coincident with, or lies below, the hydrocarbon generation window. To achieve high magnitude overpressure by this mechanism requires large volumes of gas generative source rocks connected to reservoirs of extremely limited extent. The volume of reservoir rocks in the basins is relatively high, and gas generation appears to be only a secondary mechanism. The most likely origin of overpressure is burial of the Jurassic and Lower Cretaceous group sediments (including the Muderong Shale) with early development of the Muderong Shale as a pressure seal. Lateral stress cannot be discounted as an additional mechanism of overpressure generation. However, lateral strain appears to be significantly less than vertical strain.Overpressure has the potential to influence the petroleum system in the North West Shelf if there has been high magnitude overpressure for prolonged periods of geological time. Normally pressured units today may have had a history of overpressure in the geological past. Reservoir quality can be enhanced by overpressure, but trap seal integrity either strengthened or weakened by overpressure. Timing of maturation and migration of hydrocarbon can also be affected.
Publisher: Geological Society of London
Date: 2008
DOI: 10.1144/SP306.10
Publisher: Schweizerbart
Date: 03-07-2002
Publisher: CSIRO Publishing
Date: 2001
DOI: 10.1071/AJ00009
Abstract: Deep basin hydrocarbon accumulations have been widely recognised in North America and include the giant fields of Elmworth and Hoadley in the Western Canadian Basin. Deep basin accumulations are unconventional, being located downdip of water-saturated rocks, with no obvious impermeable barrier separating them. Gas accumulations in the Nappamerri Trough, Cooper Basin, exhibit several characteristics consistent with North American deep basin accumulations. Log evaluation suggests thick gas columns and tests have recovered only gas and no water. The resistivity of the entire rock section exceeds 20 Ωm over large intervals, and, as in known deep basin accumulations, the entire rock section may contain gas. Gas in the Nappamerri Trough is located within overpressured compartments which witness the hydraulic isolation necessary for gas saturation outside conventional closure. Furthermore, the Nappamerri Trough, like known deep basin accumulations, has extensive, coal-rich source rocks capable of generating enormous hydrocarbon volumes. The above evidence for a deep basin-type gas accumulation in the Nappamerri Trough is necessarily circumstantial, and the existence of a deep gas accumulation can only be proven unequivocally by drilling wells outside conventional closure.Exploration for deep basin-type accumulations should focus on depositional-structural-diagenetic sweet spots (DSDS), irrespective of conventional closure. This is of particular significance for a potential Nappamerri Trough deep basin accumulation because depositional models suggest that the best net/gross may be in structural lows, inherited from syndepositional lows, that host stacked channel sands within channel belt systems. Limiting exploration to conventionally-trapped gas may preclude intersection with such sweet spots.
Publisher: Geological Society of London
Date: 1992
Publisher: Oxford University Press (OUP)
Date: 21-12-2004
Publisher: CSIRO Publishing
Date: 2011
DOI: 10.1071/AJ10044
Abstract: We present results from a margin-wide analysis of the history of post-breakup Cenozoic compressional deformation and related exhumation along the passive southern margin of Australia, based on a regional synthesis of seismic, stratigraphic and thermochronological data. The Cenozoic sedimentary record of the southern margin contains regional unconformities of intra-Lutetian and late Miocene–Pliocene age, which coincide with reconfigurations of the boundaries of the Indo-Australian Plate. Seismic data show that post-breakup compressional deformation and sedimentary basin inversion—characterised by reactivation of syn-rift faults and folding of post-rift sediments—is pervasive from the Gulf St Vincent to Gippsland basins, and occurred almost continually since the early- to mid-Eocene. Inversion structures are absent from the Bight Basin, which we interpret to be the result of both the unsuitable orientation of faults for reactivation with respect to post-breakup stress fields, and the colder, stronger lithosphere that underlies that part of the margin. Compressional deformation along the southeastern margin has mainly been accommodated by reactivation of syn-rift faults, resulting in folds with varying ages and litudes in the post-rift Cenozoic succession. Many hydrocarbon fields in the Otway and Gippsland basins are located in these folds, the largest of which are often associated with substantial localised exhumation. Our results emphasise the importance of constraining the timing of Cenozoic compression and exhumation in defining hydrocarbon prospectivity of the southern margin.
No related grants have been discovered for Richard Hillis.