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Published: 10 December 2022
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1

Luxton, C. W., S. T. Horan, D. L. Pickavance, and M. S. Durham. "THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN." APPEA Journal 35, no. 1 (1995): 405. http://dx.doi.org/10.1071/aj94026.

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In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.
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2

Arditto, P. A. "THE EASTERN OTWAY BASIN WANGERRIP GROUP REVISITED USING AN INTEGRATED SEQUENCE STRATIGRAPHIC METHODOLOGY." APPEA Journal 35, no. 1 (1995): 372. http://dx.doi.org/10.1071/aj94024.

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Recent exploration by BHP Petroleum in VIC/ P30 and VIC/P31, within the eastern Otway Basin, has contributed significantly to our understanding of the depositional history of the Paleocene to Eocene siliciclastic Wangerrip Group. The original lithostratigraphic definition of this group was based on outcrop description and subsequently applied to onshore and, more recently, offshore wells significantly basinward of the type sections. This resulted in confusing individual well lithostratigraphies which hampered traditional methods of subsurface correlation.A re-evaluation of the Wangerrip Group stratigraphy is presented based on the integration of outcrop, wireline well log, palynological and reflection seismic data. The Wangerrip Group can be divided into two distinct units based on seismic and well log character. A lower Paleocene succession rests conformably on the underlying Maastrichtian and older Sherbrook Group, and is separated from an overlying Late Paleocene to Eocene succession by a significant regional unconformity. This upper unit displays a highly progradational seismic character and is named here as the Wangerrip Megasequence.Regional seismic and well log correlation diagrams are used to illustrate a subdivision of the Wangerrip Megasequence into eight third-order sequences. This sequence stratigraphic subdivision of the Wangerrip Group is then used to construct a chronostratigraphic chart for the succession within this part of the Otway Basin.
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3

Heath, A. M., A. L. Culver, and C. W. Luxton. "Gathering good seismic data from the Otway Basin." Exploration Geophysics 20, no. 2 (1989): 247. http://dx.doi.org/10.1071/eg989247.

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Cultus Petroleum N.L. began exploration in petroleum permit EPP 23 of the offshore Otway Basin in December 1987. The permit was sparsely explored, containing only 2 wells and poor quality seismic data. A regional study was made taking into account the shape of the basin and the characteristics of the major seismic sequences. A prospective trend was recognised, running roughly parallel to the present shelf edge of South Australia. A new seismic survey was orientated over this prospective trend. The parameters were designed to investigate the structural control of the prospects in the basin. To improve productivity during the survey, north-south lines had to be repositioned due to excessive swell noise on the cable. The new line locations were kept in accordance with the structural model. Field displays of the raw 240 channel data gave encouraging results. Processing results showed this survey to be the best quality in the area. An FK filter was designed on the full 240 channel records. Prior to wavelet processing, an instrument dephase was used to remove any influence of the recording system on the phase of the data. Close liaison was kept with the processing centre over the selection of stacking velocities and their relevance to the geological model. DMO was found to greatly improve the resolution of steeply dipping events and is now considered to be part of the standard processing sequence for Otway Basin data. Seismic data of a high enough quality for structural and stratigraphic interpretation can be obtained from this basin.
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4

Moriarty, N. J. "3-D Seismic Surveying in the Otway Basin." Exploration Geophysics 26, no. 2-3 (June 1, 1995): 362–73. http://dx.doi.org/10.1071/eg995362.

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5

Cliff, D. C. B., S. C. Tye, and R. Taylor. "THE THYLACINE AND GEOGRAPHE GAS DISCOVERIES, OFFSHORE EASTERN OTWAY BASIN." APPEA Journal 44, no. 1 (2004): 441. http://dx.doi.org/10.1071/aj03017.

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The Thylacine and Geographe gas fields were discovered in mid-2001 in the offshore Otway Basin, in permits T/30P and VIC/P43 respectively. Geographe is 55 km south of Port Campbell and Thylacine is a further 15 km offshore, in the depo-centre of the Shipwreck Trough, in water depths of 80 m to 100 m. The Thylacine–1 well intersected a 277 m gas column in Turonian to Santonian aged reservoirs. Geographe–1 intersected a 233 m gas column in a similar sedimentary section. Thylacine–2, 5.7 km west of Thylacine–1, confirmed the field extent, and flowed gas at 28 MMSCFD (0.79 Mm3/D). Critical to the discovery of these fields was the Investigator 3D seismic survey, which covered about 1,000 km2 of the central Shipwreck Trough. The pre-drill chance of success of both structures was high-graded as a result of excellent structural imaging and the conformance of amplitude and AVO anomalies to mapped closures. The interpretation of this survey and the subsequent drilling of the Thylacine and Geographe Fields have dramatically increased the understanding of the structure and stratigraphy of the offshore eastern Otway Basin particularly in relation to the Shipwreck Trough and the Sorell Fault Zone.Combined dry gas reserves at the proved and probable level stand at 0.85 TCF and condensate reserves at 10.7 MMBBL. The fields are undergoing integrated sub-surface, development and environmental studies with the aim of supplying the nearby southeastern Australian gas markets. The preferred development concept is a small jacket structure at Thylacine, followed by a subsea tie-in of the Geographe Field with onshore processing facilities near Port Campbell.
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6

Stacey, Andrew, Cameron Mitchell, Goutam Nayak, Heike Struckmeyer, Michael Morse, Jennie Totterdell, and George Gibson. "Geology and petroleum prospectivity of the deepwater Otway and Sorell basins: new insights from an integrated regional study." APPEA Journal 51, no. 2 (2011): 692. http://dx.doi.org/10.1071/aj10072.

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The frontier deepwater Otway and Sorell basins lie offshore of southwestern Victoria and western Tasmania at the eastern end of Australia’s Southern Rift System. The basins developed during rifting and continental separation between Australia and Antarctica from the Cretaceous to Cenozoic. The complex structural and depositional history of the basins reflects their location in the transition from an orthogonal–obliquely rifted continental margin (western–central Otway Basin) to a transform continental margin (southern Sorell Basin). Despite good 2D seismic data coverage, these basins remain relatively untested and their prospectivity poorly understood. The deepwater (> 500 m) section of the Otway Basin has been tested by two wells, of which Somerset–1 recorded minor gas shows. Three wells have been drilled in the Sorell Basin, where minor oil shows were recorded near the base of Cape Sorell–1. As part of the federal government-funded Offshore Energy Security Program, Geoscience Australia has acquired new aeromagnetic data and used open file seismic datasets to carry out an integrated regional study of the deepwater Otway and Sorell basins. Structural interpretation of the new aeromagnetic data and potential field modelling provide new insights into the basement architecture and tectonic history, and highlights the role of pre-existing structural fabric in controlling the evolution of the basins. Regional scale mapping of key sequence stratigraphic surfaces across the basins, integration of the regional structural analysis, and petroleum systems modelling have resulted in a clearer understanding of the tectonostratigraphic evolution and petroleum prospectivity of this complex basin system.
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7

Moriarty, Noll. "Otway Basin Onshore Seismic Acquisition: Less Field Effort = Better Data Quality." Exploration Geophysics 23, no. 1-2 (March 1992): 231–40. http://dx.doi.org/10.1071/eg992231.

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8

O'Callaghan, E. J. "3-D Visualisation of Transpressional Structures in the Eastern Otway Basin." Exploration Geophysics 24, no. 3-4 (September 1993): 743–50. http://dx.doi.org/10.1071/eg993743.

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9

Lovibond, R., and M. Rauch. "AVO as an Exploration Tool in the Penola Trough, Otway Basin." Exploration Geophysics 26, no. 2-3 (June 1, 1995): 448–55. http://dx.doi.org/10.1071/eg995448.

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10

Pettifer, G., A. Tabassi, and B. Simons. "A NEW LOOK AT THE STRUCTURAL TRENDS IN THE ONSHORE OTWAY BASIN, VICTORIA, USING IMAGE PROCESSING OF GEOPHYSICAL DATA." APPEA Journal 31, no. 1 (1991): 213. http://dx.doi.org/10.1071/aj90016.

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Although the Otway Basin is oriented west-north-westerly, and previously recognised major structural elements follow a similar trend, other structural trends have been found on recently obtained geophysical data.In 1989, an aeromagnetic and radiometric survey of the onshore Otway Basin was completed for the Victorian Department of Industry and the Bureau of Mineral Resources, Geology and Geophysics. This survey, together with a recent gravity compilation by the Geological Survey of Victoria, enables analysis of magnetic and gravity data trends reflecting basement and intra-basin structure.The trend analysis was carried out using modern image processing techniques including simulation of real-time sun-angles of the magnetic and gravity data, and composite images of the radiometric data, to highlight lineaments. This technology enables integration of magnetic, gravity, radiometric and, potentially, seismic, Landsat, topography and bathymetry data for basin structure analysis.The magnetic, gravity and radiometric trend analysis was compared to an earlier Landsat study (Baker, 1980) and a previous seismic data compilation of the Otway Basin (Megallaa, 1986).The present study has revealed the significance of major early Palaeozoic north-south and east-north-east to easterly trends. The latter trends have not previously been identified or discussed in earlier basin reviews. There appears to be a difference between trends reflected in the radiometric and seismic data and trends apparent in the gravity and magnetic data. This could indicate a change in principal stress directions during the evolution of the basin. The shape of the northern margin of the basin appears to be controlled by major north-easterly structures.
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11

Bernecker, Thomas, George Bernardel, Claire Orlov, and Nadège Rollet. "Petroleum geology of the 2018 offshore acreage release areas." APPEA Journal 58, no. 2 (2018): 437. http://dx.doi.org/10.1071/aj17056.

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A total of 21 areas were released in 2018 for offshore petroleum exploration. They are located in the Bonaparte, Browse, Northern Carnarvon, Bight, Otway and Gippsland basins. All release areas were supported by industry nominations, indicating that interest in exploring Australia’s offshore basins remains strong, despite the significant decrease in the number of exploration wells drilled in recent years. Sixteen areas are being released under the work program bidding system with two rounds, one closing on 18 October 2018 and the other on 21 March 2019. Five areas are being released for cash bidding and include the producible La Bella gas accumulation in the Otway Basin. Prequalification for participation in the cash-bid auction closes on 4 October 2018 with the auction scheduled for 7 February 2019. Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available as part of the agency’s regional petroleum geological studies. The regional evaluation of the petroleum systems in the Browse Basin has been completed and work continues on assessing the distribution of Early Triassic source rocks and related petroleum occurrences across the North West Shelf. A wealth of seismic and well data, submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006, are made available through the National Offshore Petroleum Information Management System. Additional datasets are accessible through Geoscience Australia’s data repository.
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12

Brassil, F. M., S. P. Kravis, and P. E. Williamson. "The Role of Intensive Seismic Reflection Processing in Understanding the Offshore Otway Basin." Exploration Geophysics 19, no. 1-2 (March 1988): 29–32. http://dx.doi.org/10.1071/eg988029.

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13

Eglington, Col. "Marine Ostracoda (Crustacea) from the Late Oligocene Gellibrand Marl, Otway Basin, Victoria, Australia." Proceedings of the Royal Society of Victoria 131, no. 2 (2019): 53. http://dx.doi.org/10.1071/rs19009.

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A subsurface sample from Heywood-10 borehole, Otway Basin, Victoria, has provided the first ostracod assemblage of Oligocene age from the Gellibrand Marl (Heytesbury Group). Previous Gellibrand Marl ostracod assemblages were Miocene. This Late Oligocene assemblage of 384 specimens includes 50 species and subspecies from 34 genera across 18 families; 24 taxa are placed in open nomenclature. Of the taxa discussed, several appear to be new species but with too few specimens for them to be described as such. The reciprocal of Simpson’s Diversity Index was applied to assist assemblage comparisons. The Gellibrand Marl assemblage is larger, contains more families, genera and taxa but is less diverse than a smaller assemblage from the Early Oligocene Narrawaturk Formation (Nirranda Group) at the same location, and more diverse than an assemblage from the Early Oligocene/Ruwarung Member, South Australia. There are notable differences in the dominant taxa present in each assemblage. In the Gellibrand Marl, Pontocyprididae predominate; in Narrawaturk Formation, Cytheruridae and Xestoliberididae are most abundant; and in the South Australian assemblage, Bairdiidae by far the most numerous. This Gellibrand Marl collection has the characteristics of an at least partly allocthanous assemblage, the habitat a well-oxygenated mid-shelf environment. No cold or deep-water taxa are present.
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14

Finlayson, D. M., B. Finlayson, C. V. Reeves, P. R. Milligan, C. D. Cockshell, D. W. Johnstone, and M. P. Morse. "The Western Otway Basin — a Tectonic Framework from new Seismic, Gravity and Aeromagnetic Data." Exploration Geophysics 24, no. 3-4 (September 1993): 493–99. http://dx.doi.org/10.1071/eg993493.

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15

Gunn, P. J., J. Mitchell, T. Mackey, and D. Cathro. "Evolution and Structuring of the Offshore Otway Basin, Victoria as Delineated by Aeromagnetic Data." Exploration Geophysics 26, no. 2-3 (June 1, 1995): 303–8. http://dx.doi.org/10.1071/eg995262.

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16

Turner, Benjamin, and Steve Hearn. "Shear-wave splitting analysis using a single-source, dynamite VSP in the Otway Basin." Exploration Geophysics 26, no. 4 (September 1995): 519–26. http://dx.doi.org/10.1071/eg995519.

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17

Hill, K. A., G. T. Cooper, M. J. Richardson, and C. J. Lavin. "Structural Framework of the Eastern Otway Basin: Inversion and Interaction Between Two Major Structural Provinces." Exploration Geophysics 25, no. 2 (June 1994): 79–87. http://dx.doi.org/10.1071/eg994079.

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18

NICOLAIDES, STELIOS. "Marine-derived dolomite in the shallowly buried temperate Port Campbell Limestone (Miocene), Otway Basin, Australia." Sedimentology 44, no. 1 (February 1997): 143–57. http://dx.doi.org/10.1111/j.1365-3091.1997.tb00429.x.

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19

Falvey, D. A., P. A. Symonds, J. B. Colwell, J. B. Willcox, J. F. Marshall, P. E. Williamson, and H. M. J. Stagg. "AUSTRALIA'S DEEPWATER FRONTIER PETROLEUM BASINS AND PLAY TYPES." APPEA Journal 30, no. 1 (1990): 239. http://dx.doi.org/10.1071/aj89015.

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Vast areas of Australia's continental margin sedimentary basins lying seawards of the 200 m water depth line, or shelf edge, are under-explored for petroleum. Indeed, most are essentially unexplored. However, recent advances in drilling and production technology, as well as recent reconnaissance seismic, geochemical, geothermal and seabed sampling data collected by the Bureau of Mineral Resources' (BMR) Marine Division, may reduce the perceived economic risk of many of these deepwater basins relative to their shelf counterparts. Triassic reefs have been identified off the northern Exmouth Plateau and possibly in the deepwater Canning Basin, locally within a predicted oil window. In the deepwater North Perth Basin, major wrench structures have been identified. The deepwater areas of the Great Australian Bight and Otway Basin are actually the main depocentres of a major basin complex lying along the almost totally unexplored southern Australian continental margin. The Latrobe Group in the outer Gippsland Basin is likely to have similar geology to the well explored and productive shelf basin, but remains untested. The Queensland and Townsville troughs, in deepwater off northeast Australia, contain many significant structures typical of unbreached rift systems.All these areas have been risked relative to each other and their prospectivity assessed. The most attractive frontier areas in terms of relative risk may be the Otway and North Perth basins. The highest potential may occur in the deepwater rift troughs off northeast Australia, although the relative risk is very high. Triassic reefs of the Northwest Shelf may have the best prospectivity in the shorter term, given that they are known from drilling in a region with proven source potential and a substantial exploration infrastructure.
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20

Robson, A. G., R. C. King, and S. P. Holford. "3D seismic analysis of gravity-driven and basement influenced normal fault growth in the deepwater Otway Basin, Australia." Journal of Structural Geology 89 (August 2016): 74–87. http://dx.doi.org/10.1016/j.jsg.2016.06.002.

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21

Niyazi, Yakufu, Ovie Emmanuel Eruteya, Mark Warne, and Daniel Ierodiaconou. "Discovery of large-scale buried volcanoes within the Cenozoic succession of the Prawn Platform, offshore Otway Basin, southeastern Australia." Marine and Petroleum Geology 123 (January 2021): 104747. http://dx.doi.org/10.1016/j.marpetgeo.2020.104747.

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22

Rogers, Claire, Peter J. van Ruth, and Richard R. Hillis. "Fault reactivation in the Port Campbell Embayment with respect to carbon dioxide sequestration, Otway Basin, Australia." Geological Society, London, Special Publications 306, no. 1 (2008): 201–14. http://dx.doi.org/10.1144/sp306.10.

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23

Teasdale, J. P., L. L. Pryer, P. G. Stuart-Smith, K. K. Romine, M. A. Etheridge, T. S. Loutit, and D. M. Kyan. "STRUCTURAL FRAMEWORK AND BASIN EVOLUTION OF AUSTRALIA’S SOUTHERN MARGIN." APPEA Journal 43, no. 1 (2003): 13. http://dx.doi.org/10.1071/aj02001.

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The structural evolution of all of the Southern Margin Basins can be explained by episodic reactivation of basement structures in respect to a specific sequence of tectonic events. Three geological provinces dominate the basement geology of the Southern Margin basins. The Eyre, Ceduna, Duntroon and Polda Basins overlie basement of the Archean to Proterozoic Gawler-Antarctic Craton. The Otway and Sorell Basins overlie basement of the Neoproterozoic-early Palaeozoic Adelaide- Kanmantoo Fold Belt. The Bass and Gippsland Basins overlie basement of the Palaeozoic Lachlan Fold Belt. The contrasting basement terranes within the three basement provinces and the structures within and between them significantly influenced the evolution and architecture of the Southern Margin basins.The present-day geometry was established during three Mesozoic extensional basin phases:Late Jurassic–Early Cretaceous NW–SE transtension forming deep rift basins to the west and linked pullapart basins and oblique graben east of the Southwest Ceduna Accommodation Zone; Early–Mid Cretaceous NE–SW extension; and Late Cretaceous NNE–SSW extension leading to continental breakup. At least three, potentially trap forming, inversion events have variably influenced the Southern Margin basins; Mid Cretaceous, Eocene, and Miocene-Recent. Volcanism occurred along the margin during the Late Cretaceous and sporadically through the Tertiary.First-order structural control on Mesozoic rifting and breakup were east–west trending basement structures of the southern Australian fracture zone. Second-order controls include:Proterozoic basement shear zones and/or terrane boundaries in the western Gawler Craton, which controlled basin evolution in the Eyre and Ceduna Subbasins; Neoproterozoic structures, which significantly influenced basin evolution in the Ceduna sub-basin; Cambro-Ordovician basement shear zones and/or terrane boundaries, which were a primary control on basin evolution in the Otway and Sorell Basins; and Palaeozoic structures in the Lachlan Fold Belt, which controlled basin evolution in the Bass and Gippsland Basins.A SEEBASE™ (Structurally Enhanced view of Economic Basement) model for the Southern Margin basins has been constructed to show basement topography. When used in combination with a rigorous interpretation of the structural evolution of the margin, it provides a foundation for basin phase and source rock distribution, hydrocarbon fluid focal points and trap type/distribution.
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24

Lavin, Ciaran. "The Maastrichtian Breakup of the Otway Basin Margin – a Model Developed by Integrating Seismic Interpretation, Sequence Statigraphy and Thermochronological Studies." Exploration Geophysics 28, no. 1-2 (March 1997): 252–59. http://dx.doi.org/10.1071/eg997252.

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25

Holford, Simon P., Adrian K. Tuitt, Richard R. Hillis, Paul F. Green, Martyn S. Stoker, Ian R. Duddy, Mike Sandiford, and David R. Tassone. "Cenozoic deformation in the Otway Basin, southern Australian margin: implications for the origin and nature of post-breakup compression at rifted margins." Basin Research 26, no. 1 (January 17, 2014): 10–37. http://dx.doi.org/10.1111/bre.12035.

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26

Bailey, Adam, Rosalind King, Simon Holford, Joshua Sage, Martin Hand, and Guillaume Backe. "Defining structural permeability in Australian sedimentary basins." APPEA Journal 55, no. 1 (2015): 119. http://dx.doi.org/10.1071/aj14010.

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Declining conventional hydrocarbon reserves have triggered exploration towards unconventional energy, such as CSG, shale gas and enhanced geothermal systems. Unconventional play viability is often heavily dependent on the presence of secondary permeability in the form of interconnected natural fracture networks that commonly exert a prime control over permeability due to low primary permeabiliy of in situ rock units. Structural permeability in the Northern Perth, SA Otway, and Northern Carnarvon basins is characterised using an integrated geophysical and geological approach combining wellbore logs, seismic attribute analysis and detailed structural geology. Integration of these methods allows for the identification of faults and fractures across a range of scales (millimetre to kilometre), providing crucial permeability information. New stress orientation data is also interpreted, allowing for stress-based predictions of fracture reactivation. Otway Basin core shows open fractures are rarer than image logs indicate; this is due to the presence of fracture-filling siderite, an electrically conductive cement that may cause fractures to appear hydraulically conductive in image logs. Although the majority of fractures detected are favourably oriented for reactivation under in situ stresses, fracture fill primarily controls which fractures are open, demonstrating that lithological data is often essential for understanding potential structural permeability networks. The Carnarvon Basin is shown to host distinct variations in fracture orientation attributable to the in situ stress regime, regional tectonic development and local structure. A detailed understanding of the structural development, from regional-scale (hundreds of kilometres) down to local-scale (kilometres), is demonstrated to be of importance when attempting to understand structural permeability.
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27

Niyazi, Yakufu, Mark Warne, and Daniel Ierodiaconou. "Post-rift magmatism and hydrothermal activity in the central offshore Otway Basin and implications for igneous plumbing systems." Marine Geology 438 (August 2021): 106538. http://dx.doi.org/10.1016/j.margeo.2021.106538.

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28

McKirdy, D. M., R. E. Cox, and J. G. G. Morton. "Biological marker, isotopic and geological studies of lacustrine crude oils in the western Otway Basin, South Australia." Geological Society, London, Special Publications 40, no. 1 (1988): 327. http://dx.doi.org/10.1144/gsl.sp.1988.040.01.26.

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29

Kharazizadeh, N., W. P. Schellart, J. C. Duarte, and M. Hall. "Influence of lithosphere and basement properties on the stretching factor and development of extensional faults across the Otway Basin, southeast Australia." Marine and Petroleum Geology 88 (December 2017): 1059–77. http://dx.doi.org/10.1016/j.marpetgeo.2017.08.034.

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30

Constantine, Andrew, Glenn Morgan, and Randall Taylor. "The Halladale and Black Watch gas fields—drilling AVO anomalies along Victoria's Shipwreck Coast." APPEA Journal 49, no. 1 (2009): 101. http://dx.doi.org/10.1071/aj08008.

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The Halladale and Black Watch fields are adjacent fault-dependent gas accumulations at the Turonian Waarre Formation level situated in the eastern Otway Basin, about 4–5 km from shore in VIC/RL2(v). The two fields were first identified in 2002 when anomalous seismic amplitudes were observed on the tail-ends of several 90s-vintage 2D lines that extended into what was then vacant acreage. After being awarded the block as VIC/P37(v) Origin Energy Limited and its joint venture (JV) partner, Woodside Energy Limited, acquired a 211 km2 full-fold 3D seismic survey over the anomalous amplitudes in late 2003. Subsequent analysis of the seismic volume revealed two tilted fault blocks with strong amplitude variation with offset (AVO) anomalies in the Waarre A and Waarre C units that conformed to structure and appeared to shut off at the same depth. A similar AVO anomaly was also observed in the overlying Santonian Nullawarre Formation, raising the possibility that Halladale and/or Black Watch had leaked or were leaking. In early 2005, the VIC/P37(v) JV drilled two exploration wells targetting the key Waarre C reservoir on the eastern flank of Halladale and eastern crest of Black Watch. Both wells encountered live gas columns in the Waarre C but no GWCs were observed on logs and wireline pressure data indicated the two fields were not in pressure communication. A third well was then drilled down-dip of the Waarre C AVO shut off on the Halladale fault block to obtain a water gradient from the Waarre C. This well proved invaluable in determining the height of the gas columns in the Waarre C at both fields as it showed the gas-water contacts (GWCs) at Halladale (1,760 mSS) and Black Watch (1,770 mSS) were shallow to their respective AVO shut offs by about 20 m and 10 m respectively. Subsequent analysis of shear wave sonic data from the third well indicated there is a 17 m residual gas column at the base of the Halladale Field. This suggests Halladale either leaked slightly at some time in the past or is still leaking. A similar scenario may also occur at Black Watch. Given the close proximity of the two fields to the coast, development scenarios from onshore are now being considered.
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31

Radke, B., D. C. Champion, S. J. Gallagher, L. Wang, D. De Vleeschouwer, A. Kalinowski, E. Tenthorey, M. Urosevic, and A. Feitz. "Geology, geochemistry and depositional history of the Port Campbell Limestone on the eastern flank of the Otway Basin, southeastern Australia." Australian Journal of Earth Sciences 69, no. 4 (November 29, 2021): 509–38. http://dx.doi.org/10.1080/08120099.2022.1998220.

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32

Debenham, Natalie, Natalie J. C. Farrell, Simon P. Holford, Rosalind C. King, and David Healy. "Spatial distribution of micrometre‐scale porosity and permeability across the damage zone of a reverse‐reactivated normal fault in a tight sandstone: Insights from the Otway Basin, SE Australia." Basin Research 31, no. 3 (March 13, 2019): 640–58. http://dx.doi.org/10.1111/bre.12345.

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33

Poynton, D. J. "BEATING THE ODDS AT CASINO!—A SMALL AUSTRALIAN’S EXAMPLE OF RISK MANAGEMENT." APPEA Journal 43, no. 1 (2003): 85. http://dx.doi.org/10.1071/aj02004.

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Strike Oil was a very small unlisted Australian company with a capitalisation of less than A$10 million when it decided to bid for block V98-4 (now VIC/P44) in the offshore Otway Basin in early 1999.Block V98-4 met Strike Oil’s gas strategy of pursuing opportunities in basins close to infrastructure and markets in the eastern states of Australia.Prior to making the bid Strike Oil identified the geological, financial and operational risks associated with exploring the permit, especially with regard to conducting a 3D seismic survey in the environmentally sensitive and sometimes hostile Bass Strait. This led to the implementation of, and adherence to, a comprehensive risk management plan.The geological risks were addressed by acquiring 3D seismic and conducting an analysis of the amplitudes and AVO responses associated with nearby gas discoveries and dry holes.Management of the financial risk centred firstly around not overbidding and secondly finding a farmee who could add value to the permit during both the exploration and exploitation phases.The operational risks were all associated with conducting the Casino 3D seismic survey. Local environmental considerations, particularly in relation to migratory whale species and the seasonal activities of local fishermen, meant there was only a six weeks’ time window available for unhindered operations. This window also coincided with the spring gale season, when weather conditions can stop marine operations.The use of experienced personnel, early stakeholder consultation, and the use of contingency plans, enabled Strike Oil to achieve its objectives under adverse conditions. The Casino 3D seismic survey, despite the odds, was completed on time, under budget, and with less than 7% infill, while still delivering high quality data.The farmout, the acquisition and processing of the 3D seismic data, and the discovery and appraisal of the Casino gas field were all achieved within 14 months.
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Carpenter, Chris. "Inversion of Full Waveform Sonic Data Assists Calibration of Geomechanics Model." Journal of Petroleum Technology 73, no. 09 (September 1, 2021): 39–40. http://dx.doi.org/10.2118/0921-0039-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202260, “Inversion of Advanced Full Waveform Sonic Data Provides Magnitudes of Minimum and Maximum Horizontal Stress for Calibrating the Geomechanics Model in a Gas Storage Reservoir,” by Zachariah J. Pallikathekathil, SPE, Xing Wang Yang, and Saeed Hafezy, Schlumberger, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. In 1D geomechanics projects, calibration of stress is extremely important in the construction of a valid mechanical earth model (MEM). The effective minimum horizontal stress (Shmin) data usually are available from traditional measurements, but these have a few deficiencies. The complete paper presents a technique for deriving stresses in which the radial variation of acoustic velocity from an advanced dipole sonic logging tool is inverted to obtain stress. These derived stresses are then used to calibrate the 1D MEM for a gas storage field. Regional Geology The field is in the Otway Basin in Western Victoria. Gas is trapped in the Late Cretaceous Waarre formation at depths between 1155 and 1200 m subsea. The reservoir is sealed by the overlying marine Belfast mudstone, which is the common seal in the stratigraphy across the onshore Otway Basin. The reservoir has excellent reservoir quality and has proved ideal for gas storage. Challenge Posed by the 1D MEM Challenge Posed by the 1D MEM Well 1 was recently drilled in the basin. A 1D MEM - a numerical representation of the geomechanical properties and stress state of the earth at any depth - was planned to be constructed to obtain the current-day far-field principal stresses (Shmin), effective maximum horizontal stress (SHmax), and effective vertical stress (SV)] in the Belfast and Waarre formations. Understanding the stress field was important, especially in the caprock (Belfast) and in the reservoir (Waarre) so that the pressure limits for safe gas-storage operation could be defined better. However, for a variety of reasons, no conventional stress measurements were available to calibrate the modeled stress in the 1D MEM. Without any calibration of the stress, the geomechanics model would feature high uncertainty to be used to define the pressure operational limits for gas-storage operation. Fortunately, a new wireline sonic tool was recorded in the reservoir section and the overburden sections of the borehole in Well 1. A quick dispersion analysis of the waveforms showed that the Paaratte formation, above the Belfast formation, was acoustically stress-sensitive and that advanced processing could be performed to invert the acoustic information to stress values.
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Tassone, David R., Simon P. Holford, Ian R. Duddy, Paul F. Green, and Richard R. Hillis. "Quantifying Cretaceous–Cenozoic exhumation in the Otway Basin, southeastern Australia, using sonic transit time data: Implications for conventional and unconventional hydrocarbon prospectivity." AAPG Bulletin 98, no. 1 (January 2014): 67–117. http://dx.doi.org/10.1306/04011312111.

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36

Karolytė, Rūta, Gareth Johnson, Graham Yielding, and Stuart M. V. Gilfillan. "Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO2 systems." Petroleum Geoscience 26, no. 3 (March 4, 2020): 481–97. http://dx.doi.org/10.1144/petgeo2019-126.

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Fault seal analysis is a key part of understanding the hydrocarbon trapping mechanisms in the petroleum industry. Fault seal research has also been expanded to CO2–brine systems for the application to carbon capture and storage (CCS). The wetting properties of rock-forming minerals in the presence of hydrocarbons or CO2 are a source of uncertainty in the calculations of capillary threshold pressure, which defines the fault sealing capacity. Here, we explore this uncertainty in a comparison study between two fault-sealed fields located in the Otway Basin, SE Australia. The Katnook Field in the Penola Trough is a methane field, while Boggy Creek in Port Campbell contains a high-CO2–methane mixture. Two industry standard fault seal modelling methods, one based on laboratory measurements of fault samples and the other based on a calibration of a global dataset of known sealing faults, are used to discuss their relative strengths and applicability to the CO2 storage context. We identify a range of interfacial tensions and contact angle values in the hydrocarbon–water system under the conditions assumed by the second method. Based on this, the uncertainty related to the spread in fluid properties was determined to be 24% of the calculated threshold capillary pressure value. We propose a methodology of threshold capillary pressure conversion from hydrocarbons–brine to the CO2–brine system, using an input of appropriate interfacial tension and contact angle under reservoir conditions. The method can be used for any fluid system where fluid properties are defined by these two parameters.Supplementary material: (1) Fault seal modelling methods and calculations, and (2) hydrocarbon and CO2 interfacial tensions and contact angle values collected in the literature are available at https://doi.org/10.6084/m9.figshare.c.4877049This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series
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Bagheri, Mohammad B., and Matthias Raab. "Subsurface engineering of CCUS in Australia (case studies)." APPEA Journal 59, no. 2 (2019): 762. http://dx.doi.org/10.1071/aj18125.

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Carbon capture utilisation and storage (CCUS) is a rapidly emerging field in the Australian oil and gas industry to address carbon emissions while securing reliable energy. Although there are similarities with many aspects of the oil and gas industry, subsurface CO2 storage has some unique geology and geophysics, and reservoir engineering considerations, for which we have developed specific workflows. This paper explores the challenges and risks that a reservoir engineer might face during a field-scale CO2 injection project, and how to address them. We first explain some of the main concepts of reservoir engineering in CCUS and their synergy with oil and gas projects, followed by the required inputs for subsurface studies. We will subsequently discuss the importance of uncertainty analysis and how to de-risk a CCUS project from the subsurface point of view. Finally, two different case studies will be presented, showing how the CCUS industry should use reservoir engineering analysis, dynamic modelling and uncertainty analysis results, based on our experience in the Otway Basin. The first case study provides a summary of CO2CRC storage research injection results and how we used the dynamic models to history match the results and understand CO2 plume behaviour in the reservoir. The second case study shows how we used uncertainty analysis to improve confidence on the CO2 plume behaviour and to address regulatory requirements. An innovative workflow was developed for this purpose in CO2CRC to understand the influence of each uncertainty parameter on the objective functions and generate probabilistic results.
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Sun, He, Fengge Su, Tandong Yao, Zhihua He, Guoqiang Tang, Jingheng Huang, Bowen Zheng, Fanchong Meng, Tinghai Ou, and Deliang Chen. "General overestimation of ERA5 precipitation in flow simulations for High Mountain Asia basins." Environmental Research Communications 3, no. 12 (December 1, 2021): 121003. http://dx.doi.org/10.1088/2515-7620/ac40f0.

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Abstract Precipitation is one of the most important input to hydrological models, although obtaining sufficient precipitation observations and accurate precipitation estimates in High Mountain Asia (HMA) is challenging. ERA5 precipitation is the latest generation of reanalysis dataset that is attracting huge attention from various fields but it has not been evaluated in hydrological simulations in HMA. To remedy this gap, we first statistically evaluated ERA5 precipitation with observations from 584 gauges in HMA, and then investigated its potential in hydrological simulation in 11 HMA basins using the Variable Infiltration Capacity (VIC) hydrological model. The ERA5 precipitation generally captures the seasonal variations of gauge observations, and the broad spatial distributions of precipitation in both magnitude and trends in HMA. The ERA5 exhibits a reasonable flow simulation (RB of 5%–10%) at the Besham hydrological station of the upper Indus (UI) basin when the contribution from glacier runoff is added to the simulated total runoff. But it overestimates the observations in other HMA basins by 33%–106% without considering glacier runoff, mostly due to the overestimates in the ERA5 precipitation inputs. Therefore, a bias correction is definitely needed before ERA5 precipitation is used for hydrological simulations in HMA basins.
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39

JPT staff, _. "E&P Notes (December 2020)." Journal of Petroleum Technology 72, no. 12 (December 1, 2020): 16–17. http://dx.doi.org/10.2118/1220-0016-jpt.

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China Shale-Gas Field Sets Production Record Sinopec recorded China’s highest daily output of shale gas at 20.62 million cubic meters (Mcm) at its Fuling shale-gas field in Chongqing, China, a key gas source for the Sichuan-East gas pipeline. The first major commercial shale-gas project in China, Fuling has continuously broken records for the shortest gasfield drilling cycle while significantly increasing the drilling of high-quality reservoirs covering more than 3 million m, according to Sinopec. Gasfield production construction was also expanded to raise production capacity. The company said the field maintains a daily output of 20 Mcm, producing an estimated 6.7 Bcm per year. Apache and Total Plan Suriname Appraisals Apache filed appraisal plans for its Maka and Sapakara oil discoveries in block 58 offshore Suriname. The company said another submission is expected for Kwaskwasi, the largest find in the block, by the end of the year. Operations continue for Keskesi, the fourth exploration target. There are plans to drill a fifth prospect at Bonboni in the North-Central portion of the concession. Partner company Total is assuming operatorship of the block ahead of next year’s campaigns. BP Emerges as Sole Bid for Offshore Canada Parcels BP was the only operator to place a bid in the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) Call for Bids NL20-CFB01, which offered 17 parcels (4,170,509 hectares) in the eastern Newfoundland region. The successful bid was for Parcel 9 (covering 264,500 hectares) for $27 million in work commitments from BP Canada Energy Group. Subject to BP satisfying specified requirements and receiving government approval, the exploration license will be issued in January 2021. No bids were received for the remaining 16 parcels, which may be reposted in a future Call for Bids. Criteria for selecting a winning bid is the total amount the bidder commits to spend on exploration of the parcel during the first period of a 9-year license, with a minimum acceptable bid of $10 million in work commitments for each parcel. Beach Energy To Drill Otway Basin Well Beach Energy plans to drill at its Artisan-1 well about 32 km offshore Victoria, Australia, in the Otway basin, before the end of 2021. The well, located on Block Vic/P43, was to be spudded in 1H 2020 but was delayed due to COVID-19. The timeframe for drilling was confirmed by the National Offshore Petroleum Safety and Environmental Management Authority, which also said Beach is keeping open the option to suspend the well and develop it, pending reservoir analysis. Anchors, mooring chains, and surface buoys have already been laid for the well, which is in a water depth of approximately 71 m. The well is expected to take approximately 35–55 days to drill, depending on the final work program and potential operational delays. Diamond Offshore’s semisubmersible Ocean Onyx was contracted for the drilling program. Artisan is the first of Beach’s planned multiwell campaigns, which also include development wells at the Geographe and Thylacine fields. Hess Completes Sale of Interest in Gulf of Mexico Field Hess completed the sale of its 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico (GOM) to BHP, the field’s operator, for $505 million. Shenzi is a six-lease development structured as a joint ownership: BHP (operator, 44%), Hess (28%), and Repsol (28%). The acquisition would bring BHP’s working interest to 72%, adding approximately 11,000 BOE/D of production (90% oil). The sale is expected to close by December 2020. Hess CEO John Hess said proceeds from the sale will help fund the company’s investment in Guyana. Greenland Opens New Offshore Areas Greenland opened three new offshore areas for application of oil and gas exploitation licenses off West Greenland. The areas are Baffin Bay, Disko West, and Davis Strait. The country also said it is working on an oil strategy to reduce geological uncertainty by offering an investment package to companies that engage in its Open Door Procedures. The procedures are a first-mover advantage to remove national oil company Nunaoil, as a carried partner, reducing turnover and surplus royalties. It is estimated to reduce the government take by 51.3% to 40.6%. Shell and Impact Oil & Gas Agree to South Africa Farmout Africa Oil announced Impact Oil & Gas entered into two agreements for exploration areas offshore South Africa. The company has a 31.10% share-holding in Impact, a privately owned exploration company. Impact entered into an agreement with BG International, a Shell subsidiary, for the farm-out of a 50% working interest and operatorship in the Transkei and Algoa exploration rights. Shell was also granted the option to acquire an additional 5% working interest should the joint venture (JV) elect to move into the third renewal period, expected in 2024. Algoa is located in the South Outeniqua Basin, east of Block 11B/12B, containing the Brulpadda gas condensate discovery and where Total recently discovered gas condensate. The Transkei block is northeast of Algoa in the Natal Trough Basin where Impact has identified highly material prospectivity associated with several large submarine fan bodies, which the JV will explore with 3D seismic data and then potential exploratory drilling. Impact and Shell plan to acquire over 6,000 km² of 3D seismic data during the first available seismic window following completion of the transaction. This window is expected to be in the Q1 2022. After the closing of the deal, Shell will hold a 50% interest as the operator and Impact will hold 50%. Impact also entered into an agreement with Silver Wave Energy for the farm-in of a 90% working interest and operatorship of Area 2, offshore South Africa. East and adjacent to Impact’s Transkei and Algoa blocks, Area 2 complements Impact’s existing position by extending the entire length of the ultradeepwater part of the Transkei margin. Together, the Transkei and Algoa Blocks and Area 2 cover over 124,000 km2. Area 2 has been opened by the Brulpadda and Luiperd discoveries in the Outeniqua Basin and will be further tested during 2021 by the well on the giant Venus prospect in ultradeepwater Namibia, where Impact is a partner. Impact believes there is good evidence for this Southern African Aptian play to have a common world-class Lower Cretaceous source rock, similar excellent-quality Apto-Albian reservoir sands, and a geological setting suitable for the formation of large stratigraphic traps. Following completion of the farm-in, Impact will hold 90% interest and serve as the operator; Silver Wave will hold 10%. Petronas Awards Sarawak Contract to Seismic Consortium The seismic consortium comprising PGS, TGS, and WesternGeco was awarded a multiyear contract by Petronas to acquire and process up to 105,000 km2 of multisensor, multiclient 3D data in the Sarawak Basin, offshore Malaysia. The contract award follows an ongoing campaign by the consortium in the Sabah offshore region, awarded in 2016, in which over 50,000 km2 of high-quality 3D seismic data have been acquired and licensed to the oil and gas industry to support Malaysia license round and exploration activity. The Sarawak award will allow for a multiphase program to promote exploration efforts in the prolific Sarawak East Natuna Basin (Deepwater North Luconia and West Luconia Province). The consortium is planning the initial phases and is engaging with the oil and gas industry to secure prefunding ahead of planned acquisition, covering both open blocks and areas of existing farm-in opportunities. Total Discovers Second Gas Condensate in South Africa Total made a significant second gas condensate discovery on the Luiperd prospect, located on Block 11B/12B in the Outeniqua Basin, 175 km off the southern coast of South Africa. The discovery follows the adjacent play-opening Brulpadda discovery in 2019. The Luiperd-1X well was drilled to a total depth of about 3,400 m and encountered 73 m of net gas condensate pay in well-developed, good-quality Lower Cretaceous reservoirs. Following a coring and logging program, the well will be tested to assess the dynamic reservoir characteristics and deliverability. The Block 11B/12B covers an area of 19,000 km2, with water depths ranging from 200 to 1800 m. It is operated by Total with a 45% working interest, alongside Qatar Petroleum (25%), CNR International (20%), and Main Street, a South African consortium (10%). The Luiperd prospect is the second to be drilled in a series of five large submarine fan prospects with direct hydrocarbon indicators defined utilizing 2D and 3D seismic data. BP Gas Field Offshore Egypt Begins Production BP started gas production from its Qattameya gasfield development ‎offshore Egypt in the North Damietta offshore concession. Through BP’s joint venture Pharaonic Petroleum Company working with state-owned Egyptian Natural Gas Holding Co., the field, which is ‎expected to produce up to 50 MMcf/D, was developed through a one-well subsea development and tieback to existing infrastructure.‎ Qattameya, whose discovery was announced in 2017, is located approximately 45 km west ‎of the Ha’py platform, in 108 m of water. It is tied back to the Ha’py and Tuart field ‎development via a new 50-km pipeline and connected to existing subsea ‎utilities via a 50-km umbilical. ‎BP holds 100% equity in the North Damietta offshore concession in the East Nile Delta. ‎Gas production from the field is directed to Egypt’s national grid.
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40

Niyazi, Yakufu, Mark Warne, and Daniel Ierodiaconou. "Machine learning delineation of buried igneous features from the offshore Otway Basin in southeast Australia." Interpretation, May 4, 2022, 1–70. http://dx.doi.org/10.1190/int-2021-0210.1.

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Magmatic rocks are frequently encountered during hydrocarbon exploration in rift-related sedimentary basins. As magmatic rocks may contribute both positively and negatively to the hydrocarbon systems, their spatio-temporal distribution and structural elements are crucial for exploration in frontier basins. With the proliferation and increased density of seismic reflection data, various subsurface magmatic features can be discriminated and illuminated via conventional interpretation approaches, such as attribute extraction, opacity rendering or geo-body extraction. However, these manual interpretation techniques are labor-intensive, subject to interpreter bias and often bottleneck with respect to time data delivery. A supervised machine learning approach could efficiently resolve these issues by amalgamating suitable seismic attributes, such as energy, reflection strength, texture, and similarity, and automatically delineating these magmatic features in 3D seismic reflection data. Our machine learning neural network classified igneous features from non-igneous features in two different seismic surveys within the natural laboratory of the offshore Otway Basin, SE Australia. This multi-layer perception neural network designed in this study resulted in an optimized igneous probability meta-attribute cube that could effectively reveal the extension and distribution of igneous features and several structural elements in the study area. We presented the detailed workflow of this artificial neural network and observed the efficiency of this approach in different seismic surveys. These results illustrate the potential of neural network in imaging other complex igneous features from 3D seismic data in the Otway Basin and worldwide.
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41

P. E. Williamson, G. W. O'Brien, M. "Basin Development and Petroleum Potential of Offshore Otway Basin, Australia: ABSTRACT." AAPG Bulletin 71 (1987). http://dx.doi.org/10.1306/94887825-1704-11d7-8645000102c1865d.

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42

ALEXANDER, ELINOR M., South Austral. "Petrophysics of Gas Reservoirs, Otway Basin, South Australia." AAPG Bulletin 76 (1992). http://dx.doi.org/10.1306/f4c8f84a-1712-11d7-8645000102c1865d.

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43

Kumar, Priyadarshi Chinmoy, Yakufu Niyazi, Ovie Emmanuel Eruteya, Andrea Moscariello, Mark Warne, Daniel Ierodiaconou, and Kalachand Sain. "Anatomy of intrusion related forced fold in the offshore Otway Basin, SE Australia." Marine and Petroleum Geology, April 2022, 105719. http://dx.doi.org/10.1016/j.marpetgeo.2022.105719.

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44

Stelios Nicolaides. "Diagenesis of non-tropical carbonates of the Otway Basin, Australia: ABSTRACT." AAPG Bulletin 78 (1994). http://dx.doi.org/10.1306/8d2b0828-171e-11d7-8645000102c1865d.

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45

Wu, Nan, Harya D. Nugraha, Michael J. Steventon, and Guangfa Zhong. "How do tectonics influence the initiation and evolution of submarine canyons? A case study from the Otway Basin, SE Australia." Journal of the Geological Society, April 13, 2022, jgs2021–170. http://dx.doi.org/10.1144/jgs2021-170.

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The architecture of canyon-fills can provide a valuable record of the link between tectonics, sedimentation, and depositional processes in submarine settings. In this study, we investigate the role of plate tectonics in the initiation and evolution of submarine canyons. We demonstrate that plate tectonic-scale events (i.e. continental breakup and shortening) have a first-order influence on submarine canyon initiation and development. Initially, the Late Cretaceous (c.65 Ma) separation of Australia and Antarctica resulted in extensional fault systems, which then formed a steep stair-shaped paleo-seabed. Subsequently, the Late Miocene (c.5 Ma) collision of Australia and Eurasia has resulted in substantial uplift and exhumation in the SE Australian continental margin. These tectonic events have resulted in elevated seismicity that ultimately gave rise to the gravity-driven processes (i.e. turbidity currents and mass wasting processes) and formed the canyon base. The inherited stair-shaped topography then facilitated gravity-driven processes which established a mature sediment conduit extending from the shallow marine shelf to the abyssal plain. We indicate that the canyon stratigraphic architecture can be used as an archive to record tectonic movements. Moreover, the factors which preconditioned and triggered gravity-driven processes can also induce canyon initiation and facilitate canyon development.Supplementary material:https://doi.org/10.6084/m9.figshare.c.5937760
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P. E. Williamson, G. E. O'Brien, M. "New Exploration Potential for Cretaceous Graben-Fill Sediments of Australia's Otway Basin: ABSTRACT." AAPG Bulletin 70 (1986). http://dx.doi.org/10.1306/948862ea-1704-11d7-8645000102c1865d.

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47

G. C. Geary1, A. E. Constantine2, I. "ABSTRACT: New Perspectives on Structural Style and Petroleum Prospectivity, Offshore Eastern Otway Basin." AAPG Bulletin 86 (2002). http://dx.doi.org/10.1306/61eee8cc-173e-11d7-8645000102c1865d.

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48

PETTIFER, G. R., B. A. SIMONS, and. "Advances In Use of Image Processing for Data Integration in Basin Studies -- Eastern Otway Basin, Australia -- A Case Study." AAPG Bulletin 76 (1992). http://dx.doi.org/10.1306/f4c8fd7c-1712-11d7-8645000102c1865d.

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WILLIAMSON, P. E., and G. W. O'BRIE. "Petroleum Maturation, Tectonic and Subsidence History of the Offshore Otway Basin: Implications for Exploration." AAPG Bulletin 76 (1992). http://dx.doi.org/10.1306/f4c8ff20-1712-11d7-8645000102c1865d.

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50

Gu, Haiting, Li Liu, Zhixu Bai, Suli Pan, and Yue-Ping Xu. "A stepwise surrogate model for parameter calibration of the Variable Infiltration Capacity model: the case of the upper Brahmaputra, Tibet Plateau." Journal of Hydroinformatics, November 3, 2020. http://dx.doi.org/10.2166/hydro.2020.010.

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Abstract To alleviate the computational burden of parameter calibration of the Variable Infiltration Capacity (VIC) model, a stepwise surrogate model (SM) is developed based on AdaBoost. An SM first picks out the parameter sets in the range that the values of objective functions are close to the optimization objectives and then approximates the values of objective functions with these parameter sets. The ɛ-NSGA II (Nondominated Sorting Genetic Algorithm II) algorithm is used to search the optimal solutions of SM. The SM is tested with a case study in the upper Brahmaputra River basin, Tibet Plateau, China. The results show that the stepwise SM performed well with the rate of misclassification less than 2.56% in the global simulation step and the root mean square error less than 0.0056 in the local simulation step. With no large difference in the optimal solutions between VIC and the SM, the SM-based algorithm saves up to 90% time.
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