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1
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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Karvelas, Alex, Tekena West, Chris Nicholson, Steve Abbott, George Bernardel, Cameron Mitchell, Duy Nguyen, Merrie-Ellen Gunning, Irina Borissova, and Oliver Schenk. "New insights into the deep-water Otway Basin – Part 2. Tectonostratigraphic framework revealed by new seismic data." APPEA Journal 61, no. 2 (2021): 657. http://dx.doi.org/10.1071/aj20092.
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The inboard areas of the Otway Basin, particularly the Shipwreck Trough, are well explored and a petroleum-producing province. However, outboard in water depths greater than 500m, the basin is underexplored with distant well control and sparse 2D reflection seismic data coverage. The presence of a successful petroleum province onshore and in shallow waters raises the question as to whether these plays may extend further outboard into the deep-water areas. In the deep-water area, structural complexity and poor imaging of events in the legacy seismic data have resulted in interpretation uncertainty and consequentially a high-risk profile for explorers. The 2020 Otway Basin seismic program acquired over 7000-line km of 2D reflection seismic data across the deep-water Otway Basin. In addition, over 10000km of legacy 2D seismic data were reprocessed to improve the tie between the inboard wells and the new seismic grid. This new dataset provides the first clear insight into the structural and stratigraphic framework of this frontier area, including better imaging of the sedimentary section and the lower crust, increased structural resolution and improved calibration of the outboard seismic reflectors via ties to the inboard wells. Interpretation of the new data has led to an improved assessment of the structural elements and the extension of regional supersequences into the deep-water areas. These refinements have been used as input into petroleum systems modelling work and will provide a foundation for future work to understand petroleum prospectivity, including the distribution of source, reservoir and seal facies.
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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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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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Cooper, G. T., and K. C. Hill. "CROSS-SECTION BALANCING AND THERMOCHRONOLOGICAL ANALYSIS OF THE MESOZOIC DEVELOPMENT OF THE EASTERN OTWAY BASIN." APPEA Journal 37, no. 1 (1997): 390. http://dx.doi.org/10.1071/aj96024.
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Recent advances in cross-section balancing software have simplified the application of basic geometric constraints to the analysis of basin development. Geometric analysis of field and seismic data allows the user to verify initial interpretations and also elucidates important information about the structural evolution of a basin. Principally, computerised balancing and restoration of cross-sections assists in constraining:the amount of crustal extension;trap geometries, particularly fault geometries through time;the geometry of key horizons at any time, revealing basin morphology and migration paths;the time and amount of maximum burial and hence hydrocarbon migration; andthe likely mechanisms involved in basin evolution. In turn, these parameters can be used to further assess hydrocarbon prospectivity by providing useful data for lithospheric modelling.This study utilises 2D cross-section balancing software (Geosec™) to decompact, balance and restore a series of regional onshore-offshore cross-sections based on both reflection seismic data in the Torquay Embayment and field mapping in the Otway Ranges. The thickness of eroded strata has been constrained by Apatite Fission Track and Vitrinite Reflectance analyses. The resulting section restoration suggests that the eastern Otway Basin experienced extension of 26 per cent in the Early Cretaceous and that the Otway Ranges were subjected to −8 per cent shortening during mid-Cretaceous inversion and −4 per cent shortening during Mio-Pliocene inversion.The structural style of the Otway Ranges and Torquay Embayment is typified by steep, relatively planar, en echelon, N and NE-dipping Early Cretaceous extension faults that were subsequently inverted and eroded during the Cenomanian and Mio-Pliocene. The structural style of the region shows strong similarities with oblique- rift analogue models suggesting that the extensional history of the region was strongly controlled by prevailing basement fabric.Lower Cretaceous source rocks in the eastern Otway Basin reached maximum maturity prior to mid-Cretaceous inversion with the exception of parts of the Torquay Embayment which may not have experienced significant uplift and erosion at this time. The lack of subsidence in the eastern Otway Basin prevented the deposition of significant amounts of Upper Cretaceous sediments which are proven reservoirs in the western Otway Basin and Gippsland Basin. Subsequent Tertiary burial was insufficient, in most regions, to allow the source rocks re-enter the oil generation window.
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Nicholson, Chris, Steve Abbott, George Bernardel, and Merrie-Ellen Gunning. "Stratigraphic framework and structural architecture of the Upper Cretaceous in the deep-water Otway Basin – implications for frontier hydrocarbon prospectivity." APPEA Journal 62, no. 2 (May 13, 2022): S467—S473. http://dx.doi.org/10.1071/aj21072.
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Geoscience Australia has undertaken a regional seismic mapping study that extends into the frontier deep-water region of the offshore Otway Basin. This work builds on seismic mapping and petroleum systems modelling published in the 2021 Otway Basin Regional Study. Seismic interpretation spans over 18 000 line-km of new and reprocessed data collected in the 2020 Otway Basin seismic program and over 40 000 line-km of legacy 2D seismic data. Fault mapping has resulted in refinement and reinterpretation of regional structural elements, particularly in the deep-water areas. Structure surfaces and isochron maps highlight Shipwreck (Turonian–Santonian) and Sherbrook (Campanian–Maastrichtian) supersequence depocentres across the deep-water part of the basin. These observations will inform the characterisation of petroleum systems within the Upper Cretaceous succession, especially in the underexplored deep-water region.
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Mitchell, M. M. "ELEVATED MID-CRETACEOUS PALAEOTEMPERATURES IN THE WESTERN OTWAY BASIN: CONSEQUENCES FOR HYDROCARBON GENERATION MODELS." APPEA Journal 37, no. 1 (1997): 505. http://dx.doi.org/10.1071/aj96030.
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The Otway Basin formed during the Mesozoic separation of Antarctica and Australia. A study of apatite fission track (FT) analysis and vitrinite reflectance (VR) data from borehole samples in the western Otway Basin was initiated to elucidate some of the thermal and structural complexities of this region.Interpretation of results suggest that some areas experienced regionally elevated palaeotemperatures, however, much of the region is at present-day maximum temperatures. Where cooling from maximum palaeotemperatures is observed, the timing may be grouped over three main intervals as follows; mid-Cretaceous, Late Cretaceous to Early Tertiary, and Tertiary. Cooling was facilitated by a decline in geothermal gradient, uplift and erosion, or both. Evidence for a decline in geothermal gradient from values >55°C/km in the mid- Cretaceous is recognised in several wells. Elevated mid- Cretaceous palaeogeothermal gradients (50−60°C/km) have been reported for the eastern Otway Basin, suggesting that these high temperatures were a regional phenomena. Cooling by uplift and erosion at this time was minimal throughout the western Otway Basin in contrast to the kilometre scale uplift and erosion reported for the eastern Otway Basin and adjacent basement inland of this section of the rift.The relative early maturation of the Otway Supergroup during mid-Cretaceous regionally elevated geothermal gradients, and subsequent basin restructuring, are key factors affecting hydrocarbon preservation in the western Otway Basin. Strategies for identification of prospective areas include identification of regions that have remained at moderate temperatures during the Early Cretaceous, and have not undergone burial under a thick Upper Cretaceous to Tertiary section.
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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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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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Cockshell, C. D., G. W. O'Brien, A. McGee, R. Lovibond, D. Perincek, and R. Higgins. "WESTERN OTWAY CRAYFISH GROUP TROUGHS." APPEA Journal 35, no. 1 (1995): 385. http://dx.doi.org/10.1071/aj94025.
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Commercial volumes of hydrocarbons have been discovered in Early Cretaceous synrift sediments of the Crayfish Group of the Penola Trough, western Otway Basin. Four other such depocentres are recognised using available seismic and drilling data. A standard nomenclature is proposed for the major structural elements observed in this part of the Otway Basin.Various tectonic models proposed for the Early Cretaceous rift history of the Otway Basin are reviewed and tested using true dip analysis of seismic events and sandbox modelling experiments. Results support a generally north-south direction for rift extension in the Tithonian-Barremian. This implies that the ENE trending Robe Trough is the headwall rift compartment (although with 20°obliquity), whereas the NW trending Penola Trough is a more oblique or transtensional rift compartment.
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Burgin, Hugo B., Khalid Amrouch, Philippe Robion, and David Kulikowski. "An integrated approach to determining 4D stress development at Castle Cove." APPEA Journal 59, no. 1 (2019): 410. http://dx.doi.org/10.1071/aj18173.
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Models for basin evolution and natural fracture development often contain many uncertainties. Multiscale approaches to structural analysis assist in reducing these by providing checkpoints for structural evolution to better constrain the development of paleostress phases through time. In this study, we integrate the analysis of calcite twins, magnetic fabrics, stylolites and natural fractures at Castle Cove in the eastern Otway Basin, producing a five-phase model for stress evolution consisting of: phase 1 ~NW–SE Mid-Cretaceous strike-slip or compression; phases 2 and 3 Late Cretaceous extension, coinciding with the development of ~NW–SE and ~NE–SW striking extensional fracture sets; phase 4 ~NE–SW strike-slip and compression, representing an enigmatic period of stress evolution with respect to the current understanding of the Otway Basin; and phase 5, present day ~NW–SE strike-slip stress. The results contribute to a 4D structural history construction for the eastern Otway Basin and suggest that the evolution of the region may require reassessing in order to determine the timing and nature of the detected ~NE–SW oriented compressional event. This study also demonstrates how the use of a calcite stress inversion technique can assist in providing mechanical checkpoints for the evolution of complex natural fracture networks, which can easily be expanded within the sub-surface.
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Cooper, G. T. "SEISMIC STRUCTURE AND EXTENSIONAL DEVELOPMENT OF THE EASTERN OTWAY BASIN-TORQUAY EMBAYMENT." APPEA Journal 35, no. 1 (1995): 436. http://dx.doi.org/10.1071/aj94028.
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The Eastern Otway Basin exhibits two near-or-thogonal structural grains, specifically NE-SW and WNW-ESE trending structures dominating the Otway Ranges, Colac Trough and Torquay Embayment. The relative timing of these structures is poorly constrained, but dip analysis data from offshore seismic lines in the Torquay Embayment show that two distinct structural provinces developed during two separate extensional episodes.The Snail Terrace comprises the southern structural province of the Torquay Embayment and is characterised by the WNW-ESE trending basin margin fault and a number of small scale NW-SE trending faults. The Torquay Basin Deep makes up the northern structural province and is characterised by the large scale, cuspate Snail Fault which trends ENE-WSW with a number of smaller NE-SW trending faults present.Dip analysis of basement trends shows a bimodal population in the Torquay Embayment. The Snail Terrace data show extension towards the SSW (193°), but this trend changes abruptly to the NE across a hinge zone. Dip data in the Torquay Basin Deep and regions north of the hinge zone show extension towards the SSE (150°). Overall the data show the dominance of SSE extension with a mean vector of 166°.Seismic data show significant growth of the Crayfish Group on the Snail Terrace and a lesser growth rate in the Torquay Basin Deep. Dip data from the Snail Terrace are therefore inferred to represent the direction of basement rotation during the first phase of continental extension oriented towards the SSW during the Berriasian-Barremian? (146-125 Ma). During this phase the basin margin fault formed as well as NE-SW trending ?transtensional structures in the Otway Ranges and Colac Trough, probably related to Palaeozoic features.Substantial growth along the Snail Fault during the Aptian-Albian? suggests that a second phase of extension affected the area. The Colac Trough, Otway Ranges, Torquay Embayment and Strzelecki Ranges were significantly influenced by this Bassian phase of SSE extension which probably persisted during the Aptian-Albian? (125-97 Ma). This phase of extension had little effect in the western Otway Basin, west of the Sorrel Fault Zone, and was largely concentrated in areas within the northern failed Bass Strait Rift. During the mid-Cretaceous parts of the southern margin were subjected to uplift and erosion. Apatite fission track and vitrinite reflectance analyses show elevated palaeotemperatures associated with uplift east of the Sorell Fault Zone.
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Bendall, Betina, Anne Forbes, Dan Revie, Rami Eid, Shannon Herley, and Tony Hill. "New insights into the stratigraphy of the Otway Basin." APPEA Journal 60, no. 2 (2020): 691. http://dx.doi.org/10.1071/aj19035.
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The Otway Basin is one of the best known and most actively explored of a series of Mesozoic basins formed along the southern coastline of Australia by the rifting of the Antarctic and Australian plates during the Cretaceous. The basin offers a diversity of play types, with at least three major sedimentary sequences forming conventional targets for petroleum exploration in the onshore basin. The Penola Trough in South Australia has enjoyed over 20 years of commercial hydrocarbon production from the sandstones of the Early Cretaceous Otway Group comprising the Crayfish Subgroup (Pretty Hill Formation and Katnook sandstones) and Eumeralla Formation (Windermere Sandstone Member). Lithostratigraphic characterisation and nomenclature for these sequences are poorly constrained, challenging correlation across the border into the potentially petroleum prospective Victorian Penola Trough region. The Geological Survey of Victoria (GSV), as part of the Victorian Gas Program, commissioned Chemostrat Australia to undertake an 11-well chemostratigraphic study of the Victorian Otway Basin. The South Australia Department for Energy and Mining, GSV and Chemostrat Australia are working collaboratively to develop a consistent, basin-wide schema for the stratigraphic nomenclature of the Otway Basin within a chemostratigraphic framework. Variability in the mineralogy and hence inorganic geochemistry of sediments reflects changes in provenance, lithic composition, facies changes, weathering and diagenesis. This geochemical variation enables the differentiation of apparently uniform sedimentary successions into unique sequences and packages, aiding in the resolution of complex structural relationships and facies changes. In this paper, we present the preliminary results of detailed geochemical analyses and interpretation of 15 wells from across the Otway Basin and the potential impacts on hydrocarbon prospectivity.
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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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Bernecker, T., and D. H. Moore. "LINKING BASEMENT AND BASIN FILL: IMPLICATIONS FOR HYDROCARBON PROSPECTIVITY IN THE OTWAY BASIN REGION." APPEA Journal 43, no. 1 (2003): 39. http://dx.doi.org/10.1071/aj02002.
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Since the offshore discoveries of economic gas accumulations at Geographe and Thylacine, the Otway Basin has become the focus of an exploration resurgence. Its proximity to major markets ensures the discoveries will be commercially valuable. The latest successes in the basin are mainly due to modern 3D-seismic techniques. While the upper sedimentary succession has been imaged at high resolution, details of the deeper successions, however, remained obscure.An integrated study of magnetic, gravimetric, bathymetric and deep seismic data-sets has outlined the way that pre-existing basement fractures controlled much of the later basin-evolution, the structural style and the distribution of hydrocarbon bearing structures.The Otway Basin formed by the profound interaction between crustal fabric in the Proterozoic and Palaeozoic basement and the extensional stresses during Gondwana break-up. Overall, three different rift systems can be distinguished:Early ENE-trending Jurassic to Early Cretaceous rifts are an extension of the E-W rift system in Western Australia and South Australia, Early WNW Late Jurassic to Early Cretaceous rifts are connected to the ENE set and include the western Otway Basin east of the Robe Trough and the Torquay Sub-basin, and Early Cretaceous NNW transtensional rifts in the southern part of the Shipwreck Trough. These control the La Bella, Thylacine and Geographe discoveries, all of which overlie the Neoproterozoic to Cambrian Selwyn Block.Within these rift systems, the Jurassic to Cretaceous rifts along the continental shelf break coincide with the northern edge of the Voluta Trough, whilst the mid-slope rifts are part of the deep Voluta Trough and were possibly generated during the Late Cretaceous.Although the potential field data do not directly delineate hydrocarbon accumulations, when integrated with other data they provide powerful tools for exploration. For instance, it is possible to map the distribution of Paleocene channels that overlie the basement and represent likely reservoir facies, while data integration with palaeoenvironmental interpretations can highlight areas in which source rock facies developed.Regionally, the way the rifts have formed with respect to the basement fabric suggests that the dominant extension direction in the basin was N to NNW. Integrating the interpretation with regional studies in the western Tasmanian region supports the proposition that the western part of the south Tasman Rise was once the outer part of the upper plate adjacent to the deepwater parts of the Otway Basin SW of Cape Otway.
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Yu, S. M. "STRUCTURE AND DEVELOPMENT OF THE OTWAY BASIN." APPEA Journal 28, no. 1 (1988): 243. http://dx.doi.org/10.1071/aj87019.
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The Otway Basin developed as a series of extensional basins along the southern margin of Australia during the Late Jurassic and the Early Cretaceous, prior to the break up of Eastern Gondwanaland. The Basin developed initially as a rift which subsequently, Middle Cretaceous time onwards, drifted and separated.The structural framework of the Basin is very complex due to the superposition of various successive tectonic processes that resulted in a series of predominantly north-west-south-east striking, basin dipping faults. Strike directions of the faults progressively change to a more north-south direction off Tasmania. In addition, in the area east of Cape Otway, the predominant strike trend changes to a north-east- south-west direction.Previous models for the development of this complex Basin have all invoked an east-west right lateral wrench system across south-eastern Australia. However, results from recent seismic mapping of the basin have indicated that some features present exhibit components of east-west left lateral movement. Many younger features, particularly in the east, also exhibit recent reverse fault movements.The author interprets that a right lateral east-west couple was active during the early part of the basin development. However, many of the features and trends observed can be better accounted for by the presence of a north-south striking wrench system which has induced an apparent east-west left lateral movement. Such a wrench system is present in the Southern Ocean, where a series of north-south striking transform faults have developed as a result of relative movement at the Southern Ocean spreading centre. Lateral movements across these transform faults have played a major role in the development of some of the observed features within the Basin.
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Burgin, Hugo B., Khalid Amrouch, Mojtaba Rajabi, David Kulikowski, and Simon P. Holford. "Determining paleo-structural environments through natural fracture and calcite twin analyses: a case study in the Otway Basin, Australia." APPEA Journal 58, no. 1 (2018): 238. http://dx.doi.org/10.1071/aj17099.
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The structural history of the Otway Basin has been widely studied; however, previous works have focussed on large kilometre scale, basin and seismic structures, or have over-simplified natural fracture analysis with an excessive focus on fracture strike direction and a disregard for 3D geometry, a crucial characteristic when considering states of stress responsible for natural fracture formation. In this paper, we combine techniques of natural fracture analysis and calcite twin stress inversion to investigate the meso (outcrop and borehole) and micro (crystal) scale evidence for structural environments that have contributed to basin evolution. Our results indicate that basin evolution during the post-Albian may be markedly more complex than the previously thought stages of late Cretaceous inversion, renewed rifting and long-lived mid-Eocene to recent compression, with evidence for up to six structural environments detected across the basin, including; NE–SW and NW–SE extension, NW–SE compression, a previously undetected regime of NE–SW compression, and two regimes of strike-slip activity. By constraining structural environments on the meso- and micro-scale we can deliver higher levels of detail into structural evolution, which in turn, provides better-quality insights into multiple petroleum system elements, including secondary migration pathways and trap formation. Our research also shows that the Otway Basin presents a suitable environment for additional micro-scale structural investigations through calcite twin analyses.
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Duddy, I. R. "FOCUSSING EXPLORATION IN THE OTWAY BASIN: UNDERSTANDING TIMING OF SOURCE ROCK MATURATION." APPEA Journal 37, no. 1 (1997): 178. http://dx.doi.org/10.1071/aj96010.
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Quantitative reconstruction of the thermal and structural histories at key locations in the Otway Basin using an integrated approach based on AFTA® and vitrinite reflectance data reveals a regional pattern of elevated geothermal gradient prior to mid-Cretaceous cooling. Paleogeothermal gradients declined from −50 to 70°C/ km at −95 Ma to present day levels in the range −30 to 40°C/km by around 80 Ma. As a result, significant hydrocarbon generation must have occurred from the thick Late Jurassic to Early Cretaceous Otway Group section during the rapid rift-burial phase that preceded major mid-Cretaceous cooling.Regional decline in geothermal gradient in the Late Cretaceous leads to a 'two-stage' generation history for Otway Group source rocks because subsequent hydrocarbon generation did not recommence until the early maturation effects were overcome by greater Late Cretaceous and Tertiary burial. Such early, high heat flow is regarded as a feature of rift basins, and this results in an inverted pattern of hydrocarbon generation from rift source rocks that is here referred to as 'top-down generation', and which has a key influence on hydrocarbon prospectivity.Analysis of key hydrocarbon discoveries in the basin leads to the conclusion that all significant accumulations can reasonably be inferred to be sourced from the Otway Group, due to 'top-down generation5 delayed until the mid-Tertiary to present-day burial phase. This situation clearly favours hydrocarbon preservation in traps of a range of ages and has the added advantage of limiting the time available for traps to be breached in subsequent structuring episodes.This understanding of the decoupled relationship between the burial and thermal histories provides a sharp focus for further exploration of Otway Group-sourced accumulations, by defining areas with suitable thicknesses of the Late Cretaceous and Tertiary depositional packages which maximise the amount of re-generation since the mid-Tertiary.
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Jones, R. M., P. Boult, R. R. Hillis, S. D. Mildren, and J. Kaldi. "INTEGRATED HYDROCARBON SEAL EVALUATION IN THE PENOLATROUGH, OTWAY BASIN." APPEA Journal 40, no. 1 (2000): 194. http://dx.doi.org/10.1071/aj99011.
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Seals are one of the main components of the petroleum system, yet their evaluation has received surprisingly little attention in terms of integrated risk assessment. This paper emphasises the need for an integrated multi-disciplinary approach for robust cap and fault seal evaluation so to minimise seal risk. The region of study is the Penola Trough, Otway Basin, where recent improvements in seismic quality, stratigraphic modelling and additional well control have greatly enhanced regional prospectivity.The Laira Formation has the lowest cap seal risk of Penola Trough strata based on empirical data. The Eumeralla Formation has a similar gamma ray log signature to the Laira Formation yet contains a higher frequency of sandy, relatively high permeability horizons. These horizons increase the likelihood of fault juxtaposition and the development of leaky windows that allow cross fault communication.Faults in the Penola Trough display fractal characteristics from seismic to core scale. A prediction of regional fault extension and deformation intensity below seismic resolution is viable since fault systems appear to be systematic. Extrapolation of fault populations to the millimetre scale shows good agreement with fault density recorded in core from a fault damage zone. Deformation intensities close to seismically resolvable faults are indicative of inner damage zone geometry where faults form linked cluster arrays. Microstructural fault analysis indicates the dominant fault processes in the Upper Crayfish Group are grain boundary sliding and cataclasis with gouge quartz cementation. Petrophysical analysis indicates these faults are able to support gas columns of up to 102 m.The relative probability of seal failure due to the development of effective structural permeability within the in-situ stress field indicates that planes at the greatest risk of failure are steeply dipping (>60°) and strike between 110°N and 200°N. Open fractures crosscutting pre-existing faults have been identified through microstructural examination and these may provide a mechanism for trap leakage and tertiary hydrocarbon migration. An integrated technique for mapping the relative risk of seal breach due to the development of effective structural permeability at the seismic scale is also presented.
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Norvick, M. S., and M. A. Smith. "MAPPING THE PLATE TECTONIC RECONSTRUCTION OF SOUTHERN AND SOUTHEASTERN AUSTRALIA AND IMPLICATIONS FOR PETROLEUM SYSTEMS." APPEA Journal 41, no. 1 (2001): 15. http://dx.doi.org/10.1071/aj00001.
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Southern Australian breakup history is divisible into three phases. The first phase began with Callovian (c.159–165 Ma) rifting in the western Bight Basin. During the Tithonian (c.142–146 Ma), rifting extended eastwards into the Duntroon, Otway and Gippsland Basins. By the Valanginian (c.130–135 Ma), ocean crust formed between India and western Australia. Structural style in the western Bight changed to thermal subsidence. However, fluvio-lacustrine rift sedimentation continued in Duntroon, Otway and Gippsland until the Barremian (c.115–123 Ma) when these basins also changed to thermal subsidence. The diachronous progression of basin fill types produces a progressive shift in ages of potential source, seal and reservoir intervals along the margin.The second phase began during the Cenomanian (c.92–97.5 Ma) with uplift in eastern Australia, stress reorganisation and divergence of basin development. The Otway, Sorell and Great South Basins formed in a transtensional regime. These tectonics resulted in trap generation through faulting, inversion and wrenching. During the Santonian, oceanic spreading began in the southern Tasman Sea (c.85 Ma). Slow extension caused thinning of continental crust in the Bight and Otway Basins and subsidence into deeper water. Ocean crust formed south of the Bight Basin in the Early Campanian (c.83 Ma) and also started extending up the eastern Australian coast.The third stage in development was caused by Eocene changes to fast spreading in the Southern Ocean (c.44 Ma), final separation of Australia and Antarctica, and cessation of Tasman Sea spreading. These events caused collapse of continental margins and widespread marine transgression. The resultant loading, maturation and marine seal deposition are critical to petroleum prospectivity in the Gippsland Basin.
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Perincek, D., and C. D. Cockshell. "THE OTWAY BASIN: EARLY CRETACEOUS RIFTING TO NEOGENE INVERSION." APPEA Journal 35, no. 1 (1995): 451. http://dx.doi.org/10.1071/aj94029.
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A regional seismic interpretation ot the on shore Otway Basin has been completed and used to determine the basin's structural history.Sedimentation commenced in the Tithonian-Berriasian with the deposition of the volcanogenic Casterton Formation and continued into the Berriasian-Barremian with the deposition in elongate half graben, of thick fluviolacustrine sediments of the Crayfish Group, typically thickening dramatically towards the bounding faults. The NW to W trend of Crayfish Group depocentres and their major bounding faults suggest that the initial extension direction was N-S to NE-SW in the Late Jurassic-Early Cretaceous. Dextral transtensional movement occurred along the Trumpet Fault in the west of the basin and was complemented by sinistral transtension on the major NNE striking faults of the Torquay Sub-basin in the east during this period.The dip direction of the pre-Barremian bounding faults changes a number of times along the northern margin of the basin. These changes occur across transfer/accommodation zones of complex faulting and folding, not over discrete transfer faults.Faulting and related uplift resulted in partial erosion of the Crayfish Group from a number of structural highs, prior to the Aptian. The half graben faults are overlain by Eumeralla Formation indicating that active rifting had ceased by the Aptian in the onshore Otway Basin. Further erosion occurred following post-Albian faulting and uplift prior to the Paleocene, in particular within the eastern part of the basin.During deposition of the Sherbrook Group in the Late Cretaceous, fault reactivation produced minor, shallow grabens within the older half graben systems. Major movement also continued along the Tartwaup Fault Zone, resulting in basin deepening toward the SW. This fault activity continued into the Paleocene-Early Eocene during deposition of the Wangerrip Group. In the Eocene, the Southern Ocean spreading rates changed from slow to fast, resulting in the late-Early Eocene deltaic sediment of the Upper Wangerrip Group covering some of the earlier extension faults. Compression, resulting in right-lateral wrenching and inversion of previous faults, occurred during the Miocene-Recent. Pliocene-Holocene volcanic activity occurred along zones of weakness related to these fault systems.
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Tupper, N. P., D. Padley, R. Lovibond, A. K. Duckett, and D. M. McKirdy. "A KEY TEST OF OTWAY BASIN POTENTIAL: THE EUMERALLA-SOURCED PLAY ON THE CHAMA TERRACE." APPEA Journal 33, no. 1 (1993): 77. http://dx.doi.org/10.1071/aj92007.
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Geochemical analysis, petrographic examination and wireline log interpretation have identified intervals within the lower Eumeralla Formation of the Otway Group (Early Cretaceous) with good source potential. The sequence has a maximum penetrated thickness of 260 m and consists of thinly interbedded coal and siltstone deposited in peat swamp and lacustrine environments. Vitrinite is the dominant maceral present in the coal although the proportion of more oil-prone liptinite commonly exceeds 10 per cent. This is consistent with the intermediate Type II/ III kerogen composition indicated by Rock-Eval and is comparable with data from proven terrestrial oil-productive source rocks in the Gippsland and Cooper Basins. The siltstone is organically-lean but has some algal input. Algal-rich lacustrine source rocks could be developed nearer the basin centre.Regional stratigraphic, structural and thermal modelling studies highlight the exploration potential of the Chama Terrace in the northwest Otway Basin. Structures on the terrace are ideally situated to receive a hydrocarbon charge from mature Eumeralla Formation source rocks in fault blocks on the downthrown side of the Tartwaup Hingeline.Seismic mapping of offshore permit EPP 24, and adjacent onshore permit PEL 40, has delineated several large fault blocks where Crayfish Subgroup (Otway Group) reservoir is juxtaposed against, and sealed by, the lower Eumeralla Formation sequence. Drilling scheduled for late 1992 will determine the credibility of the Eumeralla-sourced play and provide a key test of the ultimate hydrocarbon potential of the Otway Basin.
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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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Mehin, K., and A. G. Link. "KITCHENS, KETTLES AND CUPS OF HYDROCARBONS, VICTORIAN OTWAY BASIN." APPEA Journal 37, no. 1 (1997): 285. http://dx.doi.org/10.1071/aj96018.
Full textAbstract:
Evaluation of Early Cretaceous source rocks within the onshore Victoria Otway Basin has revealed that thick, mature shales containing predominantly gas-prone and in local concentrations, oil-prone macerals exist northwest of Portland, in the Tyrendarra Embayment, and around the Port Campbell region.Current results of Rock-Eval, bulk composition, gas chromatography, and biomarker analyses, coupled with geohistory and hydrocarbon generation interpretations, indicate that at least three phases of oil generation and expulsion occurred within the basin. The earliest phase, which coincided with the maximum heatflow in the crust around 100 Ma, resulted in the charging of the existing stratigraphic/shoestring traps of the basin. The second and third phases occurred in the eastern end of the basin at around 85 and 60 Ma. There is also evidence to suggest that structural traps of the eastern areas were formed later, during Oligocene time, and that these traps are probably still receiving late-stage charges of hydrocarbons.Although the sparse well density in the basin has resulted in limited, non-uniforin sampling opportunities, several regions with good Early Cretaceous source rocks can be recognised. Some of these good source rock areas are in close proximity to the several known hydrocarbon shows and producing fields. These current studies, which also include a source rock risk analysis indicating source rock adequacy, show that locations for future exploration could include the Casterton-Portland-Mt Gambier western region, the Peterborough-Port Campbell eastern region, and the prospective close peripheries and offshore extensions of these regions.
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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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Lovibond, R., R. J. Suttill, J. E. Skinner, and A. N. Aburas. "THE HYDROCARBON POTENTIAL OF THE PENOLA TROUGH, OTWAY BASIN." APPEA Journal 35, no. 1 (1995): 358. http://dx.doi.org/10.1071/aj94023.
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The Penola Trough is an elongate, Late Jurassic to Early Cretaceous, NW-SE trending half graben filled mainly with synrift sediments of the Crayfish Group. Katnook-1 discovered gas in the basal Eumeralla Formation, but all commercial discoveries have been within the Crayfish Group, particularly the Pretty Hill Formation. Recent improvements in seismic data quality, in conjunction with additional well control, have greatly improved the understanding of the stratigraphy, structure and hydrocarbon prospectivity of the trough. Strati-graphic units within the Pretty Hill Formation are now mappable seismically. The maturity of potential source rocks within these deeper units has been modelled, and the distribution and quality of potential reservoir sands at several levels within the Crayfish Group have been studied using both well and seismic data. Evaluation of the structural history of the trough, the risk of a late carbon dioxide charge to traps, the direct detection of gas using seismic AVO analysis, and the petrophysical ambiguities recorded in wells has resulted in new insights. An important new play has been recognised on the northern flank of the Penola Trough: a gas and oil charge from mature source rocks directly overlying basement into a quartzose sand sequence referred to informally as the Sawpit Sandstone. This play was successfully tested in early 1994 by Wynn-1 which flowed both oil and gas during testing from the Sawpit Sandstone. In mid 1994, Haselgrove-1 discovered commercial quantities of gas in a tilted Pretty Hill Formation fault block adjacent to the Katnook Field. These recent discoveries enhance the prospectivity of the Penola Trough and of the Early Cretaceous sequence in the wider Otway Basin where these sediments are within reach of the drill.
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Moore, A. M. G., J. B. Willcox, N. F. Exon, and G. W. O'Brien. "CONTINENTAL SHELF BASINS ON THE WEST TASMANIA MARGIN." APPEA Journal 32, no. 1 (1992): 231. http://dx.doi.org/10.1071/aj91018.
Full textAbstract:
The continental margin of western Tasmania is underlain by the southern Otway Basin and the Sorell Basin. The latter lies mainly under the continental slope, but it includes four sub-basins (the King Island, Sandy Cape, Strahan and Port Davey sub-basins) underlying the continental shelf. In general, these depocentres are interpreted to have formed at the 'relieving bends' of a major left-lateral strike-slip fault system, associated with 'southern margin' extension and breakup (seafloor spreading). The sedimentary fill could have commenced in the Jurassic; however, the southernmost sub-basins (Strahan and Port Davey) may be Late Cretaceous and Paleocene, respectively.Maximum sediment thickness is about 4300 m in the southern Otway Basin, 3600 m in the King Island Sub-basin, 5100 m in the Sandy Cape Basin, 6500 m in the Strahan Sub-basin, and 3000 m in the Port Davey Sub-basin. Megasequences in the shelf basins are similar to those in the Otway Basin, and are generally separated by unconformities. There are Lower Cretaceous non-marine conglomerates, sandstones and mudstones, which probably include the undated red beds recovered in two wells, and Upper Cretaceous shallow marine to non-marine conglomerates, sandstones and mudstones. The Cainozoic sequence often commences with a basal conglomerate, and includes Paleocene to Lower Eocene shallow marine sandstones, mudstones and marl, Eocene shallow marine limestones, marls and sandstones, and Oligocene and younger shallow marine marls and limestones.The presence of active source rocks has been demonstrated by the occurrence of free oil near TD in the Cape Sorell-1 well (Strahan Sub-basin), and thermogenic gas from surficial sediments recovered from the upper continental slope and the Sandy Cape Sub-basin. Geohistory maturation modelling of wells and source rock 'kitchens' has shown that the best locations for liquid hydrocarbon entrapment in the southern Otway Basin are in structural positions marginward of the Prawn-1 well location. In such positions, basal Lower Cretaceous source rocks could charge overlying Pretty Hill Sandstone reservoirs. In the King Island Sub-Basin, the sediments encountered by the Clam-1 well are thermally immature, though hydrocarbons generated from within mature Lower Cretaceous rocks in adjacent depocentres could charge traps, providing that suitable migration pathways are present. Whilst no wells have been drilled in the Sandy Cape Sub-basin, basal Cretaceous potential source rocks are considered to have entered the oil window in the early Late Cretaceous, and are now capable of generating gas/condensate. Upper Cretaceous rocks appear to have entered the oil window in the Paleocene. In the Strahan Sub-Basin, mature Cretaceous sediments in the depocentres are available to traps, though considerable migration distances would be required.It is concluded that the west Tasmania margin, which has five strike-slip related depocentres and the potential to have generated and entrapped hydrocarbons, is worthy of further consideration by the exploration industry. The more prospective areas are the southern Otway Basin, and the Sandy Cape and Strahan sub-basins of the Sorell Basin.
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Trupp, Mark A., Keith W. Spence, and Michael J. Gidding. "HYDROCARBON PROSPECTIVITY OF THE TORQUAY SUB-BASIN, OFFSHORE VICTORIA." APPEA Journal 34, no. 1 (1994): 479. http://dx.doi.org/10.1071/aj93039.
Full textAbstract:
The Torquay Sub-basin lies to the south of Port Phillip Bay in Victoria. It has two main tectonic elements; a Basin Deep area which is flanked to the southeast by the shallower Snail Terrace. It is bounded by the Otway Ranges to the northwest and shallow basement elsewhere. The stratigraphy of the area reflects the influence of two overlapping basins. The Lower Cretaceous section is equivalent to the Otway Group of the Otway Basin, whilst the Upper Cretaceous and Tertiary section is comparable with the Bass Basin stratigraphy.The Torquay Sub-basin apparently has all of the essential ingredients needed for successful hydrocarbon exploration. It has good reservoir-seal pairs, moderate structural deformation and probable source rocks in a deep kitchen. Four play types are recognised:Large Miocene age anticlines, similar to those in the Gippsland Basin, with an Eocene sandstone reservoir objective;The same reservoir in localised Oligocene anticlines associated with fault inversion;Possible Lower Cretaceous Eumeralla Formation sandstones in tilted fault blocks and faulted anticlines; andLower Cretaceous Crayfish Sub-group sandstones also in tilted fault block traps.Maturity modelling suggests that the Miocene anticlines post-date hydrocarbon generation. Poor reservoir potential and complex fault trap geometries downgrade the two Lower Cretaceous plays.The Oligocene play was tested by Wild Dog-1 which penetrated excellent Eocene age reservoir sands beneath a plastic shale seal, however, the well failed to encounter any hydrocarbons. Post-mortem analysis indicates the well tested a valid trap. The failure of the well is attributed to a lack of charge. Remaining exploration potential is limited to the deeper plays which have much greater risks associated with each play element.
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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.
Full textAbstract:
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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Buffin, A. J., A. J. Sutherland, and J. A. Gorski. "THE OTWAY BASIN: EARLY CRETACEOUS RIFTING TO NEOGENE INVERSION." APPEA Journal 35, no. 1 (1995): 494. http://dx.doi.org/10.1071/aj94031.
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Borehole breakouts and hydraulic fractures inferred from dipmeter and formation microscanner logs indicate that the minimum horizontal stress (σh) is oriented 035°N in the South Australian sector of the Otway Basin. Density and sonic check-shot log data indicate that vertical stress (σv) increases from approximately 20 MPa at a depth of one km to 44 MPa at two km and 68 MPa at three km. Assuming a normal fault condition (i.e. σy > σH > σh), the magnitude of σh is 75 per cent of the magnitude of the maximum horizontal stress (σH), and the magnitude of σH is close to that of av. Sonic velocity compaction trends for shales suggest that pore pressure is generally near hydrostatic in the Otway Basin.Knowledge of the contemporary stress field has a number of implications for hydrocarbon production and exploration in the basin. Wellbore quality in vertical wells may be improved (breakouts suppressed) by increasing the mud weight to a level below that which induces hydraulic fracture, or other drilling problems related to excessive mud weight. Horizontal wells drilled in the σh direction (035°N/215°N) should be more stable than those drilled in the σH direction, and indeed than vertical wells. In any EOR operations where water flooding promotes hydraulic fracturing, injectors should be aligned in the aH (125°N/305°N) direction, and offset from producers in the orthogonal σh direction. Any deviated/horizontal wells targeting the fractured basement play should be oriented in the σh (035°N/215°N) direction to maximise intersection with this open, natural fracture trend. Hydrocarbon recovery in wells deviated towards 035°N/215°N may also be enhanced by inducing multiple hydraulic fractures along the wellbore.Considering exploration-related issues, faults following the dominant structural trend, sub-parallel to σH orientation, are the most prone to be non-sealing during any episodic build-up of pore pressure. Pre-existing vertical faults striking 080-095°N and 155-170°N are the most prone to at least a component of strike-slip reactivation within the contemporary stress field.
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Bendall, Betina, Anne Forbes, and Tony Hill. "Resolving lithostratigraphic complexities in the Crayfish Group, Otway Basin using chemostratigraphy." APPEA Journal 61, no. 2 (2021): 588. http://dx.doi.org/10.1071/aj20114.
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The Otway Basin comprises a significant part of the eastern Australian Southern Rift System, a divergent passive continental margin formed during the Cretaceous separation of the Australian and Antarctic continents. Early rifting activity resulted in the development of many half grabens within the Otway Basin, which are largely infilled by sediments of the Casterton Formation and Crayfish Group. Despite over 20 years of exploration and hydrocarbon production from these units however, their lithostratigraphic characterisation and nomenclature remain ambiguous, with structural complexity and prevalent lateral facies changes leading to confusion in their basin-wide correlation. Deposited in a largely non-marine, fluvial/lacustrine environment, repeating cycles of sandstones and shales of the Crayfish Group can be difficult to resolve using petrology, palynology and wireline log data. The use of chemostratigraphy is favoured as an investigative tool in this situation since changes in provenance, lithic composition, facies, weathering and diagenesis are reflected in the mineralogy of the sediments, resulting in variations in their inorganic geochemistry. Uniform sedimentary successions can thus potentially be differentiated into unique sequences and packages based on their characteristic geochemistry, aiding in the resolution of complex structural relationships and facies changes. In this study, we present new inorganic geochemistry data for four key wells in the South Australian (SA) Penola Trough and interpret the geochemistry data consistent with, and building on, the chemostratigraphic schema of Forbes et al. to demonstrate its utility and robustness. We then undertake inter-well wireline log correlations across the SA Penola Trough using the wells with chemostratigraphic data as controls.
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Williamson, P. E., C. J. Pigram, J. B. Colwell, A. S. Scherl, K. L. Lockwood, and J. C. Branson. "PRE-EOCENE STRATIGRAPHY, STRUCTURE, AND PETROLEUM POTENTIAL OF THE BASS BASIN." APPEA Journal 25, no. 1 (1985): 362. http://dx.doi.org/10.1071/aj84031.
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Exploration in the Bass Basin has mainly concentrated on the Eocene part of the Eastern View Coal Measures with the pre-Eocene stratigraphy hardly being tested. Structural mapping using a good quality Bureau of Mineral Resources regional seismic survey and infill industry seismic data, in conjunction with seismic stratigraphy and well data, has generated an understanding of the structure and stratigraphy of the pre- Eocene basin, which suggests that exploration potential exists in structural and stratigraphic leads of both Paleocene and Cretaceous age.The Paleocene structure is influenced by the reactivation of normal faults developed at the time of the mid Cretaceous rift unconformity and reflects drape over deeper features. Consequently fault dependent structural closures often persist from Paleocene to (?)Jurassic levels. Possible stratigraphic traps are also observed against horst blocks and around the basin margins. The longitudinal fault directions are northwest and west northwest with an oblique northerly direction and a prevailing north northeasterly transverse direction.The Paieocene and Upper Cretaceous part of the Eastern View Coal Measures consists of sands, shales and coals deposited in alluvial fans, on flood plains, and in lakes. These are underlain by Early Cretaceous Otway Groups, sands, shales and volcanics. Both intervals have potential reservoir and source rocks and often occur at mature depths. No pre-Otway Group sediments have been encountered in wells in the Bass Basin. However, the Permo- Carboniferous and possibly Triassic strata that occur in Northern Tasmania exhibit reservoir and source rock potential and may extend offshore beneath the Bass Basin.Pre-Eocene structural and stratigraphic studies of the Bass Basin thus point to reservoir and hydrocarbon source potential for possible multiple hydrocarbon exploration targets.
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Perincek, D., B. Simons, and G. R. Pettifer. "THE TECTONIC FRAMEWORK AND ASSOCIATED PLAY TYPES OF THE WESTERN OTWAY BASIN, VICTORIA, AUSTRALIA." APPEA Journal 34, no. 1 (1994): 460. http://dx.doi.org/10.1071/aj93038.
Full textAbstract:
A regional seismic interpretation was carried out over the onshore Otway Basin in western Victoria to produce two-way time formation top and thickness images and a structural elements map showing the ages of faulting. This interpretation improved the understanding of tectonic events controlling the evolution of the basin and associated hydrocarbon plays.The early development of the basin involved rifting due to NE–SW extension in the Late Jurassic–Early Cretaceous, producing a number of half-grabens. The rifting conforms with established rift development models, in which half-grabens of alternating vergence are separated by transfer zones displaying complex folding and faulting patterns. Within the northern margin of the basin these half-grabens were filled and rifting ceased prior to the Aptian.An unconformity in the Wangerrip Group has been identified in the basin, corresponding to a change in Southern Ocean spreading rates from slow to fast (52Ma).Compression, resulting in right-lateral wrenching and inversion of previous faults, occurred during the Miocene–Recent.A number of hydrocarbon play types were identified based on the structural mapping carried out. These play types include anticlines associated with transfer zones, tilted fault blocks, buried basement highs, stratigraphic traps, post-Albian horst structures, syndepositional roll-over structures and post-Oligocene normal and reverse fault related structures.
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O'Brien, G. W., C. V. Reeves, P. R. Milligan, M. P. Morse, E. M. Alexander, J. B. Willcox, Zhou Yunxuan, D. M. Finlayson, and R. C. Brodie. "NEW IDEAS ON THE RIFTING HISTORY AND STRUCTURAL ARCHITECTURE OF THE WESTERN OTWAY BASIN: EVIDENCE FROM THE INTEGRATION OF AEROMAGNETIC, GRAVITY AND SEISMIC DATA." APPEA Journal 34, no. 1 (1994): 529. http://dx.doi.org/10.1071/aj93042.
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The integration of high resolution, image-processed aeromagnetic data with regional geological, magnetic, gravity and seismic data-sets has provided new insights into the structural architecture, rifting history, and petroleum potential of the western onshore and offshore Otway Basin, south-eastern Australia.Three principal structural directions are evident from the magnetic data: NS, NE-ENE and NW-WNW. The structural fabric and regional geological data suggest that the rifting history of the basin may have taken place in two distinct stages, rather than within a simple rift-to-drift framework. The initial stage, from 150 to ~120 Ma, took place within a stress regime dominated by NW-SE extensional transport, similar to that of the basins within the Great Australian Bight to the west. ENE-striking extensional rift segments, such as the Crayfish Platform-Robe Trough and the Torquay Sub-Basin, developed during this period, contemporaneous with the deposition of thick sediments of the Early Cretaceous (Tithonian-Hauterivian) Crayfish Subgroup. In other parts of the basin, NW-striking rift segments, such as the Penola, and perhaps Ardonachie, Troughs onshore, developed within a strongly trans-tensional (left-lateral strike-slip) environment. At ~120 Ma, the regional stress field changed, and the Crayfish Subgroup-aged rift segments were reactivated, with uplift and block faulting extending through to perhaps 117 Ma. Rifting then recommenced at about 117 Ma (contemporaneous with the deposition of the Barremian-Albian Eumeralla Formation), though the extensional transport direction was now oriented NNE-SSW, almost perpendicular to that of the earlier Crayfish Subgroup rift stage. This later rift episode ultimately led to continental breakup at ~96 Ma and produced the 'traditional' normal fault orientations (NW-SE to WNW-ESE) throughout the Otway Basin.
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Jennie, Totterdell. "New exploration opportunities along Australia's southern margin." APPEA Journal 52, no. 1 (2012): 29. http://dx.doi.org/10.1071/aj11003.
Full textAbstract:
The 2012 Australian offshore acreage release includes exploration areas in four southern margin basins. Three large Release Areas in the frontier Ceduna Sub-basin lie adjacent to four exploration permits granted in 2011. The petroleum prospectivity of the Ceduna Sub-basin is controlled by the distribution of Upper Cretaceous marine and deltaic facies and a structural framework established by Cenomanian growth faulting. These Release Areas offer a range of plays charged by Cretaceous marine and coaly source rocks and Jurassic lacustrine sediments. In the westernmost part of the gas-producing Otway Basin, a large Release Area offers numerous opportunities to test existing and new play concepts in underexplored areas beyond the continental shelf. Gas and oil shows in the eastern part of the Release Area confirm the presence of at least two working petroleum systems. In the eastern Otway Basin, several Release Areas are offered in shallow water on the eastern flank of the highly prospective Shipwreck Trough and provide untested targets along the eastern basin margin southward into Tasmanian waters. To the south, a large Release Area in the frontier Sorell Basin provides the opportunity to explore a range of untested targets in depocentres that formed along the western Tasmanian transform continental margin. Two Release Areas offer exploration potential in the under-explored eastern deepwater part of the Gippsland Basin. Geological control is provided by several successful wells indicating the presence of both gas and liquids in the northern area, while the southern area represents the remaining frontier of the basin
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Langhi, Laurent, Ernest Swierczek, Julian Strand, Louise Goldie Divko, David Whittam, and Andrew Ross. "Structural containment in the Port Campbell Embayment and on the Mussel Platform, Otway Basin, Victoria." APPEA Journal 61, no. 2 (2021): 646. http://dx.doi.org/10.1071/aj20124.
Full textAbstract:
As part of the Victorian Gas Program, new geological modelling of the Cretaceous to recent deposits in the Port Campbell Embayment and the Mussel Platform was carried out to investigate fault seal and trap integrity. Structural characterisation of the Late Cretaceous to present-day sedimentary sequence highlights cross-cutting fault trends defining potential structural traps containing Waarre Formation reservoirs. The fault trends are primarily controlled by Cretaceous-Paleogene extension and are reactivated during the Paleogene. Seismic facies in the top seal suggest an N-S environmental shift from open-marine to proximal nearshore marine. The quantification of fault membrane seals suggests that while reservoir-on-reservoir juxtapositions may enable some degree of lateral flow, efficient trapping relying on juxtaposition seal against the Belfast or Skull Creek mudstones is widespread. Fault geomechanics suggests that NW-SE and E-W faults accommodated most of the extensional strain and could have been associated with increased vertical structural permeability; however, there are no leakage indicators to support widespread vertical migration. These results do not support previous assumptions that fault seal integrity and top seal bypass represent a critical and widespread issue within the nearshore Otway Basin.
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Boult, P. J., B.A.Camac, and A. W. Davids. "3D FAULT MODELLING AND ASSESSMENT OF TOP SEAL STRUCTURAL PERMEABILITY—PENOLA TROUGH, ONSHORE OTWAY BASIN." APPEA Journal 42, no. 1 (2002): 151. http://dx.doi.org/10.1071/aj01009.
Full textAbstract:
Many of the commercial hydrocarbon accumulations discovered to date within the Pretty Hill Formation in the onshore Otway Basin of southeastern Australia rely on a semi-brittle top seal and fault seal. Therefore a detailed and integrated fault, stress field and fracture analysis is fundamental to prospect evaluation.A syn-kinematic interpretation of the 3D seismic data set, using variance cube and visualisation technology was augmented with interpretation of the dip-meter and high-resolution borehole images. This resulted in the interpretation of a more complex fault history than previously inferred from 2D seismic mapping and dipmeter analysis alone.There are two major prospect/field bounding fault sets within the Penola Trough. Northwest-trending faults are associated with two commercial fields and several palaeo-accumulations. East-west trending faults are associated with three major fields, two uneconomic fields and two possible palaeo accumulations.Hydrocarbon leakage is probably caused by the creation of structural permeability across the regional seal. The location of leakage depends on the interaction between the seal, associated faults, and the regional stress field. Faults deflect regional stress trajectories within the top seal, creating local areas of high differential stress which enables brittle failure and the development of structural permeability. Predicting stress trajectories, the magnitude of differential stress and thus the location of structural permeability within the top seal to the underlying Pretty Hill Formation reservoirs, will reduce exploration risk uncertainty.
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Williams, M. L., A. J. Boulton, M. Hyde, A. J. Kinnear, and C. D. Cockshell. "ENVIRONMENTAL IMPACT OF SEISMIC OPERATIONS IN THE OTWAY BASIN, SOUTH AUSTRALIA." APPEA Journal 34, no. 1 (1994): 741. http://dx.doi.org/10.1071/aj93054.
Full textAbstract:
The Department of Mines and Energy, South Australia (DME) contracted Michael Williams and Associates Pty Ltd to audit the environmental management of seismic exploration operations in the South Australian Otway Basin. The audit was carried out in early 1992 and covered petroleum exploration operators and DME environmental management systems. An innovative field sampling technique was developed to compare the environmental impact of two different seismic line clearing techniques. Recovery of native vegetation as measured by vegetation structure was also quantified.The audit found DME to have a dynamic and integrated environmental management system while company systems varied in standard. Wide consultation assisted the audit process.As a result of clearing for agriculture, native vegetation covers only six per cent of the Otway Basin. With the strict limitations to broad-scale vegetation clearance since the mid-1980s and the cessation since 1991, the greatest environmental impact of seismic exploration is the clearance of native vegetation for access by seismic vehicles. Native vegetation structure and associated abiotic variables on seismic lines and adjacent control sites, were subject to a classification and ordination analysis which compared the impact of seismic lines constructed by bulldozer or Hydro-ax (industrial slasher). Post-seismic recovery rates of three different vegetation associations were also determined. This analytical technique permits the effects of seismic line clearance to be compared with the natural variability of specific vegetation associations within a region. In interpreting the results however, there is a confounding effect of line type and year as most of the more recent seismic lines were constructed using a Hydro-ax. Results indicate that Hydro-ax clearing affects vegetation structure less than bulldozing. Most Hydro-ax sites recovered within a few years whereas some sites, bulldozed as early as 1971, particularly tussock grasslands, have not yet recovered.This study provides a significant break-through in the debate about the persistence of seismic impacts on native vegetation. As a rapid preliminary assessment, sampling vegetation structure rather than floristics, provides a cost-effective audit and monitoring technique which can be used by non-specialists in a range of petroleum exploration environments. Any significant structural differences may require more detailed analysis to determine if floristic composition also differed.
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Mehin, Kourosh, and Alby G. Link. "SOURCE, MIGRATION AND ENTRAPMENT OF HYDROCARBONS AND CARBON DIOXIDE IN THE OTWAY BASIN, VICTORIA." APPEA Journal 34, no. 1 (1994): 437. http://dx.doi.org/10.1071/aj93037.
Full textAbstract:
Salinity distribution, structure, carbon dioxide occurrences, facies and thermal gradient variations and gas isotope studies in the onshore Victorian Otway Basin indicate that the migration of fluids from the Eumeralla Formation source rocks, and the entrapment of hydrocarbons in the Waarre Formation reservoir sands of the Port Campbell Embayment, are closely associated with the presence of three major fault systems. Hydrocarbon accumulation appears to take place where high salinities and normal rift-valley faults are in closest proximity to a structural trap. The large carbon dioxide occurrences are thought to be associated with volcanism and deep vertical fault conduits.Although there are, as yet, considerably fewer exploration wells in the Tyrendarra Embayment/Portland Trough, present studies are nevertheless indicating that broadly similar migration and salinity/fault relationships probably exist in this western portion of the basin. Drilling and analytical results also show this end of the basin to be prospective for not only gas but also oil.
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Schneider, C. L., K. C. Hill, and N. Hoffman. "COMPRESSIONAL GROWTH OF THE MINERVA ANTICLINE, OTWAY BASIN, SOUTHEAST AUSTRALIA—EVIDENCE OF OBLIQUE RIFTING." APPEA Journal 44, no. 1 (2004): 463. http://dx.doi.org/10.1071/aj03018.
Full textAbstract:
Shipwreck Trough, east-central Otway Basin, evolved through Early Cretaceous to Santonian extension, followed by Campanian–Paleocene and Miocene to Recent pulses of compression.Onshore to offshore correlation of seismic sequences combined with 3D seismic mapping reveals that the Minerva anticline is located above an Early Cretaceous, northeast trending, basement-involved, graben. The graben-forming, northeast and north–south trending faults became largely inactive prior to the end of the Early Cretaceous. During the Turonian to Santonian, the northeast trending Point Ronald anticline and newly formed east–west trending normal faults controlled sediment distribution. The structural style changed in the Campanian as the northeast trending Minerva anticline began to form with a coeval, northwest-trending, axial-perpendicular fault array located along the crest of the fold. The location and orientation of this fault set is consistent with a compressional mechanism for fold growth. Similar compressional folding events during the Miocene–Recent modified and tightened the fold. Isopach maps show that during the Campanian to Maastrichtian, sediment thinned onto the nascent Minerva anticline, but accommodation rate outpaced structural growth, preserving a continuous sedimentary sequence.The timing of compressional fold growth is enigmatic. Campanian–Maastrichtian compression at the Minerva anticline was synchronous with over 10 km of extension accommodated by the Tartwaup–Mussel hingeline, 50 km to the south. Although the compression may be far-field effects associated with Tasman Basin sea floor spreading, we speculate that the Minerva anticline grew by transpression within a larger left-lateral transtensional Shipwreck Trough.
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Moriarty, N. J., R. J. Taylor, and G. J. Daneel. "THE SAWPIT STRUCTURE—EVALUATION OF A FRACTURED BASEMENT RESERVOIR PLAY IN THE OTWAY BASIN." APPEA Journal 35, no. 1 (1995): 558. http://dx.doi.org/10.1071/aj94035.
Full textAbstract:
The 1992 exploration well Sawpit-1, drilled in the Penola Trough of the western Otway Basin, recovered a minor amount of oil (1.5 BBL) from fractured basement. This oil recovery, the first in the basin from rocks older than the Eumeralla Formation, has opened up a new oil play. Fractured basement reservoirs, which can be prolific producers, require prediction of fracture orientation and intensity to be appraised and developed successfully. Such information was sought from a detailed structural analysis of fault attributes (including dip, vertical displacement and heave) using 3D seismic data acquired over the structure in 1993.This 3D seismic data set, acquired at twice the group interval and less than one-quarter the fold of 2D data in the area, has provided the best imaging to date of the complex rifting events of the Sawpit region. Structural analysis of fault attributes indicates an initial south-southwest direction of extension in the Late Jurassic/Early Cretaceous for the Penola Trough, rather than oblique extension as suggested by some authors. This south-southwest extension orientation favours the formation of moderate to high angle fractures trending west-northwest to northwest. Present day minimum horizontal stress is favourably oriented approximately northeast-southwest for these fractures to be open. Interpretation of the 3D seismic data indicates Sawpit-1 probably intersected northeast trending fractures that are oriented perpendicular to the maximum horizontal compressive stress direction and therefore likely to be closed.A deviated well drilled from the northeast would be optimally oriented to intersect northwest trending basement fractures and test a play that has significant oil potential.
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Etheridge, M. A., J. C. Branson, and P. G. Stuart-Smith. "EXTENSIONAL BASIN — FORMING STRUCTURES IN BASS STRAIT AND THEIR IMPORTANCE FOR HYDROCARBON EXPLORATION." APPEA Journal 25, no. 1 (1985): 344. http://dx.doi.org/10.1071/aj84030.
Full textAbstract:
The Bass, Gippsland and Otway Basins of southeastern Australia were initiated by north-northeast to south- southwest lithospheric extension, largely during the Early Cretaceous. The extensional stage was followed by a Late Cretaceous to Pliocene thermal subsidence stage and a late stage of compressional tectonic overprinting.The extensional stage was dominated by two orthogonal fault sets - shallow to moderately dipping, rotational, normal faults and steeply dipping, transfer (transform) faults. Thermal subsidence involved vertical rather than horizontal movements, and consequently generated a discrete fault geometry, comprising steep, down-to-basin, normal faults with small displacements. The major extensional structures exerted a range of controls on both sedimentation and structuring during the subsidence stage. Likewise, the location and style of late Tertiary compressional structures overprinted on the Gippsland and, to a lesser extent, Bass and Otway Basins are controlled by reactivation of major early normal and transfer faults. In particular, the Kingfish, Mackerel, Halibut, Flounder and Tuna fields in the Gippsland Basin overlie a single Early Cretaceous transfer fault zone that was a basinwide structural boundary during extension. These fields occupy en echelon compressional structures generated by left-lateral wrench reactivation of the transfer zone during late Tertiary northwest-southeast compression. The major extensional structures have had an important influence on all stages of the evolution of these basins. It is contended that a thorough understanding of their extensional framework is an important factor in hydrocarbon exploration of these and other basins.
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Hill, K. A., D. M. Finlayson, K. C. Hill, and G. T. Cooper. "MESOZOIC TECTONICS OF THE OTWAY BASIN REGION: THE LEGACY OF GONDWANA AND THE ACTVE PACIFIC MARGIN—A REVIEW AND ONGOING RESEARCH." APPEA Journal 35, no. 1 (1995): 467. http://dx.doi.org/10.1071/aj94030.
Full textAbstract:
Mesozoic extension along Australia's southern margin and the evolution and architecture of the Otway Basin were probably controlled by three factors: 1) changes in global plate movements driven by mantle processes; 2) the structural grain of Palaeozoic basement; and, 3) changes in subduction along Gondwana's Pacific margin. Major plate realignments controlled the Jurassic onset of rifting, the mid-Cretaceous break-up and the Eocene onset of rapid spreading in the Southern Ocean.The initial southern margin rift site was influenced by the northern limit of Pacific margin (extensional) Jurassic dolerites and the rifting may have terminated dolerite emplacement. Changed conditions of Pacific margin subduction (e.g. ridge subduction) in the Aptian may have placed the Australia-Antarctic plates into minor compression, abating Neocomian southern margin rifting. It also produced vast amounts of volcanolithic sediment from the Pacific margin arc that was funnelled down the rift graben, causing additional regional subsidence due to loading. Albian orogenic collapse of the Pacific margin, related to collision with the Phoenix Plate, influenced mid-Cretaceous breakup propagating south of Tasmania and into the Tasman Sea.Major offsets of the spreading axis during breakup, at the Tasman and Spencer Fracture zones, were most likely controlled by the location of Palaeozoic terrane boundaries. The Tasman Fracture System was reactivated during break-up, with considerable uplift and denudation of the Bass failed rift to the east, which controlled Otway Basin facies distribution. Palaeozoic structures also had a significant effect in determining the half graben orientations within a general N-S extensional regime during early Cretaceous rifting. The late Cretaceous second stage of rifting, seaward of the Tartwaup, Timboon and Sorell fault zones, left a stable failed rift margin to the north, but the attenuated lithosphere of the Otway-Sorell microplate to the south records repeated extension that led to continental separation and may be part of an Antarctic upper plate.
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Duddy, I. R., B. Erout, P. F. Green, P. V. Crowhurst, and P. J. Boult. "TIMING CONSTRAINTS ON THE STRUCTURAL HISTORY OF THE WESTERN OTWAY BASIN AND IMPLICATIONS FOR HYDROCARBON PROSPECTIVITY AROUND THE MORUM HIGH, SOUTH AUSTRALIA." APPEA Journal 43, no. 1 (2003): 59. http://dx.doi.org/10.1071/aj02003.
Full textAbstract:
Reconstructed thermal and structural histories derived from new AFTA Apatite Fission Track Analysis, vitrinite reflectance and (U-Th)/He apatite dating results from the Morum–1 well, Otway Basin, reveal that the Morum High is a mid-Tertiary inversion structure. Uplift and erosion commencing in the Late Paleocene to mid-Eocene (57–40 Ma) removed around 1,500 m of sedimentary section. The eroded section is attributed to the Paleocene- Eocene Wangerrip Group which is considered to have been deposited in a major depocentre in the vicinity of the present Morum High. This depocentre is interpreted to have been one of a number of transtensional basins developed at the margin of the Morum Sub-basin and adjacent to the Tartwaup Hinge Zone and Mussel Fault during the Early Tertiary. The Portland Trough in Victoria represents a similar depocentre in which over 1,500 m of Wangerrip Group section, mostly represented by deltaic sediments of the Early Eocene Dilwyn Formation, is still preserved.Quantification of the maximum paleotemperature profile in Morum–1 immediately prior to Late Paleocene to mid-Eocene inversion shows that the paleo-geothemal gradient at the time was between 21 and 31°C/km, similar to the present-day level of 29°C/km, demonstrating that there has been little change in basal heat flow since the Early Tertiary.Reconstruction of the thermal history at the Trumpet–1 location reveals no evidence for any periods of significant uplift and erosion, demonstrating the relative stability of this part of the Crayfish Platform since the Late Cretaceous.The thermal and burial histories at Morum–1 and Trumpet–1 have been used to calibrate a Temis2D hydrocarbon generation and migration model along seismic line 85-13, encompassing the Crayfish Platform, Morum High and Morum Sub-basin. The model shows the cessation of active hydrocarbon generation from Eumeralla Formation source rocks around the Morum High due to cooling at 45 Ma (within the range 57–40 Ma) resulting from uplift and erosion of a Wangerrip Group basin. There has been almost no hydrocarbon generation from the Eumeralla Formation beneath the Crayfish Platform.Migration of hydrocarbons generated from the Eumeralla Formation began in the Late Cretaceous in the Morum Sub-basin and is predicted to continue to the present day, with the potential for accumulations in suitably placed reservoirs within the Late Cretaceous package both within the Morum Sub-basin and at the southern margin of the Crayfish Platform.
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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.
Full textAbstract:
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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Tuitt, Adrian, Simon Holford, Richard Hillis, John Underhill, Derek Ritchie, Howard Johnson, Ken Hitchen, Martyn Stoker, and David Tassone. "Continental margin compression: a comparison between compression in the Otway Basin of the southern Australian margin and the Rockall-Faroe area in the northeast Atlantic margin." APPEA Journal 51, no. 1 (2011): 241. http://dx.doi.org/10.1071/aj10017.
Full textAbstract:
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, amplitude, 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.
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Robson, A. G., S. P. Holford, and R. C. King. "Structural evolution of a normal fault array in the Gambier Embayment, offshore Otway Basin, South Australia: insights from 3D seismic data." Australian Journal of Earth Sciences 64, no. 5 (May 22, 2017): 611–24. http://dx.doi.org/10.1080/08120099.2017.1324822.
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Fell, Dominic, Kiran Dyal, Tony Hallam, and Sebastian Nixon. "Imaging below seafloor canyons and other rugose features." APPEA Journal 57, no. 2 (2017): 728. http://dx.doi.org/10.1071/aj16062.
Full textAbstract:
Rugose seabed and near seafloor features in marine seismic datasets such as canyons, mass transport deposits and paleo-channels, present a major imaging challenge that can be overcome by a rigorous and careful approach in the earth model building process. To obtain an accurate image of the deeper target levels, a modelling and data driven update of the distinctive velocity characteristics of the overburden features are necessary. Without adequately addressing the complexity of the shallow velocity field, the final depth image of the target intervals can be poorly focussed and contaminated with non-geologic structural distortions. Inadequate corrections ultimately have an adverse impact upon the interpretation of the dataset. This paper presents a successful earth modelling approach used to obtain an accurate depth image for a marine dataset located on the shelf break in the Otway Basin. The case study area includes extensive seafloor canyons and associated paleo-channels, requiring the strategic use of several geologically constrained model updating technologies in order to obtain a final imaged section free of velocity related structural distortions.
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Lyon, P. J., P. J. Boult, M. Watson, and R. R. Hillis. "A SYSTEMATIC FAULT SEAL EVALUATION OF THE LADBROKE GROVE AND PYRUS TRAPS OF THE PENOLA TROUGH, OTWAY BASIN." APPEA Journal 45, no. 1 (2005): 459. http://dx.doi.org/10.1071/aj04036.
Full textAbstract:
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.
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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.