Academic literature on the topic 'Structural Otway Basin (Vic'

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

A new depth-based method of seismic imaging is used to provide insights into the 3D structural geometry of faults, and to facilitate a detailed structural interpretation of the Penola Trough, Otway Basin, South Australia. The structural interpretation is used to assess fault kinematics through geological time and to evaluate across-fault juxtaposition, shale gouge and fault reactivation potential for three selected traps (Zema, Pyrus and Ladbroke Grove) thus providing a full and systematic assessment of fault seal risk for the area. Paper 1 demonstrates how a depth-conversion method was applied to two-way time seismic data in order to redisplay the seismic in a form more closely representative of true depth, here termed ‘pseudo-depth’. Some apparently listric faults in two-way time are demonstrated to be planar and easily distinguishable from genuine listric faults on pseudo-depth sections. The insights into fault geometry provided by pseudo-depth sections have had a significant impact on the new structural interpretation of the area. Paper 2 presents the new 3D structural interpretation of the area. The geometry of faulting is complex and reflects variable stress regimes throughout structural development and the strong influence of pre-existing basement fabrics. Some basement-rooted faults show evidence of continual reactivation throughout their structural history up to very recent times. Structural analysis of all the live and breached traps of the area demonstrate that traps associated with a basement rooted bounding fault host breached or partially breached accumulations, whereas non-basement rooted faults are associated with live hydrocarbon columns. Papers 3 and 4 demonstrate that for all the traps analysed (Zema, Pyrus and Ladbroke Grove), initial in-place seal integrity was good. The initial seal integrity was provided by a combination of both favourable across fault juxtaposition (Ladbroke Grove) and/or sufficiently well developed shale gouge over potential leaky sand on sand juxtaposition windows to retain significant hydrocarbon columns (Zema, Pyrus). The palaeocolumns observed at Zema and Pyrus indicate that there has been subsequent post-charge breach of seal integrity of these traps while Ladbroke Grove retains a live hydrocarbon column. Evidence of open, permeable fracture networks within the Zema Fault Zone suggest that it is likely to have recently reactivated, thus breaching the original hydrocarbon column. Analysis of the in-situ stress tensor and fault geometry demonstrates that most of the bounding faults to the selected traps are at or near optimal orientations for reactivation in the in-situ stress tensor. The main exception being the Ladbroke Grove Fault which has a NW-SE trending segment (associated with a relatively high risk of fault reactivation and possible leakage at the surface) and an E-W trending segment (associated with a relatively low risk of fault reactivation and a present day live column). The free water level of the Ladbroke Grove accumulation coincides with this change in fault orientation.
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Thesis (Ph.D.) - University of Adelaide, Australian School of Petroleum, 2008

A new depth-based method of seismic imaging is used to provide insights into the 3D structural geometry of faults, and to facilitate a detailed structural interpretation of the Penola Trough, Otway Basin, South Australia. The structural interpretation is used to assess fault kinematics through geological time and to evaluate across-fault juxtaposition, shale gouge and fault reactivation potential for three selected traps (Zema, Pyrus and Ladbroke Grove) thus providing a full and systematic assessment of fault seal risk for the area. Paper 1 demonstrates how a depth-conversion method was applied to two-way time seismic data in order to redisplay the seismic in a form more closely representative of true depth, here termed ‘pseudo-depth’. Some apparently listric faults in two-way time are demonstrated to be planar and easily distinguishable from genuine listric faults on pseudo-depth sections. The insights into fault geometry provided by pseudo-depth sections have had a significant impact on the new structural interpretation of the area. Paper 2 presents the new 3D structural interpretation of the area. The geometry of faulting is complex and reflects variable stress regimes throughout structural development and the strong influence of pre-existing basement fabrics. Some basement-rooted faults show evidence of continual reactivation throughout their structural history up to very recent times. Structural analysis of all the live and breached traps of the area demonstrate that traps associated with a basement rooted bounding fault host breached or partially breached accumulations, whereas non-basement rooted faults are associated with live hydrocarbon columns. Papers 3 and 4 demonstrate that for all the traps analysed (Zema, Pyrus and Ladbroke Grove), initial in-place seal integrity was good. The initial seal integrity was provided by a combination of both favourable across fault juxtaposition (Ladbroke Grove) and/or sufficiently well developed shale gouge over potential leaky sand on sand juxtaposition windows to retain significant hydrocarbon columns (Zema, Pyrus). The palaeocolumns observed at Zema and Pyrus indicate that there has been subsequent post-charge breach of seal integrity of these traps while Ladbroke Grove retains a live hydrocarbon column. Evidence of open, permeable fracture networks within the Zema Fault Zone suggest that it is likely to have recently reactivated, thus breaching the original hydrocarbon column. Analysis of the in-situ stress tensor and fault geometry demonstrates that most of the bounding faults to the selected traps are at or near optimal orientations for reactivation in the in-situ stress tensor. The main exception being the Ladbroke Grove Fault which has a NW-SE trending segment (associated with a relatively high risk of fault reactivation and possible leakage at the surface) and an E-W trending segment (associated with a relatively low risk of fault reactivation and a present day live column). The free water level of the Ladbroke Grove accumulation coincides with this change in fault orientation.
Thesis (Ph.D.) - University of Adelaide, Australian School of Petroleum, 2008

It is widely recognised that inverted fault zones form economically significant structures for subsurface fluid exploration and production. Inverted fault zones are formed by the contractional reactivation and reversal of pre-existing extensional fault zones. Recognising the reverse-reactivation of normal faults in sedimentary basins is fundamental, as the reconfiguration of fault geometries has implications for overall basin geometry, sediment accommodation and supply, and fluid flow pathways. This is particularly important for understanding the modification or creation of petroleum system elements through time, which in turn allows for increased targeted exploration. Notwithstanding the broad economic relevance of inverted fault zones, integrated multi-scale (from micrometre-scale to outcrop-scale) studies on the structural, petrophysical, and geochemical properties of inverted fault zones within porous reservoir rocks are limited. This thesis characterises the structural, petrophysical, and geochemical properties of inverted fault zones from two localities, the Otway Basin (Australia) and Bristol Channel Basin (United Kingdom), in order to understand how inverted faults influence fluid flow at a range of scales. To address this, this thesis has two main topics of focus: (1) identify the influence of inverted faults on surrounding lithology by assessing the relationship between faults, damage zones around faults, and fractures related to fault growth; and (2) identify how subsurface fluids flow, interact, and modify their surrounds by assessing the geochemistry of fluids in fractures and thereby constraining the source, evolution, and migration of fluids preserved in fractures. An integrated, multi-scale approach is crucial for improving the prediction of subsurface fluid flow beyond the wellbore. In order to understand the influence of inverted faults on surrounding lithology, an inverted fault (Castle Cove Fault) in the Otway Basin, southeast Australia, is the focus of the first two chapters of this thesis. The geometries and relative chronologies of natural fractures adjacent to the Castle Cove Fault are investigated. Structural mapping in the hanging wall damage zone reveals three sets of shear fractures that are geometrically related to the Castle Cove Fault. Inversion of the Castle Cove Fault has resulted in the development of an extensive network of fractures and complex fold structures, and inversion would have subsequently improved the outcrop-scale permeability structure of the damage zone for fluid migration. At the micrometre-scale, the permeability structure has also been influenced by fault inversion. Petrophysical and petrographical analyses in the hanging wall damage zone show that microstructural changes due to faulting have enhanced the micrometre-scale permeability structure of the Eumeralla Formation. These microstructural changes have been attributed to the formation of microfractures and destruction of original pore-lining chlorite morphology as a result of fault deformation. Consequently, inversion has subsequently improved the micrometre-scale permeability structure of the damage zone adjacent to the Castle Cove fault plane. Characterisation of the permeability structure adjacent to reverse-reactivated faults at a range of scales will aid with predicting fluid flow associated with inversion structures. Structural and geochemical analyses in the next two chapters of this thesis aim to understand how subsurface fluids flow and characterise the source, evolution, and migration pathways of fluids preserved in inverted fault zones. The geochemical evolution of fluids precipitated as calcite and siderite-cemented concretions and fractures throughout the eastern Otway Basin have been investigated. Pore fluids were sourced from both meteoric water and sea water during the deposition of the Eumeralla Formation and pore fluid evolution was strongly influenced by diagenetic reactions and increased temperature during burial. Using a similar analytical approach, the geochemical evolution of fluids precipitated as calcite and gypsum-cemented fractures throughout the eastern Bristol Channel Basin have vibeen investigated. The main source of fluids were connate pore waters, which were altered by diagenetic reactions within their host lithologies and subsequently redistributed through migration along faults and their associated damage zones. Knowledge of the source, evolution, and migration pathways of these fluids provides valuable insights for understanding the development of inverted sedimentary basins through time. Consequently, integrated studies on the multi-scaled permeability structure of inverted fault zones and the fluids preserved within them will ultimately improve fluid exploration and monitoring strategies in sedimentary basins.
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum (ASP), 2019

This thesis presents a multiscale structural analysis of upper crustal deformation at a passive continental margin, using the Jurassic - Quaternary Otway Basin along Australia’s southern margin as a case study. Techniques of structural analyses across the micro (calcite twin, magnetic and porefabric analyses), meso (wellbore and outcrop natural fracture analysis) and macroscales (three-dimensional seismic interpretation) providing an effective means of characterising stress and strain across space and time. The integration of these investigative methods at a passive continental margin for the first time, has assisted in reducing structural uncertainty for basin evolution models, delivering original insights into the evolution of stress within these tectonic environments. The results of this study show magnitudes of maximum differential stress as high as 69MPa during extension and continental breakup, in contrast to magnitudes as low as 13MPa during basin inversion. The influence of high extensional stresses during continental break up, resulting in layer parallel stretching (LPSt), a microstructural strain which may develop in layered rock, characterised by an azimuth of stretching or thinning, orthogonal to the orientation of regional extensional faults. LPSt occurs in the early stages of extension, prior to the development of calcite twins, natural fractures, and faults which occur progressively as the intensity and duration of extension increases. This is evidenced in the Otway Basin, where Late Cretaceous aged NE-SW and N-S oriented LPSt is co-axial with extensional azimuths during that time, derived from the stress inversion of seismic scale faults, calcite twins and natural fractures from the outcrop and wellbore. The neotectonic preservation of LPSt in the Otway Ranges, an uplifted section of Early Cretaceous sediments in the Otway Basin, suggests that early grain-scale extensional strain can be preserved during ensuing phases of inversion at continental margins. As during the process of inversion, stress is primarily released through the reactivation of previously formed extensional fault and detachment systems. A process of deformation that results in low levels of coupling between the basement and cover, an observation that is supported by the low magnitudes of compressional stress (13MPa) calculated during the same period. Additionally, the results of this study have improved our understanding of sub-surface fluid flow in the Otway Basin. Geomechanical modelling demonstrating that low contemporary magnitudes of effective normal stress, acting on NW-SE oriented faults, striking parallel to the orientation of maximum horizontal stress, results in a high risk of fault dilation. This suggests that future efforts of exploration for conventional oil and gas systems within the Otway Basin, are best focused where E-W, N-S and NE-SW striking faults interact with the major NW-SE fabric, or where the influence of basin inversion is most pronounced. A major outcome of this study is a new structural framework for the Otway Basin, one that is defined by a consistent pattern of NW-SE striking faults across much of the basin, in contrast to the previous structural model of opposing fault trends in the west and east. The new framework characterises a structural trend that is consistent with faulting patterns in sedimentary provinces to the west and east along Australia’s southern margin.
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2019

This item is only available electronically.
Over 261 naturally occurring fractures were recorded from 10 field locations in the Otway Ranges, Victoria, Australia. Fractures were sampled from the upper Jurassic –lower Cretaceous Eumeralla Formation, a volcanogenic sandstone. Eight fracture sets were recorded with defined orientations. Twenty-seven fracture samples from across the Otway Ranges were thin sectioned and analysed using an optical microscope and Scanning Electron Microscope (SEM). Host rock and fracture petrography were determined, including identification of host rock and fracture cement mineral compositions, along with fracture specific textures, such as calcite twinning, crack-seal textures, cataclastic deformation and cross-cutting cements. Siderite cements are observed to be present in all fracture sets and imply the presence of fluid flow during all periods of deformation, from lower Cretaceous extension to NW –SE Miocene compression. The addition of calcite cements in Fracture Sets One, Fracture Set Two, Fracture Set Four, Fracture Set Five and Fracture Set Seven indicate two periods of enhanced calcite and siderite fluid flow predominantly during times of NW - SE compression in the mid-Cretaceous and Miocene.
Thesis (B.Sc.(Hons)) -- University of Adelaide, School of Physical Sciences, 2016

Loose sheets comprise of profiles of the Oligocene.
Bibliography: leaves 89-158.
158, [60] leaves, [16] leaves of plates : ill., maps ; 30 cm. + seven charts (some folded)
Title page, contents and abstract only. The complete thesis in print form is available from the University Library.
This study investigates a late Eocene to Miocene succession of diverse mid-latitude assemblages of foraminifera from carbonates and calcareous muds and sands on the southern Australian margin. It contrasts foraminiferal profiles from the restricted St. Vincent and Murray Basins with the Otway Basin that is more exposed to oceanic conditions.
Thesis (Ph.D.)--University of Adelaide, Dept. of Geology and Geophysics, 1995

Loose sheets comprise of profiles of the Oligocene.
Bibliography: leaves 89-158.
158, [60] leaves, [16] leaves of plates : ill., maps ; 30 cm. + seven charts (some folded)
This study investigates a late Eocene to Miocene succession of diverse mid-latitude assemblages of foraminifera from carbonates and calcareous muds and sands on the southern Australian margin. It contrasts foraminiferal profiles from the restricted St. Vincent and Murray Basins with the Otway Basin that is more exposed to oceanic conditions.
Thesis (Ph.D.)--University of Adelaide, Dept. of Geology and Geophysics, 1995