Academic literature on the topic 'Geology, Stratigraphic Otway Basin (Vic'

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.

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.

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.

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

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

The Early Cretaceous Eumeralla Formation is regarded as an ineffective regional top seal in the Otway Basin, largely due to sand interbeds providing preferential hydrocarbon migration pathways. A deeper water lacustrine facies consisting of interbedded siltstones and claystones and massive claystones is developed at the base of the Eumeralla Formation in some wells. This interval ( Unit VI ) was deposited within a transgressive to early highstand systems tract and has better sealing properties than the other overlying Eumeralla Formation intervals. Theoretical gas column heights that the various Eumeralla Formation facies can support were calculated from mercury injection capillary pressure ( MICP ) analysis. Results range from 4 meters to 812 meters, and indicate that the fine-grained, lower Eumeralla Formation intervals have a higher seal capacity than the sand rich upper Eumeralla facies. However, the floodplain-dominated sediments commonly developed within the lower Eumeralla Formation are coal-rich and therefore associated with a high risk of brittle failure. Shallow lacustrine sediments have higher seal integrity, but are lithologically variable with extensive secondary porosity developed from dissolution of feldspar. The deeper lacustrine Unit VI provides the best Eumeralla seal for potential Katnook Sandstone and Windermere Sandstone Member reservoirs. Unfortunately, Unit VI is the only Eumeralla facies that is not developed entirely throughout the South Australian Otway Basin. The gamma ray log is generally unable to identify Eumeralla sandstone interbeds due to the sand's high volcanoclastic content. An integration of log data with seismic data, palynology, conventional core, and sidewall core and cuttings descriptions has enabled the seal geometry of the Eumeralla Formation to be determined. The deeper lacustrine Unit VI is locally developed in the St Clair Trough and on the flank of the Merino High. It is absent in the central Penola Trough and the Robe Trough, but could potentially be developed within the undrilled southern Penola Trough and in the Tantanoola Trough. Unit VI occurs preferentially in basins formed on the hanging wall of half grabens during late rift to early sag. The risk of top seal fracturing is considered high in the Robe Trough, and the Eumeralla Formation is very sandy in the central Penola Trough. Good seals are likely to be developed in the southern, predominantly offshore Otway Basin where Eumeralla sediments are generally deeper, and therefore more affected by mechanical compaction and diagenesis.
Thesis (M.Sc.)--Australian School of Petroleum, 2004.

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

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.
http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1339545
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