Brumbys 1 was an appraisal well drilled and cored through Brumbys Fault at the CO2CRC Otway International Test Centre in 2018. The Otway Project is located in South West Victoria, on private farming property approximately 35 km southeast of Warrnambool and approximately 10 km northwest of the town of Peterborough. Total measured depth was 126.6 m (80 degrees). Sonic drilling enabled excellent core recovery and the borehole was completed as a groundwater monitoring well. Brumbys 1 cores through the upper Hesse Clay, Port Campbell Limestone and extends into the Gellibrand Marl. This dataset compiles the extensive analysis undertaken on the core. Analysis includes: Core log; Foram Analysis; Paleodepth; % Carbonate (CaCO3); X-Ray Fluorescence Spectrometry (XRF); Inductively Coupled Plasma Mass Spectrometry (ICP-MS); X-Ray Diffraction (XRD); Grain Size; Density; Surface Area Analysis (SAA); Gamma. Samples were taken at approximately 1-2 m intervals.

<div>Geoscience Australia (GA) has produced a folio of 32 wells across the central and southeast regions. This folio covers the areas from Normanby 1 on the Normanby Terrace, through the Shipwreck Trough and Nelson Sub-basin, to Whelk 1 in the southeast. Composite logs for each well in the folio include wireline logs, petrophysical analysis, interpreted lithology, organic geochemical data, organic petrology data, and sequence stratigraphic markers. This folio also includes core-based depositional environment (DE) and gross depositional environment (GDE) interval interpretations which were used to constrain wireline interpretation of DE/GDE away from core control. The folio includes the digital data package used to construct each well composite. The new folio complements a recently published folio of northeast offshore Otway Basin wells, and both were designed as resource for exploration in the offshore Otway Basin.</div>

This report, completed as part of Geoscience Australia’s Exploring for the Future Program National Groundwater Systems (NGS) Project, presents results of the second iteration of 3D geological and hydrogeological surfaces across eastern Australian basins. The NGS project is part of the Exploring for the Future (EFTF) program—an eight-year, $225 million Australian Government funded geoscience data and precompetitive information acquisition program. The program seeks to inform decision-making by government, community, and industry on the sustainable development of Australia's mineral, energy, and groundwater resources, including those to support the effective long-term management of GAB water resources. This work builds on the first iteration completed as part of the Great Artesian Basin Groundwater project. The datasets incorporate infills of data and knowledge gaps in the Great Artesian Basin (GAB), Lake Eyre Basin (LEB), Upper Darling Floodplain (UDF) and existing data in additional basins in eastern Australia. The study area extends from the offshore Gulf of Carpentaria in the north to the offshore Bight, Otway, and Gippsland basins in the South and from the western edge of the GAB in the west to the eastern Australian coastline to the east. The revisions are an update to the surface extents and thicknesses for 18 region-wide hydrogeological units produced by Vizy & Rollet, 2022. The second iteration of the 3D model surfaces further unifies geology across borders and provides the basis for a consistent hydrogeological framework at a basin-wide, and towards a national-wide, scale. The stratigraphic nomenclature used follows geological unit subdivisions applied: (1) in the Surat Cumulative Management Area (OGIA - Office of Groundwater Impact Assessment, 2019) to correlate time equivalent regional hydrogeological units in the GAB and other Jurassic and Cretaceous time equivalent basins in the study area and (2) in the LEB to correlate Cenozoic time equivalents in the study area. Triassic to Permian and older basins distribution and thicknesses are provided without any geological and hydrogeological unit sub-division. Such work helps to (1) reconcile legacy and contemporary regional studies under a common stratigraphic framework, (2) support the effective management of groundwater resources, and (3) provide a regional geological context for integrated resource assessments. The 18 hydrogeological units were constructed using legacy borehole data, 2D seismic and airborne electromagnetic (AEM) data that were compiled for the first iteration of the geological and hydrogeological surfaces under the GAB groundwater project (Vizy & Rollet, 2022a) with the addition of: • New data collected and QC’d from boreholes (including petroleum, CSG [Coal Seam Gas], stratigraphic, mineral and water boreholes) across Australia (Vizy & Rollet, 2023a) since the first iteration, including revised stratigraphic correlations filling data and knowledge gaps in the GAB, LEB, UDF region (Norton & Rollet, 2023) with revised palynological constraints (Hannaford & Rollet 2023), • Additional AEM interpretation since the first iteration in the GAB, particularly in the northern Surat (McPherson et al., 2022b), as well as in the LEB (Evans et al., in prep), in the southern Eromanga Basin (Wong et al., 2023) and in the UDF region (McPherson et al., 2022c), and • Additional 2D seismic interpretation in the Gulf of Carpentaria (Vizy & Rollet, 2023b) and in the western and central Eromanga Basin (Szczepaniak et al., 2023). These datasets were then analysed and interpreted in a common 3D domain using a consistent chronostratigraphic framework tied to the geological timescale of 2020, as defined by Hannaford et al. (2022). Confidence maps were also produced to highlight areas that need further investigation due to data gaps, in areas where better seismic depth conversion or improved well formation picks are required. New interpretations from the second iteration of the 18 surfaces include (1) new consistent and regionally continuous surfaces of Cenozoic down to Permian and older sediments beyond the extent of the GAB across eastern Australia, (2) revised extents and thicknesses of Jurassic and Cretaceous units in the GAB, including those based on distributed thickness, (3) revised extents and thicknesses of Cenozoic LEB units constrained by the underlying GAB 3D model surfaces geometry. These data constraints were not used in the model surfaces generated for the LEB detailed inventory (Evans et al., 2023), and (4) refinements of surfaces due to additional seismic and AEM interpretation used to infill data and knowledge gaps. Significant revisions include: • The use of additional seismic data to better constrain the base of the Poolowanna-Evergreen formations and equivalents and the top of Cadna-owie Formation and equivalents in the western and central Eromanga Basin, and the extent and thicknesses of the GAB units and Cenozoic Karumba Basin in the Gulf of Carpentaria, • The use of AEM interpretations to refine the geometry of outcropping units in the northern Surat Basin and the basement surface underneath the UDF region, and • A continuous 3D geological surface of base Cenozoic sediments across eastern Australia including additional constraints for the Lake Eyre Basin (borehole stratigraphy review), Murray Basin (AEM interpretation) and Karumba Basin (seismic interpretation). These revisions to the 18 geological and hydrogeological surfaces will help improve our understanding on the 3D spatial distribution of aquifers and aquitards across eastern Australia, from the groundwater recharge areas to the deep confined aquifers. These data compilations and information brought to a common national standard help improve hydrogeological conceptualisation of groundwater systems across multiple jurisdictions to assist water managers to support responsible groundwater management and secure groundwater into the future. These 3D geological and hydrogeological modelled surfaces also provide a tool for consistent data integration from multiple datasets. These modelled surfaces bring together variable data quality and coverage from different databases across state and territory jurisdictions. Data integration at various scale is important to assess potential impact of different water users and climate change. The 3D modelled surfaces can be used as a consistent framework to map current groundwater knowledge at a national scale and help highlight critical groundwater areas for long-term monitoring of potential impacts on local communities and Groundwater Dependant Ecosystems. The distribution and confidence on data points used in the current iteration of the modelled surfaces highlight where data poor areas may need further data acquisition or additional interpretation to increase confidence in the aquifers and aquitards geometry. The second iteration of surfaces highlights where further improvements can be made, notably for areas in the offshore Gulf of Carpentaria with further seismic interpretation to better constrain the base of the Aptian marine incursion (to better constrain the shape and offshore extent of the main aquifers). Inclusion of more recent studies in the offshore southern and eastern margins of Australia will improve the resolution and confidence of the surfaces, up to the edge of the Australian continental shelf. Revision of the borehole stratigraphy will need to continue where more recent data and understanding exist to improve confidence in the aquifer and aquitard geometry and provide better constraints for AEM and seismic interpretation, such as in the onshore Carpentaria, Clarence-Moreton, Sydney, Murray-Darling basins. Similarly adding new seismic and AEM interpretation recently acquired and reprocessed, such as in the eastern Eromanga Basin over the Galilee Basin, would improve confidence in the surfaces in this area. Also, additional age constraints in formations that span large periods of time would help provide greater confidence to formation sub-divisions that are time equivalent to known geological units that correlate to major aquifers and aquitards in adjacent basins, such as within the Late Jurassic‒Early Cretaceous in the Eromanga and Carpentaria basins. Finally, incorporating major faults and structures would provide greater definition of the geological and hydrogeological surfaces to inform with greater confidence fluid flow pathways in the study area. This report is associated with a data package including (Appendix A – Supplementary material): • Nineteen geological and hydrogeological surfaces from the Base Permo-Carboniferous, Top Permian, Base Jurassic, Base Cenozoic to the surface (Table 1.1), • Twenty-one geological and hydrogeological unit thickness maps from the top crystalline basement to the surface (Figure 3.1 to Figure 3.21), • The formation picks and constraining data points (i.e., from boreholes, seismic, AEM and outcrops) compiled and used for gridding each surface (Table 2.7). Detailed explanation of methodology and processing is described in the associated report (Vizy & Rollet, 2023).

In association with the OB2020 seismic survey, over 8,200 line kilometre of gravity and magnetic data were acquired. These data were subsequently merged with existing satellite data to produce merged grids at 1000m grid cell size. Several enhancement processing techniques were applied to these magnetic and gravity data to better highlight buried features within the Otway Basin. The merged input data from the survey and the enhanced products in this release provide valuable information on the geometry and spatial extent of igneous rocks in the deep-water basin. The distribution of these rocks is critical to the understanding of the petroleum systems and therefore the hydrocarbon prospectivity of the area. This data package contains: 1) A metadata statement document 2) Shapefiles of the magnetic and gravity line data from the OBSP survey 3) ASCII xyz grids of the OBSP and merged grids with public domain data 4) Georeferenced (GeoTIFF) images of the survey and merged grids 5) Gravity and Magnetic data processing reports from the OBSP survey

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 500 m, 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 10 000 km 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. Presented at 2021 Australian Petroleum Production & Exploration Association (APPEA)

<div>Gas production from the Inner Otway Basin commenced in the early 2000s but the deep-water part of this basin remains an exploration frontier. Historically, the understanding of plays in this region were largely model driven and therefore the ground-truthing of depositional environments (DE) and gross depositional environments (GDE) are critical. This aspect has been investigated for the Sherbrook Supersequence (SS) by the integration of legacy wireline and core data, with regional 2D seismic facies mapping of new and reprocessed data from Geoscience Australia’s 2020 Otway Basin seismic program. Core observations were matched to wireline logs and seismic facies with resulting well based DE interpretations calibrated to seismic resolution Regional GDE intervals. Integration of well and seismic observations lead to the compilation of a basin-wide Regional GDE map for the Sherbrook SS. This GDE map indicates the distribution of Sherbrook SS play elements such as source rock, seal and reservoir, especially across the Deep Water Otway Basin where well data is sparse.</div> Published in The APPEA Journal 2023. <b>Citation:</b> Cubitt Chris, Abbott Steve, Bernardel George, Gunning Merrie-Ellen, Nguyen Duy, Nicholson Chris, Stoate Alan (2023) Cretaceous depositional environment interpretation of offshore Otway Basin cores and wireline logs; application to the generation of basin-scale gross depositional environment maps. <i>The APPEA Journal</i><b> 63</b>, S215-S220. https://doi.org/10.1071/AJ22090

The Otway Basin is a broadly northwest-southeast trending basin and forms part of a rift system that developed along Australia’s southern margin. It represents an established hydrocarbon province with mostly onshore and shallow-water offshore discoveries. However, the outboard deep-water Otway Basin, with water depths up to 6300 m, is comparatively underexplored and can be considered a frontier area. Following the completion of a basin-wide seismic depth-imaging program (Part 1; Lee et al 2021) and insights from the revised seismic interpretation (Part 2; Karvelas et al. 2021), we have developed a comprehensive petroleum system modelling (PSM) study by integrating these data and findings (Part 3). Together the studies have resulted in an improved understanding of the hydrocarbon prospectivity of the deep-water areas of the basin. Given the sparsity of data outboard, almost all legacy petroleum system modelling studies have been focused either on the onshore or shallow-water areas of the basin and primarily on their thick Lower Cretaceous depocentres. The limitations of legacy seismic datasets resulted in a high degree of uncertainty in the derivative interpretations used as input into PSM studies. In addition, the paucity and poor quality of data in the deep-water area reduced confidence in the understanding of the basin evolution and spatial distribution of depositional environments through time. The newly acquired 2D seismic survey and reprocessed legacy data, with calibration via several wells across the basin, has improved confidence in our understanding of the tectonostratigraphic evolution of the basin (Part 2; Karvelas et al. 2021). The study presented herein integrates products from the work in Part 2 into a petroleum system model with the primary objective being to better understand the petroleum systems across the deep-water Otway Basin.

Reports of bitumen stranding on the ocean beaches of southern Australia date back to the early days of European settlement. Previous investigations have shown that this ‘coastal bitumen’ comprises three categories of stranded petroleum: waxy bitumen, asphaltite and oil slicks. All three varieties are physically and chemically distinct from each other, and bear no geochemical resemblance to any indigenous Australian crude oil. This study focuses on the most common variety, waxy bitumen, which accounted for 90% of the strandings on six South Australian beaches repeatedly surveyed during 1991–1992. Geochemical analysis of 96 individual specimens collected from these survey sites and other beaches in South Australia and western Victoria has shown them to be variously weathered high-wax crude oils of paraffinic to aromatic-intermediate bulk composition. Elemental, isotopic and biomarker differences allow their assignment to at least five oil families with inferred source facies that range from deep freshwater lacustrine through paludal and deltaic to euxinic marine, possibly deposited within different sedimentary basins. Family 1, 2 and 3 waxy bitumens all contain biomarkers derived from the freshwater alga Botryococcus sp. and tropical angiosperms (notably dipterocarps). Similar biomarker assemblages are unknown in Australian sedimentary basins but are common in Cenozoic crude oils and source rocks throughout western Indonesia. Family 4 waxy bitumens lack these biomarkers, but do contain dinosterane and 24-n-propylcholestane, indicative of a marine source affinity, while the carbon isotopic signatures and high pristane/phytane (Pr/Ph) ratios of Family 5 waxy bitumens are consistent with their origin from coal-rich source rocks deposited in fluvial to deltaic sedimentary successions. The majority of these waxy bitumens represent an oceanic influx of non-indigenous, Southeast Asian crude oils carried into the waters of southern Australia by the Leeuwin Current. Although they are likely to originate from natural seepage within the Indonesian Archipelago, it is unknown whether the parent oils emanate from submarine seeps or from inland seepages which are then carried to the sea by rivers. The common practice of tanker cleaning operations in the Java and Banda seas may augment the supply of natural bitumen to the beaches of Australia.

An elemental chemostratigraphic study of the offshore Otway basin has been undertaken as part of a collaboration between Chemostrat and Geoscience Australia (GA). The main aim of which is to better constrain the sequence boundaries of, and within, the Sherbrook Supersequence. This comprehensive study includes the elemental analysis of 1185 cuttings samples from the Sherbrook Supersequence (and overlying stratigraphy) in 13 wells, located offshore Otway Basin. Sampling of cuttings for this project was particularly challenging as many of the targeted wells have a paucity of material available for destructive analysis. Lithological and well log interpretation in the basin is often inadequate for constraint of sequence boundaries. Nonetheless the use of Inductively Coupled Plasma-Optical Emission Spectrometry and Mass Spectrometry (ICP-OES and MS) analysis was undertaken to complete a regional elemental chemostratigraphic study of the Sherbrook Supersequence, Otway Basin. The resultant chemostratigraphic framework, with nomenclature adapted from Forbes et al (2020) comprises of two chemostratigraphic sequences, eight chemostratigraphic packages and seventeen chemostratigraphic units. It is important to note that in some wells the chemostratigraphic correlation differs extensively from the lithostratigraphy, highlighting areas for closer examination. From the 13 wells analysed at least three, Crayfish-1A, Copa-1 and Breaksea Reef-1, indicate necessary changes to markers for LC2 (base Sherbrook). Additionally, within the Sherbrook Supersequence, there is scope for correlation between wells despite their separation, and seismic ties can now be better constrained. Presented at the Australian Energy Producers (AEP) Conference & Exhibition

<div>Ideally when combining different 3D seismic surveys differences in acquisition parameters warrant full pre-stack reprocessing from field data. However, there are occasions where this is not possible due to time, financial or data access constraints; a valuable alternative is post-stack merging and enhancement of existing migrations. The offshore Otway Basin was the subject of such a project, the objective of which was to produce a regularised and seamless 3D dataset of the highest possible quality, within a two-month turnaround time. The input migrated volumes varied by data extent, migration methodology, angle range and grid orientation. 14 input volumes totalling 8,092 km2 were post-stack merged and processed to produce a continuous and consistent volume, enabling more efficient and effective interpretation of the region. The surveys were regularised onto a common grid, optimised for structural trend, prior to survey matching. DUG’s mis-tie analysis algorithm, applied over a time window optimised for interpretation of key</div><div>events, was used to derive corrections for timing, phase and amplitude, using the Investigator North survey as a reference. This was followed by time-variant spectral and amplitude matching, with gain corrections applied, to improve continuity between volumes. Additional enhancements including noise removal and lateral amplitude scaling were also applied. The final merged volume offers significant uplift over the inputs providing better imaging of structure and event and dramatically improving the efficiency and quality of interpretation. This enables rapid reconnaissance of the area by explorers. Presented at the Australian Energy Producers (AEP) Conference & Exhibition