Australia’s offshore carbon capture and storage regulations are largely site-centric and framed around the CO2 plume footprint. While proponents must demonstrate safe pressure limits to assure containment, far-field pressure effects resulting from multiple simultaneous CO2 storage operations could impact storage capacity, injectivity, plume migration pathways, hydrocarbon accumulations, monitoring strategies and regulatory considerations. To quantify these regional effects, we completed an integrated, multiple injection site assessment of the K20 sequence in the Barrow–Dampier sub-basin. Five storage projects were located within the model domain, each supported by six wells injecting 1 MtCO2/year/well for 30 years. Boundary conditions ranged from closed to finite-aquifer support (Carter–Tracy r-ratios 1.5–10) and simulations examined isolated, simultaneous and staggered start-ups, and scenarios with/without a nearby gas field. Under closed boundary conditions, 514 MtCO2 was stored over 30 years, versus ~924 Mt if sites were assessed in isolation (~185 Mt/site), indicating that single-site assessment can overestimate dynamic capacity. With finite external aquifer support, CO2 storage totals increased to 591 Mt (r = 1.5), 861 Mt (r = 3) and ~924 Mt (r ≥ 5); for r ≥ 5, design rates were sustained, and per-site storage converged to ~185 Mt. Plume monitoring footprints were sensitive to boundary conditions and were consistently smaller under multi-site than isolated modelling. Project sequencing mattered where aquifer support was limited (early-mover advantage), and coexistence with hydrocarbons showed mixed effects: storage capacity gains, but residual hydrocarbon trapping. These results underscore the importance of integrated regional modelling to yield realistic capacity/injectivity estimates, defensible monitoring footprints and reduced-risk coexistence with petroleum operations.

The Paleoproterozoic Fraynes Formation in the Birrindudu Basin is a chronostratigraphic equivalent to the prospective Barney Creek Formation in the McArthur Basin and yet a comparable understanding of its source potential is lacking. As part of Geoscience Australia’s Exploring for the Future program, this study aims to assess the hydrocarbon generating potential and shale gas prospectivity of the Fraynes Formation in the exploration drill hole Manbulloo S1 through the reconstruction of the original source-rock characteristics and well log interpretation. Internal units inside the Fraynes Formation were defined according to sedimentary facies. The hydrocarbon generation potential was estimated from the calculated original total organic carbon content, hydrogen index and thermal maturity data measured from bitumen reflectance data. The shale total porosity was re-interpreted from bulk density logs by removing the organic matter effect, adding organic porosity for the organic-rich shales, and updating the water saturation. The maximum amount of gas generated from the organic-rich source rocks is 3969, 2769 and 1912 Mcf/a-ft assuming the kerogen compositions of 100% Type I, mix of 50–50% Type I and II, and 100% Type II, respectively. The richness of organic matter and interpreted water saturation (<100%) imply favourable shale gas prospectivity in the Fraynes Formation. This work expands our knowledge on the potential unconventional energy resources in the west of the greater McArthur Basin.

The Neoproterozoic to Middle Ordovician sedimentary rocks of the Officer Basin, Australia, are difficult to correlate, in part because biostratigraphic studies of acritarchs and stromatolites are localised, stable isotope studies are rare, and seismic models are technically challenged by the occurrence of basaltic and halite prone-sections. Hence, the elemental chemostratigraphic framework presented here provides an independent stratigraphic model for the Neoproterozoic to Middle Ordovician sedimentary rocks of the Officer Basin. A total of six chemostratigraphic megasequences have been geochemically defined and assigned to the existing litho stratigraphy; these have been further subdivided into twenty-eight chemostratigraphic sequences. The chemostratigraphic zonation has been established based on elemental changes attributed to provenance and climatic variation which can be used for correlation as they convey regional, rather than local, changes in sedimentation. The elemental data reveals that there is lateral variation within the established lithostratigraphy (e.g., within the members of the Observatory Hill and Hussar formations), which suggests localised sediment source input to different areas of the basin.

Geoscience Visual Presentation G09 The Paleoproterozoic Fraynes Formation in the Birrindudu Basin is a chronostratigraphic equivalent to the prospective Barney Creek Formation in the McArthur Basin and yet a comparable understanding of its source potential is lacking. As part of Geoscience Australia’s Exploring for the Future program, this study aims to assess the hydrocarbon generating potential and shale gas prospectivity of the Fraynes Formation in the exploration drill hole Manbulloo S1 through the reconstruction of the original source-rock characteristics and well log interpretation. Internal units inside the Fraynes Formation were defined according to sedimentary facies. The hydrocarbon generation potential was estimated from the calculated original total organic carbon content, hydrogen index and thermal maturity data measured from bitumen reflectance data. The shale total porosity was re-interpreted from bulk density logs by removing the organic matter effect, adding organic porosity for the organic-rich shales, and updating the water saturation. The maximum amount of gas generated from the organic-rich source rocks is 3969, 2769 and 1912 Mcf/a-ft assuming the kerogen compositions of 100% Type I, mix of 50–50% Type I and II, and 100% Type II, respectively. The richness of organic matter and interpreted water saturation (<100%) imply favourable shale gas prospectivity in the Fraynes Formation. This work expands our knowledge on the potential unconventional energy resources in the west of the greater McArthur Basin. To access the Visual Presentation click the link on the right. To read the full paper click here

Led by Geoscience Australia, Exploring for the Future (EFTF) is a A$225 million Australian Government program dedicated to exploring Australia’s resource potential and boosting investment. The EFTF program energy component aimed to attract industry investment by delivering a suite of new precompetitive geoscience data in prospective Australian sedimentary basins. Through EFTF, Geoscience Australia has acquired significant amounts of new geomechanical data from underexplored onshore sedimentary basins with identified hydrocarbon prospectivity, from both legacy and newly acquired samples. These data were acquired to build a better understanding of basin sediment rock properties, particularly looking at the reservoir and seal potential of postulated unconventional and conventional targets. Four major datasets are presented herein, representing prospective intervals from the Paleozoic Canning Basin of Western Australia, the Neoproterozoic-Paleozoic Officer Basin of South Australia and Western Australia, the Paleo-Mesoproterozoic South Nicholson region of the Northern Territory and northwest Queensland, and the Paleo-Mesoproterozoic Birrindudu Basin of the Northern Territory and Western Australia. Additionally, the Paleo-Mesoproterozoic McArthur Basin of the Northern Territory is represented by a small number of analyses. Tests include unconfined compressive strength tests, laboratory ultrasonic measurements, single and multi-stage triaxial tests and Brazilian tensile strength tests. These datasets are a precompetitive resource that can facilitate investment decisions in frontier regions, helping to identify elements of conventional and unconventional hydrocarbon systems as well as providing essential data to assess geological storage opportunities.

NDI Carrara 1 is a 1751 m stratigraphic drill hole completed in 2020 as part of the MinEx CRC National Drilling Initiative, in collaboration with Geoscience Australia and Northern Territory Geological Survey under the Exploring for the Future program. It is the first stratigraphic test of the Carrara Sub-basin, a recently discovered depocentre in the South Nicholson region. The drill hole intersected Cambrian and Proterozoic sediments consisting of organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones with hydrocarbon shows. A comprehensive analytical program carried out by Geoscience Australia on the recovered continuous core from 283 m to total depth at 1751 m provides critical data for understanding this area. Using data from this drilling campaign, thermal history modelling was undertaken to provide an estimate of the time-temperature maxima that the sub-basin has experienced, contributing to an understanding of hydrocarbon maturity. Kerogen kinetics are used to estimate the petroleum prospectivity of the sub-basin and attempt to understand the timing and nature of hydrocarbon generation. Combined, these newly modelled data provide insights into the resource potential of this frontier Proterozoic–Paleozoic hydrocarbon province, delivering foundational data to support explorers across the eastern Northern Territory and northwest Queensland.

As Australia and the world transition to net zero emissions, hydrogen will continue to grow in importance as a clean energy source, with underground hydrogen storage (UHS) expected to be a key component of this new industry. Salt (halite) caverns are a preferred storage option for hydrogen, given their scale, stability and the high injection and withdrawal rates they can support. The use of salt caverns for storing gas is an established industry in North America and Europe but not in Australia, where exploration for suitable storage locations is in the initial frontier stages. Australia’s known major halite deposits occur in Neoproterozoic and Paleozoic sequences and are predominantly located in western and central Australia. This analysis has identified potential in eastern Australia in addition to the proven thick halite in the Adavale Basin, Queensland. Building on Geoscience Australia’s previous salt studies in the Canning, Polda and Adavale basins, this study expands the portfolio of areas prospective for halite in onshore and offshore basins using both direct and indirect evidence. The study correlates paleogeography and paleoclimate reconstructions with evidence of salt in wells, and in geophysical and geochemical data. Salt cavern design for UHS, the solution mining process, and the preferred salt deposits are also discussed. The results will provide pre-competitive information through a comprehensive inventory of areas that may be prospective for UHS.

The Proterozoic succession in the National Drilling Initiative Carrara 1 drill hole, Northern Territory, is dominated by tight shales, siltstones and calcareous clastic rocks. As part of Geoscience Australia’s Exploring for the Future program, this study aimed to improve the Proterozoic shale gas reservoir characterisation by derivation of porosity, permeability and gas content from laboratory testing and machine learning approaches to wireline log interpretation. The Proterozoic Lawn Hill Formation is divided into four chemostratigraphic packages. The middle two packages are further divided into seven internal units according to principal component analysis and self-organising map clustering on well logs and inorganic geochemical properties. Artificial neural networks were then applied to interpret the mineral compositions, porosity and permeability from well logs, density and neutron-density crossplot interpretations. Gas content was estimated from the interpreted porosity, gas saturation, total organic carbon and clay contents. Petrophysical interpretation results are summarised for all chemostratigraphic packages and units. P2 (1126.3–1430.1 m) has the highest potential among the four chemostratigraphic packages. P2U1 (1126.3–1271 m) and P2U3 (1335.5–1430.1 m) units have the most favourable petrophysical properties for organic-rich shales, with average total gas contents of 1.213 and 1.315 cm3/g, geometric mean permeability of 6.6 and 25.31 µD and net shale thickness of 53.5 and 83.3 m, respectively. P3U4 (687.9–697.9 m) has high gas content and permeability, with a net shale thickness of 35.9 m. The tight non-organic-rich siltstone and shale reservoirs in package P1 (below 1430.1 m) have an average gas saturation of 17.4% and a geometric mean permeability of 0.48 µD.

CO2CRC has made a significant investment into establishing the feasibility of conducting a CO2 injection experiment into a shallow fault. This world-leading experiment, located at the CO2CRC Otway International Test Centre in Victoria, Australia, would seek to improve our understanding of the conditions necessary for CO2 to move vertically up faults. The work undertaken during Phase 2 of the Otway Fault Project confirms the experiment is technically feasible and can be done safely. Two appraisal wells drilled and cored through the shallow Brumbys Fault indicate the fault extends to the base of the upper 2 m thick Hesse Clay layer, which forms the seal to the underlying Port Campbell Limestone aquifer. The fault does not have a defined core but an approximately 6-10 m wide fault cataclastic zone. Permeability within the Port Campbell Limestone is variable, ranging from tens to thousands of millidarcies. The rock strength is low, however, and it is recommended to conduct the experiment at approximately 80 m depth rather than the 40 m originally proposed. This provides more confining pressure and will ensure that the injection pressure does not exceed the fracture pressure. A deeper injection also provides better spatial and timing conditions for geophysical monitoring and tracking of the CO2 plume. Simulations indicate only a small 10 tonne CO2 injection experiment would be required to monitor CO2 migration using geophysical techniques. In addition to providing an opportunity to demonstrate semi-continuous, near real-time monitoring of CO2 migration up a fault, the planned CO2 injection experiment presents a unique opportunity to obtain field measurements on vertical fault permeability. It also provides an opportunity to predict fluid flow and potential metal remobilisation through comprehensive reactive transport modelling, collection and analysis of core post CO2 injection, and evaluate the effectiveness of the modelling versus field observations.

Poster G6 The Neoproterozoic–Paleozoic Officer Basin, located in South Australia and Western Australia, remains a frontier basin for energy exploration, with significant uncertainty due to a paucity of data. As part of Geoscience Australia’s Exploring for the Future (EFTF) program, the objective of this study is to derive the petrophysical properties and to characterise potential reservoirs in the Neoproterozoic–Cambrian sedimentary succession in the Officer Basin through laboratory testing and well log interpretation using both conventional and neural network methods. Laboratory measurements of 41 legacy core samples provide the relationships between gas permeability, Klinkenberg corrected permeability, and nano-scale permeability, as well as grain density, effective and total porosity for various rock types. Conventional log interpretation generates the volume fraction of shale, effective and total porosity from gamma ray and lithology logs. A self-organising map (SOM) was used to cluster the well log data to generate petrophysical group/class index and probability profiles for different classes. Neural network technology was employed to approximate porosity and permeability from logs, conventional interpretation results and class index from SOM modelling. The Neoproterozoic−Cambrian successions have the potential to host both conventional and tight hydrocarbon reservoirs. Neoproterozoic successions are demonstrated to host mainly tight reservoirs with the range in average porosity and geometric mean permeability of 4.77–6.39% and 0.00087–0.01307 mD, respectively, in the different sequences. The range in average porosity and geometric mean permeability of the potential Cambrian conventional reservoirs is 14.54−26.38% and 0.341−103.68 mD, respectively. The Neoproterozoic shales have favourable sealing capacities. This work updates the knowledge of rock properties to further the evaluation of the resource potential of the Officer Basin. To access the poster click the link on the right. To read the full paper click here

Poster G8 The Officer Basin spanning South Australia and Western Australia is the focus of a regional stratigraphic study being undertaken as part of the Exploring for the Future (EFTF) program, an Australian Government initiative dedicated to increasing investment in resource exploration in Australia. Despite numerous demonstrated oil and gas shows, the Officer Basin remains a frontier basin for energy exploration with significant uncertainties due to data availability. Under the EFTF Officer–Musgrave Project, Geoscience Australia acquired new geomechanical rock property data from forty core samples in five legacy stratigraphic and petroleum exploration wells that intersected Paleozoic and Neoproterozoic aged intervals. These samples were subjected to unconfined compressive rock strength tests, Brazilian tensile strength tests and laboratory ultrasonic measurements. Petrophysical properties were also characterised via X-ray computerised tomography scanning, grain density and porosity-permeability analysis. Accurate characterisation of static geomechanical rock properties through laboratory testing is essential. In the modern exploration environment, these datasets are a precompetitive resource that can simplify investment decisions in prospective frontier regions such as the Officer Basin. To access the poster click the link on the right. To read the full paper click here

Barnicarndy 1 is a stratigraphic well drilled in the southern part of the Canning Basin’s Barnicarndy Graben under Geoscience Australia’s Exploring for the Future program in collaboration with the Geological Survey of Western Australia to provide stratigraphic data for this poorly understood tectonic component. The well intersects a thin Cenozoic section, Permian–Carboniferous fluvial clastics and glacial diamictites and a thick pre-Carboniferous succession (855–2585mRT) unconformably overlying Neoproterozoic metasedimentary rocks. Three informal siliciclastic intervals were defined based on core lithology, well logs, chemical and mineral compositions: the Upper Sandstone (855–1348.1mRT), Middle Interval (1348.1–2443.4mRT) and Lower Sandstone (2443.4–2585mRT). The Middle Interval was further divided into six internal zones. Both conventional methods and artificial neural network technology were applied to well logs to interpret petrophysical and elastic properties, total organic carbon (TOC) content, pyrolysis products from the cracking of organic matter (S2) and mineral compositions. Average sandstone porosity and reservoir permeability are 17.9% and 464.5mD in the Upper Sandstone and 6.75% and 10mD in the Lower Sandstone. The Middle Interval claystone has an average porosity and permeability of 4.17% and 0.006mD, and average TOC content and S2 value of 0.17wt% and 0.047mgHC/g rock, with maximum values of 0.66wt% and 0.46mgHC/g rock, respectively. Correlations of mineral compositions and petrophysical, geomechanical and organic geochemical properties of the Middle Interval have been conducted and demonstrate that these sediments are organically lean and lie within the oil and gas window.

Exploring for the Future (EFTF) is an Australian Government initiative focused on gathering new data and information about potential mineral, energy and groundwater resources across Australia. The energy component of EFTF, initially focussed on northern Australia, aims to improve our understanding of the petroleum potential of frontier Australian basins. Building an understanding of geomechanical rock properties is key to understanding both conventional and unconventional petroleum systems as well as carbon storage and sedimentary geothermal systems. Under EFTF, Geoscience Australia has undertaken geomechanical work including stress modelling, shale brittleness studies and the acquisition of new rock property data through extensive testing on samples from the Paleo- to Mesoproterozoic South Nicholson region of Queensland and the Northern Territory, and the Paleozoic Kidson Sub-basin of Western Australia. Work in these regions demonstrates regional stress orientations in broad agreement with previously modelled, continent-scale stress orientations and stress magnitudes that vary through the basin with depth and by lithology. Rock testing highlights potentially brittle shales and demonstrates variable rock properties in line with lithology. These analyses are summarised herein. Providing baseline geomechanical data in frontier basins is essential as legacy data coverage can often be inadequate for making investment decisions, particularly where unconventional plays are a primary exploration target. As EFTF increases in scope, Geoscience Australia anticipates expanding these studies to encompass further underexplored regions throughout Australia, lowering the barrier to entry and encouraging greenfield exploration.

Natural or native molecular hydrogen (H2) can be a major component in natural gas, and yet its role in the global energy sector’s usage as a clean energy carrier is not normally considered. Here, we update the scarce reporting of hydrogen in Australian natural gas with new compositional and isotopic analyses of H2 undertaken at Geoscience Australia. The dataset involves ~1000 natural gas samples from 470 wells in both sedimentary and non-sedimentary basins with reservoir rocks ranging in age from the Neoarchean to Cenozoic. Pathways to H2 formation can involve either organic matter intermediates and its association with biogenic natural gas or chemical synthesis and its presence in abiogenic natural gas. The latter reaction pathway generally leads to H2-rich (>10mol% H2) gas in non-sedimentary rocks. Abiogenic H2 petroleum systems are described within concepts of source–migration–reservoir–seal but exploration approaches are different to biogenic natural gas. Rates of abiogenic H2 generation are governed by the availability of specific rock types and different mineral catalysts, and through chemical reactions and radiolysis of accessible water. Hydrogen can be differently trapped compared to hydrocarbon gases; for example, pore space can be created in fractured basement during abiogenic reactions, and clay minerals and evaporites can act as effective adsorbents, traps and seals. Underground storage of H2 within evaporites (specifically halite) and in depleted petroleum reservoirs will also have a role to play in the commercial exploitation of H2. Estimated H2 production rates mainly from water radiolysis in mafic–ultramafic and granitic rocks and serpentinisation of ultramafic–mafic rocks gives a H2 inferred resource potential between ~1.6 and ~58MMm3 year−1 for onshore Australia down to a depth of 1km. The prediction and subsequent identification of subsurface H2 that can be exploited remains enigmatic and awaits robust exploration guidelines and targeted drilling for proof of concept.

The Energy component of Geoscience Australia’s Exploring for the Future (EFTF) program is aimed at improving our understanding of the petroleum resource potential of northern Australia, in partnership with the state and territory geological surveys. The sediments of the Mesoproterozoic South Nicholson Basin and the underlying Paleoproterozoic Isa Superbasin in the Northern Territory and Queensland are amongst the primary targets of the EFTF Energy program, as they are known to contain organic-rich sedimentary units with the potential to host unconventional gas plays, although their subsurface extent under the cover of the Georgina Basin is presently unknown. In order to economically produce from unconventional reservoirs, the petrophysical rock properties and in-situ stresses must be conducive to the creation of secondary permeability networks that connect a wellbore to as large a reservoir volume as possible. This study utilises data from the recently drilled Armour Energy wells Egilabria 2, Egilabria 2-DW1, and Egilabria 4 to constrain rock properties and in-situ stresses for the Isa Superbasin sequence where intersected on the Lawn Hill Platform of north-west Queensland. These results have implications for petroleum prospectivity in an area with proven gas potential, which are discussed here in the context of the rock properties and in-situ stresses desired for a viable shale gas play. In addition, these results are relevant to potential future exploration across the broader Isa Superbasin sequence.

A dynamic modelling study was undertaken to assess the feasibility of a planned CO2 injection experiment into a shallow fault at the CO2CRC's Otway Research Facility. The aim was to identify key physical properties that strongly influence migration behaviour but are presently unmeasured. Two different simulators (CMG-GEM and TOUGH2) were used to model this experiment. Both simulation efforts indicate that the proposed experiment is feasible, but show the need for better data on the maximum injection pressure and the permeability distribution in the near-surface region (including the continuity of the clay layer). During the simulation with high injection rate, there could be a rapid accumulation of CO2 at the early injection stage due to the constraints of maximum injection pressure. The modelling results suggest that the dominant trapping mechanisms are likely to be free CO2 gas trapped by the upper clay layer and residual trapping. The total amount of CO2 that could be injected increased with greater injection pressure, injection rate and maximum residual gas saturation. The results suggest that dissolution of CO2 is likely to continue to increase during the injection and post-injection stages. After the CO2 injection phase, the gas was found to spread laterally within the reservoir and moved upward along the permeable grid cells at the modelled fault. A comparison between the modelling approaches suggests that if there is a desire to have CO2 migrate up the fault and reach the upper clay layer, it will be important to conduct the injection experiment at the most permeable sections of the fault and inject CO2 into a shallow high permeability layer. It is necessary to clarify whether there is an unsaturated zone beneath the clay layer as this is speculated to exist but is unknown.