Carbon capture and storage (CCS) is a critical component of proposed pathways to limit global warming, though considerable upscaling is required to meet emissions reduction targets. Quantifying and managing the risks of fault reactivation is a leading barrier to scaling global CCS projects from current levels of ~40 million tonnes of carbon dioxide(CO2) per year (to target levels of several gigatonnes of CO2 per year), because CO2 injection into reservoirs can result in increased pore-fluid pressure and temperature changes, which can reduce the strength of rocks and faults and induce brittle failure. This can result in induced seismicity, whilst hydraulic fracturing of seals could provide pathways for CO2 leakage. Consequently, identifying favourable geomechanical conditions (typically determined through data on pre-injection rock stress, mechanical and elastic properties, and pore-fluid pressures) to minimise deformation of reservoirs and seals represents a key challenge in the selection of safe and effective sites for CCS projects. Critically, however, such geomechanical data are typically spatially limited (i.e. restricted to wells) and mainly consist of pre-injection crustal stress orientation measurements, rather than a full 3D description of the stress tensor and related geomechanical properties. This paper reviews some key geomechanical issues and knowledge gaps (particularly those associated with data availability and limitations) that need to be understood to enable successful reservoir and seal management for CCS projects. We also highlight recent advances in multi-scale and dimensional geomechanical modelling approaches that can be used to assess sites for the secure storage of CO2 as well as other gases, including hydrogen.

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.

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.

Presented on Tuesday 16 May: Session 1 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. To access the Oral Presentation click the link on the right. To read the full paper click here

Visual Presentation G2 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. To access the Visual Presentation click the link on the right. To read the full paper click here

Visual Presentation G1 Geoscience Australia’s Onshore Basin Inventories project provides a whole-of-basin inventory of geology, petroleum systems, exploration status and data coverage of hydrocarbon-prone onshore Australian sedimentary basins. Two existing volumes cover many central and north Australian onshore basins, providing a single point of reference and creating a standardised national basin inventory. In addition to summarising the current state of knowledge within each basin, the onshore basin inventory reports identify critical science questions and key exploration uncertainties that may help inform future work program planning and aid in decision making for both government and industry organisations. Under Geoscience Australia’s Exploring for the Future (EFTF) program, several new onshore basin inventory reports are being delivered. The next releases include the Adavale Basin of southern Queensland and a compilation of Australia’s Mesoproterozoic basins. These reports are supported by value-add products that address identified data gaps and evolve regional understanding of basin evolution and prospectivity, including petroleum systems modelling, seismic reprocessing and regional geochemical studies. The Onshore Basin Inventories project continues to provide scientific and strategic direction for precompetitive data acquisition under the EFTF work program, guiding program planning and shaping post-acquisition analysis programs. To access the Visual Presentation click the link on the right. To read the full paper click here

Geoscience Australia’s Onshore Basin Inventories project provides a whole-of-basin inventory of geology, petroleum systems, exploration status and data coverage of hydrocarbon-prone onshore Australian sedimentary basins. Two existing volumes cover many central and north Australian onshore basins, providing a single point of reference and creating a standardised national basin inventory. In addition to summarising the current state of knowledge within each basin, the onshore basin inventory reports identify critical science questions and key exploration uncertainties that may help inform future work program planning and aid in decision making for both government and industry organisations. Under Geoscience Australia’s Exploring for the Future (EFTF) program, several new onshore basin inventory reports are being delivered. The next releases include the Adavale Basin of southern Queensland and a compilation of Australia’s Mesoproterozoic basins. These reports are supported by value-add products that address identified data gaps and evolve regional understanding of basin evolution and prospectivity, including petroleum systems modelling, seismic reprocessing and regional geochemical studies. The Onshore Basin Inventories project continues to provide scientific and strategic direction for precompetitive data acquisition under the EFTF work program, guiding program planning and shaping post-acquisition analysis programs.

A comprehensive geochemical program was carried out on rock samples collected in the NDI Carrara 1 drill hole, the first stratigraphic test of the newly discovered Carrara Sub-basin located in the South Nicholson region of northern Australia. The drill hole recovered continuous core from 284 m to total depth at 1750 m and intersected approximately 1120 m of Proterozoic sedimentary rocks, unconformably overlain by 630 m of Cambrian Georgina Basin carbonate-rich rocks. Total organic carbon (TOC) contents from Rock-Eval pyrolysis highlight the potential for several thick black shales to be a source of petroleum for conventional and unconventional plays. Cambrian rocks contain an organic-rich section with TOC contents of up to 4.7 wt.% and excellent oil-generating potential. The Proterozoic section is overmature for oil generation but mature for gas generation, with potential for generating gas in carbonaceous mudstones showing TOC contents up to 5.5 wt.% between 680 and 725 m depth. A sustained release of methane (up to 2%) recorded during drilling from 1150 to 1500 m suggests potential for an unconventional gas system in the Proterozoic rocks from 950 to 1415 m depth, which exhibit favourable organic richness and thermal maturity. The Proterozoic rocks, which are comparable in age to the sediment-hosted deposits of the Century Mine, contain local occurrences of lead, zinc and copper sulfide minerals providing hints of mineralisation. The combined geochemical results offer the promise of a potential new resource province in northern Australia.

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.

Presented on Wednesday 18 May: Session 17 NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland. To access the presentation click the link on the right. To read the full paper click here

The Camooweal deep-crustal seismic reflection survey (GSQ Open Data Portal SS095590) was acquired in 2019 by the Geological Survey of Queensland (GSQ) as part of the Queensland Government’s Strategic Resources Exploration Program (SREP). The survey is centred on the northwest Queensland town of Camooweal, with the total length of acquisition spread over three lines: 19Q-C1 (65.8 km), 19Q-C2 (173.6 km) and 19Q-C3 (60.9 km).

The South Nicholson region, which includes the Paleoproterozoic Isa Superbasin, the Mesoproterozoic South Nicholson Group and overlying younger sediments, is sparsely explored and has recently come into increased focus as a result of the Australian Government's Exploring for the Future program. Previous exploration has identified potential shale gas plays within the River and Lawn supersequences of the Isa Superbasin in northwest Queensland's northern Lawn Hill Platform region. Understanding mineralogy is important for characterising shale reservoirs, as mechanical properties such as shale brittleness are influenced by mineral composition. Mineralogy can, therefore, be utilised as a proxy for mechanical properties that are crucial to minimising risks associated with exploring for and developing shale reservoirs. This study utilises three different methods for calculating brittleness: X-ray diffraction (XRD) mineralogy, X-ray fluorescence (XRF) major-element geochemistry and derived elastic properties. Results indicate highly variable mineralogy within the analysed samples, demonstrating heterogeneity in shale brittleness throughout the studied supersequences. Brittleness calculated from XRD analysis ranges from ductile to brittle, with zones of brittle shales present in all supersequences. Increasing quartz and decreasing clay content is the dominant control on shale brittleness in the studied samples. Correlation between XRF major-element geochemistry and XRD mineralogy is demonstrated to be moderate to poor, with brittleness derived from XRF major-element geochemistry observed to be significantly higher than brittleness derived from XRD mineralogy. Conversely, brittleness derived from derived elastic properties agrees closely with XRD mineralogy derived brittleness. As brittleness derived from XRF major-element geochemistry provides brittleness estimates that are excessively high and with minimal overlap with the other two brittleness datasets, the use of these data to calculate brittleness in the South Nicholson region is not recommended. Analysis of brittleness indices from this study, in combination with total organic carbon content drawn from regional geochemical analysis in the South Nicholson region, identifies potential shale gas target intervals in the River, Term and Lawn supersequences. Data presented on correlated well sections highlight intervals of exploration interest within these supersequences, being those depths where high-organic-content, brittle rocks are identified. The rocks that meet this criterion are primarily constrained to the already-known potential shale gas plays of the River and Lawn supersequences. Recent data from Geoscience Australia imply a significantly increased lateral extent of these potential shale gas plays, likely extending from the northern Lawn Hill Platform, underneath the South Nicholson Basin and into the Carrara Sub-basin.

NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland.

This study assesses the prospectivity of the world’s oldest known stacked petroleum systems from the Proterozoic greater McArthur Basin (Northern Territory, Australia), which has immense potential to host both conventional natural gas and oil, in addition to shale-gas accumulations. The Mesoproterozoic succession of the Beetaloo Sub-basin and surrounding region hosts the Territory’s premier shale-gas play and is at an advanced stage of exploration for shale hydrocarbon plays. However, there is also potential for natural gas in older sedimentary packages, with flows and shows reported in underlying Paleoproterozoic successions. At the continent-scale, four regional petroleum supersystems are identified and described in order to provide a platform for consistent nomenclature at the sedimentary package and group level; in ascending stratigraphic order; these are the Paleoproterozoic Redbank and McArthur supersystems, the Paleoproterozoic–Mesoproterozoic Lawn Supersystem, and the Mesoproterozoic Beetaloo Supersystem. The Redbank and Lawn supersystems are newly named and defined, and the Beetaloo Supersystem is renamed from the former Urapungan Supersystem. Eight possible conventional natural gas plays and six shale-gas plays are documented within the McArthur Supersystem, which incorporates Glyde Package successions of the McArthur Basin and the Birrindudu Basin. Petroleum play concepts are also described from this supersystem to assist with assessing the potential for gas resources. A better understanding of the petroleum systems of the greater McArthur Basin is critical to the targeting of areas for geoscience data acquisition in order to facilitate the reduction of exploration search space; and it enables a more rigorous assessment of the potential for conventional and unconventional hydrocarbon resources at local (play) and regional scales.