The Rafael discovery was drilled in 2021, flow tested in 2022 and since then an extensive appraisal plan has been undertaken. 3D seismic was acquired in 2023, with the aim of further constraining the size of the accumulation coupled with identifying locations for appraisal drilling, planned for 2024.
Rafael sits in the Canning Basin and has the potential to be the largest conventional onshore gas discovery in Western Australia. Buru’s interpretation from pressure data indicated that the hydrocarbon column could be at least 700 metres, coincident with the structural closure on 2D seismic data.
Gas and condensate were identified and tested in the Devonian aged Laurel Carbonates, extending the play fairway from the existing Ungani Oil Field, and identifying a new play in the Upper Laurel dolomites.
A successful flow test was undertaken from a restricted zone within the Lower Laurel carbonates (Ungani Dolomite) and yielded 40bbls/mmcf condensate with low CO2. The flow test was suboptimal for several reasons, so further testing is planned during appraisal drilling, including possible re-test of the discovery well. The Upper Laurel dolomite section has not been tested and may provide significant upside.
The new 3D seismic has provided further insight into the extent of the accumulation, which has narrowed the uncertainty range and enabled a targeted appraisal plan. Appraisal drilling later in 2024 will allow the testing of the full sequence of hydrocarbon intervals alongside numerous other reservoir data for the overall characterisation of this important discovery in the Canning Basin.

The Beetaloo Basin comprises one of the oldest working petroleum systems in the world where Mesoproterozoic organic-rich shales are being appraised for their unconventional reservoir potential. The basin is also considered as an exploration target for liquid hydrocarbons, with potential for geothermal energy and natural hydrogen resources. Production tests of the Velkerri and Kyalla shales, conducted through fracture-stimulated wells, have demonstrated the presence of movable gas. However, flow rates required to establish an economically sustainable shale gas industry with 2P reserves is yet to be proven. A 3D basin model developed for the basin predicts some of the shale properties that are key to locating production ‘sweet-spots’ including hydrocarbon composition, pressure and temperature. The ‘sweet-spots’ are likely to be associated with regions of elevated reservoir pressure and permeability. The model demonstrates that pressure distribution across the basin has been affected by multiple burial-inversion events that the basin experienced over more than a billion years. Furthermore, the model demonstrates that basal heat-flow variations are related to basement structures and provides guidance for geothermal prospectivity across the basin. Recently published results highlighted the occurrence of natural hydrogen in significant concentrations associated with the Mesoproterozoic shales in the Beetaloo. However, the accuracy of hydrogen data reported in the databases, with respect to sample preservation and analytical techniques, needs to be validated. Our basin model has been applied to kinetically simulate hydrogen generation from thermal decomposition of organic matter in the Velkerri and Kyalla shales, with results delineating regions of significant hydrogen generation.

While Mesoproterozoic organic-rich shales in the Beetaloo Basin are currently being appraised for their unconventional gas potential, liquid-rich hydrocarbons may play a role in future developments. A CSIRO strategic project has been investigating these shows in more detail with the Grains with Oil Inclusions (GOI™) fluid inclusion technique. This has revealed, in unprecedented detail, the presence of a ‘hidden’ palaeo-oil column in the Moroak Sandstone in Elliott-1 and possibly in all four Kyalla ‘sands’ above. These oil inclusion assemblages (OIA 1) were entrapped early in quartz cement and from a probable Velkerri source at peak oil generation (~1.25 Ga) and represent some of the earliest known oil accumulations on earth. A later entrapment event is recorded in the Kyalla ‘sands’ in both ankerite-filled veins and cement, together with transgranular healed fractures (OIA 2). It is argued that this oil was entrapped from a Kyalla source with oil generation from ~750 Ma. In the basin centre, at Jamison-1, there is no evidence for either palaeo-oil accumulations or significant migration. This is consistent with structure, or rather lack of it, in this stratigraphic test well. While there is a slight decline of organic richness in the Velkerri towards the south of the basin, this ‘early’ oil would appear to have migrated to the margins of the basin where it can preserve porosity until lost. Further work is underway to understand both the regional burial and maturity histories as well as timing of entrapment and molecular composition of the inclusion oils.

Led by Geoscience Australia and coming to a close in 2024, Exploring for the Future (EFTF) is 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 and petrophysical 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, single and multi-stage triaxial tests, Brazilian tensile strength tests, laboratory ultrasonic measurements, X- ray computerised tomography scans, grain density, porosity-permeability and mercury injection capillary pressure 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.