It’s a wrap! The “Australia’s Future Energy Resources” (AFER) project, funded under the Government’s “Exploring for the Future” (EFTF) program, is almost completed. The project’s four modules have evaluated a mixture of energy resource commodities, including natural gas, hydrogen, subsurface storage opportunities for carbon dioxide and hydrogen, and are complimented by several targeted basin inventories which outline the current geological knowledge of energy resources in underexplored, data-poor regions.
The presentation and extended abstract will provide an overview of the project’s key achievements, including updates on underground hydrogen storage opportunities and CCS resource assessments. A special focus will be placed on the improved geological understanding of the energy resources potential in a series of stacked Permian to Late Cretaceous basins in eastern central Australia.
Several publicly available data sets have been generated and published under the AFER project, including about 5,750 line-km of reprocessed 2D seismic data, of which key lines have been interpreted and integrated with geological and petrophysical well log data. Relative prospectivity maps have been produced for five energy resource commodities from 14 play intervals to show the qualitative variability in prospectivity of these resources, including quantitative resource assessments where warranted. A hydrogeological study has also been undertaken to understand groundwater resources in the project area in relation to impacts from any future CCS projects or to support future hydrogen projects.
Results from the AFER project have helped to identify and geologically characterise the required energy resource commodities to accelerate Australia’s path to net zero emissions.

In the context of Carbon Capture and Storage (CCS) site appraisal procedures, the assessment of Geomechanical risks associated with injection tests are important, including injection pressure thresholds, guarding against formation fracturing and solids production during fall-off tests or due to unplanned shut-in occurrences.
The Bonaparte CCS project, situated northeast of the Petrel Field, offshore Northern Territory, serves as a pertinent case. Two appraisal wells are planned, complemented by an extensive data acquisition program to fully characterise the storage site, focusing on confirming the storage reservoir and cap rock continuity and properties along with the assessment of matrix injectivity within the storage reservoir.
A geomechanical study is conducted to assess the risk of formation fracturing and sanding during a water injection test. Considering the temperature difference between the storage formation and the injection fluid, the cooling effects could lead to a reduction of almost 15% in fracture initiation pressure (FIP). Notably, the FIP for perforations aligned with the maximum horizontal stress direction are lower than the minimum horizontal stress. While injection pressures surpassing FIP might trigger tensile fracturing in specific perforations, fracture propagation from the wellbore remains unlikely if the injection pressure remains below the field’s minimum horizontal stress.
The pressure requirements for current envisaged matrix injection rates fall below the estimated FIPs. Consequently, the risk of formation fracturing during the injection test is deemed low. The propensity of sanding during flowback, considering a range of rock weakening and thermal effects of water injection, is also found to be low.

Australian Federal Greenhouse Gas (GHG) storage legislation was enacted in the mid-2000s. The CarbonNet project, initiated in 2009, exposed early challenges in these laws and facilitated legislative changes to support the nascent industry at the time. This paper presents the CarbonNet Project as a case study to suggest new areas for improvement and efficiencies associated with more mature CCS projects.
Project proponents need to navigate the GHG legislation to meet strict regulatory requirements, including establishing storage plume boundaries, demonstrating compliance with containment obligations, and deriving an acceptable risk profile required for key applications such as the Declaration of a GHG Storage Formation (DoS).
The concept of "containment" under the existing legislation currently encompasses vertical migration to surface; lateral migration out of the storage formation; and migration out of the permit boundary. In the case of the CarbonNet project, loss of containment under each of these conditions would have vastly different consequences, and the paper explores these consequences and mitigations.
At basin scale, anticipating interactions between projects and managing issues like pressure inflation becomes crucial. The suggestion of developing a CCS Regional Basin Management Framework, like existing models such as the Office of Groundwater Impact Assessment (OGIA) in Queensland is proposed to address these challenges effectively.
Legislation for GHG Storage should be forward-looking, supporting strategies for managing future CCS developments in basin regions and ultimately promoting the growth of a robust CCS network.

Understanding the mechanisms of large-scale, subsurface hydrogen migration is essential for natural hydrogen exploration and for hydrogen storage assessment. The unique properties of hydrogen make that the timescales of hydrogen migration through the deep and shallow Earth and within geological basins vary from billions to thousands of years. Within the deep Earth, advection of hydrogen-enriched rocks from the lower mantle delivers material to a variety of geological settings, including Mid Ocean Ridges and hotspots. Within the shallow Earth, diffusive and advective transport mechanisms are dependent on a wide range of parameters including geological structure, microbial activity, and subsurface environmental factors, e.g., salinity, temperature, and pressure. Furthermore, the provenance of sedimentary rocks that contain material from Archean – Proterozoic crystalline basement rocks are also an important factor in subsurface and fluvial hydrogen migration.
In this study, we extensively review the nature and timescale of hydrogen migration from the planetary to basin-scale, and within both the deep and shallow Earth. We explore the role of planetary accretion in setting the hydrogen budget of the lower mantle, propose a conceptual framework for primordial hydrogen migration to the Earth's surface and evaluate its role in setting the hydrogen budget of the rocks delivered from the deep Earth. We also review the mechanisms and timescales of hydrogen within diffusive and advective, fossil and generative and within biologically moderated systems within the shallow Earth. Finally, we assess the challenges of and discuss potential methods for modelling basin-scale hydrogen migration.

Native hydrogen's viability as a sustainable energy source will be enhanced through comprehensive geological modelling. This paper integrates existing open-source and proprietary data to delve into the geological aspects of native hydrogen exploration and proposes possible workflows.
Geological and geophysical modelling entails characterizing subsurface formations conducive to native hydrogen generation and trapping. Utilizing geological surveys, seismic and gravity data, alongside existing well logs, this analysis looks to identify regions with favourable geological structures for hydrogen accumulation.
Additionally, geological modelling informs the selection of optimal locations for hydrogen production facilities. By considering geological features such as fault lines, aquifers, and natural fractures, potential hazards and environmental impacts are mitigated.
Furthermore, understanding subsurface geology aids in the development of safe and efficient extraction techniques. By incorporating geological modeling into the evaluation of native hydrogen, this paper provides a comprehensive overview of its potential as a sustainable energy solution. Leveraging existing open-source data alongside geological insights ensures a robust foundation for decision-making in exploration, production, storage, and utilization strategies. This integrated approach empowers stakeholders to make informed choices in shaping a greener, more sustainable energy landscape.

In October 2023, Gold Hydrogen, an ASX listed natural hydrogen explorer, drilled Ramsay 1, the first natural hydrogen exploration well in Australia. Twinning an historic well, the Ramsay Oil Bore 1 well in PEL687 in South Australia, the objective of the Ramsay 1 well was to demonstrate movable hydrogen generated in the subsurface and establish the presence of a commercially attractive natural hydrogen resource base.
This paper will highlight some of the learnings from the process of designing and executing this natural hydrogen exploration well and how the initial hurdles of demonstrating the presence of a hydrogen resource were overcome during the drilling phase. The well design and geological sampling programs were adapted to cater for the unusual characteristic of hydrogen gas and the paper will discuss the appropriateness of these adaptations. As global drilling for natural hydrogen is still in its infancy, these modification to the petroleum exploration well design could have a significant impact on future drilling for this highly attractive green energy source.
This paper will also discuss the results of the well and its impact on the regional prospectivity for a commercial natural hydrogen play on the Yorke Peninsula. With a program of seismic and follow-up wells planned for 2024, Gold Hydrogen is leading a group of Australian natural hydrogen explorers, who are trying to unlock commercial natural hydrogen resources in the world.