A technical and economic assessment of underground hydrogen storage in Western Australia (23.RP2.0176) – Completed

Introduction and Objectives

The Perth Basin is an attractive place to start. It hosts a network of depleted gas fields that already have decades of geological data, existing wells, and, in some cases, pipeline connections – all of which can significantly reduce the cost and risk of developing new storage. But repurposing a gas field for hydrogen is not automatic: hydrogen is a smaller, more reactive, more mobile molecule than methane, and the rock, faults and wells that safely contained natural gas for decades need to be re-examined specifically for hydrogen. This project was established to answer that question for the Perth Basin.

The project set out to answer five questions, agreed with the project partners at the outset:

• Which depleted gas reservoirs in the Perth Basin are geologically suitable for underground hydrogen storage, and for compressed air energy storage?
• How much hydrogen could realistically be stored and recovered from those reservoirs, and how “clean” (pure) would it stay through repeated storage cycles?
• How does the economics of underground hydrogen storage compare with battery storage, in both Victoria and Western Australia?
• Can we predict how hydrogen storage would actually perform, over time, in a specific field – the Yardarino gas field?
• Will the caprock – the layer of rock that seals a reservoir – that has safely contained methane for decades also safely contain hydrogen, including where it already has small pre-existing fractures?

Project Findings

The project’s subsurface work followed a logical sequence: first map where the faults are and what stresses they are under; then test whether those faults would stay stable if the reservoirs were re-pressurised with hydrogen; then work out how much hydrogen could actually be stored and which fields make the best candidates; and finally test, in the laboratory, whether the sealing rock itself – the caprock – would keep hydrogen in over many storage cycles. Each of these steps is summarised below.

1. Mapping the Perth Basin’s faults and stresses

Before assessing whether any site is safe for hydrogen storage, the project first needed a clear picture of where the basin’s faults are, how they are oriented, and what stress conditions they experienced before the gas fields were produced. This baseline mapping covered ten depleted gas fields across the Perth Basin. With existing data, The Perth Basin’s fault network is well enough understood to identify, early, which fields start with a favourable geological hand and which will need closer attention.

2. Will the faults hold? Testing storage integrity under hydrogen injection

Building on the fault map, the project then asked the harder question: if these reservoirs are re-pressurised with hydrogen, could any of these faults slip and compromise the seal? This required modelling four representative fields – Yardarino, Mondarra, Xyris and Redback – under two bounding scenarios deliberately chosen to bracket the uncertainty: an optimistic case in which the rock stress fully recovers as pressure is restored, and a conservative case in which it does not recover at all.

• In reservoirs with high permeability, such as Mondarra and Xyris, the rock stress is likely to recover substantially as pressure is restored, which meaningfully lowers the reactivation risk compared with the most cautious assumption.
• Mondarra’s long, safe operating history as a natural gas storage facility under repeated injection and withdrawal cycles is real-world evidence that this stress recovery does occur, and gives confidence in the models used for other sites.
• Yardarino benefits from a strong natural water drive, which helps keep pressures manageable, though ongoing monitoring of how the surrounding aquifer behaves is recommended.
• Overall, a conservative planning assumption of about 85% stress recovery is proposed for high-permeability reservoirs, to be confirmed with further site-specific data.

None of the four fields tested show a fundamental barrier to hydrogen storage, but each has specific faults that will need active pressure and stress management once a project moves toward operation.

3. How much hydrogen can we store, and where?

With subsurface risk better understood, the project then asked a practical, investment-relevant question: applying detailed reservoir simulation and a purpose-built screening tool, which Perth Basin fields actually make the best hydrogen storage candidates, and how much hydrogen could they hold?

• The main factor affecting how “clean” recovered hydrogen stays during repeated storage cycles is gravity – hydrogen being lighter than the residual natural gas and water in the reservoir – rather than mixing through diffusion. Storing in reservoirs with a steeper dip (greater than about 10°) and injecting at a higher rate can improve the purity of recovered hydrogen by 10–20%.
• A three-stage screening framework – weighing containment assurance and wellbore integrity most heavily – was applied to ten Perth Basin fields. Five passed initial screening: Mondarra, Xyris, Yardarino, Beharra Springs and Redback.
• Together, Mondarra, Xyris and Yardarino could offer roughly 85 PJ of recoverable hydrogen-equivalent storage – enough to make a material contribution toward the roughly 110 PJ/year of underground storage capacity WA is projected to need by 2050 to firm a renewables-dominant grid.

Mondarra, Xyris and Yardarino stand out as the Perth Basin’s strongest, most investment-ready hydrogen storage candidates, combining low subsurface risk with existing pipeline and grid access.

4. Will the sealing rock itself hold hydrogen in?

The final piece of subsurface work asked the most fundamental question of all: caprocks that have sealed methane for millions of years – will they also seal hydrogen, especially as pressure is cycled up and down season after season? This was tested on shale samples from the Yardarino field’s caprock, using an integrated combination of chemical modelling, laboratory rock-strength testing and neutron imaging. After testing, hydrogen does not appear to chemically weaken this caprock in the short term, but the way pressure is cycled during storage operations is likely to be the main long-term factor governing whether the seal holds – which is good news, because cycling regimes can be actively managed.

5. Comparing the economics of hydrogen storage with batteries

Batteries and underground hydrogen storage are not competitors so much as a relay team: batteries are very good at smoothing out day-to-day swings in solar and wind output, but become expensive very quickly if asked to carry a grid through an entire low-wind, low-sun winter. To test whether hydrogen storage is the right tool for that longer job, and at what cost, the project built an hour-by-hour model of future electricity demand and renewable generation for the Western Australian SWIS grid (out to 2042) and the Victorian grid (out to 2035), and used it to size and cost the battery and underground hydrogen storage needed to keep the lights on.

• For WA in 2042, meeting demand with full reliability was modelled using the Dongara depleted gas field, requiring a 21 GW electrolyser and 12 GW fuel cell system and around $46 billion of additional infrastructure (mostly the electrolyser). The extra cost this adds to each unit of electricity – the Additional Levelised Cost of Electricity, or ALCOE – came to $53.5/MWh, comparable to the $73/MWh wholesale electricity price recorded in the SWIS in 2024.
• A smaller, nearer-term option was also modelled: using the Yardarino field – the smallest of the candidate reservoirs – to run a modest field-trial-scale system by 2031. A 0.4 GW electrolyser and fuel cell system lifts the demand met by only about one percentage point, but does so for roughly $1.1 billion at an ALCOE of just $2.7/MWh – a far more affordable, realistic stepping stone than the full-scale 2042 system, and one that conveniently uses the same field that the project’s subsurface work (Sections 2.1–2.4) already flags as a strong storage candidate.
• Across a range of onshore Victorian depleted gas fields, the project also estimated a combined storage volume of roughly 21.8 million m³, showing that Victoria, too, has enough depleted-reservoir capacity to support a seasonal hydrogen store, should it choose this path.

Batteries are the right tool for daily swings, and underground hydrogen storage is the right tool for the seasonal gap – and this modelling shows that gap can be closed at a cost broadly in line with today’s wholesale electricity price, with a much cheaper field-trial-scale option available at Yardarino as a practical first step

6. Predicting how the Yardarino reservoir would actually perform

A further strand of the project, used detailed reservoir simulation to predict, case by case and cycle by cycle, how hydrogen storage would actually perform at Yardarino: the depleted gas field discovered in 1964, roughly 8 km southeast of Dongara and 320 km north of Perth, whose single production well was decommissioned in 2012. An earlier state-wide screening (RISC, together with Dodangoda et al.) had already ranked Yardarino second out of 23 depleted WA oil and gas fields for hydrogen potential; this project’s own more detailed six-criteria screening in Milestone 4 independently placed it third among five short-listed Perth Basin fields (Section 2.3) – two different studies, at different levels of detail, both landing on Yardarino as a strong prospect.

Detailed field-specific modelling backs up the project’s broader screening results: Yardarino can store and recover high-purity hydrogen using straightforward well designs. Its geology keeps hydrogen contained where it should stay, and a single vertical well – the simpler design – performs as well as, or better than, more complex alternatives (relative drilling costs still need to be confirmed).

Recommendations

The project’s findings point to a clear, staged pathway for turning the Perth Basin’s depleted gas fields into working hydrogen storage assets, while continuing to manage the specific risks identified above.

• Prioritise a modest, field-trial-scale underground hydrogen storage system at Yardarino (in the order of 0.4 GW electrolyser and fuel cell capacity) as an affordable near-term step – modelled at roughly $1.1 billion and an ALCOE of $2.7/MWh – to build real operating experience ahead of any full-scale investment.
• Advance Mondarra, Xyris and Yardarino, as Tier-1 candidates, to front-end engineering design (FEED)-level evaluation, including hydrogen-specific core-flooding tests and wellbore integrity audits.
• Design any Yardarino pilot around a single crestal vertical well in the first instance, consistent with the Milestone 5 reservoir modelling, while keeping injection pressures within the fault-safe limits identified in Section 2.2; evaluate the relative drilling cost of vertical versus horizontal wells before finalising the design.
• Put in place real-time stress and pressure monitoring during any pilot storage operations, to check that the fault stability assumptions used in this project’s modelling hold true in the field.
• Manage injection and withdrawal pressures deliberately at higher-risk faults (e.g. MON-N, Allanooka, Red-S) rather than treating all faults in a field the same way.
• Explore near-term hydrogen/methane blending trials, for example through the Parmelia Gas Pipeline into the Kwinana Industrial Area, to generate early revenue and operational experience ahead of pure-hydrogen storage.
• Undertake targeted further studies at Beharra Springs (geochemical compatibility) and Redback (pressure management near faults) before committing major capital, and revisit Dongara’s role only once nearer-term sites are established.
• Extend the caprock testing programme to true cyclic, field-representative pressure paths, and refine 3D fault models, to build a predictive “safe operating envelope” for pressure ranges and cycling frequency at each candidate site.
• Establish a Joint Industry Project, bringing together FEnEx CRC partners, Beach Energy, DMIRS and other operators, to coordinate regulatory engagement and pilot validation across the Perth Basin, so that lessons from one site benefit all.
• Apply the screening and risk-assessment framework developed in this project to other depleted gas fields around Australia, to build a broader, de-risked pipeline of underground hydrogen storage opportunities.

Taken together, these steps would move underground hydrogen storage in the Perth Basin from a promising concept to a bankable, near-term piece of infrastructure – supporting Western Australia’s hydrogen export ambitions while making use of billions of dollars of existing gas infrastructure already in the ground.