Compositional simulation of underground hydrogen storage in a depleted gas field: injection and withdrawal strategy trade-offs

This study assesses the performance of commercial-scale underground hydrogen storage in a depleted Otway Basin gas field. Ten annual injection–withdrawal cycles were modelled under different injection and withdrawal strategies, accounting for infrastructural, market and reservoir constraints. Three withdrawal strategies, each targeting 0.88 PJ per cycle, were investigated: (i) high-rate episodic drawdown, (ii) high-rate prolonged drawdown and (iii) continuous low-rate production. The high-rate episodic and prolonged strategies required large withdrawal rates, necessitating more wells to remain within tubing velocity constraints. In contrast, the continuous strategy, with its lower flow rate, allows the energy target to be met with a single crestal well. The prolonged case underdelivered in the energy target due to aquifer-driven pressure rebound during shut-in, which reduced injectivity. The episodic and continuous strategies met energy targets, with the continuous case achieving higher recovery and reduced hydrogen spreading. Injection performance was also assessed by testing mild overpressure scenarios. This increased the injected hydrogen volume. However, the additional injection did not translate into proportional increases in recovery, as a portion of the hydrogen migrated further from the wells, highlighting diminishing returns when increasing injection pressure beyond the baseline constraint used here. These findings emphasise that energy delivery targets should guide the optimisation of well count and placement. These design decisions must account for reservoir dynamics and operational constraints. A robust design should balance initial objectives with potential future shifts in energy demand, withdrawal frequency or other limits.