Integrated Modelling of CO₂ Storage in Multi-Operator Basins, Lessons for Operations and Regulation

Current Australian offshore CCS regulation and guidance are site-centric and largely framed around the CO₂ plume footprint (the mapped migration pathways). While operators are expected to demonstrate safe pressure limits for integrity (caprock, wells, structural stability), there is no explicit requirement to delineate or quantify a pressure footprint—which is larger than the plume footprint—or to assess the cumulative, far-field pressure effects of multiple GHG operations across titles. Thus, even where projects operate within a safe integrity window, regional pressure propagation that can constrain dynamic capacity and injectivity, reshape monitoring areas, and affect neighbouring GHG/petroleum operations is not explicitly addressed by the approvals pathway. Addressing these effects requires integrated regional modelling beyond current minimum regulatory expectations.



An integrated, multi-site regional assessment of the K20 sequence in the Barrow–Dampier sub-basin—a high-potential saline aquifer for CO₂ storage—was conducted to quantify how regional pressure communication influences dynamic capacity, injectivity, and monitoring footprints. A 4,310 km² model domain was constructed, incorporating five candidate storage formations, each with six injectors operating at ≤ 1 Mtpa per well for 30 years under bottom hole pressure (BHP) constraints. Boundary conditions were varied from closed to finite-aquifer support, with aquifer strength ranging from weak to strong (Carter–Tracy r-ratios of 1.5–10). Eighteen cases were simulated, covering simultaneous and staggered activation of storage operations, as well as scenarios with and without a nearby gas field.



Under closed boundaries, substantial inter-project interference was observed: integrated modelling—where all five sites are represented and operated concurrently within a single simulation—resulted in 514 Mt CO₂ stored over 30 years, compared to ~924 Mt CO₂ if each site were assessed in isolation (~185 Mt CO₂ per site). This demonstrates that single-site assessment can significantly overestimate dynamic (pressure-limited) capacity. With finite aquifer support, total storage increased to 591 Mt (r-ratio &#61; 1.5), 861 Mt (r-ratio &#61; 3), and ~924 Mt (r-ratio ≥ 5). For r-ratio values of 5 or greater, design injection rates were sustained for the whole injection period, and per-site storage converged to ~184.75 MtCO2. These results highlight the significant influence of correctly defining aquifer properties and external support when assessing dynamic capacity in regional CO₂ storage systems. Bias from isolated site assessment persisted at moderate external aquifer support: at r-ratio &#61; 3, Site 1 stored 184.75 Mt in isolation but 140.77 Mt when neighbouring site operations were considered (a reduction of 24%).



On the basis of these results, integrated regional modelling, defined by the pressure-connected area and including all active and planned CCS sites plus relevant hydrocarbon assets, should be adopted as standard practice in hydraulically connected regions to ensure realistic capacity and injectivity estimates, defensible monitoring footprints, and lower-risk coexistence with petroleum operations.

Tags: Barrow-Dampier Sub-basins, Carbon Capture and Storage, Carbon Capture, Utilisation and Storage, Pressure interference, Pressure space, Published_External, Resource geoscience, Resourcing Australia’s Prosperity
Organization: Geoscience Australia Data