Pressure-Constrained CO₂ Storage Capacity and Injection Performance in Depleted Hydrocarbon Reservoirs: An Uncertainty-Aware Modelling Framework for the Niger Delta

Depleted hydrocarbon reservoirs can provide pressure headroom, existing wells and subsurface data, but static pore-volume estimates can overstate operable CO₂ storage when pressure and well constraints are neglected. We present a reproducible reduced-order screening framework for a non-proprietary, Niger Delta-informed depleted-sandstone benchmark. The revised formulation uses connected pore volume for pressure capacitance, a separate swept-volume constraint, radial well resistance with the finite-radius correction, and pressure- and temperature-dependent CO₂ density and viscosity. A 25.000 km² connected area, 60.000 m net thickness and 0.220 porosity case targets 31.688 kg s⁻¹ for 20 years. At 358.15 K, the Peng-Robinson equation of state gives CO₂ density increasing from 157.824 kg m⁻³ at 8.000 MPa to 683.759 kg m⁻³ at 28.000 MPa, while the Fenghour correlation gives viscosity from 0.020 to 0.056 mPa s. The 28.000 MPa bottom-hole-pressure limit becomes active at 13.083 years; cumulative injection is 19.232 × 10⁹ kg, the terminal rate is 28.138 kg s⁻¹, maximum average reservoir pressure is 27.772 MPa, and the equivalent swept-footprint radius is 1.399 km. In 3000 Monte Carlo realisations with fully declared priors and a porosity-permeability dependency, the 10th, 50th and 90th statistical quantiles are 11.696, 18.012 and 20.000 × 10⁹ kg, respectively, with 35.0% of realisations reaching the schedule-imposed target cap. Using the SPE-style exceedance convention, these correspond to P90, P50 and P10, respectively. The benchmark is pressure-dominated: permeability does not independently limit injection over the regional sandstone range, so the framework should not be interpreted as demonstrating an injectivity-limited case. The results are a methodological screening benchmark, not a field reserve estimate.