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

Depleted hydrocarbon reservoirs offer pressure headroom, existing wells and subsurface data, but pore-volume estimates can overstate operable CO₂ capacity when pressure and well constraints are ignored. We develop a reproducible pressure-constrained reduced-order model for a representative Niger Delta depleted-sandstone benchmark. Mass injection is coupled to reservoir-scale pressure accumulation and dissipation and radial well resistance, while a complementarity-style controller reduces rate when a 28 MPa (4061 psi) bottom-hole-pressure limit would otherwise be exceeded. A 25 km² (6178 acres), 60 m (197 ft) net-thickness, 22% porosity case targeted 31.688 kg s⁻¹ (52.047 MMscf /d) for 20 years. The model stores 19.52 × 10⁹ kg (371.1 Bscf), with rate declining to 26.894 kg s⁻¹ (44.173 MMscf /d) after the pressure constraint becomes active; maximum average reservoir pressure is 27.78 MPa (4030 psi) and equivalent plume radius is 1.33 km (4364 ft). A 3000-realisation Monte Carlo analysis yields P10, P50 and P90 cumulative masses of 10.61, 19.11 and 20.00 × 10⁹ kg (201.7, 363.3 and 380.2 Bscf), respectively. Effective compressibility, net thickness, connected area and pressure-dissipation timescale dominate uncertainty. Operable storage is therefore a joint capacity-injectivity-containment problem rather than a pore-volume quantity. All processed data and source code required to reproduce the reported findings are supplied in a repository-ready package.