CO₂-Enhanced Gas Recovery in a Tight Gas Reservoir Using History-Matched Effective Fractures and Automated Regional Gas Inventory Analysis

Reliable assessment of CO₂-enhanced gas recovery (CO₂-EGR) in developed tight gas reservoirs requires production-constrained fracture characterization and quantitative estimates of remaining gas. This study integrates boundary element fracture modeling, automated history matching with the embedded discrete fracture model (EDFM), and polygon-based regional gas accounting for a 14-well Sulige reservoir. Simulated wetted fractures provide geometric constraints for history matching against bottomhole-pressure observations under prescribed gas-production rates. The best-matching realization yields effective-to-wetted fracture half-length ratios of 57–75% and height ratios of 54–70%, with a fracture conductivity of approximately 10 mD·m. Automated inventory analysis identifies 2.81 × 10⁸ m³ of gas remaining in a candidate injection area after 20 years of depletion, equivalent to approximately 57% of its initial inventory of 4.91 × 10⁸ m³. A subsequent 10-year CO₂-injection scenario through an existing horizontal well at 35 MPa increases cumulative methane production at year 30 from 2.31 × 10⁸ to 2.52 × 10⁸ m³ relative to continued depletion, representing an incremental 2.1 × 10⁷ m³, or 9.1%. The post-injection regional gas inventory is 2.39 × 10⁸ m³; its decline from the pre-injection value reflects regional depletion and gas redistribution rather than incremental recovery alone. The workflow connects calibrated fracture behavior with spatial resource assessment to support injection-target selection and scenario evaluation. The predicted recovery improvement is conditional on the calibrated model and evaluated operating conditions.