Hydraulic fracturing has enabled production from unconventional reservoirs in the U.S., but production rates often decline sharply, limiting recovery factors to under 10%. This study proposes an optimization workflow for the CO₂ huff-n-puff process for multistage-fractured horizontal wells in the Wolfcamp A formation in the Delaware Basin. The potential for enhanced oil recovery and CO₂ sequestration simultaneously was addressed using a coupled geomechanics–reservoir simulation. Geomechanical properties were derived from a 1D mechanical earth model and integrated into reservoir simulation to replicate hydraulic fracture geometries. The fracture model was validated using a robust production history matching. A fluid phase behavior analysis refined the equation of state, and 1D slim tube simulations determined a minimum miscibility pressure of 4300 psi for CO₂ injection. After the primary production phase, various CO₂ injection rates were tested from 1 to 25 MMSCFD/well, resulting in incremental oil recovery ranging from 6.3% to 69.3%. Different injection, soaking and production cycles were analyzed to determine the ideal operating condition. The optimal scenario improved cumulative oil recovery by 68.8% while keeping the highest CO₂ storage efficiency. The simulation approach proposed by this study provides a comprehensive and systematic workflow for evaluating and optimizing CO₂ huff-n-puff in hydraulically fractured wells, enhancing the recovery factor of unconventional reservoirs.

Hydraulic fracturing has enabled production from unconventional reservoirs in the U.S., but production rates often decline sharply, limiting recovery factors to under 10%. This study optimizes the CO2 huff-n-puff process for multistage-fractured horizontal wells in Wolfcamp A formation in the Delaware Basin. The potential for enhanced oil recovery and CO2 sequestration simultaneously was addressed using a coupled geomechanics-reservoir simulation. Geomechanical properties were derived from a 1D mechanical earth model and integrated into reservoir simulation to replicate hydraulic fracture geometries. The fracture model was validated using a robust production history matching. Fluid phase behavior analysis refined the equation of state, and 1D slim tube simulations determined a minimum miscibility pressure of 4300 psi for CO2 injection. After the primary production phase, various CO2 injection rates were tested from 1 to 25 MMSCFD/well, resulting in incremental oil recovery ranging from 6.3% to 69.3%. Different injection, soaking, and production cycles were analyzed to determine the ideal operating condition. The optimal scenario improved cumulative oil recovery by 68.8% while keeping the highest CO2 storage efficiency. The simulation approach proposed by this study provides a systematic workflow for evaluating and optimizing CO2 huff-n-puff in hydraulically fractured wells, enhancing the recovery factor of unconventional reservoirs.

This paper synthesizes lessons learned from drilling a CO₂-storage stratigraphic well in the San Juan Basin (New Mexico, USA) to clarify drivers of operational incidents and to inform future well planning. A literature review of regional drilling problems was combined with pre-drill engineering based on offset-well history and a geomechanical model, including casing, cementing, and hydraulics designs developed in commercial software; these designs were compared with field execution to extract incident-specific lessons. The most frequent problems observed are lost circulation, stuck pipe, and poor control of drilling parameters, consistent with complex lithology and reservoir pressure depletion that reduces fracture pressure below anticipated values. Based on the lessons learned, three mitigations are proposed as follows: (1) update the geomechanical model with the latest pore, fracture pressure estimates; (2) apply underbalanced drilling using nitrified mud by injecting nitrogen through a parasite string while drilling intermediate and production sections; and (3) maintain operating limits (weight on bit < 44.5 kN, top-drive rotation < 45 rpm, and pump rate < 1.32 m³/min) to improve fluid returns through low-fracture-pressure intervals. Simulation results support the applicability of the proposed solutions.