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Summary

Depleted hydrocarbon reservoirs are attractive targets for gas storage and carbon dioxide (CO₂) disposal because of proven storage capacity and seal integrity, existing infrastructure, and other reasons. Optimum well completion and injection design in depleted reservoirs would require understanding of important rock-mechanics issues considering rock/fluid-interaction effects (e.g., drillability and completion of new wells, maximum-sustainable-storage pressures avoiding fracturing, and fault reactivations). Building a field-specific geomechanical model calibrated with well and production data is a prerequisite for addressing these issues. Through a case study, this paper demonstrates a systematic approach for geomechanical risk assessments for CO₂ storage in depleted reservoirs.

A depleted gas reservoir at a 4,050-ft depth with the current pressure of 45 psi is considered in this study for CO₂ sequestration. The study used offset-well drilling and wireline-log data to derive field stresses, formation pressure, rock strength, and elastic properties. A practical workflow was developed to characterize the interaction between pressure depletion and fracture-gradient changes. In this particular case, the results showed that the fracture gradient (FG) was as low as approximately 9.3 lbm/gal, and the wellbore-collapse pressure in the overburden shale was highly dependent on the well trajectory. If an operating mud-weight window of 0.5 lbm/gal is required, the well inclination should be below 65° if it is planned to be oriented toward the minimum-horizontal-stress (Shmin) direction, or less than 45° if toward the maximum-horizontal-stress (Shmax) azimuth, to mitigate drilling risks. Field data and analytical-sanding evaluations indicate no sand-control installation would be needed for injectors. Fracturing and faulting assessments confirm that the critical pressures for fault reactivation and fracturing of caprock are significantly higher than the planned CO₂-injection and -storage pressures. However, the initial CO₂ injection could lead to a temperature in the near-wellbore region as low as 0.7°C. There is a high risk that a fault with cohesion of less than 780 psi could be activated because of the significant effect of reduced temperature on field stresses, and it is therefore recommended that the CO₂ injectors be placed in fault-free regions.

The methodology and overall workflow presented in this paper are expected to assist well engineers and geoscientists with geomechanical assessments for optimum well-completion and injection design for both natural-gas and CO₂ storage in depleted reservoirs.