CO2 sequestration in depleted sandstone hydrocarbon reservoirs could cause a number of geomechanical problems associated with well drilling, completions, and CO2 injection. The depletion narrows the operational drilling mud weight window, which could exacerbate wellbore instabilities while drilling. Well completions may need to consider the potential of solids flowback to the injectors when injection is interrupted due to CO2 supply or required system maintenance. CO2 injection alters the temperature in the near wellbore region, which could cause fault reactivation or thermal fracturing. In addition, the injection pressure may exceed the maximum sustainable storage pressure for avoiding fracturing and fault reactivations. Through a case study, this paper demonstrates a systematic approach for geomechanical risk assessments for CO2 storage in depleted reservoirs. The study used offset well drilling and wireline log data to derive field stresses, formation pressures, rock strengths and elastic properties. A practical workflow was developed to characterize the interaction between pressure depletion and fracture gradient changes. In this particular case if an operating mud-weight window of 0.5 ppg is required, the well inclination should be below 65º towards the minimum horizontal stress Shmin orientation, or less than 45º towards the maximum horizontal stress SHmax azimuth to mitigate drilling risks. 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 high risk that a fault with a cohesion of less than 780 psi could be activated, due to the significant effect of reduced temperature on field stresses.


Carbon dioxide (CO2) emissions have elevated the concentration of greenhouse gases in the atmosphere.

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