|Publisher||Society of Petroleum Engineers||Language||English|
|Content Type||Journal Paper|
Geomechanical Risk Assessments for CO2 Sequestration in Depleted Hydrocarbon Sandstone Reservoirs
Z. Fang, SPE; A. Khaksar, SPE; and K. Gibbons, SPE, Baker Hughes
|Journal||SPE Drilling & Completion|
|Volume||Volume 27, Number 3||Pages||pp. 368-382|
2012. Society of Petroleum Engineers
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.
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