Determination of well stability and sand risk minimization parameters for gas condensate field conditions using geomechanical and CT-based approaches

The paper presents the results of geomechanical and CT-based studies of deformation, fracture and filtration processes in reservoir rocks of the Arctic shelf gas condensate field. The experimental study combines (i) determination of mechanical properties, (ii) true triaxial physical modeling of near-wellbore filtration and geomechanical processes, (iii) triaxial sand production studies, and (iv) digital CT-analysis of the rock matrix and sand particles. Based on true triaxial physical modeling, the relationships between permeability, rock deformation, and stresses around a horizontal well during drawdown were determined. Hollow cylinder-type tests were used to determine the stress conditions for sand release initiation, the intensity of sand production under varying stress states, and the total volume of sand produced. Digital particle size analysis of the matrix and released sand provided insights into the dominant mechanisms of hole failure during sand production. A significant strength anisotropy of reservoir rocks was identified, suggesting that drawdown in horizontal wells could lead to asymmetric bottomhole zone fracture, initiated at the upper and lower points on the wellbore contour. The obtained results allowed to determine (i) the drawdowns required to maintain wellbore stability in the given reservoir interval; (ii) the optimal parameters of downhole gravel filter screens for sand control; (iii) to identify the prevailing type of wellbore fracture and to localize failure initiation points on the wellbore walls. The results highlight the importance of integrating modern laboratory core analysis methods to enhance the development of complex reservoirs and reduce the risks of fractures and sand production in weakly cemented formations.