Formation Failure Analysis for Longitudinally Fractured Horizontal Wells Completed by Multistage Fracturing Sleeves

Abstract

Abstract This study reviewed the formation failure analysis of horizontal wells completed with both cemented and uncemented multistage fracturing sleeves to evaluate the risk of sand production and formation failure in a sandstone and mudstone interbedded reservoir. Consequently, the effects of increased confining stresses caused by fracture creation and proppant placement inside a hydraulically created longitudinal fracture were investigated. In addition, a parametric study was performed for different types of fracturing sleeves to determine the optimum flow port designs for reducing the formation failure potential. A 3D elastoplastic finite element method (FEM) model was developed for horizontal wells completed using fracturing sleeves. Reservoir rock constitutive model was obtained through several triaxial compression tests performed on the reservoir cores. The FEM model considered various loading steps, including in-situ stress, overbalanced drilling, fracture creation, reservoir depletion, and drawdown during production. Moreover, the onset of formation failure was judged based on the critical plastic strain determined from the triaxial compression test data and compared for different fracture and sleeve designs. The formation failure potential of a horizontal borehole with various completion designs was evaluated through a case study. A significant reduction in potential of formation failure for cased hole completions was observed, and the maximum allowed reservoir pressure depletion before formation failure depended on the rock strength, direction of reservoir inflow, drawdown pressure, and other factors. Similar to the oriented perforation design, the flow port location significantly affected the stability of the formation in the vicinity of the sleeve. The flow ports located in the upward and downward directions delayed the onset of formation failure, while closely spaced flow ports covering the entire circumference of the wellbore substantially increased the formation failure potential. Further, excessive stress increases caused by fracturing and proppant placement resulted in large shear stress and resultant plastic strain development at the connection between the longitudinal fracture and borehole. Openhole completions where the fracture is misaligned with the wellbore have the same risk of formation failure at the flow port as that of the cemented sleeve completions. Moreover, there is an additional risk of formation failure of the uncemented wellbore. In the idealistic case, wherein the fracture is completely aligned with the wellbore, large plastic strains develop at the sidewalls of the horizontal openhole wellbore. The difference in the formation failure tendency between the cased hole and openhole completions may affect post-failure well productivity, depending on the type of debris after failure and its size relative to the sleeve port size. The results presented in this work demonstrate that the onset of formation failure is mainly determined by rock strength, reservoir pressure support, drawdown pressure, completion design and other factors. Cemented frac sleeve completion is necessary when the wellbore is widely exposed to weak, water-sensitive formations, which tend to fail during the early flowback period. Further, in openhole completions, the weak intervals must be mechanically isolated such that the failed rock debris in the annulus between the open hole and production liner does not plug the sleeve ports. In addition, the formation failure potential was elevated owing to the longitudinal fracture creation along the wellbore. The findings from this study provide critical inputs for optimizing lower-completion designs and achieving long-term solid-free production in fractured horizontal wells in moderately consolidated sandstone reservoirs.