Field Experience with Coiled Tubing Stimulation in Long Open-Hole Injector Wells Under Lock-Up Conditions, North Kuwait

Abstract

In the North Kuwait (NK) fields, injector wells are routinely drilled with long open hole (OH) horizontal intervals ranging from 3,000 to 4,000 ft. This design is driven by the need to maximize reservoir contact and improve waterflood efficiency in low-permeability carbonate formations. However, these wells frequently exhibit poor injectivity due to formation damage, heterogeneity, and reduced permeability, requiring stimulation to restore performance. Coiled tubing (CT) stimulation offers precise placement of treatment fluids but becomes extremely challenging in long OH horizontals because of CT lock-up, which limits depth reach and treatment distribution. Addressing these operational constraints is critical to maintaining reservoir pressure support and sustaining field production targets. A structured stimulation methodology was applied across multiple NK injector wells, with a strong reliance on simulator-based planning to predict and manage CT lock-up. Prior to execution, CT reach simulations were performed to identify the maximum achievable depth before mechanical lock-up. During field operations, the CT was run to the simulated lock-up depth, within safe mechanical limits. Approximately 60–80% of the OH interval could be directly stimulated through the CT. To treat the lower section of the long OH interval beyond the CT reach, the treatment fluids were pumped through the stationary CT, thereby displacing the fluids toward the interval below the predicted lock-up depth. This approach was intended to improve treatment of reservoir sections beyond the mechanical reach of the CT. Field applications demonstrated that the proposed stimulation methodology can be successfully implemented in long horizontal injector wells with severe CT reach limitations. In several cases, wells that initially accepted only 0.5 bpm at approximately 3,000 psi were successfully stimulated using the proposed workflow. Post-stimulation injectivity improved significantly, with injection rates of up to 8 bpm achieved at approximately 1,500 psi, representing a substantial reduction in injection pressure and a marked increase in injection capacity. The observed improvement in post-stimulation injectivity supports the effectiveness of the proposed treatment workflow under CT lock-up conditions. The consistent performance achieved across the field applications demonstrates that integrating CT reach prediction with optimized treatment planning provides a practical approach for improving injectivity in long horizontal injector wells operating under CT lock-up conditions. Unlike conventional stimulation programs, the study integrates mechanical, hydraulic, and chemical optimization to overcome depth reach limitations and ensure meaningful treatment coverage. The procedure also eliminated the need for expensive extended-reach tools. The successful field cases provide new insights for operators managing similar challenges in mature carbonate reservoirs worldwide. This experience establishes a benchmark for extending CT stimulation capability in complex well designs and highlights the potential for significant injectivity improvement in otherwise marginal wells.