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Summary Inflow control devices (ICDs) have become important tools in managing the injection profile of wells. Their design is typically based on the initial condition of each injection zone. This paper, inspired by a Middle East offshore field study, explores the interaction between the ICD design and placement in horizontal injectors and how their performance is affected by the initiation and propagation of injection-induced fractures (IIFs) during the reservoir’s dynamic evolution. We use an advanced fully coupled reservoir-fracture-wellbore simulator that integrates ICD pressure drop modeling with dynamic IIF propagation under thermal and porous elastic stresses. This allows us to systematically investigate, for the first time, not only how ICDs redistribute injection flow, but also how IIFs alter ICD performance over time. This simulator integrates wellbore dynamics with ICD functionality, multiphase flow in the reservoir, solid mechanics, and energy balance, allowing for thermally induced fracture propagation and particle plugging. It accounts for the thermoporoelastic effects in the stress field during cold water injection, simulating fracture initiation and propagation driven by both internal and external filtration as well as thermal effects. The pressure drop across the ICDs is solved within a fully coupled nonlinear system of equations using the Newton-Raphson (NR) method, enabling the prediction of fracture initiation and growth at various sections of the well over time. The model allows us to assess the impact of ICD placement and characteristics on the long-term injection profile in the well. The model was validated through history matching field data and demonstrates that ICD placement and specifications can significantly influence long-term injection profiles. To demonstrate the impact of IIFs, we first focus on model results for a homogeneous reservoir setup. The setup is intentionally used as a benchmark, providing a unit-test style validation before extending the model to heterogeneous reservoirs. This avoids the complex effects associated with reservoir heterogeneity and clearly demonstrates important ICD-IIF interactions. The results indicate that the growth of IIFs significantly impacts ICD performance and governs the injection flow profile. In the absence of ICDs, the flow distribution can vary considerably over time due to the development of IIFs. Injector performance is analyzed for different ICD configurations, demonstrating that ICDs can effectively regulate flow distribution along the wellbore, enhancing conformance control even when fractures start and propagate. When designed appropriately, ICDs can mitigate the impact of potentially problematic “thief” fractured zones. Although ICDs introduce an additional pressure drop that may reduce injectivity, they promote a more uniform flow distribution, which can slow the decline in injectivity and improve reservoir sweep and oil recovery. Our findings suggest that, in many instances, optimizing the placement and specifications of ICDs can enhance the injection profile, leading to improved recovery rates and a reduced risk of out-of-zone fracture growth. Our results illustrate the dynamics of multiple fracture growth in segments of the injector wellbore separated by ICDs and their effect on flow distribution for the first time. These insights provide a foundation for the effective design and placement of ICDs in horizontal injectors.