Several field cases reported that polymer injection in a horizontal well is a viable solution to increase oil recovery. The injectivity, however, may vary significantly depending on fluid, reservoir, and geomechanical conditions. Polymer injection without understanding these factors may lead to injectivity impairment, unswept zones, and fractures undesirable for the sweep. In this paper, we present a comprehensive viscoelastic polymer injectivity model for vertical and horizontal wells.

We developed a simulator to compute viscoelastic polymer injectivity by accounting for particle filtration, thermo-poro-elastic stress changes, fracture propagation, flow distributions among multiple layers, and viscoelastic polymer rheology. Simulation results clearly show that the contribution of shear-thickening characteristics on the polymer can have a large impact in un-fractured wells but have a much smaller impact in fractured injectors. The impact of geomechanical stress changes and subsequent induced fractures are also highlighted.

The model was then applied for a field case study to identify critical aspects needed to maintain high injectivity. Two field case wells are presented where water and viscoelastic polymer are injected for a vertical well and a horizontal well accessing the multi-layered reservoir respectively. For the two injectors, water was injected initially, and then HPAM polymer solution followed to improve oil recovery. Fracture growth and injection into a long horizontal lateral are the key factors that allowed the operator to maintain injectivity by reducing the Darcy velocity, shear rate, and shear-thickening zone. For a horizontal well, operating conditions are also identified by simulations to ensure matrix injection, which is the desired conformance and sweep improvement option.