Polymer flooding leads to enhanced oil recovery by accelerating oil production and improving sweep efficiency. However, because of the higher viscosity, the injectivity of polymer solutions is of some concern and is important to understand to predict incremental oil recoveries. Achieving high polymer-injection rates is required to increase oil-production rates.

In the field test performed in the Matzen field (Austria), polyacrylamide polymers were injected for the past 2 years. Coreflood experiments with these polymers showed a significant increase in apparent viscosity because of the viscoelastic properties of the polymer solutions. Also, severe degradation of the polymer solution at high flow velocities was detected. In addition to coreflood experiments, flow experiments through fractures were performed. In these experiments, shear thinning and limited degradation of the polymer solution were observed and quantified.

Detailed polymer-injection simulations were conducted that included complex polymer rheology in the fractures and the matrix. The reservoir stress changes and their effects on the fractures were also taken into account as a result of cold-polymer injection. The results of the simulations matched the field data both for waterfloods and polymer-test floods.

The simulations revealed two distinct phases during the injection of the polyacrylamide-polymer solution:

  1. Injection under matrix conditions in an early phase resulting in severe degradation of the polymers

  2. Injection under fracturing conditions after the formation parting pressure is reached, leading to limited degradation of the polymers

The calibrated model was used to investigate the impact of polymer rheology and particle plugging on injectivity and fracture growth.

The results of the field test and the simulations indicate that screening of fields for polyacrylamide-polymer projects needs to include geomechanical properties of the reservoir sand and cap/base rock in addition to the conventional parameters used in screening such as oil viscosity, water salinity, reservoir temperature, and reservoir permeability.

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