  Polymer flooding is crucial in hydrocarbon production, increasing oil
recovery by improving the water-oil mobility ratio. However, the high viscosity
of displacing fluid may cause problems with sand production on poorly
consolidated reservoirs. This work investigates the effect of polymer injection
on the sand production phenomenon using the experimental study and numerical
model at a laboratory scale. The experiment uses an artificially made sandstone
based on the characteristics of the oil field in Kazakhstan. Polymer solution
based on Xanthan gum is injected into the core to study the impact of polymer
flooding on sand production. The rheology of the polymer solution is also
examined using a rotational rheometer, and the power-law model fits outcomes.
We observe no sand production during the brine injection at various flow rate
ranges. However, the sanding is noticed when the polymer solution is injected.
More than 50% of cumulatively produced sand is obtained after one pore volume
of polymer sand is injected. In the numerical part of the study, we present a
coupling model of DEM with CFD to describe the polymer flow in a granular
porous medium. In the solid phase, the modified cohesive contact model
characterizes the bonding mechanism between sand particles. The fluid phase is
modeled as a non-Newtonian fluid using a power-law model. We verify the
numerical model with the laboratory experiment result. The numerical model
observes non-uniform bond breakage when only a confining stress is applied.
Alternatively, the injection of the polymer into the sample leads to a
relatively gradual decrease in bonds. The significant difference in the
pressure of the fluid results in its higher velocity, which causes intensive
sand production at the beginning of the simulation. The ratio of medium-sized
produced particles is greater than the initial ratio of those before injection.
