Effect of Residual Oil Saturation and Salinity on HPAM Rheology in Porous Media

Abstract

Abstract During polymer flooding, the velocities where shear-thickening occurs directly impact HPAM injectivity, fracture initiation, and whether viscoelasticity is significant in oil recovery. The onset velocity for shear-thickening in oil-free porous media is known to translate with the square root of permeability-porosity. However, few studies report HPAM rheology with residual oil present, and those conflict and are inconsistent with behavior seen without oil. This paper experimentally clarifies how Sor, salinity, and temperature impact HPAM rheology in rock. HPAM rheology at 20°C was determined in Berea sandstone for Darcy velocities from 0.01 to 100 ft/d, Sor from zero to 0.55, and krw from 0.03 to 1. In a given experiment, the core was first exposed to the highest pressure-gradient for the test series. After stabilization, resistance factors were recorded and effluent viscosity was measured. Next, the velocity was halved, and the stabilization and measurement processes were repeated. This procedure was extended in steps to the lowest velocities. We also studied the effect of salinity on HPAM rheology in porous media between 0.105% to 10.5% TDS for 0.1% and 0.2% HPAM (at 20°C). Temperature effects on rheology in Berea from 20°C to 60°C were investigated using 0.2% HPAM in 0.105%-TDS water. This work provides key information that will be crucial to establishing whether HPAM viscoelasticity can play a significant role in recovering oil in field polymer floods. It also provides crucial information for analytical/numerical efforts to establish when fractures will initiate and how far they will extend from the wellbore during polymer flooding field applications.