Effect of Salinity and Hardness on HPAM Rheology in Sandstone

Abstract This paper clarifies the impact of salinity and hardness on HPAM rheology in sandstones with permeability greater than 200 mD. For modelers/simulators of polymer flooding, the experimental findings should be of high relevance when projecting HPAM injectivity, fracture initiation, and whether viscoelasticity is significant in oil recovery of capillary-trapped residual oil with or without the presence of fractures. The literature review summarizes the effects of polymer concentration and molecular weight and rock permeability and oil saturation on HPAM rheology in sandstones. The experimental work examines HPAM rheology in sandstones with permeability from 252 mD to 838 mD, salinities from 0.1 to 10.5% total dissolved solids (TDS), and hardness levels from 0 to 0.1% CaCl2. As expected, the magnitude of resistance factors increased with increased HPAM concentration but decreased with increased salinity. The maximum resistance factor in the shear-thickening regime correlated well with C[μ]/(k/ϕ)0.5. The velocity dependence of the rheology (in sandstone) was largely unchanged by salinity between 0.1% and 5% TDS. At 1% TDS, the velocity dependence of rheology (in sandstone) was very weakly dependent on CaCl2 concentration between 0 and 0.1%. We examine the relation between the onset of shear thickening and the inverse of the polymer solution relaxation time determined from bulk rheological data. The level of mechanical degradation was fairly unaffected by HPAM concentration between 25 and 2000 ppm. These findings should simplify the job of modelers when projecting the performance of polymer flooding.