The success of polymer flooding as a method of oil recovery has been attributed to a profile control mechanism of the displacing fluid (polymer solutions) related to the displaced fluid (crude oil), depending on properties such as polymer viscosity and its dependence with reservoir and flow conditions. The viscosity of polymer flow depends not only on the size of the molecules or molecular weight but it is further affected by salinity and divalent content on the brine used for the preparation of the polymer slug. The effect of salinity on polymer viscosity is more critical in presence of divalent ions Ca2+ and Mg2+ and high salinity conditions, which limits the use high salinity produced water for re-injection in polymer flooding processes where high salinity is involved. A series of salinity resistant polymers have been developed by incorporating co-monomers including hydrophilic and hydrophobic groups or combination of them along the chain of polyacrylamide which has made the viscosity behavior more complex and affected by ionic interactions both intra-molecular and inter-molecular. Therefore, an extensively screening process that includes evaluation of variables such as: stability of polymer solutions under salinity and ion composition, flow conditions and sensitivity analysis using simulation according to specific applications, is required for the selection of any specific system.

A systematic comparative study of the screening of commercial partial hydrolysed polyacrylamide (PHPA), and co-polymers of acrylamide and hydrophobic modified Comb-polymers (HMPAM) under high salinity conditions is investigated. Synthetic high salinity and multi-component (with divalent ions) produced water from a North Sea reservoir was used on Bernheimer sandstone core samples using a crude oil from the North Sea with specific gravity 21 °API. Results from core flooding and rheology were matched to obtain required mathematical correlations to simulate core flooding experiments numerically and compare the efficiency of the different polymers.

While polymers PHPA and co-polymers AM-AMPS and AM-nVP showed typical Newtonian behavior at low shear rates and non- Newtonian at high shear rates, HMPAM polymers have shear thinning behavior. Newtonian behavior on PHPA-3 seems to support its higher recovery factor comparing with PHPA-6 (higher MW). Viscosity of HMPAM solutions is more sensitive to changes of the polymer concentration and more sensible to flow conditions. Additionally, ionic interactions and steric effects in the co-polymers contribute the efficiency of the oil recovery at high salinity. Therefore, their viscosity behavior needs to be evaluated.


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