Modeling the Combined Effects of Water Salinity and Polymer Rheology on the Performance of Polymer Flooding and In-Depth Gel Treatment


Assessment of the potential of polymer flooding and gel treatment to investigate their roles of improving sweep efficiency requires an accurate modeling of polymer rheology (polymer viscosity versus shear rate) coupled with the effects of water salinity. A 3-D simulation model that represent quarter of five-spot pattern with one injector and one producer was utilized to run different scenarios using 1,000 ppm partially hydrolyzed polyacrylamide (HPAM) polymer solution with brine varying in salinities from 2,000 to ppm using UTGEL simulator. The in-situ gelation system consisted of HPAM as a polymer solution, trivalent chromium (Cr3+) as a crosslinker, and malonate ion as a delaying ligand. A unified viscosity model (UVM) developed by Delshad et al. (2008) that covers a full spectrum of Newtonian, shear-thinning, and shear-thickening behaviors was used to model the polymer rheology during polymer flooding and gel treatment and the results were compared with running the same scenarios assuming shear- thinning behavior only. Input parameters that relates the effects of salinity on both polymer viscosity and polymer adsorption were obtained. Finally, the effect of the presence of divalent cations such as Ca2+, Mg2+ in the reservoir brine were also investigated. In this study, we demonstrated that using polymer solutions that have viscoelastic characteristic such as HPAM can indeed increase recovery more than shear-thinning behavior only, and more importantly was the effect of gel rheology on the gelation process of the gel system. Thus, oil recovery factor was always higher when considering UVM compared to shear-thinning behavior only. In addition, increasing the salinity of the injected water decreases the viscosity and increases the adsorption of polymer solution; therefore, the higher the brine salinity, the lower the recovery factor. A further enhancement of the recovery factor was achieved using low-salinity chase water flooding. This improvement was more noticeable when the initial salinity of the model was very high (i.e., 20,000 ppm). In addition, the effects of lowering chase water salinity were more pronounced with polymer flooding compared to gel treatment. Moreover, the treatments were less efficient when the hardness was high in the reservoir brine. Finally, low-salinity chase water flooding reverse the effect of the presence of divalent cations in the reservoir brine.

Meeting Name

SPE Western Regional Meeting 2018 (2018: Apr. 22-26, Garden Grove, CA)


Geosciences and Geological and Petroleum Engineering

Keywords and Phrases

Polymers; Oil well flooding; Polymer flood

International Standard Book Number (ISBN)


Document Type

Article - Conference proceedings

Document Version


File Type





© 2018 Society of Petroleum Engineers (SPE), All rights reserved.

This document is currently not available here.