Polymer flooding is an important enhanced oil recovery technology introduced in field projects since the late 1960s. The key to a successful polymer flood project depends upon proper estimation of polymer retention. The aims of this paper are twofold. First, to show the mechanism of polymer flooding and how this mechanism is affected by polymer retention. Based on the literature, the mobility ratio significantly increases as a result of the interactions between the injected polymer molecules and the reservoir rock. Secondly, to provide a better understanding of the polymer retention, we discussed polymer retention types, mechanisms, factors promoting or inhibiting polymer retention, methods and modeling techniques used for estimating polymer retention.

This research aims to test four new polymers for their stability under high salinity/high hardness conditions for their possible use in polymer flooding to improve oil recovery from hydrocarbon reservoirs. The four sulfonated based polyacrylamide co-polymers were FLOCOMB C7035; SUPERPUSHER SAV55; THERMOASSOCIATIF; and AN132 VHM which are basically sulfonated polyacrylamide copolymers of AM (acrylamide) with AMPS (2-Acrylamido-2-Methylpropane Sulfonate). AN132 VHM has a molecular weight of 9–11 million Daltons with 32 mol % degree of sulfonation. SUPERPUSHER SAV55 mainly has about 35 mol % sulfonation degree and a molecular weight of 9–11 million Daltons. FLOCOMB C7035, in addition, has undergone post-hydrolysis step to increase polydispersity and molecular weight above 18 million Daltons but it has a sulfonation degree much lower than 32 mol %. THERMOASSOCIATIF has a molecular weight lower than 12 million Daltons and a medium sulfonation degree of around 32 mol %, and also contains LCST (lower critical solution temperature) type block, which is responsible for its thermoassociative characteristics. This paper discusses the rheological behavior of these polymers in aqueous solutions (100–4500 ppm) with NaCl (0.1–10 wt %) measured at 25 °C. The effect of hardness was investigated by preparing a CaCl₂-NaCl solution of same ionic strength as the 5 wt % of NaCl. In summary, it can be concluded that the rheological behavior of the newly modified co-polymers was in general agreement to the existing polymers, except that THERMOASSOCIATIF polymers showed unique behavior, which could possibly make them a better candidate for enhanced oil recovery (EOR) application in high salinity conditions. The other three polymers, on the other hand, are better candidates for EOR applications in reservoirs containing high divalent ions. These results are expected to be helpful in selecting and screening the polymers for an EOR application.

Copolymers of acrylamide with the sodium salt of 2-acrylamido-2-methylpropane sulfonic acid—known as sulfonated polyacrylamide polymers—had been shown to produce very promising results in the enhancement of oil recovery, particularly in polymer flooding. The aim of this work is to develop an empirical model through the use of a design of experiments (DOE) approach for bulk viscosity of these copolymers as a function of polymer characteristics (i.e., sulfonation degree and molecular weight), oil reservoir conditions (i.e., temperature, formation brine salinity and hardness) and field operational variables (i.e., polymer concentration, shear rate and aging time). The data required for the non-linear regression analysis were generated from 120 planned experimental runs, which had used the Box-Behnken construct from the typical Response Surface Methodology (RSM) design. The data were collected during rheological experiments and the model that was constructed had been proven to be acceptable with the Adjusted R-Squared value of 0.9624. Apart from showing the polymer concentration as being the most important factor in the determination of polymer solution viscosity, the evaluation of the model terms as well as the Sobol sensitivity analysis had also shown a considerable interaction between the process parameters. As such, the proposed viscosity model can be suitably applied to the optimization of the polymer solution properties for the polymer flooding process and the prediction of the rheological data required for polymer flood simulators.

Increasing the viscosity of injected water by the addition of polymer improves the displacement efficiency during the water flooding process. In this study, a sulfonated polyacrylamide copolymer has been added to salt water. Several parameters, such as polymer concentration, shear rate, NaCl concentration, molecular weight and sulfonation degree, have a significant effect on the polymer solution viscosity. The main objective of this paper is to investigate how the polymer solution viscosity varies with changes in the input parameters so as to identify the relative importance of these parameters. This paper incorporates the Design of Experiments technique using Taguchi’s method and the Analysis of Variance (ANOVA) to investigate the effect of process variables on the viscosity of a polymer solution. Five input parameters and six possible interactions have been investigated. The analysis of the experimental results revealed that two input parameters, namely, polymer concentration and shear rate, have the most significant impact on polymer viscosity. Two strong interactions were observed in the (1) NaCl concentration and sulfonation degree and (2) molecular weight and NaCl concentration studies. The results show that the Taguchi method was successful in identifying the main effects and interaction effects. ANOVA further buttresses the results from Taguchi’s method by showing a strong similarity in its results.

The viscosity of four new polymers was investigated for the effect of aging at high temperature, with varying degrees of salinity and hardness. The four sulfonated based polyacrylamide co-polymers were FLOCOMB C7035; AN132 VHM; SUPERPUSHER SAV55; and THERMOASSOCIATIF copolymers. All polymer samples were aged at 80 °C for varying times (from zero to at least 90 days) with and without isobutyl alcohol (IBA) as an antioxidant. To see the effect of divalent ions on the polymer solution viscosity, parallel experiments were performed in a mixture of CaCl₂-NaCl of the same ionic strength as 5 wt % NaCl. The polymers without IBA showed severe viscosity reduction after aging for 90 days in both types of preparation (5 wt % NaCl or CaCl₂-NaCl). In the presence of IBA, viscosity was increased when aging time was increased for 5 wt % NaCl. In CaCl₂-NaCl, on the other hand, a viscosity reduction was observed as aging time was increased. This behavior was observed for all polymers except AN132 VHM.

Polymers are often added with water as a viscosifier to improve oil recovery from hydrocarbon reservoirs. Polymer might be lost wholly or partially from the injected polymer solution by adsorption on the grain surfaces, mechanical entrapment in pores, and hydrodynamic retention in stagnant zones. Therefore, having a clear picture of polymer losses (and retention) is very important for designing a technically and economically successful polymer flood project. The polymer adsorption and mechanical entrapment are discussed more in depth in the literature, though the effect of hydrodynamic retention can be just as significant. This research investigates the effect of the hydrodynamic retention for low and high molecular weight (AN 113 VLM and AN 113 VHM) sulfonated polyacrylamide polymer. Two high permeability Bentheimer core plugs from outcrops were used to perform polymer corefloods. Polymer retention was first determined by injecting 1 cm³/min, followed by polymer core floods at 3, 5, and 8 cm³/min to determine the hydrodynamic retention (incremental retention). A higher molecular weight polymer (AN 113 VHM) showed higher polymer retention. In contrast, hydrodynamic retention for lower molecular weight (AN 113 VLM) was significantly higher than that of the higher molecular weight polymer. Other important observations were the reversibility of the hydrodynamic retention, no permanent permeability reduction, the shear thinning behavior in a rheometer, and shear thickening behavior in core floods.