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Keywords: surfactant solubility phase behaviour microemulsion interfacial tension retention a b s t r a c t Ideally, in a chemical flooding process, one would like to inject a surfactant solution that has good solubility at the relevant conditions, ultralow interfacial tension (efficient oil mobilisation) and low loss of surfactant (better economics) in the porous medium. The key question is-can you have low loss of surfactant, i.e. low retention, at ultralow interfacial tension? To answer this question, we have undertaken a systematic study of surfactant solubility, phase behaviour, interfacial tension and retention as a function of salinity for a given surfactant formulation. The idea is to explore the interrelationship between these properties and find the best condition(s) for combined low interfacial tension and low retention in a surfactant flooding process. For the investigated surfactant formulation, ultra-low interfacial tensions (o0.01 mN/m) can be found in the Winsor III region at optimal salinity. The aqueous solution at optimal salinity is, however, turbid, and retention values are high. On the other hand, for light oils, there are regions in the Winsor I area where (i) interfacial tensions are low (0.01 mN/m o IFT o0.1 mN/m), but not ultralow, (ii) aqueous solutions are clear and (iii) retention is 10 times lower than at optimal salinity. The search for an optimum surfactant formulation has to consider solution properties and retention in addition to the low interfacial tension. Based on our result, we therefore propose that Winsor I phase behaviour is the best option for a compromise between the properties in question.

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Hydrophobically modified polyelectrolytes have been suggested as an alternative to the more commonly used polyelectrolytes in enhanced oil recovery (EOR) applications involving polymers. Compared to regular polyelectrolytes, the hydrophobically modified polyelectrolytes are known to be more stable at high salinities. In this study, we have investigated the influence of brine salinity and ionic composition for a series of six hydrophobically modified polyelectrolytes with the same polymer backbone, but with an increasing average number of hydrophobic groups per polymer molecule. Polymer characterization has been performed using a combination of steady-state shear viscosity and dynamic oscillatory measurements. Hydrophobic interactions leading to a change in rheological properties was only observed above a threshold value for the concentration of hydrophobe. At the threshold value, saltinduced hydrophobic interactions were observed. For higher concentrations of hydrophobe, high salinity solutions showed one order of magnitude increase in viscosity compared to the polymer without hydrophobic groups. This could partly be explained by an increase in elasticity. These findings have important implications for polymer selection for EOR. V

Polymer flooding has increasingly been considered for heavy oil recovery applications. This has been encouraged by positive results from field applications at e.g. Pelican Lake and Tamaredjo and lab experiments showing that highly efficient recovery can be obtained at mobility ratios far from unity. Improved understanding of the mobilization process will increase process efficiency. Here we have used x-ray visualization to study sweep efficiency by an associative polymer at adverse mobility ratio in 2D flow. The x-ray scanner provides visual information on the development of fingers and saturation changes during the flooding process. Sweep efficiency was evaluated in two dimensional flow using a 30x30x2 cm slab of Bentheimer outcrop sandstone. A 540 cP crude oil was first displaced by water, then by 1000 ppm of a PAM-based associative polymer in a low salinity brine. Associative polymers have a potential for intermediate heavy oil/heavy oil applications due to favorable salt and shear tolerance, thermo-thickening properties and high resistance factors (RF) obtained in porous media due to hydrophobic interactions. Oil displacement by water at adverse mobility ratio is characterized by frontal instability and fingering of the water phase through the oil phase, leading to early water breakthrough and poor sweep efficiency. The details of this process is not revealed in typical core floods as pressure and production data can be fitted to a multitude of recovery scenarios for an unstable displacement. The x-ray visualization showed that the water flood was highly unstable with numerous thin fingers forming. As expected, an early water breakthrough was observed at about 0.07 PV injected. After water breakthrough additional oil recovery was primarily inefficient sweep between existing fingers. Polymer injection initiated at a stable, high water cut (97 - 98 %) was highly efficient, recovering 21 % OOIP over 0.7 PV injected. Production data showed a strong reduction in water cut suggesting formation of an oil bank. Saturation images confirmed this, and additionally revealed that the oil bank was formed by a combined polymer sweep between fingers and by expansion of established fingers in the first 2/3 of the slab, leading to accumulation toward the production well. However, the polymer flood was unstable, with no clear polymer bank formed in contrast to typical 2D polymer floods at lower mobility ratio. This is to our knowledge the first 2D flow experiment of oil mobilization by associative polymers. It shows that the polymer is highly efficient in accelerating the production in a tertiary flood where water is inefficiently flowing predominantly in an established water finger pattern. Combining visualization of 2D flow with pressure and production data leads to better insight into the mechanism of oil mobilization by associating polymer.