An experimental study of shear stability of several high-molecular-weight polymers used as mobility control agents in EOR projects has been performed in well-controlled conditions. The shearing device was made of a capillary tube with ID of 125 μm, through which polymer solution was injected at controlled rate. The set-up enables a precise measurement of the shear rate to which the polymer macromolecule is submitted. The degradation rate was measured by the viscosity loss induced by the passage into the capillary tube. The shear rate was gradually increased up to 106 sec-1 while checking degradation rate at each stage. Different commercial EOR polymer products were submitted to the test with polyacrylamide backbone and different substitution monomer groups. All macromolecules behave as flexible coils in solution. The parameters investigated were: Molecular weight (between 6 and 20x106)Nature of substitution group (Acrylate, ATBS/sulfonate, nVP/Vinyl-Pyrrolidone)Salinity Polymer shear degradation increases with molecular weight and salinity, but decreases with the presence of Acrylate, ATBS and nVP. All results can be interpreted in terms of chain flexibility. The highly flexible polyacrylamide homopolymer is the most sensitive to shear degradation. Introduction of acrylate groups in the polymer chain induces some stability because of the rigidity provided by charge repulsion, which vanishes in the presence of high salinity (due to the screening of acrylate negative charges). ATBS and VP groups, which are larger in size, provide significant chain rigidity thus better shear stability. It is also shown that some very-high molecular-weight polymers, after passing the shearing device, attain a final viscosity lower than lower-molecular-weight products with the same chemical composition. This factor has to be taken into account in the final choice of a polymer for a given field application. As a comparison, although less popular today than two decades ago, xanthan gum, which behaves like a semi-rigid rod, is shown to be much less sensitive to the shear degradation test than the coiled polyacrylamides.

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This work investigates the possibility of injecting dilute aqueous solutions of novel surfactants into the Yibal field (Sultanate of Oman). This was accomplished through an experimental protocol based on the following criteria: (i) compatibility of the surfactants with the high-saline reservoir water (~200 g/L); (ii) low interfacial tension (IFT) between crude oil and reservoir water (less than 10 -2 mN m -1 ); and (iii) maintaining the low IFT behavior during the entire surfactant flooding. Novel surfactants selected in this study consist of a series of ether sulfonates and an amphoteric surfactant (6-105). These surfactants were found to be compatible with reservoir water up to 0.1% surfactant concentration, whereas 6-105 and 7-58 showed compatibility within the full range of surfactant concentration investigated (0.001-0.5%). All surfactant systems displayed dynamic IFT behavior, in which ultralow transient minima were observed in the range 10 -4 -10 -3 mN m -1 , followed by an increase in the IFT to equilibrium values in the range 10 -3 -10 -1 mN m -1 . The results also showed that with respect to concentration (0.05-0.5 %) and temperature (45-80°C), AES-205 and 7-58 surfactants exhibit a wide range of applicability, with the IFT remaining below 10 -2 mN m -1 , as required for substantial residual oil recovery. In addition, ultralow IFT were obtained at surfactant concentrations as low as 0.001%, making the use of these surfactants in enhanced oil recovery extremely cost-effective.Paper no. S1524 in JSD 9, 287-293 (Qtr. 3, 2006). KEY WORDS: Compatibility, dynamic interfacial tension, surfactants, ultralow transient interfacial tension.Approximately 60% of the original oil in place (OOIP) will remain in an average oil reservoir after primary and secondary (water flooding in most cases) production. The residual oil is trapped in the reservoir pore structures by capillary forces and cannot be recovered by conventional means. Among the non-conventional techniques (known as enhanced oil recovery [EOR]) used to enhance oil production, surfactant flooding is one of the most appealing methods to enhance oil recovery from depleted reservoirs. In this technique, surfactants are added to the oil/water system to reduce the interfacial tension (IFT) from about 20-30 mN m -1 to less than 10 -2 mN m -1 (1,2). This seems to be a very simple method for recovering residual oil from reservoirs. However, from a technical point of view, there are some adverse conditions that prevent this technique from being successful in the field. The environment of an oil reservoir is often such that surfactants cannot generate this considerable reduction in surface tension as simply as described. One crucial aspect is that the water in these reservoirs is very salty (up to 200 g/L)-salinities above the solubility limits of most conventional surfactants used in EOR. Clearly, the compatibility of surfactants with reservoir brine is essential to avoid plugging of the porous medium, especially in reservoirs of low permeability. The other importa...

The modification of the surface wetting characteristics in fractured oil-wet carbonate reservoirs, by reversing wettability from oil-wet to water-wet, leads to improved oil recovery. However, in order to obtain a successful oil recovery process, it is crucial to understand the active mechanisms of wettability alteration. This study looks at the effect of sulfate ions as one of the most promising wettability influencing ions on the wetting properties of oil-wet calcite; the effect is studied both with and without the presence of cationic surfactant and possible mechanisms of wettability alteration are explored. A number of analytical techniques were utilized to analyze the mineral surface before and after treatment. The study presents a thorough discussion of the influence of sulfate ions in displacing adsorbed carboxylate from the oil-wet surface, both with and without the presence of cationic surfactant are discussed thoroughly. The interaction between sulfate ions and the calcium ions attached to carboxylate groups on the surface is believed to be the main active mechanism of wettability alteration at high concentration of sulfate ions. Ion-exchange between the hydroxide group and the adsorbed stearate ion on the calcite surface is shown to act as a supplementary mechanism that desorbs stearate ions from the surface. In the treatment of an aged calcite surface with sulfate ions, a combination of these two mechanisms resulted in a more water-wet surface. The copresence of sulfate ions and cationic surfactant resulted in a further reduction in the amount of adsorbed carboxylate on the surface. This can be attributed to the release of adsorbed carboxylate groups on the surface through ion pair formation with the cationic surfactant. The desorption of negatively charged carboxylate groups from the surface facilitates the approach of negatively charged sulfate ions to the aged calcite surface. It can therefore be concluded that sulfate ions accompanied by cationic surfactant molecules can alter the wetting properties toward water-wet state more effectively than sulfate ions alone.

Yibal oil reservoir, a fractured carbonate formation located in the north of Oman and characterized by high salinity brine and high temperatures, is a potential candidate for enhanced oil recovery (EOR) projects. This experimental study focused on the possibility to use surfactant injection as an EOR process in the Yiabl field. On the basis of the results from our previous investigations, ethoxylated sulfonates and amphoteric surfactants were used in this study. Selected surfactants showed a great tolerance to high salinity and temperatures. All surfactant systems displayed dynamic interfacial tension (IFT) behavior, in which transient ultra-low IFTs were detected. Dilute surfactant solutions (0.1 wt %) were considered for core-flooding tests on limestone plugs. In one set of experiments, surfactant solutions were injected into a fully water-flooded core (surfactant tertiary recovery). In another set, surfactant solutions were injected without pre-water-flooding (surfactant-modified water-flooding or surfactant secondary recovery). Results of tertiary recovery were found to be between 1 and 7% of original oil in place (OOIP), which correspond to 6 and 24% of residual oil in place (percentage based on the remaining oil in place after water-flooding). Tertiary surfactant injection therefore appears to be an attractive option for pre-water-flooded zones for additional oil recovery. In the other hand, results of secondary recovery for some surfactants showed significant oil recovery compared to water-flooding, whereas for other surfactants, water-flooding was more effective. Secondary surfactant recovery resulted in faster rate recovery as compared to water-flooding. Thus, minimum pore volume (PV) injected at ultimate oil recovery for 7-58 surfactant was found to be significantly lower (2.3 PV) than the corresponding PV in water-flooding (9.1 PV).