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Pore-Scale Investigation of Low-Salinity Nanofluids on Wetting Properties of Oil Carbonate Reservoir Rocks Studied by X-ray Micro-Tomography

Pore-Scale Investigation of Low-Salinity Nanofluids on Wetting Properties of Oil Carbonate Reservoir Rocks Studied by X-ray Micro-Tomography

3.1. Effect of Nanoparticles and Different Surfactants on the IFT of Water–Oil System

The IFT reduction between oil and brine is one of the main mechanisms of surfactant flooding. Low IFT values help to improve oil recovery due to the increased capillary number. Therefore, it is important to study the ability of surfactants to reduce IFT at harsh reservoir conditions and to choose an optimal concentration, at which the minimum IFT can be achieved.

Therefore, before testing the effect of nanoparticles on the surfactants’ ability to reduce IFT, it is important to find the optimal surfactant concentration. For this purpose, the influence of surfactants (CTAB, SDS, and AOS) with different concentrations on oil–brine IFT was studied. The dependence of interfacial tension values of aqueous surfactant solutions on surfactant concentrations is shown in Figure 4. The concentration at which surfactants have minimum IFT values is known as the critical micelle concentration (CMC). The graphs show that the CMC values were 0.01 wt.% for CTAB, 0.1 wt.% for SDS, and 0.06 wt.% for AOS. The corresponding interfacial tension values at these surfactant concentrations were 0.74 ± 0.06 mN/m, 0.54 ± 0.04 mN/m, and 1.4 ± 0.12 mN/m, respectively. However, taking into account possible surfactant adsorption onto carbonate rocks, concentrations of 0.05 wt.% CTAB, 0.1 wt.% SDS, and 0.1 wt.% AOS were used in further experiments. Note that the IFT values at these concentrations were higher than at the CMC point, but were still low (~2 mN/m).
Then, in order to study the effect of nanoparticles, various concentrations of silica nanoparticles were added to the surfactant solutions with optimal concentrations. The following five concentrations of silica nanoparticles were chosen for the study: 0.005 wt.%, 0.01 wt.%, 0.025 wt.%, 0.05 wt.%, and 0.1 wt.%. The CTAB solutions with the addition of 0.025 wt.%, 0.05 wt.%, and 0.1 wt.% SiO2 resulted in the precipitation of nanoparticles. Furthermore, the addition of only 1 wt.% of NaCl to 0.05 wt.% CTAB with 0.005 wt.% and 0.01 wt.% SiO2 also led to precipitation, and thus CTAB surfactant was not used in further experiments. Importantly, the addition of SiO2 showed better stability with anionic surfactants than with the cationic ones. Figure 5 shows that all SDS solutions were transparent upon the addition of nanoparticles in the whole range of studied concentrations after 14 days at 70 °C. The influence of different NP concentrations on IFT values of 0.1 wt.% SDS without and with 1 wt.% NaCl is shown in Figure 6.
Figure 6 shows that the interfacial tension values of SDS increased upon the addition of nanoparticles but remained almost unaffected in the presence of 1 wt.% NaCl. The increase in the IFT values of surfactant with nanoparticles can be attributed to several reasons. First, nanoparticles can reach the interface between oil and brine, and thus block surfactant molecules from approaching it, resulting in higher IFT values. Second, nanoparticles can interact with surfactant molecules, and thus less surfactant can adsorb at the interface and reduce IFT. However, it should be pointed out that the IFT of nano-surfactant dispersions is still less than the IFT of brine–oil without surfactant (Figure 4).
Although the addition of 1 wt.% NaCl had an insignificant influence on the IFT of nano-surfactant dispersions, the addition of LSW (Table 1) led to the high instability of dispersion. The resulting solution precipitated almost immediately after preparation (Figure 5b). Therefore, it was decided not to use SDS surfactant in further experiments. These results show the importance of testing surfactant or nano-surfactant dispersions under reservoir conditions and screening their properties at different salinities to avoid precipitation and negative synergism. Notably, the AOS surfactant showed better stability in the LSW than the CTAB and SDS. Moreover, upon the addition of salts with concentrations corresponding to LSW, the IFT of 0.1 wt.% AOS reduced from 2.6 mN/m (Figure 4c) to 0.12 mN/m (Figure 7).
In Figure 7, the influence of different concentrations of nanoparticles on the IFT of 0.1 wt.% AOS with LSW is presented. As demonstrated, the addition of nanoparticles showed an insignificant effect on IFT in comparison with the addition of salts (NaCl, MgCl2, CaCl2, and Na2SO4), illustrating that salt ions have a more pronounced influence on IFT than NPs. The same results were obtained in other works [20,33], where the IFT of surfactants was studied with the addition of different nanoparticle concentrations. The authors [33] stated that the CMC of SDS was strongly influenced by salt concentrations, while the CMC was only slightly affected by SiO2 nanoparticles. Moreover, the authors reported that the synergism of IFT reduction of surfactants and NPs can be achieved at particular NP concentrations that are usually small and do not exceed 0.1–0.3 wt.%. However, reservoir brine consists of high salt concentrations, and thus the influence of salt ions on nanofluids should be tested in order to realistically mimic the nanofluids’ behavior under reservoir conditions.

Afterwards, 0.1 wt.% AOS in LSW with different nanoparticle concentrations were tested for thermal stability at 70 °C (reservoir temperature) for at least 14 days. Thermal stability results showed that dispersions with only 0.005 wt.% and 0.01 wt.% SiO2 were the most stable among others (no precipitation occurred). Therefore, for further core-flooding and μCT experiments, AOS surfactant was chosen with a concentration of 0.1 wt.% in a mixture with 0.005 wt.% SiO2 nanoparticles in LSW.

3.2. Investigation of the Effect of Different Fluids on Wettability Using X-ray Micro-Tomography

LSW and nanoparticles have been regarded as promising wettability modifiers of rock surfaces [29,30,34]. Therefore, in this work, we studied and compared the effect of different fluids, including just LSW, surfactant with LSW, and surfactant nanofluids with LSW, on the wetting properties of oil-saturated carbonate rocks. It should be noted that the composition of LSW was the same in all experiments.
For this purpose, the rock sample was first saturated with oil and reservoir brine (see the methods section) to create the residual oil and water saturation. Afterwards, the rock sample was consequently flooded with low-salinity water with 0.1 wt.% AOS and 0.1 wt.% AOS in a mixture with 0.005 wt.% SiO2 (Table 1). Such a flooding design was applied in order to study the impact of each chemical on the wetting properties of carbonates. Moreover, an application of μCT allowed the three-phase contact angle change on a pore-level to be studied after each flooding process.
Examples of μCT images of the sample’s slices after different core flooding tests are presented in Figure 8. In order to visualize and study the dynamics of wettability alteration, the same sample’s parts were analyzed. The images were processed and contrasted to define the phases. The darkest phase is the non-wetting phase (brine), the intermediate phase is the wetting phase (oil), and the brightest phase is the solid (rock surface). In Figure 8a,c, the oil trapped in the pore throat can be seen after filtration with brine and LSW with the strong hydrophobic properties of surfaces. However, after filtration with 0.1 wt.% AOS in LSW and 0.1 wt.% AOS with 0.005 wt.% SiO2 in LSW, the trapped oil was fully removed from the pore throats (Figure 8e,g). By comparing the stages of filtration, it can be noticed that, at the final stage of filtration (surfactant nanofluid in LSW), the non-wetting phase (water) further spread over the rock surface (Figure 8h), which could be the result of wettability alternations towards more water-wet states. As such, after surfactant and surfactant nanofluid flooding, carbonate pore surfaces became more prone to a hydrophilic wetting state, illustrating the significant change in water contact angles and the displacement of oil droplets. The surfactant ability to initiate wettability alternations from oil-wet states to water-wet states is well known [19,21] and is described by means of surfactant adsorption onto rock surfaces covered by hydrocarbons. Importantly, depending on the surfactant ionic type, the mechanism of wettability alterations will be different. In this study, we used AOS, which is a strong anionic surfactant with a liner alkyl tail and an anionic sulfonate headgroup, with a sodium ion as a counterion. Therefore, such surfactant will tend to adsorb on hydrocarbons via hydrophobic interactions rather than electrostatic ones. This occurs due to the electrostatic repulsion between the same negative charge in the surfactant headgroups and adsorbed polar oil components on carbonate surfaces. As such, it is energetically favorable for surfactant molecules to interact by weak hydrophobic bonding with hydrocarbons, thereby leaving the hydrophilic groups on top, which contribute to hydrophilic surface wettability. When hydrophobic interaction is more than the binding force, the polar oil components desorb from the surface, rendering it more water-wet.
When nanoparticles are introduced to the system, the change in contact angle is more pronounced than when only the surfactant is used. This can be attributed to the disjoining pressure buildup in the wedge film between the oil and rock surface [35,36]. This phenomenon stems from the fact that nanoparticles tend to order inside the confined geometry of the wedge as it increases the entropy of the dispersion (more freedom to nanoparticles in the bulk). Thus, the spreading of nanoparticle films on surfaces is driven by the structural disjoining pressure gradient directed towards the wedge from the bulk solution. This results in the oil droplet becoming detached from the surface and instigates water-wet changes in the wetting state. In a mixture with the surfactant, this effect is more pronounced as nanoparticles form aggregates with surfactant molecules that further facilitate the detachment process of hydrocarbons from the surfaces by the structural disjoining pressure phenomenon.
This can be further supported by the three-phase contact angle calculations, for which ImageJ software was utilized (Figure 9). The changes in contact angles indicated that the rock sample from strongly oil-wet states (144°) became more water-wet (49°) through the flooding stages. It is noteworthy that almost all the oil was displaced from porous media with only a few droplets left after the surfactant nanofluid with LSW. Moreover, as can be noticed, the water shape significantly changed, illustrating a more prolonged form (Figure 9).

Furthermore, it can be concluded that LSW had an insignificant influence on the wettability of carbonate rock, which still exhibited strong hydrophobic properties after LSW flooding. This can be attributed to the fact that the ionic strength of LSW was not suitable in this case to expand the electrical double layer, and thus to increase the electrostatic repulsion between charged polar oil components and the surface, which in turn could facilitate the detachment process of oil.

However, after the addition of 0.1 wt.% AOS to LSW, the effect became more pronounced, resulting in a contact angle reduction of up to 79°. Moreover, the inclusion of only 0.005 wt.% SiO2 to surfactant solution with LSW further decreased the contact angle of carbonate surface to 49°, indicating that nanoparticles can aid in the wettability alteration towards a more hydrophilic state. This observation illustrates that if the type and concentrations of chemicals are accurately selected, it is possible to achieve a positive synergizing effect.

Although the adsorption measurements were not conducted in this work, a quantitative evaluation was performed. For this purpose, the fluids after filtration were collected to measure the IFT. As such, it was suggested that an increase in IFT values after filtration illustrates that some surfactant molecules were adsorbed onto surfaces, and a fewer number of them approached the interface. The results are presented in Table 3. As demonstrated (Table 3), both the IFT values of brine and LSW slightly decreased in comparison with the results before filtration up to 20% and 30%, respectively. It is also interesting to point out that the IFT of 0.1 wt.% AOS significantly increased from 0.15 mN/m to 1.15 mN/m after filtration. This can be attributed to the adsorption of surfactant onto rock surfaces and its uncontrollable and unfavorable loss during flooding. Meanwhile, the IFT of 0.1 wt.% AOS and 0.005 wt.% SiO2 in LSW changed from 0.14 mN/m to 0.46 mN/m, which is much less than for just surfactant. This observation suggests that nanoparticles can serve as sacrificial agents to prevent surfactant adsorption.

It should be pointed out that the application of nanoparticles in chemical EOR can be limited by nanoparticle precipitation, which in turn reduces the stability of the dispersion. This can result in pore blockage during flooding and thus lead to formation damage. In order to avoid this, the optimal concentration of nanoparticles in surfactant dispersion at which the solution will be stable under reservoir conditions should be determined.

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