1. Introduction
In the exploration of the efficacy of low-salinity waterflooding/smart waterflooding (LSWF/SWF), various studies have yielded mixed results. For instance, Y. Zhang and Morrow found that, in oil/sandstone media, there was no significant increase in recovery factors during secondary recovery (secondary recovery in this research is associated with LSWF/SWF used as an alternative to conventional waterflooding) [
1]. However, in the tertiary mode (tertiary mode or tertiary recovery in the literature refers to LSWF/SWF injection after conventional waterflooding), they observed a notable 6% increase in the original oil-in-place (OOIP) recovery for the same combination. On the other hand, Rivet et al. reported an increase in oil recovery during secondary recovery operations in weak water-wet systems. However, when it came to tertiary low-salinity injection, they did not observe any significant increase in recovery [
2].
Different mechanisms have been suggested to explain the incremental recovery of oil by LSWF/SWF. Rock et al. identified up to 15 distinct mechanisms, particularly those involving the interplay between rock and fluid. The top three mechanisms, highlighted in descending order, were wettability alteration, multi-ion exchange (MIE), and fine migration. Furthermore, they acknowledged other mechanisms involved in the interaction between brine and oil. These included reductions in interfacial tension (IFT), enhancements in the elasticity of the interface, and the generation of microemulsions [
3].
Based on different observations, the main controlling mechanism of oil recovery when adjusting the water composition/salinity is wettability alteration, which is attributed to electric interactions between the rock and negatively charged oil components. Repulsion is induced by LSWF, because the injected ions may affect the bonding between the oil and rock and detach oil droplets from the surface [
4,
5]. Other mechanisms such as fluid flow diversion were also reported. Nguyen et al. reported that fines migration occurs in two scenarios: an inadequate total cation concentration or an inadequate percentage of divalent cations. These lead to the blocking of pore throats by the released clay particles, diverting water flow into non-swept pores [
6].
Fluid/fluid mechanisms were also observed to be effective during LSWF/SWF. For example, IFT affects the capillary pressure and electric charge at the brine/oil interface, which results in additional oil recovery during LSWF. Takeya et al. showed that the electric charge of the brine/oil interface is affected by the presence of excessive ions at the oil/brine interphase. Hence, viscoelasticity is an important capacity of the fluid/fluid interphase, allowing it to become more rigid, which results in fluid continuity through the small pore [
7]. Viscoelasticity avoids the snap-off and the separation of a fluid droplet when moving through a reduced channel [
8]. An alteration in viscoelasticity is also reported as a possible fluid/fluid mechanism that affects oil recovery by LSWF/SWF. Salehpour et al. showed that microemulsions induced changes in the local waterfront, pointing to areas with higher oil saturation [
9]. Tagavifar et al. proposed that micro-dispersions were formed and segregated and settled at the bottom of isolated oil ganglia. This did not result in any redistribution of fluids or additional oil recovery. However, in slightly oil-wet pores, this was observed and attributed to the release of surface-active components from the oil/water interface [
10].
LSWF/SWF is often highlighted as a significant technique for enhancing oil recovery in scenarios where rocks are oil-wet, such as carbonate formations. However, there is also supporting evidence of the effectiveness of this method in sandstone formations. For instance, Patil et al. demonstrated that LSWF led to a decrease in residual oil saturation in sandstones [
11]. The study also noted a minor improvement in the Amott–Harvey wettability index, indicating increased water-wetness, particularly in cores that had been exposed to oil for longer periods. In another study, Law et al. explored the application of LSWF in the Forties Sandstone Reservoir through simulations. They found that LSWF consistently enhanced oil recovery across various scenarios, with increases ranging from 2.3% to 4.2%, largely dependent on oil viscosity [
12]. Nasralla et al. conducted experiments on Berea sandstone cores and observed that using LSWF/SWF in a secondary recovery mode (applied after primary recovery but before any other enhanced recovery methods) significantly boosted oil recovery compared to injections of high-salinity brines, regardless of the oil’s composition. However, the same approach did not improve oil recovery when used in a tertiary mode (applied after secondary recovery methods), although it was effective in the secondary mode [
13].
In Berea sandstones, there is consensus among researchers that the impact of wettability alterations on oil recovery is relatively limited. For instance, Romero et al. observed incremental oil production during low-salinity water injections, with all significant changes in production, pressure, and pH happening after 2–3 pore volumes (PVs) of injection. They also concluded that a reduction in permeability is not the main driver of increased oil recovery in the context of LSWF/SWF [
14]. Further research by Garcia-Olvera, Alvarado, and Mohamed and Alvarado supports the idea that wettability alteration, by itself, is unlikely to fully explain the mechanisms enhancing oil recovery. They suggest that when there are no oil components on the surface, additional oil recovery is mainly due to the interactions between the oil and the injected brine [
15,
16]. Smith et al. discovered that, in Berea sandstones, optimal interactions between fluids are reduced by confinement effects under different wetting conditions. According to their findings, the mechanisms driving this response are not linked to changes in the rock surface but are primarily associated with fluid/fluid interactions [
17]. The absence of a universal explanation for the LSWF/SWF effect may be due to differences in rock/fluid types. In addition, the complex interactions between minerals, crude oils, and water phases make it challenging to find a one-size-fits-all mechanism for this effect. The varying success of LSWF/SWF under different circumstances suggests the involvement of multiple mechanisms.
Rock/fluid mechanisms are active under special conditions. For example, wettability alteration is effective when the initial wettability is more oil-wet, so alteration to a less oil-wet condition can detach the oil, as reported by Al-Nofli et al. [
18]. Flow diversion occurs when fines migrate, which is a function of the injected water salinity and critical salt concentration (CSC). In some cases, rock/fluid mechanisms are not dominant. In this work, we question whether it is possible to design an LSWF/SWF that could be beneficial even for a water-wet case or even recover oil without mechanisms like a wettability alteration or fines migration. If we can define the criteria for oil and injected low-salinity brine that activate fluid/fluid interactions, LSWF/SWF may still be beneficial, even in cases where rock/fluid mechanisms are weak. Hence, the main goal of this research is to determine whether optimizing the ionic composition of water can enhance the RF through fluid/fluid interactions and whether this enhancement can rival the impact of traditional rock/fluid mechanisms. Previous studies have primarily focused on individual mechanisms such as wettability alterations, fines-assisted oil recovery, and fluid/fluid interactions. However, in real reservoir conditions, these mechanisms often interact, and their interplay is influenced by the salinity of the injected brine. By examining the combined influence of these mechanisms, this study provides a more comprehensive understanding of the complexities involved in LSWF/SWF processes.
The objective of this study is to assess the impact of optimized brine compositions on oil displacement and quantify the influence of fluid/fluid interactions during LSWF in sandstones, comparing the effect of multiple interactions under multiple composition and wettability state scenarios. During tests conducted in our previous research, Villero-Mandon et al. [
19], changes in salinity led to an improved interface between the oil and brine, an improvement between 40 and 70% in the elastic modulus, a 1 mN/m reduction in IFT for every 1000 ppm reduction in the brine salinity, and an improvement in the micro-dispersions of the oil phase. To achieve this, we conducted coreflooding experiments for oil-wet/water-wet sandstones, above and below the CSC, and in the presence and absence of dominant ions to activate fluid/fluid interactions. Based on the observations of Bidhendi et al., Chai et al., and Mohamed and Alvarado [
16,
20,
21], the initiation of fine migration depends on the CSC. Below the CSC, fines deposition occurs, resulting in fines migration, as shown by Nguyen et al. and Tang and Morrow [
6,
22]. The primary objective is to assess how the varied behaviors within these areas impact the efficiency of LSWF/SWF.
3. Results and Discussion
Figure 2 shows the results of a coreflooding experiment using brine 1 in a water-wet scenario (i.e., the core 1 case). Initially, we observed a stable pressure drop, with insignificant variations. The RF after HSWF (High-Salinity Waterflooding) increased by 6.1%, indicating improved oil recovery. However, above the CSC yielded a 5.2% increase, while below the CSC only yielded an additional 0.9%, aligning with the general findings reported in the literature regarding Berea sandstone [
13]. On average, the pressure drop above the CSC was approximately 1.8 psi, while below the CSC the value slightly increased to around 1.85 psi, which shows a possible blockage due to fines migration.
Figure 3 shows the results of the coreflooding experiment using brine 1 in the oil-wet scenario (i.e., the core 2 case). Initially, the pressure behavior is more unpredictable compared to the same brine injection in a water-wet scenario. With increasing oil-wetness, the pressure drop during WF becomes lower because of the likely channeling of the injected water. The RF after WF increased by 9%, indicating improved oil recovery. Above the CSC yielded a 5.0% increase, while below the CSC the recovery yielded an additional 4%. On average, the pressure drop before reaching the CSC was approximately 1.1 psi, while below the CSC a sharp increase in pressure drop was observed, most likely due to the migration of fines. Below the CSC a clear peak in pressure at 13 PV is observed, which could be due to fines migration and blockage, and then a reduction, which could be an indication of fines displacement.
Figure 3 shows the combination of a wettability alteration that reduces and fines migration that increases the pressure drop. Our observation proved that wettability alteration is the stronger mechanism.
Figure 4 shows the results of the coreflooding experiment using brine 2 in the water-wet scenario. The observed pressure drop was much higher than that in case 1, which is due to the improvement of the interface and the generation of microemulsions. This finding shows that, by adjusting the injected water’s composition, fluid/fluid mechanisms were activated. On average, the pressure drop before reaching the CSC was approximately 6.8 psi, while, below the CSC, the value slightly increased to about 8.5 psi. The results indicate that a combination of fine migration and microemulsions was observed as the pressure response increased. Above the CSC yielded a 5.8% increase while below the CSC the recovery yielded an additional 1.1%.
Figure 5 shows the performance of the recovery factor throughout the EOR stage across all scenarios. As can be seen from
Figure 5, the oil-wet case shows the highest RF, which proves that rock/fluid mechanisms such as wettability alteration are strong and effective. Following wettability alteration, brine 2 ranks second, demonstrating that optimizing the brine composition strengthens fluid/fluid mechanisms, yielding marginally improved results. Previous findings by Villero-Mandon et al. (2024) [
19] highlight brine 2’s superior IFT and microemulsion ratio compared to brine 1, which could be the main reason behind the difference in recoveries.
Below the CSC, in the oil-wet case, the higher recovery is attributed to the combination of a fluid diversion and wettability alteration, which boosts the recovery factor post-waterflooding. For water-wet cases, only a minor increase in oil recovery was observed below the CSC, possibly attributable to fluid diversion, albeit weaker compared to the effects of the wettability alteration.
Table 7 provides a detailed breakdown of the results of the coreflooding experiments, which are categorized into two distinct zones. These results show the RF achieved through coreflooding. The data show that rock/fluid mechanisms such as wettability alterations could be effective and can enhance oil recovery even with the injection of brine 1, where fluid/fluid interactions are less effective. In scenarios where the rock is water-wet, the injection of brine 2, an optimized brine, results in a higher recovery factor, attributed to stronger fluid/fluid interactions.
Figure 6 shows the comparison between pressure drops along the core during the EOR stage for all scenarios. The higher pressure drop of brine 2 is due to the formation of micro-dispersions, which is a proof of the activation of fluid/fluid interactions. The reduction in pressure drop for the oil-wet case could be evidence of a wettability alteration to a more water-wet state. The increase in pressure drop due to fines migration/fluid diversion below the CSC is small, which can be observed in the water-wet case (brine 1), where wettability alterations and micro-dispersion development did not occur. Smith et al. (2022) also showed that the impact of fines migration is minimal.
As mentioned, a dispersion of oil in brine was observed during the injection of brine 2.
Figure 7 presents the recovered oil/brine in this case, which shows that the oil phase becomes more dispersed into the water phase, which is also an indication of fluid/fluid mechanisms’ activation.
During LSWF, due to fluid/fluid interactions and fluid diversion, mobility changes. For water-wet cases, where wettability alteration is absent, MRF values were measured as shown in
Table 8. Theoretically, the observed MRF is mostly due to fluid/fluid interactions above the CSC and a combination of both mentioned mechanisms below the CSC. By injecting the optimized brine, the interface exhibits increased stability and resistance. This aligns with findings from Kakati et al. [
27], who noted that, in high-paraffin-content oil and high-sulfate-content brine, the interface is more stable. For both cases, below the CSC, MRF values became higher, most likely due to pore blockage. Hence, through an appropriate design and activating fluid/fluid interactions, even for a water-wet formation, there is a potential to enhance oil recovery by LSWF through a combination of fines migration and fluid/fluid interaction mechanisms. This was also observed in Berea sandstone cores by Thyne and Gamage [
28]. In Gray Berea Sandstones with less than 15% clay content, fines migration is considered a secondary mechanism, especially in tertiary recovery phases. Thus, the increase in ΔP can be primarily attributed to fluid/fluid interactions in water-wet formations.