Importance of Fluid/Fluid Interactions in Enhancing Oil Recovery by Optimizing Low-Salinity Waterflooding in Sandstones

Abstract

Low-salinity waterflooding/smart waterflooding (LSWF/SWF) is a technique involving the injection of water with a modified composition to alter the equilibrium between rock and fluids within porous media to enhance oil recovery. This approach offers significant advantages, including environmental friendliness and economic efficiency. Rock/fluid mechanisms such as wettability alteration and fines migration and fluid/fluid mechanisms such as a change in interfacial tension and viscoelasticity are considered active mechanisms during LSWF/SWF. In this study, we evaluated the effect of these mechanisms, by LSWF/SWF, on sandstones. To investigate the dominant mechanisms, coreflooding studies were performed using different injected fluid composition/salinity and wettability states. A comparative analysis of the recovery and mobility reduction factor was performed to clarify the conditions at which fluid/fluid mechanisms are also effective. Our studies showed that wettability alteration is the most dominant mechanism during LSWF/SWF, but, for weak oil-wet cases, optimizing brine compositions may activate fluid/fluid mechanisms. Brine composition significantly influences interface stability and performance, with sulfate content playing a crucial role in enhancing interface properties. This was observed via mobility behavior. A comparative analysis of pressure differentials showed that fines migration may act as a secondary mechanism and not a dominant one. This study highlights the importance of tailored brine compositions in maximizing oil recovery and emphasizes the complex interplay between rock and fluid properties in enhanced oil recovery strategies.

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.

2. Materials and Methods

2.1. Fluids and Rock

This study’s materials include oil samples, brine, and chemicals. Details are discussed in this section. The first question is the brine/oil criteria that enhance fluid/fluid mechanisms such as interfacial tension (IFT), reduction, viscoelasticity, and the formation of micro-dispersions. The details of experiments conducted to answer this question are published in our previous research; Villero-Mandon et al. conducted experiments to explore the mechanisms behind fluid/fluid interactions and the performance of LSWF/SWF at different salinity levels. IFT, the formation of micro-dispersions, and rheological properties were evaluated during the injection of ten different brines, each with specific ionic compositions and salinities of 7500 ppm and 5000 ppm [19]. A significant finding was the role of their asphaltene content, where concentrations between 1.5% and 3% yielded the most favorable outcomes during the screening process [19]. Hence, for this research, a crude oil with high paraffinic and asphaltene content from a field in the west of Kazakhstan was selected. The oil has a low TAN (Total Acid Number), 0.08 mg KOH/g. The viscosimeter SVM 3000 from Anton Paar (Graz, Austria) was used for measuring viscosity and density, as shown in

Table 1. Oil characteristics at 63 °C.

Oil	Density (g/cc)	Kinematic Viscosity (cst)	Dynamic Viscosity (cP)
oil sample	0.8225	11.4	9.41

.

The key ionic components are the concentration of monovalents (Na⁺), divalents (Mg²⁺), and sulfates (SO₄²). Higher concentrations of divalent ions, such as (Mg²⁺), and sulfates in the brine composition can impact recovery processes. The presence of divalent and sulfate ions enhances the elasticity at the oil/brine interface. Furthermore, although increasing salinity reduced the formation of microemulsions, it did not alter the type of emulsion formed. Based on the screening study presented in our previous paper [19], the best brine was selected to activate fluid/fluid mechanisms as strongly as possible.

Table 2. Brine characterization at reservoir temperature.

		@ 11,500 ppm		@ 8500 ppm		@ 1000 ppm
Type of Brine	Brine Composition	Molarity (M)	Density (g/cc)	Molarity (M)	Density (g/cc)	Molarity (M)	Density (g/cc)
Brine 1	100% NaCl	0.33	1.0038	0.29	1.0028	0.22	1.002
Brine 2	50% Na2SO4, 25% MgCl2 6H2O 25% NaCl	0.57	1.0027	0.53	1.0019	0.47	1.001

shows the composition of the designed LSW brine used in our study. Brine 1 is set to be totally NaCl, as a reference case, where the fluid/fluid interactions are weak. Brine 2 was the optimum brine, with the ions’ composition was adjusted to activate fluid/fluid interactions. To evaluate the effect of different mechanisms on oil recovery by LSWF, different oil displacement experiments were designed. By utilizing the designed brine, initial wettability, and injection design, we assessed whether fluid/fluid interactions under LSWF/SWF had a significant impact and how they compared to other rock/fluid mechanisms. The injected brines’ molarity and density are in Table 2. It is relevant to clarify that the screening results allowed us to select brine 2; however, to visualize the effects of the LSWF/SWF over the core distance, the CSC is required, which is the reason why the salinity levels presented. Molarity values are calculated by the methods proposed by Harvey and IUPAC [23,24], while density values are measured by a viscosimeter SVM 3000 from Anton Paar.

Moreover, formation water (FW) is used for saturating the cores in the first moment to simulate reservoir conditions. This brine, with a total salinity of 182,980 ppm and a density of 1.15 g/cc at reservoir temperature, provided a high-salinity environment so that the ionic disbalance could have a relevant effect. The composition of the ions in the FW is presented in

Table 3. Formation water’s ionic composition (ppm).

Ions	Concentration (ppm)
Na+, K+	81,600
Ca2+	9540
Mg2+	1470
Cl−	90,370
Total	182,980

. The composition was determined by Shakeel et al. [25].

Three cores, with similar properties, from Gray Berea sandstone were used for coreflooding experiments. The CSC (critical salinity concentration) to initiate fine migration in Gray Berea sandstone was determined by Muneer et al. as 5844 ppm [26]. The main characteristics of the core samples are presented in

Table 4. Cores’ characteristics for coreflooding.

Core	L (cm)	D (cm)	Φ (%)	Kgas (mD)	${\mathbf{S}}_{\mathbf{w}\mathbf{i}}(\%)$
1	7.70	3.80	19.5	339.9	28
2	7.57	3.80	21.8	329.9	35
3	7.50	3.81	21.0	349.9	24

; porosity (Φ) was measured by a Helium Porosimeter from VINCI technologies (Nanterre, France). Its absolute permeability to gas (K_gas) was measured using PoroPerm Prod reference AP-125-004-0, by VINCI technologies. Before coreflooding, cores were saturated in a Manual Saturator with FW for 24 h. Core 3 was aged with the oil sample for the 30 days at 80 degrees and atmospheric pressure; the details are presented in the following section.

2.2. Experiments Methodology

The main procedures include all these processes, equipment, and working mechanisms. This section includes the brine solution’s preparation, the aging of the core, and the coreflooding design.

Accurately prepared LSWF/SWF solutions play a crucial role. The brine preparation process involved the precise mixing of different salts in deionized water. The measured total organic content (TOC) in deionized water was 5000 ppb, guaranteeing the absence of reactive components. The measured resistivity was 18.3 MΩ cm. Homogeneity in the brine preparation was achieved using a magnetic stirrer at a consistent speed of 400 rpm until complete dissolution occurred. Subsequently, the prepared solutions were securely stored in air-tight containers to prevent contact with air and preserve their integrity.

Core 3 was designated as an oil-wet system after establishing initial oil and water saturations; Core 3 was aged in oil at 80 °C for 30 days to change its wettability from a strong water-wet state to an oil-wet one.

Linear coreflooding was conducted on three Gray Berea sandstone cores, as presented. A schematic of the Coreflooding system (CFS) 700 equipment provided by VINCI technologies is shown in Figure 1. The flowing rate was determined to be 0.2 cc/min with a confining pressure of 1000 psi, maintaining the backpressure as atmospheric pressure. Coreflooding was performed at 63° Celsius, which corresponds to reservoir temperature. Cores were fully saturated with FW, and then oil was injected until Swi was achieved, before proceeding with the coreflooding scenarios presented in

Table 5. LSW/SW injection scheme for the coreflooding tests.

Initial Wettability	Core Used	Brine Used	LSW Injection Stage 1	LSW Injection Stage 2	LSW Injection Stage 3
Water-wet	Core 1	Brine 1	11,500 ppm	8500 ppm	1000 ppm
Oil-wet	Core 2	Brine 1	11,500 ppm	8500 ppm	1000 ppm
Water-wet	Core 3	Brine 2	11,500 ppm	8500 ppm	1000 ppm

.

Coreflooding tests were designed to evaluate the effect of different rock/fluid and fluid/fluid mechanisms. For all tests, cores were saturated with FW, and then FW was injected at different rates until pressure stabilized at each rate. The oil was then injected into the cores at different rates until pressure was stabilized and a 100% oil cut was observed. By measuring the produced water volume, the initial water saturation in the cores was calculated using Equation (1). There is a margin of error of 0.01 psi for pressure measurements and 0.2% for the recovery factor, calculated based on the volumes produced in each scenario.

$$S_{wi}=\frac{V_p-V_w}{V_p}\times 100\%$$

(1)

• $V_p$ = Porous volume.
• $V_w$ = Total produced water volume during oil flooding stage.

After these steps, different LSW/SW injection scenarios were conducted, as shown in Table 5. For all cases, the injection rate was set to 0.2 cc/min and the injection was continued until no oil was produced. During the oil displacement stage, the confining pressure was set to 1000 psi. To assess the impact of fluid/fluid mechanisms and compare them with rock/fluid mechanisms, the pressure drop along the core and the recovery factor (RF) at different injection stages were carefully monitored to study the possible fines migration and the formation of microemulsions. The alteration in rheology was also determined through the evaluation of the mobility reduction factor (MRF) parameter, defined in Equation (2), where ${∆P}_{LSWF/SWF}$ is the stabilized delta p of the section and ${∆P}_{WF}$ is the delta p at the end of the waterflooding.

$$MRF=\frac{{∆P}_{LSWF/SWF}}{{∆P}_{WF}}$$

(2)

The scenarios shown in Table 5 were designed to evaluate different mechanisms, as, at each step, one or two mechanisms were more dominant. For example, wettability alteration was expected for the oil-wet core and fine migration was triggered when the injected brine salinity was less than the CSC [26]. To analyze the effectiveness of different mechanisms, we categorized the oil displacement tests based on initial wettability, the CSC, and ion composition, as shown in

Table 6. Likely dominant mechanisms in different injection scenarios.

		Mechanism at Play
Studied Scenarios	Type of Ions	Above CSC (8500 ppm)	Below CSC (1000 ppm)
Water-wet (Core 1)	Brine 1	Fluid/fluid (weak)	Fluid/fluid (weak) + fines migration (strong)
Oil-wet (Core 2)	Brine 1	Fluid/fluid (weak) + wettability alteration (strong)	Fluid/fluid (weak) + wettability alteration (strong) + fines migration (strong)
Water-wet (Core 3)	Brine 2	Fluid/fluid (strong)	Fluid/fluid (strong) + fines migration (strong)

.

By comparing fluid/fluid interactions in water-wet cores at different salinity levels, we gain insights into the relative importance of these interactions compared to rock/fluid interactions. In addition, by examining the differences between oil-wet and water-wet scenarios, we can better understand and quantify the impact of wettability alterations. The injection rate was set to 0.2 cc/min to avoid fines migration by hydrodynamic forces, as studied by Ref. [26].

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. Incremental RFs for all the scenarios.

		RF after WF (%)
Studied Scenarios	Type of Ions	Above CSC	Below CSC
Water-wet	Brine 1	5.2	0.9
Oil-wet	Brine 1	5.0	4.0
Water-wet	Brine 2	5.8	1.1

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. MRFs for both water-wet scenarios.

	MRF
Studied Scenarios	Above CSC	Below CSC
Brine 1	1.14	1.23
Brine 2	1.52	1.88

. 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.

4. Conclusions

In this study, we investigated the mechanisms underlying fluid/fluid interactions and the performance of LSWF/SWF in multiple Berea Sandstone core wettability scenarios across a range of salinity levels, from 1000 to 11,500 ppm. We aimed to measure and compare RFs and MRFs to determine how the fluid/fluid interactions’ effectiveness compared to the rock/fluid interactions’ and how these mechanisms depend on brine composition and salinity. Our primary focus was on assessing the impact of LSWF/SWF on the brine/oil interface and its correlation with the RF and pressure response, exploring potential synergistic mechanisms. The conclusions drawn from the study include the following:

• Wettability alteration was found to be the most effective mechanism, leading to enhanced oil recovery even in cases where fluid/fluid interactions were negligible. For the oil-wet case, 40% recovery was observed, which was more than the 25% recovery in the water-wet state.
• In water-wet cores, optimizing the injection brine to activate fluid/fluid mechanisms led to a high recovery factor due to the enhanced elasticity of the interface and the formation of micro-dispersions. This was confirmed by the change in pressure drop and mobility.
• Fluid diversion due to fines migration is not a strong mechanism during LSWF/SWF and cannot be considered the dominant reason for incremental oil production below the CSC in water-wet sandstones.
• The MRF results indicated that the sulfate content in the brine significantly influenced the stability of the interface by reducing snap-off, which is particularly beneficial for high-paraffin-content oil in sandstones.