Experimental Investigation of Surfactant-Assisted Low-Salinity Brine Flooding in Oil-Wet Carbonate Reservoirs for Enhanced Oil Recovery

Abstract

Low-salinity water flooding (LSWF) has been widely investigated as an enhanced oil recovery (EOR) method for carbonate reservoirs; however, the relative contributions of wettability alteration and oil–brine interfacial tension (IFT) reduction remain poorly understood, particularly under strongly oil-wet conditions. This study systematically investigates the physicochemical mechanisms governing oil recovery during hybrid LSWF–surfactant flooding in oil-wet carbonate systems. Oil-wet Indiana limestone cores were used as representative carbonate reservoir rocks. Seawater and its diluted analogs were employed as base brines and combined with anionic and cationic surfactants at varying concentrations. Zeta potential and pH measurements were conducted to characterize electrostatic interactions at the rock–brine and oil–brine interfaces, while dynamic contact angle and pendant-drop IFT measurements were used to quantify wettability evolution and fluid–fluid interactions. Core flooding experiments were subsequently performed to link interfacial phenomena to macroscopic oil recovery behavior. The results demonstrate that brine dilution induces more negative surface charges at both interfaces, promoting double-layer expansion and electrostatic repulsion, which stabilizes the aqueous film and drives wettability alteration toward a water-wet state. The addition of anionic surfactants further amplifies this effect by increasing surface charge negativity, whereas cationic surfactants preferentially adsorb onto the negatively charged rock surface, limiting wettability alteration despite producing greater IFT reduction. Sulfate ions enhance wettability alteration by facilitating divalent cation interactions with adsorbed oil components; however, excessive sulfate concentrations lead to precipitation-induced flow impairment. Core flooding results reveal that diluted seawater combined with an anionic surfactant yields the highest incremental oil recovery. Our findings conclusively demonstrate that wettability alteration—rather than IFT reduction—is the more dominant recovery mechanism in oil-wet carbonate reservoirs under the investigated conditions. These results provide mechanistic guidance for optimized brine and surfactant design in hybrid LSWF–chemical EOR applications.

1. Introduction

Low-salinity waterflooding (LSWF) has emerged as a promising enhanced oil recovery (EOR) technique for carbonate reservoirs due to its economic attractiveness and relatively low environmental footprint. Carbonate reservoirs are commonly oil-wet or weakly water-wet, which presents significant challenges for conventional waterflooding. In oil-wet (OW) systems, capillary forces oppose spontaneous water imbibition into the rock matrix, resulting in limited oil displacement and poor recovery efficiency. Consequently, altering reservoir wettability toward a less oil-wet state has been widely recognized as a key requirement for improving oil recovery from carbonate formations [1,2,3].

Over the past decades, numerous studies have proposed wettability alteration as the dominant mechanism governing the success of LSWF in carbonate reservoirs. This wettability alteration is commonly attributed to changes in rock–fluid and fluid–fluid interactions induced by variations in brine chemistry. One widely discussed mechanism involves the role of divalent cations, particularly Ca²⁺ and Mg²⁺, which can form electrostatic bridges between negatively charged polar oil components and the positively charged carbonate surface [4]. Dilution of formation water or injected brine reduces the concentration of these potential-determining ions (PDIs), weakening oil–rock bonding and facilitating the release of polar oil compounds from the rock surface [5]. Although this mechanism has been experimentally supported, its effectiveness has been shown to be highly dependent on crude oil composition and mineralogy, leading to inconsistent outcomes across different carbonate systems.

The chemical composition of crude oil plays a fundamental role in determining the effectiveness of LSWF. The presence of polar components such as carboxylic acids, resins, and asphaltenes governs the strength of oil–rock interactions in carbonate formations. Several studies have reported that oils with higher total acid number (TAN) exhibit stronger adsorption onto positively charged carbonate surfaces due to the formation of calcium–carboxylate complexes [6,7]. Conversely, low-acid-number oils may display weaker wettability alteration during brine dilution, as fewer polar species are available for desorption. Moreover, resin-to-asphaltene ratios influence interfacial film stability and emulsion formation, which can impact both wettability alteration and IFT reduction mechanisms. Despite its importance, crude oil chemistry is often treated as a secondary variable in mechanistic LSWF studies, contributing to inconsistent and non-transferable results across different carbonate reservoirs [8].

An alternative explanation for wettability alteration during LSWF is the double-layer expansion (DLE) mechanism. According to this theory, reducing brine salinity increases the thickness of the electrical double layer at both the oil–brine and rock–brine interfaces, enhancing electrostatic repulsion and stabilizing the aqueous film between oil and rock [9,10,11]. The DLE mechanism emphasizes the importance of surface charge behavior, which can be quantified through zeta potential measurements. Identical signs of zeta potential at the oil–brine and brine–rock interfaces promote repulsive forces, favoring water film stability and a shift toward water-wet conditions [12]. However, many zeta potential studies have been conducted under idealized conditions—such as water-wet rocks or oil-free systems—which may not accurately reflect the true electrokinetic behavior of oil-wet carbonate reservoirs. Beyond electrostatic interpretations, several researchers have emphasized the importance of surface complexation and thermodynamic stability of interfacial species during LSWF. Surface complexation models suggest that carbonate minerals, particularly calcite, undergo ion exchange and specific adsorption reactions that modify surface speciation and charge density as a function of brine composition and pH [13,14]. These reactions influence the stability of adsorbed carboxylate species and may alter the free energy of adhesion between oil and rock. In this context, wettability alteration is not solely an electrostatic phenomenon but also a consequence of changes in surface chemical equilibria and mineral–fluid interactions. However, quantitative coupling between surface complexation reactions, zeta potential evolution, and macroscopic oil recovery remains insufficiently validated experimentally, particularly in oil-wet carbonate systems subjected to hybrid chemical flooding [15].

Zeta potential is strongly influenced by brine composition, ionic strength, and pH. Several studies have demonstrated that both rock–brine and oil–brine zeta potentials become more negative with increasing pH [4,16]. Al Mahrouqi et al. [17] suggested that pH evolution during LSWF could be used as an indirect indicator of in situ surface charge modification. Nevertheless, the coupled effects of pH, surface charge, surfactant adsorption, and wettability alteration remain insufficiently understood, particularly in systems involving chemical additives and mixed brine chemistries.

In addition to rock–fluid interactions, fluid–fluid interactions—specifically oil–brine interfacial tension (IFT) reduction—have been proposed as a contributing mechanism for enhanced oil recovery. Emadi and Sohrabi [18] suggested that IFT reduction alone could mobilize trapped oil ganglia, even in the absence of significant wettability alteration. Wang and Alvarado [19] further argued that rock–fluid interactions may inhibit oil recovery in some systems, concluding that fluid–fluid interactions can dominate under certain conditions. Supporting this view, Alshakhs et al. [20] demonstrated that low-salinity water can promote micro-dispersion formation, thereby improving oil mobility. However, these conclusions are largely derived from water-wet or weakly water-wet systems, and their applicability to strongly oil-wet carbonate reservoirs remains uncertain.

From a displacement perspective, the relative importance of wettability alteration and IFT reduction can also be interpreted through capillary number analysis. IFT reduction increases the capillary number (Nc), potentially mobilizing trapped oil by overcoming capillary forces. However, in carbonate reservoirs where initial wettability is typically strongly oil-wet, capillary forces are predominantly adhesive rather than trapping in nature. In such systems, altering the sign and magnitude of capillary pressure through wettability modification may exert a more profound impact on recovery than modest changes in IFT alone. Previous experimental studies have shown that substantial IFT reduction without concurrent wettability alteration does not always result in significant incremental recovery in oil-wet carbonates [21]. This suggests that the relative dominance of IFT versus wettability mechanisms may be strongly wettability-dependent, yet systematic comparative studies remain limited.

Ion-specific effects and detailed brine composition have also been shown to play a critical role in LSWF performance. Beyond total salinity reduction, the relative concentrations of Ca²⁺, Mg²⁺, and SO₄²⁻ ions can significantly influence wettability alteration, surface charge behavior, and oil recovery [22]. Sulfate ions have been reported to enhance wettability alteration through surface complexation and catalytic effects; however, elevated sulfate levels may also promote inorganic scale formation, such as CaSO₄ precipitation, potentially impairing permeability and injectivity. Despite its practical importance, this trade-off has received limited experimental attention in hybrid LSWF–surfactant systems.

Given the inconsistent performance of standalone LSWF, hybrid EOR approaches combining low-salinity water with chemical flooding have gained increasing attention. Surfactant flooding is one of the most widely investigated chemical EOR methods due to its ability to simultaneously reduce oil–water IFT and alter rock wettability [23,24]. However, surfactant performance in carbonate reservoirs is strongly influenced by surfactant charge, brine salinity, and ion composition, which control adsorption, retention, and surface interactions [25]. Many previous studies have focused on either pore-scale physicochemical observations or core-scale recovery experiments in isolation, limiting mechanistic clarity. A major challenge in surfactant-assisted flooding of carbonate reservoirs is the high adsorption and retention of surfactant molecules on positively charged mineral surfaces. Carbonate rocks typically exhibit a positive surface charge at neutral pH, promoting strong electrostatic attraction of anionic surfactants and potentially leading to significant chemical loss [26]. Conversely, cationic surfactants may adsorb preferentially onto negatively charged oil-coated surfaces, limiting their availability at the oil–water interface. Adsorption behavior is further influenced by brine salinity, divalent ion concentration, and pH, which control micelle formation and surfactant aggregation [27]. Despite extensive adsorption studies, the direct linkage between surfactant retention, surface charge evolution, and incremental oil recovery in hybrid low-salinity systems remains insufficiently quantified.

Overall, the literature reveals substantial uncertainty regarding the relative contributions of wettability alteration and IFT reduction in hybrid LSWF–surfactant processes, particularly under oil-wet conditions. The lack of integrated, multi-scale experimental analyses hinders the establishment of direct causal links between surface chemistry, interfacial behavior, and macroscopic oil recovery. The primary objective of this study is to elucidate the dominant mechanisms governing oil recovery during hybrid low-salinity waterflooding (LSWF) and surfactant-assisted EOR in oil-wet carbonate reservoirs. Specifically, this work aims to decouple and systematically evaluate the relative contributions of wettability alteration and oil–brine interfacial tension (IFT) reduction under varying brine salinity, surfactant type, and ion composition. Despite extensive research, significant ambiguity persists regarding the dominant physicochemical mechanisms responsible for enhanced oil recovery during hybrid low-salinity and surfactant-assisted flooding in oil-wet carbonate reservoirs. Many studies investigate either surface charge behavior, contact angle evolution, or IFT reduction independently, without establishing quantitative links to macroscopic displacement efficiency. Furthermore, the combined effects of surfactant charge, brine dilution, sulfate concentration, and pH evolution have rarely been evaluated within a unified experimental framework [28,29]. As a result, the relative contributions of wettability alteration, double-layer expansion, and IFT-driven capillary number increase remain debated. A systematic, multi-scale investigation that integrates electrokinetic characterization with interfacial measurements and core-scale flooding is therefore necessary to resolve these uncertainties.

The scope of our study encompasses a comprehensive experimental investigation using oil-wet Indiana limestone cores as representative carbonate reservoir rocks. Seawater and diluted seawater systems, with and without anionic and cationic surfactant, were employed to examine the effects of salinity reduction, surfactant charge, and surfactant concentration on surface charge behavior, wettability evolution, and fluid–fluid interactions. Zeta potential measurements and pH monitoring were conducted to characterize electrostatic interactions at the rock–oil-brine interfaces, while dynamic contact angle and interfacial tension measurements were used to quantify wettability alteration and IFT reduction, respectively. Core flooding experiments were subsequently performed to directly link these physicochemical observations to macroscopic oil recovery and flow behavior. By integrating pore-scale and core-scale measurements, this study seeks to provide mechanistic clarity regarding the effectiveness of hybrid LSWF–surfactant flooding in oil-wet carbonate systems. The outcomes are intended to offer practical insights for optimizing brine design and surfactant selection, while also addressing key uncertainties and inconsistencies reported in previous studies.

2. Materials and Methods

2.1. Rock Samples

Indiana limestone core samples were employed in this study to represent carbonate reservoir rock for core flooding, zeta potential, and wettability experiments. Core slices with a diameter of 1 in and a thickness of 0.5 in were utilized in contact angle and zeta potentiometric measurements. The zeta potential apparatus (SurPASS 3, Anton Paar GmbH, Graz, Austria) also accommodated core plugs with lengths of up to 10 cm. For core flooding experiments, cylindrical core plugs measuring 12 in in length and 1 in in diameter were prepared. To render the core plugs and slices oil-wet (OW), they were initially cleaned using toluene and xylene via conventional Dean–Stark or Soxhlet extraction techniques. Subsequently, the rock samples were immersed in crude oil for a period of six weeks to achieve complete oil-wetting.

2.2. Crude Oil

Properties of the crude oil used in this study, which is waxy, are given in

Table 1. Properties of the crude oil.

Properties	Value
Specific gravity at 15 °C	0.85
API gravity at 15 °C	36°
Pour Point	33 °C
Wax Appearance Temperature	55 °C
Wax Content (wt.%)	20%
Acid Number (mg KOH)	~0.2
Viscosity at 40 °C	4–8 cP

. The SARA (Saturates Aromatics Resins Asphaltenes) analysis of the crude oil is shown in

Table 2. Sara analysis of the crude oil.

Components	Value (wt.%)
Saturates	66%
Aromatics	27%
Resins	4.8%
Asphaltenes	2.4%
Resin/Asphaltene ratio	2.0

.

The crude oil employed in this study exhibits a relatively low total acid number (TAN ≈ 0.2 mg KOH/g) and modest asphaltene content (2.4 wt.%). In carbonate systems, adsorption of acidic polar components onto positively charged calcite surfaces is frequently invoked to explain oil-wet behavior. Although the measured TAN is low compared to highly acidic crude oils, several studies have demonstrated that even small concentrations of carboxylic acids can significantly influence carbonate wettability due to the strong affinity between negatively charged carboxylate groups and surface calcium ions. Furthermore, prolonged aging under reservoir-like conditions promotes adsorption and surface restructuring, allowing limited polar species to establish stable oil-wet conditions. In addition to acidic components, resins and other polar heteroatomic species may contribute to surface activity and interfacial film formation, influencing wettability independent of TAN alone.

2.3. Brines and Surfactants

Seawater (SW), 10-times diluted seawater (10× dSW), and 100-times diluted seawater (100× dSW) were used as base solutions in combination with cationic and anionic surfactants (Aspiro S 6420 and Aspiro S 8710, respectively) at concentrations of 0.1, 0.5, and 1 wt.% to determine the optimum surfactant concentration for performance evaluation. The surfactants were supplied by BASF Chemical Company (Houston, TX, USA). In this study, the cationic and anionic surfactants are designated as C and A, respectively. In selected experiments, the brines were spiked with sulfate ions at concentrations of 2×S, 4×S, and 6×S (where × corresponds to the baseline concentration of SO₄²⁻). To incorporate SO₄²⁻ without altering the overall brine salinity, the brine salinity was first reduced, followed by the addition of the appropriate amount of Na₂SO₄. Seawater samples were analyzed for ionic composition using ion chromatography, and the results are presented in

Table 3. Ionic concentrations, TDS, and ionic strength of seawater and diluted brines.

Brine Type	Na+ (mg/L)	Cl− (mg/L)	HCO3− (mg/L)	Sr2+ (mg/L)	Mg2+ (mg/L)	Ca2+ (mg/L)	SO42− (mg/L)	Total Dissolved Solids (mg/L)	Ionic Strength (mol/L)
SW	11,638	20,913	857	50	265	1101	1198	36,022	0.65793
10× dSW	1163.8	2091.3	85.7	5	26.5	110.1	119.8	3602.2	0.06579
100× dSW	116.4	209.1	8.6	0.5	2.6	11	11.9	360.2	0.00658
100× dSW + 2× S	127.76	188.2	7.74	0.45	2.34	9.9	23.8	360.19	0.00658

. The ionic concentrations, total dissolved solids (TDS), and ionic strengths of the diluted brines are also summarized in Table 3. The use of undiluted SW was excluded in zeta potential tests, as the zeta potentiometric apparatus is not capable of measuring zeta potential in high-salinity solutions. Properties of the surfactants are visible in

Table 4. Properties of the surfactants used in this study.

Name	Provider	Main Components	Active Content (%)	Density (g/cc) at 20 °C	Chemical Stability	Type
Aspiro S 6420	BASF	Cetyltrimethy lammuniom chloride	29.4	1.11–1.14	Stable	Cationic
Aspiro S 8710	BASF	Ethylenediamine co-surfactants	45.0	1.046	Stable	Anionic

.

2.4. Zeta Potential and pH Measurement

Zeta potential measurements were conducted for various solutions using a SurPASS 3 electro-kinetic analyzer (Anton Paar GmbH, Graz, Austria) at ambient temperature. The surface zeta potential (ζ) of oil-wet (OW) core plugs was determined employing classical streaming potential and streaming current techniques. A detailed description of the apparatus and measurement procedures is provided by Singh et al. 2021 [30], which is briefly explained here: When an aqueous electrolyte is forced through a capillary channel, an electrokinetic response is produced that can be quantified either as a direct current (DC) voltage (streaming potential) or as a DC current (streaming current). The zeta potential (ζ) can be determined from streaming current measurements using the Helmholtz–Smoluchowski (HS) relationship, expressed as:

$$\zeta =\left({\displaystyle \frac{dI}{dp}}\right)\left({\displaystyle \frac{\eta }{\epsilon {\epsilon }_0}}\right)\left({\displaystyle \frac{L}{A}}\right)$$

(1)

where ${\epsilon }_0$ is the vacuum permittivity $(8.85\times {10}^{-12} \mathrm{F}/\mathrm{m})$, $\epsilon$ is the dielectric constant of the bulk electrolyte, $\eta$ is the dynamic viscosity (Pa·s), and $dI/dp$ is the streaming current coupling coefficient. In addition, $L$ represents the length of the slit channel formed between two planar surfaces, and $A$ is the channel cross-sectional area $\left(A=W\times H\right)$, where $W$ is the channel width, and $H$ is the gap height. The ratio $L/A$ corresponds to the flow cell constant.

Alternatively, ζ can be estimated from streaming potential measurements using a modified HS equation:

$$\zeta =\left({\displaystyle \frac{dU}{dp}}\right)\left({\displaystyle \frac{\eta }{\epsilon {\epsilon }_0}}\right)\kappa$$

(2)

where $dU/dp$ is the measured streaming potential coupling coefficient, and $\kappa$ is the electrical conductivity within the channel. Further methodological details are provided by Singh et al. (2021) [30].

Due to the limitations of the electro-kinetic analyzer, only brines with an ionic strength below 0.1 mol/L were selected for analysis [30]. Prior to loading the rock samples into the sample holder, the pH and conductivity probes were calibrated using standard solutions. The pH of each solution was independently measured from zeta potential tests with a different sample holder. During each measurement, the sample holder cylinder was filled with the test solution, allowing simultaneous monitoring of pH and conductivity. To ensure the reliability of the results, all measurements were repeated three times.

2.5. Contact Angle Tests

The sessile drop technique was employed to determine the contact angle (CA) of the OW limestone/crude oil/brine system at ambient temperature. These experiments were designed to evaluate the wettability alteration of the OW calcite rock, which underwent the same aging process as the core flooding experiments. During each measurement, an oil droplet was dispensed from below into a cell containing the desired brine and allowed to adhere to the rock surface. The contact angle was monitored over time to obtain both the initial and equilibrium values. The CA measurement apparatus used in this study is shown in Figure 1.

2.6. Interfacial Tension Measurements

The interfacial tension (IFT) of the crude oil/brine system was determined using the pendant drop technique at ambient temperature. The measurement procedure and apparatus are summarized as follows: as illustrated in Figure 2, an oil droplet was injected from below through a needle into a chamber filled with the target brine, minimizing the influence of hydrodynamic forces on the IFT measurement. Images of the pendant oil droplet were captured using a camera and subsequently analyzed with ImageJ software (version 1.54 r) three times to ensure the repeatability and reliability of the results.

2.7. Core Flooding Experiments

The core flooding apparatus was integrated with a data acquisition system to systematically record system pressure, differential pressure, and the weight and volume of effluent produced as functions of time during the experiment. A limestone core measuring 12 inches in length and 1 inch in diameter was installed within the core holder, where it was confined by a Viton sleeve. The core plug was subsequently installed in the core holder and subjected to a confining pressure of 6.89 MPa (1000 psi) while maintained under vacuum conditions. The porosity of the composite core was determined through vacuum-assisted water imbibition conducted over a period of 72 h. Following this process, water was allowed to enter the core by gravity from a graduated burette positioned at a slightly higher elevation. Porosity was then calculated based on the total volume of fluid imbibed by the core prior to the occurrence of breakthrough. Subsequently, the absolute permeability of the core was measured, followed by the restoration of both the initial oil saturation and the irreducible water saturation. A series of five flooding experiments was conducted, beginning with formation water (SW) and a diluted brine solution 100× dSW, then 100× dSW + 0.5% A, 100× dSW + 0.5% C, and then 100× dSW + 0.5% A +S. The tests were performed at reservoir temperature (80 °C). The schematic of the core flooding apparatus is visible in Figure 3.

3. Results and Discussion

3.1. Zeta Potential and pH Measurements

Zeta potential measurements on oil-wet (OW) or oil-saturated carbonate rock are essential for understanding the true interfacial charging behavior at the oil/rock/brine interface, as most carbonate reservoirs are predominantly oil-wet. These experiments also provide insight into the wettability alteration of OW rock and can be interpreted as fluid–fluid (oil–water) zeta potential measurements.

As shown in Figure 4, the zeta potential at the interface between brine and OW limestone is negative, primarily due to the presence of carboxylic groups from the adsorbed oil on the rock surface. Dilution of seawater increases the magnitude of the negative zeta potential because the reduced ionic strength of the brine decreases the concentration of cations near the rock surface, expanding the electrical double layer and enhancing repulsive interactions. Conversely, the addition of cationic surfactant to the brines shifts the zeta potential toward more positive values, attributable to an increased concentration of cations near the rock surface. Higher surfactant concentrations and elevated brine ionic strength further reduce the negative magnitude of the zeta potential. In contrast, the introduction of anionic surfactants leads to more negative zeta potential values, likely due to the adsorption of negatively charged surfactant molecules onto the rock surface. Notably, the addition of anionic surfactants does not produce a substantial further decrease in zeta potential. This behavior may result from the partitioning of anionic surfactant molecules into the oil phase and their interaction with cations in the solution, which partially removes carboxylic groups from the rock surface. Consequently, this effect counterbalances the increased adsorption of negatively charged surfactant molecules, limiting the overall shift in zeta potential.

As shown in Figure 4, the addition of sulfate ions caused the zeta potential of all tested solutions to shift toward more positive values. This observation is counterintuitive, as sulfate ions are negatively charged and would be expected to induce a more negative zeta potential. One reason can be the dissolution of calcite at the rock surface into the solution due to being attracted by negatively charged sulfate ions in the solution, along with which the negatively charged oil is detached from the oil-wet surface, resulting in a less oil-wet condition and a less negative charge at the rock/brine interface. Other reasons can be specific adsorption of co-added Na⁺ ion and changes in surface complexation equilibria.

The pH of the solutions varied with changes in brine salinity and surfactant concentration, which may influence interactions at the rock/brine interface and, consequently, oil recovery. Figure 5 illustrates the pH values for the different solutions. It is evident that reducing brine salinity results in higher pH values; in other words, lower concentrations of divalent cations lead to higher pH because, at higher salinities, more OH⁻ ions are neutralized by cations present in the solution. The addition of cationic surfactants, on the other hand, decreases pH, whereas the incorporation of anionic surfactants increases it. This behavior can be explained by the interaction of surfactant charges with the solution: positively charged cationic surfactant molecules partially neutralize OH⁻ ions, lowering pH, while negatively charged anionic surfactants may neutralize H⁺ ions, resulting in higher pH. Furthermore, the addition of sulfate ions increases the pH due to a reduction in free H⁺ ions, which are attracted to the SO₄²⁻ ions. However, increasing the concentration of sulfate ions produces diminishing returns on pH elevation. This effect is likely caused by the concomitant increase in Na⁺ ions, which attract some OH⁻ ions and partially counteract the impact of the SO₄²⁻ ions. The range of error for all zeta and pH tests was 0.1% to 0.34%.

3.2. Dynamic Contact Angle Tests

To check the extent of rock–fluid interaction on ultimate oil recovery, the trend and degree of wettability alteration should be investigated. Therefore, a set of contact angle tests is conducted at different salinity levels (i.e., SW, 10× dSW and 100× dSW) and different surfactant concentrations of 0.1%wt and 0.5%wt.

3.2.1. Effect of Brine Salinity

As illustrated in Figure 6, reducing the salinity of the brines induces a shift in rock wettability toward a less oil-wet state. This behavior can be explained by both double-layer expansion and adsorption mechanisms. Since both the oil-wet limestone surface and the diluted seawater exhibit negative zeta potential values, electrostatic repulsion occurs between them. Additionally, the lower concentration of Ca²⁺ ions in the diluted brine reduces the adsorption of polar-displacing ions (PDIs) on the rock surface, decreasing the attachment of negatively charged oil components and thereby promoting wettability alteration toward a less oil-wet condition.

Moreover, a comparison of the zeta potential measurements for the oil/brine/rock system highlights the effect of low-salinity water on rock wettability. The data indicate that reducing brine salinity results in more negative surface charges at both the rock/brine and oil/brine interfaces. This increase in interfacial electrostatic repulsion enhances the thickness of the intervening water film, ultimately shifting the rock wettability toward a more water-wet state [31].

The wettability alteration observed during brine dilution has been interpreted herein primarily in terms of double-layer expansion (DLE), whereby reduction in ionic strength increases the thickness of the electrical diffuse layer at the carbonate–brine interface, thereby enhancing electrostatic repulsion between negatively charged oil components and the rock surface. This electrostatic framework has been widely proposed in the low-salinity waterflooding literature for both sandstones and carbonates [30]. According to classical DLVO theory, decreasing ionic strength increases Debye length, reducing screening of surface charge and weakening attractive interactions between oppositely charged surfaces. However, in carbonate systems, dilution of seawater does not only reduce ionic strength but simultaneously decreases concentrations of potential-determining ions such as Ca²⁺, Mg²⁺, and SO₄²⁻. These ions are known to directly participate in surface complexation reactions on calcite surfaces and influence adsorption/desorption of polar crude oil components [24]. Sulfate ions, in particular, have been reported to adsorb onto positively charged calcite surfaces, reducing surface charge and promoting desorption of carboxylate species through competitive adsorption mechanisms. Divalent cations such as Ca²⁺ and Mg²⁺ may form ion bridges between negatively charged carboxylate groups and the carbonate surface, thereby stabilizing oil-wet conditions. Consequently, brine dilution inherently modifies both (i) general electrostatic conditions through ionic strength reduction and (ii) specific surface complexation equilibria through changes in ion concentrations. Because these changes occur simultaneously and proportionally during dilution, the present experimental design does not fully isolate pure DLE effects from ion-specific chemical mechanisms.

3.2.2. Effect of Anionic Surfactant and Sulfate

Figure 7 and Figure 8 demonstrate that the addition of anionic surfactants to various brines effectively promotes wettability alteration. This effect arises because anionic surfactants increase the negative charge on the rock surface, enhancing electrostatic repulsion and consequently shifting wettability toward a more water-wet state. Furthermore, reducing the brine salinity amplifies the performance of the surfactant. Lower salinity provides more favorable conditions for surfactant activity by minimizing undesired chemical adsorption, thereby enhancing its wettability-altering effect.

The results indicate that lower brine salinity enhances surfactant performance, identifying 100× diluted seawater (100× dSW) as the optimal salinity. Increasing the surfactant concentration to 0.5 wt.% led to improved wettability alteration toward a water-wet state; however, further increasing the concentration from 0.5 wt.% to 1 wt.% did not produce a significant additional effect. This behavior is likely due to the adsorption of excess surfactant molecules onto cations in the brine, which limits their availability to participate in interactions at the rock/oil interface. The results also indicate that the presence of sulfate ions markedly enhances wettability alteration, promoting a shift toward a more water-wet state. This effect can be attributed to two primary mechanisms: (1) the adsorption of SO₄²⁻ ions reduces electrostatic repulsion between the calcite surface and Ca²⁺/Mg²⁺ ions, facilitating the access of these cations to the rock surface, where they can react with adsorbed carboxylic groups, form complexes, or replace calcium ions bonded to the adsorbed carboxylic groups; and (2) SO₄²⁻ ions act as catalysts by approaching the rock surface and enabling Ca²⁺/Mg²⁺ ions to more readily interact with the adsorbed carboxylic groups, either forming complexes or substituting the bridging calcium ions [32].

3.2.3. Effect of Cationic Surfactant

To assess the effect of cationic surfactants on wettability alteration and compare their performance with anionic surfactants, Aspiro S 6420 was employed as the cationic surfactant. As shown in Figure 9 and Figure 10, while the cationic surfactant enhances the wettability-altering performance of diluted seawater, it is less effective than the anionic surfactant. This reduced effectiveness can be attributed to the negative surface charge of oil-wet rock, which favors adsorption of cationic surfactant molecules onto the rock surface rather than facilitating the detachment of carboxylic groups and the transition toward a water-wet state. Consequently, anionic surfactants are more favorable for promoting wettability alteration from oil-wet to water-wet conditions.

Nevertheless, despite the limited effect observed in zeta potential measurements, cationic surfactants can still contribute slightly to wettability alteration. This is due to their partitioning into the oil phase, where they are attracted to anions in the solution. As a result, oil molecules bound to the hydrophobic tails of the surfactant are removed from the rock surface, reducing oil-wet characteristics and promoting a less oil-wet state.

3.2.4. Comparison of Performance of Anionic and Cationic Surfactants

Figure 11 and Figure 12 demonstrate that anionic surfactants outperform cationic surfactants in shifting rock wettability toward a water-wet (WW) state. This can be explained by the negative surface charge of oil-wet (OW) rock, which arises from carboxylic groups present on the rock surface, as confirmed by zeta potential measurements. The introduction of anionic surfactants enhances this negative charge, increasing electrostatic repulsion between the rock and adsorbed oil, and thereby promoting a stronger transition toward a WW condition. Conversely, cationic surfactants tend to adsorb directly onto the negatively charged OW surface, limiting their ability to displace oil and resulting in less effective wettability alteration. The equilibrium contact angle for all tests is shown in

Table 5. Equilibrium contact angle for different solutions.

Solution	Equilibrium Contact Angle
SW	162
10× dSW	152
100× dSW	143
SW + 0.1%wt A	115
10× dSW + 0.1%wt A	106
100× dSW + 0.1%wt A	95
SW + 0.5%wt A	98
10× dSW + 0.5%wt A	91
100× dSW + 0.5%wt A	85
100× dSW + 0.5%wt A + 2× S	63
100× dSW + 1%wt A	79
SW + 0.1%wt C	150
10× dSW + 0.1%wt C	144
100× dSW + 0.1%wt C	136
SW + 0.5%wt C	145
10× dSW + 0.5%wt C	138
100× dSW + 0.5%wt C	132

.

3.3. Dynamic Interfacial Tension

Interfacial tension (IFT) measurements were conducted for the crude oil/brine system across a range of brine salinities, including seawater (SW), 10× diluted SW, and 100× diluted SW, and in the presence of both anionic and cationic surfactants. Based on the findings from zeta potential and contact angle analyses, a surfactant concentration of 0.5 wt.% was selected as the optimal level for these experiments. For IFT tests, the range of error was 0.18% to 0.46% for different measurements.

3.3.1. Effect of Brine Salinity

Interfacial tension (IFT) measurements conducted on surfactant-free brine systems (Figure 13) reveal that IFT increases as salinity decreases across brines with different ionic strengths. A sharp initial decline in IFT is observed, followed by a progressively slower reduction until an equilibrium value is attained. This characteristic trend is consistently exhibited by all brine samples in the absence of surfactants. Among the tested solutions, the most pronounced IFT reduction occurs in SW, whereas 100× dSW exhibits the least reduction. The IFT values measured for SW fall between those of the other two brines. These behaviors can be attributed to the presence of polar components within the oil phase, which possess hydrophilic functional groups and migrate toward the oil–brine interface. An increase in salinity, and, consequently, in cation concentration, enhances the adsorption of these polar compounds at the interface, leading to a greater reduction in oil–brine IFT. This phenomenon was investigated in Farhadi et al.’s 2021 study [16]. Additionally, these findings suggest that the impact of rock–brine interactions is more influential than the oil–brine interactions, which were thoroughly explained in our previous study [33]. As a result, the final equilibrium IFT values follow the order: 100× dSW > 10× dSW > SW.

3.3.2. Effect of Cationic and Anionic Surfactants

As widely reported in the literature, a primary objective of surfactant application in enhanced oil recovery (EOR) processes is the reduction of oil–brine interfacial tension (IFT). As illustrated in Figure 14, the addition of both anionic and cationic surfactants to all brine systems results in lower IFT values compared to their corresponding surfactant-free brines. However, the magnitude of IFT reduction is more pronounced in the presence of cationic surfactants. This behavior can be attributed to the mechanism discussed in Section 3.2.1, whereby polar components within the oil phase preferentially migrate toward the oil–brine interface in environments with higher cation concentrations. The presence of cationic surfactant further enhances this interfacial accumulation of polar species, thereby intensifying interfacial interactions and leading to a greater reduction in oil–brine IFT.

3.4. Core Flooding Experiments

The primary objective of enhanced oil recovery (EOR) processes is to maximize oil recovery while employing optimal concentrations of chemical additives. Based on the findings presented in the preceding sections, an optimal surfactant concentration of 0.5 wt.% was selected for each surfactant and applied in the core flooding experiments. These tests were designed to identify the dominant mechanism(s) responsible for enhanced oil recovery in an oil-wet (OW) carbonate reservoir. In the core flooding procedure, the OW limestone core was initially saturated with the displacing fluid (formation water), followed by injection of the displaced fluid (oil) to establish irreducible water saturation (Swirr). Subsequently, seawater (SW) flooding was conducted until incremental oil production became negligible, representing a high-salinity waterflood. Thereafter, sequential flooding stages were performed using diluted seawater (100× dSW), followed by its combination with cationic and anionic surfactants, and finally 100× dSW containing anionic surfactant and an increased sulfate concentration. Each flooding stage was continued until both the oil recovery and pressure-drop curves reached a plateau.

Figure 15 presents the oil recovery and pressure-drop profiles as a function of injected pore volume (PV). The results indicate that injection of diluted brine (100× dSW) increased the recovery factor by approximately 16%. Despite its limited effectiveness in reducing interfacial tension (IFT), which indicates its lower capillary number than SW (4 × 10⁻⁴ compared to 6 × 10⁻⁴), diluted brine significantly contributed to wettability alteration toward a less oil-wet condition. Accordingly, wettability alteration is identified as the dominant mechanism governing the incremental recovery observed when transitioning from SW to 100×dSW flooding. Upon switching the injected fluid to the cationic surfactant solution, a sharp increase in pressure drop (ΔP) was observed, while the corresponding incremental oil recovery was relatively modest. This behavior is attributed to the adsorption and retention of the cationic surfactant on the negatively charged surface of the oil-wet carbonate rock. Nevertheless, an additional recovery of approximately 7% was achieved during the 100× dSW + 0.5 wt.% cationic surfactant flood, which can be attributed to a combination of IFT reduction and minor wettability alteration, consistent with contact angle (CA) measurements.

A more pronounced incremental recovery was observed when the injected solution was switched from cationic to anionic surfactant, yielding an additional recovery of approximately 13%. This enhanced performance is attributed to the superior wettability alteration capability of the anionic surfactant despite its lower capillary number than that of the solution with cationic surfactant (4 × 10⁻³ compared to 2 × 10⁻²), due to its higher IFT value. Although some degree of surfactant retention is evident at the onset of this flooding stage—based on the pressure-drop and recovery trends—it is considerably less severe than that observed for the cationic surfactant. In the final flooding stage, the sulfate concentration in the diluted brine was doubled and injected in combination with the anionic surfactant. A sharp increase in pressure drop was recorded, which is likely associated with calcium sulfate (CaSO₄) precipitation, as the propensity for CaSO₄ formation increases with higher sulfate concentrations. Despite the strong wettability alteration potential of this solution observed in CA tests, the incremental oil recovery during the 100× dSW + 0.5 wt.% anionic surfactant + 2× sulfate flood was not as high as that of 100× dSW + 0.5 wt.% anionic surfactant. This discrepancy is attributed to pore blockage and flow impairment caused by CaSO₄ precipitation within the porous medium.

4. Conclusions

This study presents a comprehensive experimental investigation of chemically assisted low-salinity waterflooding (LSWF) and its effectiveness in enhancing oil recovery from oil-wet (OW) carbonate reservoirs. Seawater and its diluted forms, in combination with anionic and cationic surfactants, were employed as injected fluids. A series of dynamic contact angle (CA) and interfacial tension (IFT) measurements, along with zeta potential and pH analyses, was conducted to elucidate the physicochemical mechanisms governing oil recovery. These pore-scale observations were subsequently integrated with core flooding experiments performed on oil-wet limestone cores to identify the dominant recovery mechanisms at the core scale.

• Zeta potential measurements revealed that dilution of seawater shifts the surface charge toward more negative values, particularly in the presence of anionic surfactant. This shift enhances electrostatic repulsion at the oil–rock–brine interface, favoring wettability alteration toward a water-wet state. In contrast, the addition of cationic surfactants resulted in a shift of zeta potential toward positive values, reducing repulsive forces and thereby limiting their effectiveness in wettability modification.
• Dynamic contact angle measurements demonstrated that reducing brine salinity promotes wettability alteration toward less oil-wet conditions. The incorporation of anionic surfactant further enhanced this effect, whereas cationic surfactant exhibited a comparatively limited impact on wettability alteration. The slight wettability modification observed in the presence of cationic surfactants, despite their unfavorable zeta potential behavior, is attributed to surfactant partitioning into the oil phase and subsequent removal of oil components from the rock surface through interactions with anions in the aqueous phase.
• Dynamic IFT measurements indicated that increasing brine salinity leads to lower oil–brine IFT values. Furthermore, cationic surfactant was more effective than anionic surfactant in reducing IFT. This behavior is attributed to the presence of polar oil components containing hydrophilic functional groups that preferentially migrate to the oil–brine interface under higher cation concentrations, thereby enhancing interfacial adsorption and reducing IFT.
• Core flooding experiments showed that dilution of the injected brine resulted in an incremental oil recovery of approximately 16%. Although brine dilution had a limited impact on IFT reduction, it significantly improved oil recovery through wettability alteration. Consistent with the pore-scale observations, anionic surfactant flooding yielded higher incremental recovery than cationic surfactant flooding (approximately 13% versus 7%), confirming the superior role of wettability alteration. In contrast, the combination of anionic surfactant with sulfate ions resulted in only marginal additional recovery (approximately 3%), despite its strong wettability alteration potential observed in CA tests. This discrepancy is attributed to calcium sulfate (CaSO₄) precipitation within the porous medium, which likely impaired fluid flow and oil displacement.
• The results indicate that the solution of 100× dSW + 0.5 wt.% anionic surfactant is the optimal solution for increasing oil recovery in such an oil-wet reservoir.

Overall, the results of this study demonstrate that wettability alteration is the dominant and underlying mechanism governing oil recovery enhancement in oil-wet carbonate reservoirs under the investigated conditions. The findings highlight the importance of optimizing brine salinity and surfactant type to maximize wettability modification while minimizing adverse effects such as surfactant retention and inorganic scale formation.