Effects of Divalent Cations on the Interfacial Properties of Surfactant–Crude Oil Systems and Their Implications for Ion-Tuned Waterflooding

Abstract

The integration of ion-tuned waterflooding with surfactant flooding has emerged as a promising strategy for enhanced oil recovery (EOR), yet the mechanisms governing ion-surfactant interactions at fluid–fluid and fluid–solid interfaces remain insufficiently understood. This study systematically investigated the effects of divalent cations (Ca²⁺ and Mg²⁺) on the interfacial behavior and displacement performance of cationic, zwitterionic, and nonionic surfactants. Surfactant solutions were prepared with low-salinity (1000 mg/L) and high-salinity (50000 mg/L) CaCl₂ and MgCl₂ brines. Interfacial tension, dilatational modulus, and contact angle measurements were conducted to characterize fluid–fluid and fluid–solid interactions, followed by pore-scale displacement experiments in microfluidic devices containing dead-end pore structures. The results demonstrated that the influence of divalent cations strongly depended on the surfactant type and salinity. For the cationic surfactant, high-salinity CaCl₂ significantly reduced the IFT, whereas MgCl₂ exhibited a weaker IFT-reduction effect. Divalent cations progressively decreased the dilatational modulus of the cationic surfactant interface, indicating an enhanced interfacial mobility. In contrast, the zwitterionic surfactant exhibited minimal changes in IFT but showed an increased dilatational modulus upon salt addition, suggesting the formation of a more rigid interfacial film through ion-mediated intermolecular interactions. The nonionic surfactant displayed limited sensitivity to divalent cations with only moderate variations in IFT and interfacial rheology. Wettability measurements revealed that divalent cations altered the adsorption behavior of the cationic surfactant on quartz surfaces, while their influence on the zwitterionic and nonionic surfactants was comparatively weak. Microfluidic displacement experiments showed that higher oil recovery correlates with a balance between interfacial tension and dilatational modulus, particularly when their values are comparable. Statistical analysis further identified salinity as the dominant factor controlling oil recovery and revealed a significant synergistic interaction between selected surfactant species and salinity with the largest effect size. These findings provide mechanistic insights into ion-surfactant interactions and offer guidance for the design and optimization of ion-tuned surfactant flooding processes for enhanced oil recovery.

1. Introduction

Water injection is one of the most widely used development methods worldwide. However, the oil recovery efficiency can no longer meet the requirement after long-term development. In the early 90s, it was discovered that oil recovery could be improved by lowering the injection brine salinity and was denoted as low-salinity flooding or low-salinity effect. − Various lab and field test results have implied that the low-salinity effect could result in higher oil recovery. − The improved recovery has been attributed to a combination of rock-fluid and fluid–fluid interactions, including wettability alteration, multicomponent ion exchange, electrical double-layer expansion, fines migration, and changes in interfacial properties. ,,−

The dominant mechanisms of low-salinity flooding depend strongly on the reservoir mineralogy. In sandstone reservoirs, oil recovery is generally associated with multicomponent ion exchange, expansion of the electrical double layer, fines migration, and the consequent alteration of rock wettability toward more water-wet conditions. − These processes modify the interactions among crude oil, brine, and mineral surfaces, thereby facilitating the detachment of adsorbed oil components. In carbonate reservoirs, potential-determining ions, particularly Ca²⁺, Mg²⁺, and SO₄ ²⁺, play a central role in controlling surface chemistry. − These ions participate in surface complexation and ion-exchange reactions that modify the surface charge of carbonate minerals, thereby promoting wettability alteration and improving oil recovery. , Besides rock mineralogy, both the salinity and the ionic composition of the injected brine are critical factors governing the efficiency of low-salinity waterflooding. Particularly, ions in the brine play an important role in the low-salinity effect. − For instance, previous work has shown that the presence of monovalent cations in the brine resulted in higher oil recovery efficiency than that of divalent cations. Haagh et al. have investigated the impact of divalent cations on the wettability alteration in various oil–brine–silicate systems. It was previously shown that a positive low-salinity effect was observed by using Ca²⁺-diluted floods. The presence of Mg²⁺ might inhibit the positive effect. Therefore, addition and/or removal of specific ions from the injection water could impact the functionality of low-salinity waterflooding. −

Afterward, the combination of surfactant and brine has been proposed as a new approach of smart waterflooding to further improve the oil recovery efficiency. − The performance of the combination of brine and surfactant is largely dependent upon the interfacial phenomenon among active components in crude oil, ions in the brine solution, surfactant molecules, and solid surface charges. − The addition of salts facilitates surfactant partitioning into the oil phase, thus reducing the interfacial tension. The impact of brine salinity and surfactants on the interparticle forces was examined. Cetyltrimethylammonium bromide and Quillaja saponin surfactants in low-salinity water facilitated the reduction of the electrical repulsion between oil and rock, yet sodium dodecyl sulfate and Triton X-100 surfactants in low-salinity water showed nonsignificant impact on the surface charge between oil and rock. The combination of low-salinity waterflooding and nanoparticles stabilized with surfactant was also introduced and termed as hybrid enhanced oil recovery method. Nanofluids modified with Gum Arabic could improve the applicability of low-salinity waterflooding. Besides cations, the impact of anions in the aqueous phase was also investigated. It was shown that the solution with H₂PO₄ ^– exhibited the highest oil recovery with and without the presence of cationic surfactants. It was also proposed that the presence of SO₄ ²– could lead to a more effective oil-water interaction. The addition of surfactant to the smart water system could reduce the contact angle for carbonate rock. The combination of surfactant and polymer under high temperature and high salinity has also been investigated previously to demonstrate the impact of salinity on the critical micelle concentration and rheology of the solutions. Molecular dynamics simulation was incorporated to investigate the interaction of surfactants and different ions at the oil–water interface. The study showed that salts in the aqueous phase and hydrophobic acids demonstrated a synergistic effect to orient surfactants parallel to the interface therefore impacting the oil-water interfacial behavior. The combination of divalent cations and different surfactants could lead to complex interfacial behaviors. Beyond equilibrium IFT, interfacial dilatational rheology provides important information on the viscoelastic properties of adsorption films by quantifying their resistance to periodic changes in interfacial area. The dilatational modulus reflects the elasticity and stability of the interfacial film and has been shown to influence droplet deformation, emulsification, coalescence, and the transport of oil through porous media. Consequently, interfacial rheological properties are increasingly recognized as an important factor governing the performance of chemical flooding systems, complementing conventional measurements such as interfacial tension and wettability. The dilatational modulus could be affected by surfactant type, electrolyte composition, and crude oil composition. − Therefore, combining IFT and dilatational modulus measurements provides further insight into the complicated interfacial interactions between oil and aqueous phase. Although numerous studies have investigated the effects of surfactant and electrolyte on the interfacial properties between oil and water, most previous work focused upon surfactant screening, interfacial tension reduction, and wettability changes. The specific roles of individual cations in regulating surfactant interfacial behavior and their subsequent impact on microscale oil displacement performance remain insufficiently understood. A systematic investigation of the fluid–fluid and fluid–solid interfacial interactions among crude oil, different cations in brine, and surfactant chemistry could be beneficial to the solid understanding and optimization of ion-tuned waterflooding.

In this study, brines with two salinity levels and two commonly observed divalent cations (Ca²⁺ and Mg²⁺) were selected and combined with three types of surfactants, respectively. Interfacial tension (IFT), the dilatational modulus between crude oil and the aqueous solution, and contact angle were measured to systematically investigate the influence of cation type and salinity and surfactant type on interfacial behaviors. Microfluidic devices with dead-end pores were employed to provide a well-controlled pore-scale visualization platform for isolating the effects of surfactant–cation interactions on interfacial properties and oil displacement behaviors. This work offers an experimental and mechanistic reference for the application of ion-tuned waterflooding in the oilfield.

2. Materials and Methods

2.1. Materials

Four surfactants with different headgroup chemistries including cationic (cetyltrimethylammonium bromide, CTAB), anionic (isopropylammonium dodecylbenzenesulfonate, LAS-IPA), zwitterionic (oleoylamidopropyl betaine, OAB), and nonionic (nonylphenol polyoxyethylene ether, NP-10) surfactants were selected in this study to investigate the influence of surfactant charge characteristics on surfactant-cation interactions. Their chemical structures are shown in Figure . These surfactants were chosen because their distinct molecular structures provide different electrostatic and hydration environments at the oil-water interface, which may result in different responses to divalent cations. Two different salts, including CaCl₂ and MgCl₂, were used in this work. Each surfactant with a concentration of 0.2 wt % was mixed with different salts with two salinities (1000 and 50000 mg/L, denoted as LS and HS, respectively). Therefore, a total of 16 solutions were evaluated in this work. The details of the solutions are shown in Table . The critical micelle concentrations (CMC) of CTAB, LAS-IPA, OAB, and NP-10 in deionized water are 0.686, 0.778, 0.012, and 0.132 mmol/L, respectively, as determined in our previous study. A surfactant concentration of 0.2 wt % was selected for all experiments to provide a consistent basis for comparing the effects of different ionic environments on surfactant performance. The surfactant concentrations employed in the present work are within the range commonly investigated for surfactant flooding studies and were selected to be above their respective CMC values to ensure sufficient interfacial adsorption, while allowing the influence of different cations on the interfacial properties to be systematically evaluated.

1.

Chemical structures of the surfactants used.

1. Details of the Tested Solutions.

No.	Composition
1	1000 mg/L CaCl2+0.2 wt %CTAB
2	50000 mg/L CaCl2+0.2 wt %CTAB
3	1000 mg/L MgCl2+0.2 wt %CTAB
4	50000 mg/L MgCl2+0.2 wt %CTAB
5	1000 mg/L CaCl2+0.2 wt % LAS-IPA
6	50000 mg/L CaCl2+0.2 wt % LAS-IPA
7	1000 mg/L MgCl2+0.2 wt % LAS-IPA
8	50000 mg/L MgCl2+0.2 wt % LAS-IPA
9	1000 mg/L CaCl2+0.2 wt %OAB
10	50000 mg/L CaCl2+0.2 wt %OAB
11	1000 mg/L MgCl2+0.2 wt %OAB
12	50000 mg/L MgCl2+0.2 wt %OAB
13	1000 mg/L CaCl2+0.2 wt % NP-10
14	50000 mg/L CaCl2+0.2 wt % NP-10
15	1000 mg/L MgCl2+0.2 wt % NP-10
16	50000 mg/L MgCl2+0.2 wt % NP-10

Crude oil used in this study contains 2.09% asphaltenes, 22.78% resins, 4.27% aromatics, and 70.86% saturates. Formation water used in this study consists of 80% NaCl, 10% CaCl₂, 7% MgCl₂, and 3% KCl with a total salinity of 50000 mg/L.

2.2. Methods

2.2.1. Compatibility Tests of Surfactants and Brines

Prior to interfacial characterization and oil displacement experiments, the compatibility between each surfactant solution and the prepared brines was evaluated by visual observation. After mixing the surfactant with the corresponding brine as shown in Table , the solutions were allowed to equilibrate at room temperature for 24 h before the compatibility evaluation.

2.2.2. Interfacial Tension and Dilatational Modulus

IFT was measured using spinning drop method (CNGTX QBZY). The measurement was conducted at a rotational speed of 5000r/min and a temperature of 30 °C. The sample tube was filled with the tested solution, and a small drop of crude oil was injected into the tube using a microsyringe. After the system reached equilibrium at 5000 rpm, the rotational speed was periodically varied with an amplitude of 300 rpm for two cycles over 40 s, inducing controlled oscillations in the interfacial area of the oil droplet. Figure shows a representative output obtained from the spinning drop tensiometer during a single interfacial dilatational rheology measurement, illustrating the temporal variations in interfacial tension, interfacial area, and rotational speed, which are recorded during the oscillatory deformation of the oil droplet. These data were subsequently used to determine the interfacial dilatational modulus ε, which describes the interfacial resistance to changes in the area between the crude oil and the tested solution, using the following equation. IFT was measured at least three times for each formulation, and the results are reported as mean±standard deviations. The dilatational modulus was obtained from the interfacial response during the measurement and was calculated based on the corresponding interfacial tension variation. No error bars were reported for this parameter.

$$\epsilon =\frac{\mathrm{d}\gamma }{\mathrm{d\; ln}A}$$ 1

2.

Representative spinning drop measurement illustrating the temporal evolution of interfacial tension, interfacial area, and rotational speed.

where γ represents the IFT, mN/m; A represents the interfacial area, mm².

2.2.3. Contact Angle

Prior to the measurement, a glass slide was aged in a beaker filled with crude oil at 30 °C for 24 h. Contact angle was measured through the captive drop method using the optical contact angle measuring device (KRÜSS DSA100) as shown in Figure . A small crude oil droplet serving as the captive phase was injected beneath the glass slide immersed in the distilled water. After measuring the initial contact angle, the slide was aged in the beaker filled with tested solution at 30 °C for 24 h. The contact angle was measured again to obtain the degree of wettability alteration by the tested solution. The entire procedure was repeated for the tested solutions listed in Table . Contact angle was measured at least three times, and the results are reported as mean±standard deviations.

3.

Demonstration of (a) the captive drop method and (b) image taken using the optical contact angle measuring device.

2.2.4. Displacement Tests in Dead-End Structure

The microfluidic device consists of dead-end pore structures with the planar geometry shown in Figure and it possesses a uniform channel depth of 100 μm. The model contained seven dead-end pores, each with an approximate pore volume of 3.0×10⁶ μm³. Polydimethylsiloxane (PDMS) devices were used in this work, and the detailed fabrication process of the microfluidic devices has been described in previously published work. No additional surface treatment or aging procedure was performed prior to the displacement experiments, so that all surfactant systems were evaluated under identical surface conditions. The device was first saturated with formation water at a rate of 5μL/min. Crude oil was subsequently injected to displace the aqueous phase at a rate 2 μL/min to establish the initial oil saturation. Subsequently, the test solution was injected into the device at a rate of 2μL/min to simulate the displacement process. Each displacement experiment was conducted for 40 min. Images were periodically taken during the entire process for subsequent calculation of the oil saturation using ImageJ software. Oil recovery efficiency η was calculated using the following equation. Oil recovery was calculated from three representative dead-end pores in each experiment, and the corresponding variation is represented by standard deviation.

$$\eta =(\mathrm{1-}\raisebox{1ex}{${\mathrm{S}}_{\mathrm{or}}$}\!\left/ \!\raisebox{-1ex}{${\mathrm{S}}_{\mathrm{oi}}$}\right.)\times \mathrm{100\%}$$ 2

4.

Schematic of microfluidic device with dead-end structures.

where S_oi represents the initial oil saturation and S_or represents the residual oil saturation.

3. Results and Discussion

3.1. Compatibility of Surfactants and Brines

Figure and Table present the compatibility of the four surfactants in the investigated brines. CTAB, OAB, and NP-10 remained clear and homogeneous under all tested conditions, indicating good compatibility. In contrast, LAS-IPA exhibited visible precipitation in the presence of Ca²⁺ and Mg²⁺, indicating poor compatibility with divalent cations. Our previous work showed that LAS-IPA possesses better compatibility with Na⁺ and K⁺. This behavior indicates the formation of poorly soluble divalent surfactant salts, thus preventing reliable measurements of the interfacial properties under these conditions. Therefore, the discussion of the impact of LAS-IPA on the interfacial properties, contact angle, and oil recovery was excluded.

5.

Demonstration of solution compatibility between surfactants and varying brine solutions.

2. Compatibility of the Surfactant and Brine Solutions (S: Stable, P: Precipitation).

	Addition of salt
Surfactant	LS CaCl2	HS CaCl2	LS MgCl2	HS MgCl2
0.2 wt % CTAB	S	S	S	S
0.2 wt % OAB	S	S	S	S
0.2 wt % NP-10	S	S	S	S
0.2 wt % LAS-IPA	P	P	P	P

3.2. Interfacial Tension and Dilatational Modulus

The measured IFT between crude oil and varying solutions, and the comparison of IFT between single-surfactant and composite solutions are presented in Figures and . In general, the addition of salts to different surfactants has various impacts on the IFT. For the cationic surfactant CTAB, the addition of low-salinity CaCl₂ has an indistinctive impact on the IFT compared with the individual surfactant. However, the combination of high-salinity CaCl₂ and CTAB resulted in lower IFT. After adding low-salinity CaCl₂, the weak charge-screening effect has less impact on the arrangement of CTAB at the interface. When the concentration of CaCl₂ increases, the charge screening effect could facilitate the denser packing of CTAB molecules, thus reducing the IFT. The combination of MgCl₂ and CTAB resulted in a relatively higher IFT despite the salt concentration. Differences in IFT trends in the presence of Ca²⁺ and Mg²⁺ could be attributed to differences in hydration ability. Mg²⁺ is much more strongly hydrated due to its smaller ionic radius and higher charge density. ,, Consequently, Mg²⁺ may interact differently with the interfacial environment and influence the adsorption configuration and organization of CTAB molecules, leading to weaker IFT reduction compared with Ca²⁺. Although CTAB exhibited interfacial responses under high-salinity conditions, its potential application in sandstone reservoirs requires careful consideration because electrostatic adsorption onto negatively charged mineral surfaces may reduce chemical utilization efficiency.

6.

Interfacial tension between crude oil and different surfactants in varying salt solutions.

7.

Heat map of the percentage change for IFT between the composite solution and single surfactant (positive values indicate an increase in IFT relative to the surfactant-only control, while negative values indicate a decrease).

For zwitterionic surfactant OAB, the addition of CaCl₂ has an indistinctive effect on the IFT. The addition of MgCl₂ could result in an increase in IFT similar to the trend observed for the cationic surfactants. The zwitterionic surfactant OAB demonstrates good stability in IFT when combined with brines. Mg²⁺ exhibits a smaller ionic radius and higher charge density than Ca²⁺, resulting in stronger hydration characteristics and potentially stronger effects on the hydration environment surrounding the OAB molecules. These ion-specific interactions may alter the interfacial adsorption behavior of the OAB and reduce its ability to achieve a lower IFT at high MgCl₂ concentrations.

For the nonionic surfactant NP-10, the addition of low-salinity salts resulted in an increase in IFT, whereas the addition of high-salinity salts resulted in a decrease in IFT despite the salt type. For NP-10, the hydrophilic character originates from polyoxyethylene groups. In the presence of low-concentration Mg²⁺ and Ca²⁺, salt ions could interact with the polyoxyethylene groups, reducing its hydrophilicity. In the presence of high-salinity salts, the electrolyte induces a salting-out effect that could reduce the solubility of the surfactant in the bulk aqueous phase. Therefore, surfactant molecules migrate to the interface, leading to a decrease in IFT. In addition, for NP-10, the interfacial behavior is sensitive to the ion concentration rather than the ion type.

The results of the calculated dilatational modulus using eq are shown in Figure The comparison of dilatational modulus between single surfactant and composite solutions is presented in Figure . Dilatational modulus could present resistance of the interface to periodic compression and expansion. For the cationic surfactant CTAB, the dilatational modulus was reduced with the addition of salts, regardless of the salt type and concentration. The reduction was more pronounced when high-salinity salts were added. It’s possibly due to the fact that the addition of electrolytes could lead to double-layer compression and the interfacial rearrangement easier therefore the interface behaves more fluid-like. For the zwitterionic surfactant OAB, on the contrary, the addition of salts led to an increase in the dilatational modulus. This could be attributed to the interaction between salt ions and OAB molecules that altering the interfacial structure rather than adsorption amount. For nonionic surfactant, the addition of salt has indistinctive impact on the dilatational modulus. Ca²⁺ and Mg²⁺ mainly interact with polyoxyethylene groups, but they might not generate strong intermolecular networks at the interface.

8.

Dilatational modulus between crude oil and different surfactants in varying salt solutions.

9.

Heat map of the percentage change for dilatational modulus between the composite solution and single surfactant (positive values indicate an increase in dilatational modulus relative to the surfactant-only control, while negative values indicate a decrease).

3.3. Contact Angle

The results of contact angle measurements and comparison of contact angles between single-surfactant and composite solutions are presented in Figures and . For the cationic surfactant CTAB, the combination of low-salinity salt and surfactant resulted in relatively higher contact angles. CTAB molecules carrying positive charges could adsorb on the negatively charged solid surface and leave the hydrophobic tail extending outwards, resulting in an oil-wet surface. The addition of a low concentration of salt could reduce the repulsion between surfactant headgroups, leading to higher adsorption density. Consequently, the enhanced adsorption density is expected to increase the hydrophobicity of the surface. In contrast, the combination of high-salinity salt and surfactant led to a more water-wet condition. It’s possibly a result of enhanced adsorption of divalent cations, which competing with the adsorption of CTAB therefore the contact angles decreased. For the zwitterionic surfactant OAB, except for low-salinity CaCl₂, the addition of salts has nonsignificant effect on the surface wettability, suggesting that the balanced positive and negative charges within the OAB headgroup reduce its sensitivity to external ionic conditions. Low concentrations of Ca²⁺ might influence the organization or orientation of the adsorbed zwitterionic surfactant layer through ion-specific interactions. Similarly, for nonionic surfactant, the addition of MgCl₂ has indistinctive impact on the contact angle. Yet the combination of CaCl₂ and surfactant resulted in a slight increase in contact angle. Nonionic surfactants usually adsorb onto the solid surface through intermolecular forces. Their adsorption onto mineral surfaces is less sensitive to electrostatic screening caused by electrolytes compared with ionic surfactants.

10.

Measured contact angle between crude oil and different surfactants in varying salt solutions.

11.

Heat map of the percentage change for contact angle between the composite solution and the single surfactant (positive values indicate an increase in contact angle relative to the surfactant-only control, while negative values indicate a decrease).

3.4. Oil Displacement in Dead-End Pores

A microfluidic device with triangular-shaped dead-end pores was employed to simulate the oil displacement process. The results for oil recovery rate using various solutions and the comparison of oil recovery between single-surfactant and composite solutions are shown in Figures and . Overall, NP-10 with high-salinity brines and CTAB with low-salinity CaCl₂ resulted in relatively high oil recovery rates. However, no evident and direct correlation among oil recovery rate, brine composition, and surfactant type was observed. The oil recovery rate is a result of IFT, interfacial dilatational modulus, and wettability. Therefore, oil displacement behaviors using different combinations of surfactant and salt are discussed in detail in the following subsections.

12.

Oil recovery rate of different tested solutions in the dead-end structures.

13.

Heat map of the percentage change for oil recovery between the composite solution and single surfactant (positive values indicate an increase in oil recovery relative to the surfactant-only control, while negative values indicate a decrease).

Interestingly, an empirical relationship between the oil recovery efficiency and the ratio of IFT and dilatational modulus was observed under the investigated experimental conditions. As shown in Figure , the dilatational modulus was plotted against the IFT for three types of solutions based on the surfactant used. The corresponding oil recovery results are also labeled in the figure. It was observed that when the values of the dilatational modulus and IFT are close, or the IFT values are smaller than those of the dilatational modulus, the resulting oil recovery rate is generally higher. As the data points deviate downward to the right from the dashed line, the resulting oil recovery efficiency is relatively lower. This implies that the balance between IFT and the dilatational modulus could be critical for the oil displacement performance. Further development of quantitative correlations will require more comprehensive datasets encompassing broader surfactant chemistries, ion compositions, surfactant concentrations, temperatures, and reservoir conditions. Three scenarios observed in this study, demonstrating different IFT and dilatational modulus characteristics, are discussed as follows.

14.

Dilatational modulus versus IFT for the combinations of different surfactants and salts, with the corresponding oil recovery labeled next to each marker (slope of the dashed line is 1).

3.4.1. Relatively Higher IFT and Lower Dilatational Modulus

Figure displays the images taken during the experiment using the LS MgCl₂+OAB solution possessing relatively higher IFT and lower dilatational modulus. Because of the relatively higher IFT, small O/W emulsions were rarely observed. Upon the contact between crude oil and the composite surfactant solution, the crude oil was gradually solubilized by the surfactant solution and mobilized to the outlet, yet the solubilization efficiency is relatively low. A relatively low dilatational modulus represents a more mobile and deformable interface, which may promote the droplet deformation and emulsification. However, high IFT could dominate the displacement behavior, resulting in limited oil mobilization. As a result, the overall oil displacement efficiency in the dead-end pores was relatively low. It was supported by the markers in the lower right part, which represent a lower oil recovery rate (Figure ).

15.

Evolution of the oil phase during displacement process using LS MgCl₂+OAB.

3.4.2. Relatively Lower IFT and Higher Dilatational Modulus

Figure displays the images taken during the experiment using LS CaCl₂+CTAB possessing relatively lower IFT and higher dilatational modulus. First, smaller-sized O/W emulsions were observed because of the lower IFT. Second, long and thin oil filaments were observed during the displacement process, which is presumably attributed to the relatively higher interfacial dilatational modulus. Crude oil in the dead-end structures was recovered through emulsification and dragging with the injected solution. Overall oil recovery is higher than that under the previous condition.

16.

Evolution of the oil phase during displacement process using LS CaCl₂+CTAB.

3.4.3. Moderate IFT and Dilatational Modulus

Figure displays the images taken during the experiment using HS MgCl₂+NP-10 solutions possessing moderate IFT and dilatational modulus. Unlike the previous scenarios, smaller O/W emulsions were frequently observed owing to relatively lower IFT and dilatational modulus that facilitate the mobilization of the oil phase. The oil droplets are generally not dragged into long oil filaments but rather dispersed into small droplets, which are better to be mobilized. As a result, the oil recovery rate is usually high under moderate IFT and dilatational modulus conditions.

17.

Evolution of the oil phase during the displacement process using HS MgCl₂+NP-10.

3.5. Statistical Analysis

To quantitatively evaluate the effects of selected surfactant species, divalent cation type, and salinity on interfacial properties and oil recovery performance, a series of statistical analyses was conducted. Prior to significance testing, the Shapiro–Wilk normality test and Levene’s test for homogeneity of variances were performed to assess the suitability of the experimental dataset for parametric analysis. The results in Table indicated deviations from normality and variance homogeneity for the IFT data. However, considering the balanced experimental design and the robustness of analysis of variance (ANOVA) under small sample conditions, a three-way ANOVA was employed to provide statistical insight into the effects of the investigated factors. The main effects of selected surfactant species, cation type, and salinity, as well as their interaction effects, on IFT, contact angle, and oil recovery were subsequently evaluated. The significance of the main effects was determined based on the corresponding p-values. Partial eta-squared (η_p ²) was calculated to evaluate the effect size with larger values indicating a stronger influence of the corresponding factor or interaction, and interaction terms were used to identify potential synergistic effects between surfactants, cation type, and salinity.

3. Normality and Homogeneity-of-Variance Test Results.

Evaluation index	IFT	Contact angle	Oil recovery
Normality test p value	0.0037	0.0002	0.0730
Homogeneity test p value	0.0347	0.5440	0.2675

The results of the three-way ANOVA are summarized in Table . For IFT, the main effects of the surfactant species, cation type, and salinity were all statistically significant. Among these factors, surfactant species exhibited the largest effect size of 0.951, indicating that the chemical characteristics of surfactants played a predominant role in determining IFT under the investigated conditions. Furthermore, the significant interaction between surfactant species and salinity suggests that the influence of salinity on IFT reduction depends strongly on surfactant chemistry.

4. Three-Way ANOVA Results.

Effect	IFT, p; ηp 2	Contact angle, p; ηp 2	Oil recovery, p; ηp 2
Selected surfactant species	<0.001; 0.95	<0.001; 0.97	0.198; 0.13
Cation type	<0.001; 0.64	<0.001; 0.39	0.095; 0.11
Salinity	<0.001; 0.88	<0.001; 0.87	<0.001; 0.53
Selected surfactant species×cation type	<0.001; 0.68	<0.001; 0.47	0.0011; 0.43
Selected surfactant species×salinity	<0.001; 0.86	<0.001; 0.81	<0.001; 0.76
Cation type×salinity	0.037; 0.17	<0.001; 0.59	<0.001; 0.45
Selected surfactant species×cation type×salinity	0.193; 0.13	<0.001; 0.47	0.590; 0.04

For the contact angle, all three main effects and their interactions were statistically significant. Surfactant species showed the largest effect size of 0.970, demonstrating that surfactant molecular structure and associated interfacial properties were the primary factors governing wettability alteration. The interaction between surfactant species and salinity also exhibited a substantial effect with η_p ² of 0.808, highlighting the strong dependence of wettability modification on the combined effects of surfactant chemistry and salinity. In addition, the statistically significant three-way interaction indicates that the influence of surfactant species cannot be considered independently from cation type and salinity.

For oil recovery, surfactant species and cation type did not exhibit statistically significant main effects, whereas salinity showed a significant influence, with an effect size of 0.534. Notably, the interaction between surfactant species and salinity demonstrated the largest effect size of 0.758, suggesting that the displacement efficiency was primarily governed by the synergistic effects between surfactant chemistry and salinity. Overall, these results indicate that salinity and their interactions with surfactant properties play a critical role in controlling the microscale oil displacement performance. It should be noted that these conclusions are limited to the three investigated surfactants under the specified brine compositions, temperatures, and PDMS-based microfluidic conditions.

4. Conclusion

This study systematically investigated the interfacial behavior of cationic, zwitterionic, and nonionic surfactants in the presence of divalent salts through IFT, dilatational modulus, and contact angle measurements. Microfluidic displacement experiments employing dead-end pore structures were conducted to visualize pore-scale displacement processes and evaluate oil recovery performance. Statistical analysis was further performed to identify the dominant factors governing displacement efficiency. The major conclusions are summarized as follows:

• (1)The effects of divalent cations on IFT were strongly dependent on the surfactant type and salinity. For the cationic surfactant, high-salinity CaCl₂ significantly reduced IFT, whereas both low- and high-salinity MgCl₂ increased IFT. The zwitterionic surfactant exhibited minimal sensitivity to divalent cation addition, while low-salinity CaCl₂ and MgCl₂ increased the IFT of the nonionic surfactant.
• (2)Divalent cations exerted distinct influences on the interfacial rheology. The addition of Ca²⁺ and Mg²⁺ decreased the dilatational modulus of the cationic surfactants. In contrast, the zwitterionic surfactant exhibited an increased dilatational modulus following salt addition. The nonionic surfactant showed only minor variations in the dilatational modulus under different salinity conditions.
• (3)Wettability alteration was primarily observed for the cationic surfactant systems. The incorporation of low-salinity divalent salts shifted the surface toward more oil-wet conditions, whereas the wettability of the zwitterionic and nonionic surfactant systems remained largely unaffected by the divalent cations.
• (4)Oil recovery was governed by the combined effects of IFT and interfacial elasticity rather than by the IFT reduction alone. Microfluidic displacement experiments demonstrated that enhanced oil recovery was achieved when the IFT and dilatational modulus were maintained at comparable levels, highlighting the importance of balancing IFT reduction and interfacial film stability.
• (5)A three-way ANOVA showed that salinity had a significant main effect on oil recovery. All two-way interactions were significant, with the selected surfactant species and salinity interaction exhibiting the largest effect size of 0.76. These results indicate that displacement efficiency depended on salinity and its interactions with selected surfactant species and cation types under the tested conditions.

Overall, the results provide new mechanistic insights into ion-surfactant interactions at fluid–fluid and fluid–solid interfaces and demonstrate the critical role of divalent cation type and salinity in regulating interfacial properties and displacement efficiency. It should be noted that the present investigation was conducted at 30 °C using a controlled microfluidic system without considering the complex mineralogical and geological heterogeneity of actual reservoirs. Therefore, the observed trends should be interpreted as mechanistic insights under the investigated conditions rather than direct predictions of field-scale performance. Further validation using coreflooding experiments is required for reservoir applications. Nevertheless, these findings contribute to a deeper understanding of ion-tuned surfactant flooding and provide a scientific basis for the its design and optimization of enhanced oil recovery strategies.

The authors confirm that the data are provided within the article.

The authors declare no competing financial interest.