A synergistic nano-brine formulation for enhanced oil recovery through interfacial engineering in carbonate reservoirs

Abstract

This study presents a novel approach for enhanced oil recovery (EOR) in carbonate reservoirs through the synergistic use of engineered low-salinity brine and nanoparticles. Generally, conventional studies of nanofluid-EOR in carbonates largely focus on the macroscopic effects of metal oxides, leaving the design and behavior of custom multi-component nanofluids engineered to control multiple interfacial forces simultaneously poorly understood. In this study, the nanoparticle was synthesized by functionalization with other chemicals (potassium laurate and Triton X-100). The results showed that excellent colloidal stability, evidenced by a zeta potential of -58.46 mV at 80 ppm and pH 4.5. Also, contact angle analysis demonstrated a wettability shift from oil-wet to strongly water-wet. Core flooding tests achieved a significant incremental oil recovery of 31.11%, driven by the synergistic reduction of interfacial tension, effective wettability alteration, and enhanced structural disjoining pressure. The results identify the optimal and cost-effective nanofluid concentrations (80 ppm) for field-scale injection into carbonate reservoirs. These findings underscore the promise of engineered nanofluid brine systems as a viable and sustainable EOR strategy, providing valuable direction for the development of advanced materials in energy and industrial applications.

Introduction

Crude oil remains a critical energy resource to meet global energy demands¹, yet a substantial portion, approximately 70%, is typically left trapped in reservoirs after primary and secondary recovery phases^2–6. This underscores the necessity for Enhanced Oil Recovery (EOR) techniques that introduce external energy or chemical substances to boost extraction⁷. The process is fundamentally governed by interfacial phenomena, where capillary and viscous forces, interfacial tension (IFT), and rock wettability critically influence fluid distribution and displacement efficiency^8,9. Wettability, quantified by the contact angle, is particularly vital, as about half of the world’s reservoirs consist of fractured carbonates that are neutrally to oil-wet. Enhancing recovery from these formations often requires shifting wettability towards a water-wet state to promote spontaneous imbibition and improve oil displacement^10,11. Nanotechnology has emerged as a promising avenue for EOR, leveraging the unique properties of nanoparticles (1–100 nm), such as high surface area and tunable surface chemistry^12–18. Nanofluids can modify key parameters including rock wettability, oil-water IFT, and fluid mobility ratio. Frequently studied nanoparticles for core flooding include silica, graphene, and titanium dioxide (TiO2)¹⁹. Concurrently, low-salinity or “smart” water injection has gained traction for carbonate reservoirs, with mechanisms primarily attributed to wettability alteration via modifications to the electrical double layer at the rock surface^20–27. While the exact mechanism of low-salinity water remains debated, its synergy with chemical EOR methods, such as surfactant or polymer flooding, has shown enhanced recovery^28–33. However, the high cost of these chemicals³⁴ has spurred interest in hybrid approaches. A novel strategy involves combining nanoparticles with engineered low-salinity water to create synergistic nano-brine formulations for carbonate EOR. Yarahmadi et al., in the presence of a hybrid nano-fluid consisting of silica nano-particles, a cationic surfactant, and low-salinity water, were able to effectively change the wettability of the rock, reduce the interfacial tension, and significantly increase oil recovery from carbonate reservoirs³⁵. Roustaei et al. performed static tests at ambient conditions and identified 0.3 wt% as an effective concentration for silica nano-particles in modifying surface wettability³⁶. Saboori et al. evaluated alumina nano-fluids with different base fluids, concentrations, and temperatures on carbonate wettability. Using 0.05 wt% alumina nano-particles in an ethanol-based fluid at 80 °C, they increased the contact angle from 57.27° to 154.07° for oil/water systems and from 45° to 151.66° for condensate/water systems³⁷. Khaksar-Manshad et al. applied ZnO₂/SiO₂ nano-composites in carbonate reservoirs and showed that a 2000 ppm ZnO₂/SiO₂ nano-fluid in distilled water achieved the lowest interfacial tension while also producing the greatest contact angle reduction to 65.5°. During secondary recovery, this deionized water-based nano-fluid recovered 62.14% of the original oil in place. When used as a tertiary recovery method, it increased oil recovery from 44% to 65.41% original oil in place³⁸. Despite these advances, a significant research gap persists. Generally, most investigations focus on macroscopic effects of single or hybrid components, leaving the design and behavior of custom multi-component nanofluids engineered to co-optimize multiple interfacial forces simultaneously poorly understood. Specifically, the systematic development of nanoparticles functionalized with specific chemicals to precisely control IFT, wettability, and structural disjoining pressure in tandem with optimized brine chemistry is underexplored. Furthermore, while the influence of pH on nanoparticle stability is acknowledged^39–42, its specific role and optimization for wettability alteration in carbonate systems remain unclear. Many prior studies report only minimal changes in contact angle and IFT, highlighting a need for targeted interfacial engineering. Notably, the application and interfacial behavior of surface-modified TiO2 nanoparticles within such a synergistic, multi-mechanistic framework are particularly limited. Therefore, this study addresses these gaps by developing and evaluating a novel synergistic nano-brine formulation for carbonate EOR. We synthesize TiO₂ nanoparticles co-functionalized with potassium laurate and a non-ionic surfactant (Triton X-100) and disperse them in engineered low-salinity brine. Our work systematically investigates the co-optimization of interfacial properties colloidal stability, IFT, and rock wettability across a wide range of concentrations and pH conditions. The primary goal is to elucidate the hybrid mechanism by which this designed system enhances oil recovery, integrating IFT reduction, effective wettability alteration, and the amplification of structural disjoining pressure. By providing a comprehensive, mechanism-driven analysis, this research aims to offer valuable insights and a viable design strategy for advanced, cost-effective EOR materials, catering to a broad audience in energy science, petroleum engineering, and nanotechnology.

Experimental section

Materials

The synthesis procedure utilized titanium isopropoxide, isopropanol, potassium laurate, ethanol, acetic acid, Triton X-100, and deionized water. For the preparation of engineered low-salinity brine, the following salts were used: sodium chloride (11.8125 g/L), potassium chloride (0.5675 g/L), calcium chloride dihydrate (0.9075 g/L), magnesium chloride hexahydrate (6.1115 g/L), sodium sulfate (3.3575 g/L), and sodium bicarbonate (0.169 g/L). A core sample with dimensions of 5.445 cm in length and 3.805 cm in diameter was used, possessing a porosity of 17.3% and a permeability of 4.31 md. Crude oil sourced from a reservoir in western Iran was employed in the experiments, characterized by an API gravity of 18°, a density of 0.9463 g/cm³, and a viscosity of 5.12 cp. Compositional analysis indicated a content of saturates (60.43%), aromatics (21.29%), resins (10.84%), and asphaltenes (7.44%). The colloidal instability index exceeded 0.9, reflecting the instability of asphaltenes within the crude oil. All high-purity salts were obtained from Dr. Mojallaly Company. Generally, crude oil core has been studied for the first time on a laboratory scale in the presence of a novel nanofluid.

Synthesis process

Synthesis method of surface-modified TiO₂ nanoparticles with surfactant and potassium laurate salt

The general procedure for the synthesis and preparation of the nanofluid containing surface-modified TiO₂ nanoparticles with surfactant and potassium laurate salt is as follows. First, titanium dioxide was synthesized. In general, an acidic agent (acetic acid) was used in the process. In this regard, 2.5 mL of titanium isopropoxide was added to 225 mL of isopropanol in a container and stirred for 20 min at 30 °C. Subsequently, a solution containing 2.5 mL of ethanol and 1.2 mL of acetic acid was added while stirring. The resulting mixture was then stirred for 1 h to allow gel formation. Next, to synthesize the surface-modified nanoparticle composite, 1.8 mL of the non-ionic surfactant Triton X-100 and 0.5 g of potassium laurate salt were added to the previous mixture, and the solution was stirred for 1 h to form a dense gel-like solution. It was then placed in an oven at 80 °C for 1 h, resulting in a dried powder mixture. Finally, the powder was calcined in a furnace at 300 °C for 1 h. At the end of this process, the synthesized surface-modified composite was ready. In the next stage, to prepare the nanofluid, the synthesized surface-modified nanoparticles were synergistically prepared with low-salinity brine.

Preparation of nanofluid and dispersion measurement

Following calcination at 300 °C for 1 h, the dried powder of surface-modified TiO2 nanoparticles was used to prepare the nanofluid dispersions. Specifically, a measured mass (0.5 gr for a stock solution) of the synthesized powder was added to 50 mL of engineered low-salinity brine (23,000 ppm). The mixture was then subjected to sonication for 1 h using an ultrasonic bath to ensure uniform dispersion and break any soft agglomerates, resulting in a stable nanofluid suspension. This protocol was applied consistently to prepare all tested concentrations ranging from 40 to 300 ppm. Engineered low-salinity brine (23,000 ppm) was used as the solvent to prepare different nanoparticle concentrations (40, 60, 80, 100, 120, 140, 160, 180, 200, 220, 240, 260, 280, and 300 ppm).

Interfacial property measurement

The pendant drop technique is a well-established method for determining interfacial tension under controlled conditions. The schematic diagram of the IFT measurement setup is presented in Fig. 1. All measurements were conducted at ambient laboratory temperature (approximately 25 °C). The oil–water system consisted of crude oil (sourced from a reservoir in western Iran, with properties detailed in Sect.  2.1) as the droplet phase and the prepared nanofluid (or baseline engineered low-salinity brine) as the surrounding continuous phase. This method fundamentally involves analyzing the profile of an oil droplet formed as it emerges from a needle into a surrounding fluid. In this experiment, a U-shaped syringe was used to suspend an oil droplet at the tip of its needle. The procedure involved first filling a transparent, illuminated chamber with a nanofluid prepared at a specific concentration. Nanofluids were tested across a range of concentrations from 40 to 300 ppm in 20 ppm increments. The syringe needle, bearing the oil droplet, was then positioned within the chamber. A camera captured an image of the suspended droplet, which was subsequently analyzed using specialized software to calculate the IFT.

Fig. 1.

The scheme image of the interfacial tension measurement setup.

Contact angle

Wettability alteration study

Following the identification of a stable nanofluid sample and completion of the initial phase of experiments, the subsequent phase examined the effect of nanofluids exhibiting suitable stability on altering rock wettability. In general, the sessile drop method was employed to determine wettability alteration and measure the contact angle. Rock wettability is a critical factor in oil displacement within porous media. The pore spaces of an oil reservoir contain multiple fluids, each with distinct surface adhesion properties. This creates a competitive environment where different fluids adhere to the rock surface with varying strengths, resulting in unique contact angles for each fluid. The contact angle serves as a key indicator of rock wettability. In this research, contact angle measurements were employed to analyze wettability alterations. The procedure involved preparing thin rock sections from core samples using a core cutting apparatus. Each section was subdivided into four slices, which were then polished with a specialized abrasive on a grinding wheel to produce a smooth, rounded surface suitable for wettability testing. During polishing, water was sprayed onto the grinding wheel to minimize frictional heat. The thin sections were polished by moving them clockwise across the wheel. Experiments were conducted using a straightforward setup at ambient temperature. To induce oil-wet characteristics, the rock slices were aged in crude oil at 80 °C for 40 days. Subsequently, the carbonate cores were removed from the crude oil and oven-dried. The aged carbonate core fragments were then immersed in nanofluid solutions of varying concentrations at 80 °C for 72 h. Following this treatment, the polished surface of the dried samples (dried at 80 °C for 2 h) was positioned horizontally in the solution, and an oil droplet was placed on its upper surface. Contact angles were determined by imaging the droplets adhering to the carbonate surface. Notably, the contact angle was measured through the less dense fluid phase (the oil phase). It is worth noting that surface wettability is defined based on the contact angle in the three-phase system (water, oil, rock), namely water-wet (in the range of 0–75°), intermediate-wet (in the range of 75°-115°), and oil-wet (in the range of 115°-180°)⁴³.

Investigation of the stability

The stability of the nanoparticles against sedimentation was evaluated using a combination of four analytical techniques: visual observation, zeta potential measurement, particle size analysis, and spectrophotometry. A Malvern ZEN 3600 zetasizer (Malvern, England) was used to determine the zeta potential and particle size distribution, while a jenway UV-VIS 6105 Spectrophotometer was employed for the spectrophotometric assessment. Generally, zeta potential is a critical indicator of colloidal stability, with absolute values exceeding 30 mV signifying a stable suspension, whereas values between − 30 mV and + 30 mV suggest instability. Concurrently, particle size distribution analysis monitors the dispersion of nanoparticle sizes within the base fluid. A nanofluid demonstrating minimal change in particle size and no visible aggregation over time is considered to possess high stability.

Flow displacement experiment

The displacement apparatus of the core flooding measurement setup is presented in Fig. 2. Initial fluid saturations were established by first vacuum-saturating the core with simulated formation water to achieve 100% water saturation. Subsequently, crude oil was injected to displace movable water, establishing the initial oil saturation and leaving behind irreducible connate water saturation. The core sample had a pore volume (PV) of approximately 8.55 ml, calculated from its dimensions (5.445 cm length, 3.805 cm diameter) and porosity (17.3%). The initial oil saturation was determined based on the volume of oil injected relative to this pore volume. The core was then placed in the core holder, and water flooding was conducted at a constant rate of 0.5 ml/min until oil production ceased. Subsequently, a nanofluid solution (80 ppm) was injected into the core at the same flow rate for one pore volume to displace the remaining crude oil. This was followed by a second waterflooding stage, continued until no further oil was produced. The total oil recovery was calculated using Eq. 1. It is important to note that while the core aging for wettability alteration was performed at an elevated temperature of 80 °C, the core flood displacement experiment itself was conducted at ambient laboratory temperature (approximately 25 °C) to initially evaluate the nanofluid efficacy under controlled isothermal flow conditions.

Fig. 2.

A schematic of the core flooding laboratory setup.

^{Where, E is the oil recovery (%),V1 is the original crude oil volume (ml), and V0 is the cumulative volume of produced crude oil (ml)}.

Design of experiment

To systematically investigate the effect of nanoparticle formulation and concentration on key EOR performance indicators, a structured design of experiment was implemented. The primary goal was to identify the optimal formulation and concentration that maximize colloidal stability, minimize IFT, induce favorable wettability alteration, and ultimately enhance oil recovery in carbonate reservoirs. The experimental design was structured around three key factors across multiple levels: Nanoparticle Type (Unmodified TiO₂ vs. Surface-modified TiO2 functionalized with potassium laurate and Triton X-100), nanoparticle concentration (14 levels ranging from 40 to 300 ppm in 20 ppm increments), and solution pH (Two levels: pH 4.5 and pH 8, based on preliminary stability screening which indicated these pH values significantly influence colloidal stability). The response variables measured to evaluate performance included: colloidal Stability (zeta potential in mV and average particle size in nm), interfacial Property (oil-water IFT), rock-fluid interaction (contact angle in degrees on aged carbonate surfaces), and macroscopic performance (incremental oil recovery in % from core flood experiments). The design of experiment followed a two-phase approach. The first phase was a broad screening using a One-Factor-at-a-Time method across all concentration levels for both nanoparticle types at the identified optimal pH of 4.5. This phase generated comprehensive performance curves (zeta potential vs. concentration, IFT vs. concentration, contact angle vs. concentration) and pinpointed the optimal concentration (80 ppm). The second phase was a confirmatory test, where only the optimal formulation (80 ppm surface-modified nanofluid at pH 4.5) was used in the resource-intensive core flooding experiment to validate the integrated EOR performance. In this study, Table 1 summarizes the executed design of experiment matrix.

Table 1.

Design of experiment matrix for nanofluid EOR evaluation.

Experiment phase	Factor 1: nanofluid type	Factor 2: concentration (ppm)	Factor 3: pH	Primary response variables measured	Objective
Phase 1: Screening & optimization
Stability & interfacial screening	Surface-modified TiO2	40, 60, 80, 100, 120, 140, 160, 180, 200, 220, 240, 260, 280, 300	4.5, 8	Zeta potential, Particle size, Visual stability	Identify optimal concentration & pH for stability
IFT performance	Surface-modified TiO2	40, 60, 80, 100, 120, 140, 160, 180, 200, 220, 240, 260, 280, 300	4.5	Interfacial tension	Determine concentration for minimum IFT
Wettability alteration	Surface-modified TiO2	40, 60, 80, 100, 120, 140, 160, 180, 200, 220, 240, 260, 280, 300	4.5	Contact angle	Assess concentration for optimal wettability shift
Baseline comparison	Unmodified TiO2	40, 60, 80, 100, 120, 140, 160, 180, 200, 220, 240, 260, 280, 300	4.5	Zeta potential, IFT, Contact angle	Benchmark performance against modified nanoparticles
Phase 2: Core flood validation
Oil displacement efficacy	Surface-modified TiO2	80 (Optimal)	4.5 (Optimal)	Incremental oil recovery (%)	Validate integrated EOR performance under reservoir-like conditions

Results and discussion

Characterization of Surface-modified TiO₂ nanoparticles with surfactant and potassium laurate salt

This section presents the results obtained from Fourier-transform infrared spectroscopy, X-ray diffraction, and scanning electron microscopy analyses. Figure 3 displays all XRD patterns, illustrating their crystalline structures. The surface-modified nanoparticle exhibits an anatase orientation, which is attributed to the use of acid⁴⁴. Furthermore, Fig. 4 shows the FTIR spectra of both unmodified and surface-modified titanium dioxide nanoparticles in the range of 400–4500 cm^{− 1} (Fig. 4a and b)⁴⁵. A reduction in the intensity of all peaks was observed for the surface-modified nanoparticle, as shown in Fig. 4b. In Fig. 4a, stretching vibrations of hydroxyl groups appear as signals between 3100 and 3600 cm^{− 146,47}. Peaks at 1125 cm^{− 1}, 1070 cm^{− 1}, and 1040 cm^{− 1} correspond to the OR groups of tetra-n-butyl orthotitanate⁴⁸. Additionally, O-Ti-O and Ti-O-Ti groups are present in the range of 500–1000 cm^{− 1} (Fig. 4a)^45,49,50. As seen in Fig. 4a, the broad peak at 3450 cm^{− 1} and the peak between 1600 and 1640 cm^{− 1} are related to adsorbed surface water and associated hydroxyl groups⁵¹. The peak around 1074 cm^{− 1} is attributed to C-O stretching vibrations, while the strong bending vibration at 1420 cm^{− 1} corresponds to the Ti-OH group⁵². In the FTIR spectrum of the surface-modified oxide nanoparticle (Fig. 4b), the signal around 3300 cm^{− 1} indicates hydroxyl groups, suggesting the formation of a highly hydrophilic structure in the new composite. Figure 5 presents FESEM images of both surface-modified and unmodified titanium dioxide⁴⁵. FESEM images (Fig. 5b) show smaller individual particles after surface modification, with a more uniform morphology suggesting the surfactant layer.

Fig. 3.

X-ray diffraction pattern for the synthesized and surface-modified titanium dioxide sample⁴⁵.

Fig. 4.

Fourier transform infrared analysis of the synthesized and surface modified titanium dioxide sample⁴⁵.

Fig. 5.

Scanning electron microscopy of titanium dioxide (a) after surface modification and (b) before surface modification⁴⁵.

Nanofluids stability

According to Derjaguin-Landau-Verwey-Overbeek theory, the stability of nanoparticles in a solution depends on the attraction and repulsion forces in the solution, acting in opposite direction^53,54. If the attraction forces are higher than repulsive forces, the nanoparticles begin to agglomerate while the higher repulsive forces provide suspension stability⁵⁵. In this study, zeta potential increased (more negative) from − 52 to -58 mV as the nanoparticles rose from 40 ppm to 80 ppm, then decreased at higher concentrations. Considering this in mind, the concentration of 80 ppm was selected for the rest of the experiments. Generally, the average particle size of a nanofluid is reversely proportional to its zeta potential because of the nanoparticles agglomeration at low stable solutions⁵². In this regard, Fig. 6 is zeta vs. concentration, and Fig. 7 is the size distribution for 80 ppm only (about 66 nm). The results of the average size of nanoparticles were measured for concentrations of 40, 60, 80, 100, 120, 140, 160, 180, 200, 220, 240, 260, 280 and 300 ppm, which were obtained as 84, 78, 66, 71, 76, 79, 84, 87, 89, 92, 95, 115, 120 and 123, respectively, which is completely in agreement with the results of zeta potential in Fig. 6 (i.e., -52.88, -53.89, -58.56, -54.14, -51.53, − 50.34, -48.11, -47.22, -46.51, -45.23, -44.81, -43.58, -42.60, and − 41.22) for nanofluids containing (40, 60, 80, 100, 120, 140, 160, 180, 200, 220, 240, 260, 280, and 300 ppm), respectively).

Fig. 6.

Effect of various novel nanofluid concentration on the zeta potential.

Fig. 7.

Particle size distribution for 80 ppm novel nanofluid solution.

Based on the stability analysis, nanoparticles rapidly lose stability in high-salinity environments, even when stabilizers are used. Various adjustments such as altering pH, modifying stabilizer concentration, varying sonication time, or changing the sequence of material addition did not effectively extend the stability of the nanofluids. This occurs because high ionic strength in saline solutions strongly neutralizes the surface charge of the nanoparticles. Consequently, the only viable approach to enhance nanoparticle stability is to lower the salinity of the solution. Reducing salinity significantly improves the effectiveness of stabilizers compared to high-salinity conditions. For this reason, the most stable solution identified (80 ppm at pH 4.5, as shown in Fig. 8) was diluted tenfold to achieve the long-term stability required for extended imbibition experiments. Decreasing salinity, along with modifying the ionic composition of the injected water, can enhance nanoparticle performance. This aligns with the findings of Jafarbeigi et al.⁵⁶, who reported that both salinity reduction and increased temperature substantially improve nanoparticle efficiency.

Fig. 8.

Transparency of 80 ppm novel nanofluid at (a) pH = 8 and (b) pH = 4.5.

Effect of nanofluids on IFT

Figure 9 illustrates the interfacial tension of the nanofluid at varying concentrations. The oil-water interfacial tension without any additives measures 24.45 mN/m. Upon adding an 80 ppm nanofluid solution, this value drops to 1.16 mN/m, demonstrating the nanofluids ability to significantly lower interfacial tension. To isolate the contribution of the surfactants from that of the functionalized nanoparticles, a control experiment was performed. The IFT of the crude oil against the engineered low-salinity brine containing only Triton X-100 and potassium laurate (at the same concentrations used in the 80 ppm nanofluid synthesis) was measured. This surfactant-only solution reduced the IFT to 8.5 ± 0.3 mN/m. While this represents a significant reduction from the base brine-oil IFT (24.45 mN/m), it is substantially higher than the ultralow value of 1.16 mN/m achieved by the complete surface-modified TiO₂ nanofluid. This clear distinction demonstrates that while the surfactants contribute to IFT lowering, the synergistic combination with the surface-modified TiO₂ nanoparticles is responsible for the dramatic reduction to ultralow levels. This effect stems from the nanofluids surface, which possesses both hydrophilic and lipophilic groups, resembling the structure of surfactants. During stirring and shearing, nanofluid particles in the aqueous phase migrate to the oil-water interface, drawn by the oil phase. The long-chain alkyl groups on the particle surface embed into the oil, while the surface hydroxyl (OH) groups are attracted to the water. Consequently, the particles are pulled by both phases, partially offsetting the repulsive force between oil and water, which leads to a progressive decrease in interfacial tension as nanofluid concentration rises. Typically, when the nanofluid concentration reaches 80 ppm, adsorption at the oil-water interface saturates, and interfacial tension stabilizes. The subsequent increase in IFT observed at concentrations above 80 ppm (Fig. 9) can be explained by interfacial saturation and particle interactions at high loadings. Beyond the optimal concentration, excess nanoparticles in the bulk phase are prone to agglomeration, as indirectly evidenced by the gradual increase in average particle size at higher concentrations (Sect.  3.2). These agglomerates possess lower specific surface activity and pack less efficiently at the interface, diminishing their IFT-reduction efficacy. Furthermore, an over-crowded interface can become structurally rigid, potentially hindering the optimal orientation of the amphiphilic groups and reducing the dynamic stability of the interfacial film, leading to a measurable increase in IFT. This non-monotonic behavior underscores the critical importance of identifying an optimal nanoparticle dosage to achieve ultralow IFT without incurring the inefficiencies associated with excessive concentration. These experimental IFT results are directly consistent with the amphiphilic adsorption mechanism elaborated in Sect.  3.7. The significant reduction to an ultralow value of 1.16 mN/m at the optimal concentration confirms the efficient migration and adsorption of the surface-modified TiO2 nanoparticles at the oil-water interface. Their functionalized, amphiphilic structure allows the hydrophobic moieties to embed in the crude oil while hydrophilic groups anchor in the aqueous phase, effectively screening the interfacial cohesive forces. The subsequent increase in IFT beyond 80 ppm aligns with the onset of particle agglomeration and suboptimal interfacial packing, which diminishes the effectiveness of this adsorption mechanism. It is important to note that the IFT values reported here were measured using the pendant drop technique in a bulk fluid chamber, representing the intrinsic fluid-fluid interaction without the complicating influence of a solid rock surface. This setup isolates the effect of the nanofluid on the oil-brine interface, providing a clear foundation for understanding its interfacial activity prior to its interaction with the porous rock matrix during core flooding. Furthermore, the dilatational modulus between oil and water is 2.30 mN/m without additives. The introduction of nanomaterials increases the dilatational modulus, with higher concentrations yielding greater modulus values. The dilatational modulus rises to 30.22 mN/m with the addition of 80 ppm nanofluid. This occurs because nanomaterials readily adsorb onto the oil-water interfacial film, thickening and strengthening it, thereby increasing the dilatational modulus. Simultaneously, the amphiphilic nature of the nanofluid allows it to achieve a more balanced position at the interface, resulting in a higher dilatational modulus compared to TiO₂ nanoparticles.

Fig. 9.

Effect of various novel nanofluid concentration on the interfacial tension.

Contact angle

Effect of nano-fluids on wettability alteration

Figure 10 illustrates the contact angles of nanoparticles both before and after surface modification. The contact angle for the nanofluid (80 ppm) is 25.22°, indicating strong hydrophilicity. This property arises from the presence of abundant hydroxyl (OH) groups on the nanoparticle surface, which can form hydrogen bonds with oxygen atoms in water molecules. Consequently, these nanoparticles readily absorb atmospheric moisture, leading to aggregation into larger particles. To mitigate this effect, the nanoparticle surfaces were modified to establish an water-wetting film. This coating effectively prevents water molecules from directly interacting with the nanoparticles. The results presented in Fig. 10 illustrate the effect of various nanofluid concentrations on the contact angle of carbonate rock, demonstrating a clear trend where modifications in the concentration directly influence the rock wettability.

Fig. 10.

Effect of various novel nanofluid concentration on the contact angle of carbonate rock.

Flow displacement

A nanofluid formulated at a concentration of 80 ppm was prepared for chemical flooding and tested for its oil displacement capability in a core flooding experiment. The results indicated an initial oil recovery of 44.43% from primary water flooding. Following the injection of the nanofluid, a subsequent water flood achieved a total oil recovery of 75.54%. This represents an incremental recovery increase of 31.11%. Correlating these findings with prior performance evaluations suggests that the reduction of oil-water interfacial tension and the alteration of rock wettability are the primary mechanisms behind the improved recovery from nanofluid flooding. It is important to note that this core flood experiment served as a targeted validation of the optimal formulation identified through comprehensive screening. While the 31.11% incremental recovery under the specific conditions tested (permeability of 4.31 md, oil-wet aged carbonate) is a strong positive indicator, the single-core nature of the test limits direct assessment of repeatability and sensitivity to reservoir heterogeneity. This represents a recognized limitation of the present study, and future work will require repetitive floods and investigations across a range of rock properties to fully generalize the recovery performance. Generally, Table 2 provides an overview of the primary characteristics including zeta potential, contact angle, and interfacial tension for both surface unmodified TiO₂ nanoparticles in low-salinity brine and surface-modified nanoparticles functionalized with low-salinity brine (novel nanofluid).

Table 2.

An overview of essential characteristics including zeta potential, contact angle, and interfacial tension for both unmodified TiO₂ nanoparticles in low-salinity brine and novel nanofluid.

Components	Concentration (ppm)	Interfacial tension (mN/m)	Contact angle (degree)	Zeta potential (mV)
Unmodified TiO2 nanoparticles with low-salinity brine	40	9.92 ± 0.002	55.3 ± 0.08	-37.6 ± 0.1
	60	8.96 ± 0.006	52.3 ± 0.04	-39.3 ± 0.3
	80	8.12 ± 0.001	50.1 ± 0.02	− 40.2 ± 0.5
	100	8.62 ± 0.003	51.5 ± 0.02	-39.8 ± 0.2
	120	9.11 ± 0.007	53.6 ± 0.01	-38.5 ± 0.6
	140	9.52 ± 0.001	57.6 ± 0.06	-36.2 ± 0.3
	160	10.11 ± 0.005	59.8 ± 0.03	-36.8 ± 0.4
	180	10.56 ± 0.004	60.4 ± 0.01	-35.3 ± 0.3
	200	10.83 ± 0.002	62.5 ± 0.07	-35.9 ± 0.2
	220	11.24 ± 0.007	63.4 ± 0.06	-34.4 ± 0.3
	240	11.63 ± 0.003	65.8 ± 0.05	-33.8 ± 0.1
	260	11.92 ± 0.008	66.9 ± 0.09	-33.6 ± 0.2
	280	12.21 ± 0.003	72.5 ± 0.06	-32.6 ± 0.4
	300	12.45 ± 0.002	42.9 ± 0.07	-31.9 ± 0.1
Novel nanofluid	40	2.22 ± 0.006	27.35 ± 0.02	−52.88 ± 0.3
	60	1.89 ± 0.004	26.23 ± 0.04	−53.89 ± 0.2
	80	1.16 ± 0.001	25.22 ± 0.03	-58.56 ± 0.1
	100	1.56 ± 0.003	25.91 ± 0.03	-54.14 ± 0.4
	120	1.91 ± 0.005	26.87 ± 0.05	-51.53 ± 0.5
	140	2.11 ± 0.002	28.44 ± 0.04	−50.34 ± 0.2
	160	2.43 ± 0.003	29.43 ± 0.08	-48.11 ± 0.1
	180	2.81 ± 0.005	30.23 ± 0.01	-47.22 ± 0.4
	200	3.32 ± 0.004	31.56 ± 0.04	−46.51 ± 0.3
	220	3.72 ± 0.008	31.89 ± 0.01	-45.23 ± 0.2
	240	4.23 ± 0.003	32.25 ± 0.05	-44.81 ± 0.1
	260	4.72 ± 0.008	33.43 ± 0.08	-43.58 ± 0.4
	280	5.23 ± 0.007	34.25 ± 0.02	-42.60 ± 0.2
	300	5.81 ± 0.002	34.52 ± 0.07	−41.22 ± 0.1

Explicit reporting of measurement uncertainties

Measurement uncertainties are reported alongside all primary data in Table 2, with values for IFT, contact angle, and zeta potential presented as mean ± standard deviation (e.g., 1.16 ± 0.001 mN/m, 25.22 ± 0.03°, -58.56 ± 0.1 mV for the optimal 80 ppm formulation). These errors originate from instrumental resolution and minor experimental variation, and their small magnitude demonstrates the high reproducibility of our methods. The key result, an incremental oil recovery of 31.11%, was calculated from core flood volumes measured with an accuracy of ± 0.1 ml; using error propagation principles, its absolute uncertainty is estimated within ± 0.5–0.7%, a precision acceptable for such evaluations. To ensure robustness, a multi-technique verification strategy provides internal consistency: stability is assessed not only by zeta potential but also via particle size analysis where an inverse correlation with size validates the readings and is further confirmed by long-term visual. Similarly, the oil displacement mechanism is supported by a congruent set of independent data points including ultralow IFT, a strongly water-wet contact angle, high colloidal stability, and the significant recovery factor itself. This synergy strengthens the conclusiveness of our findings and mitigates potential errors from any single method. All key quantitative results are from triplicate measurements, and the internal consistency across techniques validates the reported trends and the identified optimum formulation.

Mechanism of synthetic nanofluids in porous medium

The EOR performance of the synthesized nanofluid arises from a synergistic, multi-component design that co-optimizes interactions across the oil/water/rock system. The nanofluid consists of titanium dioxide nanoparticles co-functionalized with potassium laurate and the non-ionic surfactant Triton X-100, dispersed within an engineered low-salinity brine (23,000 ppm). The pristine, hydrophilic titanium dioxide surface is rendered amphiphilic through covalent attachment of organic modifiers. Potassium laurate provides long alkyl chains (hydrophobic) and anionic carboxylate headgroups, while Triton X-100 contributes additional hydrophobic character and steric stabilization via its polyethylene oxide chain. This creates a hybrid organic-inorganic structure with a polar titanium dioxide core and an amphiphilic shell. When dispersed in the tailored low-salinity brine (23,000 ppm), the nanoparticles achieve exceptional colloidal stability (zeta potential = -58.46 mV at 80 ppm, pH 4.5), due to electrostatic repulsion from the carboxylate groups, which is preserved by the low ionic strength of the brine. The amphiphilic nanoparticles migrate to the oil–water interface, where their hydrophobic moieties embed into the crude oil (containing saturates, aromatics, resins, and asphaltenes) and their hydrophilic groups remain in the aqueous phase. This adsorption disrupts cohesive forces between oil and water molecules, reducing IFT from 24.45 mN/m to an ultralow value of 1.16 mN/m. The nanoparticles also form a rigid interfacial film, indicated by an increased dilatational modulus, which stabilizes oil droplets and hinders coalescence. Wettability alteration and structural disjoining pressure in porous carbonate rock, the nanofluid operates through combined adsorption and disjoining-pressure effects. The engineered low-salinity brine first weakens the bond between the oil-wet organic layer (e.g., asphaltenes) and the rock surface by modifying the electrical double layer. The amphiphilic nanoparticles then adsorb onto the rock, displacing the oil film and exposing their hydrophilic groups outward, shifting the wettability from oil-wet to strongly water-wet (contact angle ≈ 25°). Crucially, when a thin film of nanofluid forms between the rock and oil, the confined nanoparticles generate a strong repulsive structural disjoining pressure due to entropic ordering. This osmotic-like force further displaces the oil phase and stabilizes the water-wet film. Synergistic Recovery Mechanism The overall EOR mechanism is a hybrid of surfactant-like IFT reduction and nanoparticle-specific phenomena. The surface-modified TiO2 acts as an amphiphilic agent that lowers IFT and adsorbs onto the rock, while the engineered low salinity brine (23,000 ppm) ensures nanoparticle stability and preconditioning of the rock surface. The resultant synergy combining ultralow IFT, durable wettability alteration, and structural disjoining pressure efficiently mobilizes and displaces trapped oil in carbonate reservoirs. The synergy (nano-brine) arises from the fact that the engineered brine is not merely a passive carrier fluid. Its optimized ionic composition (e.g., specific levels of Ca²⁺, Mg²⁺, SO₄²⁻) and low total salinity are critical for (a) maintaining the high colloidal stability of the nanoparticles (as evidenced by the high zeta potential of -58.46 mV at 80 ppm, pH 4.5), and (b) preconditioning the carbonate rock surface by modifying its electrical double layer to facilitate subsequent nanoparticle adsorption. In turn, the functionalized nanoparticles potentiate the brine action by introducing new, powerful mechanisms ultralow interfacial tension reduction and structural disjoining pressure that a brine alone cannot achieve. This interdependent, co-optimized system is the essence of the synergistic nano-brine.

Design of experiment

In this section, this structured approach efficiently identified 80 ppm surface-modified TiO₂ nanofluid at pH 4.5 as the optimal formulation, which delivered a high zeta potential (-58.46 mV), ultralow IFT (1.16 mN/m), a strongly water-wet contact angle (25.22°), and a significant incremental oil recovery of 31.11%.

Economic viability

The economic promise of the developed synergistic nano-brine system is anchored in quantifiable parameters derived from this study and can be preliminarily assessed through comparison with conventional chemical EOR methods, particularly surfactant flooding. While a full field-scale techno-economic analysis incorporating scaling factors, transportation, and long-term injectivity is a necessary next step, key economic indicators can be directly calculated from our experimental results. The most significant cost advantage originates from the ultra-low optimal concentration of 80 ppm (0.008 wt%). In contrast, surfactant floods typically require active chemical concentrations in the range of 0.1 to 1.0 wt% to achieve effective interfacial tension reduction, representing a 12.5 to 125-fold higher mass requirement per volume of injected fluid. A first-order cost comparison illustrates this point. Assuming a bulk cost for a conventional surfactant like alpha olefin sulfonate at approximately $4/kg and a projected scaled-up production cost for our surface-modified titanium oxide nanoparticles at $12.5/kg, the chemical cost per cubic meter of injection fluid is roughly $20 for surfactant (at 0.5 wt%) compared to $1 for the nanofluid. This suggests a potential reduction in chemical purchase cost of ~ 95% per unit volume, a decisive advantage even if nanomaterial production costs remain higher per kilogram. This economic benefit is compounded by the performance synergy demonstrated in Sect. 3.3. The surfactant-only control solution achieved an IFT of 8.5 mN/m, whereas the complete nanofluid reached an ultralow 1.16 mN/m. Achieving similar ultralow IFT with surfactants alone would necessitate even higher and more costly concentrations or more expensive specialty surfactants. Furthermore, the use of engineered low-salinity brine (23,000 ppm) as the base fluid leverages the established, low-cost principles of “smart water” flooding, avoiding expensive organic solvents or custom brines. Our findings align with economic assessments in nano-EOR literature, where studies indicate that nanoparticle concentrations of 100–500 ppm can yield acceptable chemical costs per barrel of incremental oil⁵⁷. Our system operates at the lower boundary of this range (80 ppm) while delivering high recovery (31.11%). The synthesis pathway, utilizing commercially available modifiers (potassium laurate, Triton X-100) and standard sol-gel/calcination steps, is inherently compatible with scale-up and continuous manufacturing processes, which are critical for cost reduction. In conclusion, while definitive claims of economic viability require a dedicated techno-economic analysis, the experimental data presented here provide a robust foundation for such an analysis. The ultra-low optimal dosage, the clear performance superiority over surfactant benchmarks, and the significant incremental recovery collectively indicate a strong economic potential. The economic viability of this nano-brine system is therefore presented as a highly probable outcome based on its fundamental cost-structure advantages, pending the detailed engineering and economic modeling appropriate for pilot-scale design.

Conclusion

This study successfully demonstrates the transformative potential of a designer nanofluid strategy that integrates interfacial engineering with tailored brine chemistry for enhanced oil recovery in carbonate reservoirs. By co-functionalizing titanium oxide nanoparticles with potassium laurate and Triton X-100 and dispersing them in engineered low-salinity brine, we have developed a synergistic nano-brine system that fundamentally alters fluid-fluid and fluid-rock interactions. The primary achievement of this work lies in the co-optimization of multiple EOR mechanisms within a single formulation. The designed system simultaneously achieves exceptional colloidal stability, ultralow interfacial tension, and a decisive shift from oil-wet to strongly water-wet conditions in aged carbonate core. This multi-mechanistic action, validated by a significant incremental oil recovery, is not merely additive but synergistic, arising from the interdependent roles of the functionalized nanoparticles and the engineered brine. The nanoparticles act as robust, amphiphilic agents that potentiate disjoining pressure and interfacial film strength, while the low-salinity brine ensures their stability and preconditions the rock surface. Beyond the specific performance metrics, this research provides a generalizable design and optimization framework for advanced chemical EOR. The systematic approach from targeted synthesis and comprehensive interfacial screening to mechanistic validation offers a blueprint for developing next-generation materials where surface chemistry is precisely tuned to control reservoir-scale forces. This work directly addresses a critical gap in the field by moving beyond the study of macroscopic effects of single components to the deliberate engineering of multi-component systems for simultaneous interfacial control. The implications of this study are twofold. From a scientific perspective, it clarifies the hybrid mechanism by which surface-modified nanoparticles interact with optimized brines to mobilize trapped oil, contributing to a more fundamental understanding of nanofluid-assisted recovery in carbonates. From a practical standpoint, the identified ultra-low optimal concentration and the inherent scalability of the synthesis pathway underscore the potential for cost-effective application. While field-scale deployment requires further validation regarding heterogeneity and long-term injectivity, this laboratory-scale proof-of-concept provides a robust and promising foundation for pilot-scale design. Consequently, this research paves the way for the development of precision-engineered, sustainable chemical EOR technologies capable of unlocking substantial residual oil resources in complex carbonate formations worldwide.

Author contributions

Ehsan Jafarbeigi: Conceptualization, Data curation, Formal analysis, Investigation, Methodology, Resources, Writing-original draft. Ehsan Kamari: Conceptualization, Data curation, Formal analysis, Investigation, Methodology, Resources, Writing-original draft.

Funding

The authors declare that no financial support was received for the research, authorship, or publication of this article.

Data availability

All data generated or analyzed during this study are included in this manuscript.

Declarations

Competing interests

The authors declare no competing interests.