Synergy Between CTAB, AOT, TiO2 And CuO NPs for Surface Properties Modifications; Effects  of Acidic Crude Oil and Syntehtic Mixed Resinous and Asphaltenic Oil and Saline Water

Synergy Between CTAB, AOT, TiO2 And CuO NPs for Surface Properties Modifications; Effects of Acidic Crude Oil and Syntehtic Mixed Resinous and Asphaltenic Oil and Saline Water | Research Square window.SnipcartSettings = { analytics: { enabled: false } }; (function() { var accessVector = localStorage.getItem('access_vector') || ''; window.dataLayer = window.dataLayer || []; if (accessVector) { window.dataLayer.push({ user: { profile: { profileInfo: { snid: accessVector } } } }); } })(); (function(w,d,s,l,i){w[l]=w[l]||[];w[l].push({'gtm.start':new Date().getTime(),event:'gtm.js'});var f=d.getElementsByTagName(s)[0],j=d.createElement(s),dl=l!='dataLayer'?'&l='+l:'';j.async=true;j.src='https://www.googletagmanager.com/gtm.js?id='+i+dl;f.parentNode.insertBefore(j,f);})(window,document,'script','dataLayer','GTM-K279D39R'); Browse Preprints In Review Journals COVID-19 Preprints AJE Video Bytes Research Tools Research Promotion AJE Professional Editing AJE Rubriq About Preprint Platform In Review Editorial Policies Our Team Advisory Board Help Center Sign In Submit a Preprint Cite Share Download PDF Article Synergy Between CTAB, AOT, TiO2 And CuO NPs for Surface Properties Modifications; Effects of Acidic Crude Oil and Syntehtic Mixed Resinous and Asphaltenic Oil and Saline Water Firooz Abbasi Larki, Seyednooroldin Hosseini, Mohammad Abdideh, and 1 more This is a preprint; it has not been peer reviewed by a journal. https://doi.org/ 10.21203/rs.3.rs-8232999/v1 This work is licensed under a CC BY 4.0 License Status: Posted Version 1 posted You are reading this latest preprint version Abstract It is well established that the presence of chemicals and nanoparticles (NPs) in aqueous solutions has a significant impact on surface properties, particularly in the context of interactions with oil components. The asphaltene and resin fractions of crude oil, regardless of the oil type, greatly influence surface phenomena. In light of these facts, the current investigation aims to assess the impacts of two surfactants—dioctyl sulfosuccinate sodium (AOT) and cetrimonium bromide (CTAB)— (with concentration of 0-2000 ppm) along with titanium oxide (TiO 2 ) (with concentration of 0-500 ppm) and copper oxide (CuO) nanoparticles (NPs) (with concentration of 0-250 ppm) on interfacial tension (IFT) reduction and wettability alteration, using contact angle (CA) analysis for two types of acidic crude oil (ACO) and synthetic mixed resinous and asphaltenic oil (SMRAO). The measurements revealed that AOT is more efficient for IFT reduction, especially when using 50% diluted Persian Gulf water (DPGW). It was found that replacing distilled water (DW) with DPGW has a significant effect on IFT reduction by reducing the IFT values from 33.5 and 26.2 mN/m for ACO and SMRAO to 23.6 and 19.9 mN/m for ACO and SMRAO in contact with DPGW, respectively, likely due to the presence of sulfate ions and other ions that can function as “smart water.” In essence, the results indicated that the use of DPGW enhances the surface activity of the aqueous solution, and the addition of surfactants maximizes this effect by reducing the IFT value to minimum values of 0.95 and 0.69 mN/m for AOT solutions with concentration of 2000 ppm dissolved in DPGW in contact with ACO and SMRAO, respectively. In the second stage, the effects of surfactants on wettability alteration were investigated through contact angle measurements. These tests demonstrated a substantial impact of DPGW and the dissolved surfactants on wettability alteration. Specifically, the individual effect of DPGW led to a reduction in CA from 141.2° and 152.9° for ACO and SMRAO with DW, down to 98.5° and 91.1°, respectively which was toward neutral or mixed wettability conditions. Further measurements indicated that the presence of surfactants can enhance wettability alteration capabilities, with AOT showing a greater effect, resulting in contact angles of 40.1° and 39.7° for ACO and SMRAO, respectively. Notably, both IFT and CA measurements indicated that systems dealing with SMRAO experienced better IFT reduction and more effective wettability alteration, attributed to the surface-active nature of the resin and asphaltene, which act as additional surfactants. Moreover, the acidic nature of these fractions may provide additional opportunities for in-situ soap production and saponification processes that function as surfactants. The presence of NPs, specifically TiO 2 and CuO at concentrations of 0-500 ppm and 0-250 ppm, respectively, showed an improved potential for wettability alteration, trending toward a more water-wet condition, with TiO2 (500 ppm) in AOT (1000 ppm) solutions demonstrating superior results with CA values of 27.7 o and 23.3 o for ACO and SMRAO, respectively. Besides, the synergistic impact of these two NPs were examined on the wettability alteration using a solution activated with 1000 ppm of CTAB and AOT with concomitant presence of 100 ppm of TiO 2 and 100 ppm of CuO on the CA values. The measurements revealed a significant reduction in CA with lower amount of NPs demonstrating an excellent synergistic effect of chemicals with each other with minimum CA values of 31.2 o and 26.6 o for ACO and SMRAO, respectively, for AOT solution and those NPs. Finally, several optimum chemical formulations along with the solutions prepared with hybrid NPs were used to perform core flooding experiments revealed the possibility of producing 12.8 % based on original oil in place (OOIP) and 16.6% based on OOIP if 30 days of soaking are replaced with quick flooding, since wettability alteration can reach its ultimate impact during 30 days of soaking. Physical sciences/Chemistry Earth and environmental sciences/Environmental sciences Physical sciences/Materials science Synergy IFT Wettability alteration AOT CTAB Nanoparticles Saponification Figures Figure 1 Figure 2 Figure 3 Figure 4 1. Introduction In recent years, there has been considerable interest in using enhanced oil recovery (EOR) techniques to boost oil output from both active and depleted reservoirs, driven by decreasing oil production and increasing demand. Several methods have been suggested, each with distinct benefits. These include chemical injection to change wettability and lower interfacial tension (IFT), the use of nanoparticles (NPs) to alter surface characteristics, gas injection to initiate swelling mechanisms or aid in oil extraction through miscible or immiscible methods, and thermal techniques to mobilize heavy crude oils. Among the different possibel techniques, injecting chemicals inclduing alkaline, surfacatnt, polymers, NPs, etc are getting much interest due to their capabilities to activate severeal mechanims inclduing changing wettability 1 , 2 , viscosity modification, or IFT reduction 3 – 5 . Among these chemicals, surfactants play a crucial role in EOR processes by altering the interaction between oil, water, and rock in reservoirs. These compounds are composed of two distinct parts: a hydrophilic (water-attracting) head and a hydrophobic (water-repelling) tail. This unique structure allows surfactants to reduce IFT between oil and water, making it easier to mobilize trapped oil. Surfactants are categorized based on the charge of their hydrophilic head to, a) anionic aurfactants which carry a negative charge and are effective in reducing IFT in alkaline conditions, making them suitable for certain oil types, b) cationic surfactants which possessing a positive charge, these surfactants are often used for their strong adsorption onto negatively charged mineral surfaces, enhancing oil displacement, c) nonionic surfactants which they do not carry a charge and can be effective across a wider range of pH and salinity levels, making them versatile for various EOR applications, and d) zwitterionic surfactants which possess both positive and negative charges concomitanatly capables them to tolerate different environmental conditions, providing benefits in specific EOR situations. The point is that surfacatnst can facilitate EOR purposes by activating primary mechanims of wettability alteration by modifying the wettability of rock surfaces from hydrophilic to hydrophobic (or vice versa), surfactants help to release oil that is otherwise trapped in the pores of the reservoir rock and reducing IFT between oil and water, which promotes the formation of in-situ micro-emulsions. This is the net effects of these two phenomena allows for more efficient oil mobilization. In the light fo these facts, the strategic application of surfactants in EOR can significantly enhance oil recovery rates, making it an essential aspect of modern oil extraction techniques 6 . The impact of surfactants on IFT reduction is well understood, but it’s crucial to delve deeper into the relationship between surfactants and carbonate wettability. While existing research has provided valuable insights, it has also highlighted remarkable variability in data outcomes. This inconsistency signals that there is much more to uncover regarding how different surfactants influence carbonate wettability. Given that this area of study is not only fundamental to enhancing our understanding of oil recovery processes but also vital for optimizing environmental applications, it is imperative that we conduct more comprehensive investigations. By doing so, we can pave the way for more reliable and efficient use of surfactants in various industries, ultimately driving innovation and progress. The evidence is there; further exploration in this field is not just desirable but necessary for future advancements. For example, the contact angle (CA) on a carbonate surface treated with 100 ppm CTAB was reported as 102° 7 , while other reports revealed that a CA of 131° 8 for the same concentration and type of surfactant, highlighting the considerable data variability. Besides, Derikvand et al. 9 found that a CA of 81° on a carbonate surface modified with CTAB solution with concentration of 300 ppm, while another carbonate sample being contacted to 330 ppm of CTAB revealed a CA of 35° 8 . Moreover, they reported that there is ample difference between the impact of SDBS and CTAB on wettability alteration. Based on the results obtained by Hajibagheri et al. 7 , the lowest CA was obtained for SDBS solution with concentration of 1,000 ppm led to CA value of 73°, while a much lower CA value of about 30° was obtained if CTAB solution with similar concentration being used 7 . According to these findings it seems that the findings are inconsistent through the wetting behavior of carbonate surfaces being contacted with surfactants which can be not only correlated to the rock mineralogy, surface roughness, the structure and texture of the surface, the operating conditions concerning pressure and temperature, and the surface chemistry of the rock or mineral surfaces but also to surface cleaning technique which can introduce bias into the measured CA values 10 , 11 . The point is that although there are large numbers of investigations correlated the emulsions stability and surfactant adsorption capabilities zeta potential 12 – 15 , only a limited number of reports existed about the chemical functional groups and wetting behavior 15 – 18 . Despite existing knowledge, the exact factors that affect how surfactants change the wettability of carbonate surfaces—taking into account different mineral compositions and surface traits—are still not well understood and require additional investigation. It's important to highlight that carbonate rocks can have considerable differences in their mineral makeup; even samples with comparable mineralogy can display distinct wetting properties. Research has indicated that carbonate samples from the same formation may behave differently due to variations in local minerals, pore structures, and surface roughness. 18 . Alongside the well-established impacts of surfactants on rock wettability changes and the reduction of IFT, there has been a growing interest in the use of NPs for altering surface properties in recent decades. This increased focus is due to the distinct advantages NPs provide in surface modification via various mechanisms. 19–21 These mechanisms primarily include their adsorption onto rock surfaces 22 which changes wetting conditions and enhances the thermal stability of the systems 23, 24 . Recently, the use of NPs has gained traction as EOR agents in the oil and gas industry because they can maintain fluid stability over extended periods 25 , 26 . The appeal of NPs lies in their unique characteristics, such as a high surface area-to-volume ratio, extremely small size, low toxicity, and cost efficiency, with silica and clay NPs being common examples. 27,28 . These NPs can act as effective sacrificial agents, reducing the adsorption of surfactants and their corresponding loss in reservoir environments. 29,30 . Additionally, surfactants are often prone to degradation in the harsh conditions of oil reservoirs; here, NPs significantly help by improving the thermal stability of EOR systems. They also enhance the long-term stability of nanofluids, which is vital for effective field application. When used together with low-salinity surfactant flooding, NPs greatly lessen surfactant adsorption on reservoir rock surfaces, promoting a transition from an oil-wet to a water-wet state. While NPs alone show remarkable potential for changing wettability and boosting oil recovery, larger NPs can agglomerate and precipitate under high temperature and salinity conditions, which complicates their practical use. Thus, it is essential to modify the surfaces of these particles to produce thermally and kinetically stable nanofluids. Some research teams suggest that the alteration of wettability is the key mechanism behind EOR processes. 29 – 31 . Recent studies have highlighted the influence of silica NPs on contact angle measurements, revealing how variations in their concentration can lead to significant changes. These findings indicate that silica NPs play a crucial role in altering reservoir wettability, successfully shifting it from an oil-wet state to a water-wet state. This shift in wettability is essential for enhancing oil recovery processes and optimizing reservoir management. Research conducted by Hou et al. 31 focuses on the intricate micro-mechanisms responsible for altering the wettability of oil-wet sandstone surfaces, an essential aspect of enhancing oil recovery processes. The study specifically investigates the effects of positively charged calcium carbonate NPs and cationic-anionic gemini surfactants on these surfaces. The findings reveal significant alterations in wettability as a result of these treatments. More precisely, the researchers documented a remarkable decrease in the contact angle of oil droplets on the modified surfaces. Initially, the contact angle measured 130° for untreated oil-wet sandstone, indicating a strongly hydrophobic surface. However, after treatment with calcium carbonate NPs, this angle dropped to 60°. Further treatment with gemini surfactants reduced the contact angle even more, leading to values of 45° and eventually reaching as low as 36° when the surfaces were treated with the resulting nanofluids. Such reductions demonstrate a substantial transition towards more hydrophilic properties, which is crucial for enhancing oil mobilization and recovery. In addition to the improvements in wettability, the reduction of IFT between oil and water is highlighted as a vital factor influencing oil recovery. Lower IFT can facilitate better displacement of oil from the pores of the sandstone, thereby contributing to more efficient extraction processes. Such insights underscore the importance of using advanced materials and strategies to tackle challenges associated with oil recovery from complex geological formations. The combination of modified wettability and reduced IFT presents a promising approach for enhancing oil extraction efficiency in various geological settings. This research, therefore, not only expands our understanding of surface chemistry but also opens new avenues for developing more effective techniques in the oil and gas industry. 32,33 . Rezvani et al. 32 showed that the integration of seawater with a chitosan-coated Fe 3 O 4 nanocomposite significantly reduced the interfacial tension (IFT) of crude oil, decreasing it from 22.49 mN/m to 14.47 mN/m as the nanocomposite concentration increased. In a similar study, Kazemzadeh et al. 33 achieved a substantial reduction in the IFT of an oil-water system, decreasing it from 39 mN/m (using distilled water) to 13.2 mN/m by employing a synthesized TiO 2 /SiO 2 nanocomposite. These results highlight the essential roles of modifying wettability and reducing interfacial tension in enhancing the effectiveness of (EOR strategies. This investigation aims to comprehensively assess the effects of two powerful surfactants, sodium cetrimonium bromide (CTAB) and sodium bis-(2-ethylhexyl) sulfosuccinate (AOT), using diluted Persian Gulf water (DPGW) as a testing medium. The study is particularly notable as it explores both acidic crude oil and synthetic mixed resinous and asphaltenic oil (SMRAO) for the first time. By analyzing these combinations, the impact of chemical formulations—including surfactants and nanoparticles—on interfacial tension (IFT) reduction and wettability alteration, which are critical factors in enhancing tertiary oil recovery through core flooding experiments can be evaluted. The research will systematically investigate a range of surfactant concentrations from 0 to 2000 ppm and nanoparticle concentrations between 0 to 500 ppm for TiO2 and CuO (0-250 ppm), along with hybrid solutions at a concentration of 1000 ppm for each NPs and optimum surfacatnt concnetration. The goal is to observe how these components interact and influence IFT and wettability. In addition, various injection strategies will be examined to identify the most effective method for tertiary oil recovery. This will involve an extended 30-day soaking period designed to enhance the effects of wettability alteration, ensuring our findings contribute valuable insights to the field of EOR techniques. By positioning this study at the forefront of this area, the aim of this investigation was set to optimize the sequence of chemical formulation injections to achieve maximum efficiency in oil recovery processes. 2. Experimental procedure 2.1. Materials A sample of crude oil with a specific gravity of 0.86 and a total acid number (TAN) of 1.45 was graciously provided by the National Iranian South Oil Company (NISOC) asphaltene and resin fractions of 8.5% and 11.1%, respectively. This sample was utilized to extract the resin and asphaltene fractions, resulting in a synthetic oil sample. Chemicals such as CTAB and AOT were obtained from Sigma Aldrich (USA), boasting a purity greater than 97%, and were used directly without any additional processing or purification to prepare the solutions. Additionally, TiO2 and CuO nanoparticles were sourced from Borhan Company in Iran. For the saline water, it was collected from the Persian Gulf and then diluted with distilled water in equal proportions (50%-50% in volume), ensuring it's a suitable source for solution preparation. The other point to note is that the necessary Persian Gulf water for dilution to prepare the chemical solutions was collected from Asaluyeh Port. This water maintained the following composition: sodium (13,360 ppm), potassium (505 ppm), magnesium (1,580 ppm), calcium (438 ppm), chloride (25,012 ppm), and sulfate (3,410 ppm), with a total pH of 8.1. 2.3. Contact angle and IFT measurement In this investigation, a pendant drop method was employed, a technique derived from the sessile drop approach, to study the properties of liquid-solid interfaces. Specifically, this method allows for the precise measurement of CA, which is crucial for understanding wettability and surface interactions. To enhance the accuracy of our measurements, we integrated a drop shape analysis technique, known as the tangent method. This approach involves analyzing the curvature of the drop at its contact point with the surface, enabling us to determine the average contact angle with greater precision. This work was conducted using a device supplied from Fanavari Atiyeh Pouyandegan Exir Co. in Arak, Iran, which capable the operator to measure the CA and IFT with an acceptable level of accuracy A visual representation of the setup and measurements can be found in Fig. 2, highlighting the intricacies of the pendant drop method and the tangent method in action 34 ) (see Fig. 1 ). The pendant drop method is a sophisticated technique widely used in various scientific and engineering applications, particularly in the study of surface and interfacial phenomena. This method consists of two primary interconnected sections: drop suspension and image processing/capturing, each playing a critical role in ensuring accurate measurements and observations. The first section, drop suspension, is vital for the successful formation and manipulation of the droplet at the nozzle's tip. It employs an advanced XYZ positioning stage, which allows the operator to finely control the position of the droplet in relation to the substrate, such as a rock surface. This degree of control enables precise positioning of the droplet, whether in an upward or downward direction, which is crucial for various experimental setups. To achieve optimal droplet formation at the nozzle tip, the system is equipped with an automatic injection mechanism. This mechanism typically comprises a 500 µL glass syringe manufactured by Hamilton, USA, paired with a stainless steel U-shaped flat-end needle. The syringe's design allows for controlled and consistent delivery of the fluid, ensuring that the droplet is formed with the desired volume and characteristics. The effective functioning of the XYZ positioning system is essential, as it delicately moves the thin rock section toward the droplet. This careful approach is paramount to capturing the droplet without causing any sudden impacts. Abrupt contact between the droplet and the rock surface can lead to significant deviations in the measurements of contact angles, which are crucial for analyzing the wettability and surface interactions. If the droplet were to strike the surface violently, it could cause the oil to spread uncontrollably on the rock, skewing the results of the experiment. The second section, image processing and capturing, involves sophisticated imaging techniques to obtain high-resolution images of the droplet at the moment of contact. This data is critical for analyzing the droplet's behavior, including its shape, size, and interface with the substrate. Advanced image processing algorithms may be employed to assess the droplet's contact angle accurately, facilitating a deeper understanding of the interactions occurring at the oil-rock interface. Overall, the pendant drop method is a careful and meticulously designed experimental technique that provides invaluable insights into interfacial properties and fluid dynamics. By ensuring precise control during drop suspension and utilizing advanced imaging techniques, researchers can obtain reliable and reproducible data that contribute to advancements in various fields, including materials science, geology, and chemical engineering. The U-shaped needle was employed due to the lower density of the crude oil phase compared to the aqueous solution. This design allows the oil droplet to remain suspended at the tip of the nozzle, ensuring precise placement beneath the rock surface. The aqueous solution is housed in a sophisticated aquarium made of stainless steel and quartz glass, providing an unobstructed view for the imaging system, which includes a high-resolution camera and macro lens. Once the oil droplet is accurately positioned beneath the rock, we can measure the contact angle, offering critical insights into whether the wettability has shifted under various conditions. This methodology not only enhances our understanding of the interactions at play but also contributes significantly to advancements in oil recovery techniques. The pendant drop method is a well-established technique that combines both accuracy and simplicity for measuring interfacial tension (IFT) in various binary systems, particularly those involving synthetic oils and aqueous solutions. This method is favored due to its relatively straightforward setup and the high level of precision it offers in determining the physical properties of fluids at the interface and uses the following equation: $$\:\gamma\:=\frac{\varDelta\:\rho\:\:g{\:D}^{2}}{H}$$ 1 Where Δρ represents the difference in density between the drop and the bulk phases, g is the acceleration due to gravity, and H is a shape-dependent parameter. In Eq. 1 , the value of H depends on the shape factor, denoted as S = d/D, where D is the equatorial diameter and d is the diameter at a distance D from the top of the drop 35 – 38 . In the process, an oil drop is carefully suspended at the tip of a specially designed capillary nozzle. The diameter of this nozzle is chosen to ensure that it facilitates the formation of the desired drop shape, which is typically spherical or nearly so, depending on the balance of forces acting on it. The formation of the drop is a critical step, as its shape is directly related to the interfacial tension between the two immiscible phases involved. Once the drop is formed, capturing its image becomes essential for further analysis. This is achieved using a Charge-Coupled Device (CCD) camera equipped with a macro lens. The macro lens allows for a detailed and magnified view of the pendant drop, ensuring that the subtleties of its shape are visible and measurable. The image capture is typically performed under controlled lighting conditions to minimize reflections and enhance clarity. After acquiring the images of the drop, the next step involves transferring these images to specialized software designed for image analysis. The software utilizes algorithms to process the images, enabling the extraction of critical geometrical parameters of the drop, such as its radius and height. These parameters are then used to calculate the interfacial tension values based on established equations. The equation commonly used in this context relates the shape of the drop to the interfacial forces at play, allowing for the precise calculation of IFT from the measured drop dimensions. By applying this method to various binary systems, researchers can gain insights into how different synthetic oils interact with water-based solutions, which is crucial for applications in industries. Overall, the pendant drop method stands out as an effective means for quantifying interfacial tension, providing valuable data that can inform both theoretical studies and practical applications in fluid dynamics and material interactions. In this study, we placed significant emphasis on ensuring the accuracy of the measurements related to IFT and contact angles. The maximum uncertainty for the IFT was carefully determined and found to be approximately ± 0.2 mN/m. This value was derived from conducting at least three independent measurements for each data point, allowing for a reliable assessment of the results. Similarly, for both contact angle and IFT measurements, each data point underwent rigorous testing, with three measurements taken to guarantee accuracy and repeatability. This meticulous approach enhances the overall trustworthiness of our findings. 2.4. Core flooding experiment The core flooding experiments were conducted using a specially designed apparatus capable of handling pressures up to 600 bar and temperatures reaching 150°C (Fig. 3 , APEX Technologies Co., Arak, Iran). The described equipment is essential for studying fluid injection processes in oil recovery. It features several key components: 1. High-Pressure Injection Pump: This pump plays a vital role in injecting fluids, such as crude oil, synthetic oil, and aqueous solutions, into a core sample. 2. Accumulator: This component stores the necessary fluids for the injection process. By keeping these fluids ready in appropriate accumulators, the system can ensure injections occur in the correct sequence and at precise timings. 3. Core Holder: This is where the core sample is placed for testing. The high-pressure pump injects fluids into this holder, allowing researchers to observe the effects of different liquids on the core sample. 4. Heating Oven: This may be used to maintain the core sample at specific temperatures for various tests. 5. Data Acquisition System: This system monitors and records the injection process and the core’s response, providing valuable data for analysis. By controlling the injection rates, researchers can effectively push the prepared solutions through the core. This allows for detailed examination of how different fluids can enhance oil recovery, particularly in mobilizing trapped oil droplets. Understanding these interactions is crucial for advancing techniques in oil extraction and improving overall recovery rates. To carry out core flooding experiments effectively, follow a systematic procedure that focuses on accurately simulating reservoir conditions and optimizing oil recovery. 1. Calculate Permeability and Porosity: Begin with determining the permeability and porosity of the core sample to understand how fluids will flow through it. These properties are essential for predicting the behavior of fluids in the reservoir. 2. Water Injection for Saturation: Perform an initial water injection to ensure the core sample is fully saturated. This should be done at a flow rate of 0.3 cc/min, which closely matches the typical flow velocity found in reservoirs, specifically around 1 ft/day. 3. Inject Oil to Reach Irreducible Water Saturation: Next, introduce oil at a flow rate of either 0.2 or 0.3 cc/min. This step aims to achieve irreducible water saturation, which is the point at which water can no longer be removed from the pore spaces by additional oil injection. 4. Calculate Oil and Water Saturation: Following the oil injection, assess the saturation levels of oil and water, specifically under conditions reflective of a depleted reservoir. This will provide insight into how much oil remains accessible for recovery. 5. Simulate Secondary Oil Recovery: Introduce an aqueous solution to replicate the secondary oil recovery process. This step is critical in analyzing how effective this recovery method can be in enhancing oil extraction. 6. Conduct Chemical Injection: Carry out the chemical injection, ensuring the slug size does not exceed 0.3 pore volumes (PV). The chemical solutions are designed to enhance the oil recovery process by modifying the properties of the fluids within the core. 8. Continue Injection with Saline Water: Finally, maintain the injection process with saline water to push the chemical slug through the core. This stage aims to maximize oil recovery by ensuring that all injected materials are effectively triggering the displacement of oil. 2.2. Extraction of Asphaltene and Resin In recent years, there has been a growing emphasis among researchers on isolating specific components from crude oil to create synthetic oils for various scientific experiments and measurements. Crude oil is comprised of a complex mixture of compounds, which can introduce uncertainties and impact the reliability of experimental outcomes. As a result, this study is focused on extracting resin and asphaltene fractions, recognized as the most active components of crude oil. These fractions function as natural surfactants, making it possible to develop resinous and asphaltenic synthetic oils that can be utilized in experimental settings. This targeted approach aims to enhance the precision and clarity of research findings in the field. Crude oil is composed of four principal fractions: resins, asphaltenes, saturates, and aromatics. The asphaltene and resin fractions are especially significant due to their surfactant-like properties, which can modify surface characteristics, particularly those of rock surfaces and interfacial tension. These alterations can affect various processes in fields such as petroleum engineering and reservoir optimization by influencing oil recovery and fluid behavior in reservoirs. Understanding the roles of these fractions is crucial for enhancing the efficiency of extraction and production methods in the oil industry. 39 . The stability of crude oil/water emulsions is heavily influenced by the presence of various fractions in a solution. This is primarily due to their unique structural characteristics and the presence of heteroatoms within their molecular composition. These factors play a crucial role in modulating IFT, which ultimately affects the stability and behavior of the emulsions. Understanding these interactions is a key to optimize the properties of crude oil/water emulsions in various applications. 40 , 41 . To effectively differentiate between asphaltene and resin fractions, it is essential to utilize the hydrogen-to-carbon (H/C) ratio criterion. This ratio serves as a useful indicator of the molecular structure of these two components, which are often found together in crude oil and other petroleum products. The H/C ratio is a fundamental measure in organic chemistry that provides insight into the degree of branching in a molecule’s structure. Specifically, when the H/C ratio is close to 1, it indicates a non-branched structure, which is characteristic of certain heavier molecular fractions. On the other hand, a significant deviation from this ratio suggests a branched structure, which affects the physical and chemical properties of the molecules. Typically, resin fractions exhibit an H/C ratio that ranges between 1.2 and 1.7. This range reflects the higher degree of branching and complexity in the resin molecules, which generally possess more functional groups, such as naphthenic acids. These acids, which can impact the acidity and solubility of the resin fractions, contribute to their distinct chemical behavior in different environments. Conversely, the H/C ratio for asphaltene fractions tends to fall between 0.9 and 1.2. Asphaltene molecules are less branched and tend to have a more complex aromatic structure, which results in a lower H/C ratio. This can influence their solubility and behavior in petroleum systems, often leading to challenges such as precipitation or stability issues in crude oils. Despite their similarities, there are notable distinctions between resin and asphaltene molecules. Resins are typically smaller in size compared to asphaltenes, which allows them to be more fluid and less viscous. The higher branching in resin molecules contributes to their ability to dissolve in lighter oils, making them more compatible in certain refining processes. This structural difference not only affects their physical behavior but also plays a significant role in the overall processing and utilization of petroleum products. Understanding these differences, particularly through the lens of the H/C ratio, provides valuable insights into the composition and characteristics of crude oil, aiding in the efficient processing, treatment, and application of the various fractions derived from it.. 42 . The IP 143/90 method was employed to isolate the resin and asphaltene components. Subsequently, both fractions were dissolved in toluene to form synthetic oils for studies focused on resinous and asphaltenic characteristics. It is noteworthy that while the resin and asphaltene fractions play significant roles due to their intricate structures and surface activity, their impact on lowering IFT and modifying wettability across different operating conditions has not been extensively explored. 43 These two fractions primarily contain hydroxyl groups, esters, acids, carbonyl functions, and long paraffinic chains, along with naphthenic rings and polar functions in their structures 44 , 45 . However, despite their similar chemical compositions, they differ in terms of aromaticity, size, polarity, and even physical appearance 46 . By the way, by employing a standard method to separate the asphaltene fraction using n-heptane at a precise ratio of 40:1, we can set the stage for deeper analysis. This initial step, followed by thorough purification using Soxhlet recycling, ensures that we obtain a high-quality product suitable for our investigations. Moreover, what remains after removing the asphaltenes—the de-asphalted residue—is not just waste; it presents an invaluable opportunity. By utilizing column chromatography for the isolation of the resin fraction, we can unlock additional insights that have been elaborated upon in previous studies. Therefore, this methodical approach not only enhances our understanding of crude oil components but also paves the way for innovative applications in synthetic oil research. Embracing these techniques can lead to significant advancements in a field that promises both academic and practical benefits.. 47,48 . The process of separating different components from de-asphalted oil through a silica gel column is both intricate and essential for obtaining desired fractions. Initially, the de-asphalted oil, characterized by its complex hydrocarbon composition, is blended with n-heptane. This mixture forms a thick, molten-like residue that serves as a suitable feedstock for the adsorption process. Following the preparation of the mixture, it is introduced into a silica gel column. The choice of silica gel with a mesh size of 35–70 is significant, as it adheres to ASTM (American Society for Testing and Materials) standards for adsorption processes. This carefully calibrated mesh size allows for effective separation based on molecular size and polarity. As the mixture traverses the column, the different components interact with the silica gel, allowing for selective adsorption. To enhance the separation and purification, the column is then rinsed with a solvent solution composed of 70% n-heptane and 30% toluene. This step is crucial for eliminating saturates and aromatics that could interfere with the subsequent extraction of valuable compounds. The combination of n-heptane and toluene works synergistically; n-heptane, a high-purity hydrocarbon solvent, effectively dissolves non-polar compounds, while toluene, being more polar, assists in solubilizing certain aromatic compounds. After rinsing, the next phase of the extraction process involves the use of a ternary solvent mixture consisting of acetone, dichloromethane, and toluene in a specific ratio of 40:30:30. This mixture is strategically chosen for its ability to selectively extract resins from the silica gel column. Each solvent plays an essential role: acetone provides moderate polarity, enhancing solubility for a range of organic compounds; dichloromethane, with its excellent extraction capabilities, helps to dissolve more challenging substances, and toluene contributes additional aromatic solubilization. The outcome of this meticulously designed process is a series of purified fractions, each rich in specific hydrocarbon types. These fractions can then be further analyzed or utilized in various applications, from fuel production to the creation of specialty chemicals, underscoring the importance of effective separation techniques in petroleum refining and chemical engineering. 34,49,50 (see Table 1 ). Table 1 Elemental analysis of heteroatoms of resin and asphlatene fractions H/C ratio wt % of heteroatoms of resin and asphaltene fractions Fractions Total acid number S, O and N S O N 1.16 12.12 3.81 8.31 0.00 Asphaltene 0.58 1.51 10.67 6.81 3.87 0.00 Resin 0.69 A detailed look at Table 2 indicates that the asphaltene fraction exhibits less branching than the resin fraction. The asphaltene fraction has a hydrogen-to-carbon (H/C) ratio or aromaticity index of 1.16, while the resin fraction has an H/C ratio or aromaticity of around 1.51. This increased branching in the resin structure relative to that of the asphaltene fraction enhances its surface activity. As a result, the resin fraction is more adept at interacting with other charged particles and surfaces, which improves its ability to reduce interfacial tension (IFT) and modify wettability. Generally, both asphaltene and resin fractions contain heteroatoms, such as sulfur and oxygen, which possess negative charges. This feature makes resin molecules akin to surfactant molecules, as they also exhibit distinct "head" and "tail" regions. 3. Results and discussions 3.1. Compatibility test for the surfactant solutions In the first stage of this study, the compatibility of the chemicals regardless of their impact on the wettability, IFT or tertiary oil recovery must be examined. In this way, different chemical solutions using two surfactant and two NPs were prepared by changing the concentration of surfactants in the range of 0-2000 ppm while the concentration of NPs were changed between 0-500 ppm for TiO 2 and 0-250 ppm for CuO. The measurements revealed that as the concentrations of AOT and CTAB was increased to 1000 ppm, stabilized NPs for more than 2 months could be obtained for maximum concentration of 250 ppm and 500 ppm for CuO and TiO 2 , respectively while further increase in the surfactant concentration leading to precipitation of the both NPs with similar concentrations. The point is that as the measurements were extended, the results revealed that the NPs precipitation vanished as the NPs concentrations were reduced to 100 ppm while the surfactant concentration for both of them was 2000 ppm. In other words, it can be concluded that the operator has two options to prevent the NPs precipitation in the prepared solution which the first one is to fix the surfactant concentration to 1000 ppm and then select the NPs concentration in the range of 0-500 ppm and 0-250 ppm for TiO 2 and CuO, respectively without any risk of precipitation or fix the surfactant concentration at 2000 ppm while the NPs concentration must not be exceeded 100 ppm regardless of the NPs type. As a consequence of these contradicting trends, the operator must carefully examine the effect of each combination on wettability alteration and IFT reduction and then select the optimum chemical formulation for EOR purposes. The other point is that the performed measurements using different saline water showed that the obtained thresholds for stability of the NPs in the aqueous solution was similar for the examined formation brine and DPGW with a slight difference. In detail, regardless of the used type of saline water, addition of 1000 ppm of surfactant led to stabilization of NPs in the solution with their maximum studied concentration in the current work. But, for the formation brine only as the surfactant concentration reached to 1000 ppm, the NPs got stabilized while for DPGW, the addition of 500 ppm of surfactant regardless of the surfactant type, the NPs got stabilized. In detail, it seems that the D PGW has higher capability to stabilized the NPS under lower surfactant concentrations probably due to its ionic composition which can act as a kind of smart water or due to the presence of lower amounts of ions which can reduce the repulsive forces existed in the solution and provide more stabilized networks of NPs, surfactant and ions leading to easier stabilization of NPs in the aqueous solution. The other reason could be correlated to the lower IFT values for the solution prepared with SPGW which will be examined the next stages for confirmation. To sum up, the reason behind this observed trend can be due to the following phenomena. The first possible reason comes from the ability of the surfactant to reduce the IFT which directly affects the easier movement of the particles and repulsive forces. In detail, surfactants generally increase nanoparticle stability by providing electrostatic and/or steric repulsion, while the addition of sulfate ions (electrolytes) generally decreases stability by screening electrostatic repulsion. The other reason can be correlated to this fact that the presence of ions in a solution screens the electrostatic repulsion between charged nanoparticles. The higher the ionic concentration (e.g., from added sulfate salts), the more compressed the electrostatic double layer around the particles becomes. This allows the particles to approach each other closely enough for attractive van der Waals forces to cause aggregation. Moreover, in some complex systems, certain combinations of nanoparticles and surfactants may show a synergistic effect on stability, potentially related to enhanced interfacial elasticity, but this is highly system-specific. The overall stability depends on whether the repulsive forces (steric and/or remaining electrostatic repulsion due to strong surfactant adsorption) are sufficient to overcome the attractive forces under the given ionic strength. 3.2. Effect of surfactants on the IFT In the second phase of this investigation, the effect of surfactants including their types and concentration prepared with formation brine and DPGW were examined. In this way, the concentration was changed between 0-2000 ppm for each surfactant considering the formation brine and DPGW as the aqueous media for dissolving the surfactants. Also, the prepared solutions were contacted with acidic crude oil and SMRAO to find the interaction existed between the oil and the chemicals including surfactants and ionic composition of the aqueous solution. In the first stage of this investigation, the impact of surfactant dissolution in formation brine in contact with two different oil types was investigated. The measurements depicted in Fig. 4 revealed that for both surfactants regardless of the oil type, an increase in the surfactant concentration from 0 to 2000 ppm has a reducing impact on IFT although the effect of AOT for IFT reduction was more dominant. In details, the results demonstrated that using AOT with concentration of 2000 ppm dissolved in formation can reduce the IFT value to minimum value of 1.1 and 0.85 mN/m for acidic crude oil and SMRAO, respectively while the dissolution of CTB with concentration of 2000 ppm in formation brine reduced the IFT to minimum values of 4.5 and 2.3 mN/m for acidic crude oil and SMRAO, respectively, which is about 4 and 3 times higher than that values obtained for AOT. The reason of this observed trend can be correlated to this fact that generally; AOT (anionic) is often more effective at reducing interfacial tension (IFT) than CTAB (cationic) due to its chemical nature and the way AOT can pack at the interface. In detail, due to the bulky structure of the AOT compared with CTAB, it is possible for AOT molecules to interact with the formation brine ions to reduce the surface charges in a way that the higher number of AOT molecules being packed in the interface. As a consequence of higher concentration of AOT molecules in the interfaces, lower IFT values can be obtained. In other words, AOT has a negatively charged head group and two branched hydrophobic tails, which contribute to its unique properties, such as forming stable reverse micelles in organic solvents. The AOT IFT reduction mechanism can be correlated to its specific structure allows for effective packing and disruption of interfacial forces, which is crucial for significant IFT reduction. Its performance can be impacted by factors like the presence of ions and other chemicals, which affect its packing and adsorption at the interface. However, in the case of CTAB, the single-chain structure and positive charge lead to different aggregation and adsorption behaviors compared to the double-chained AOT. Its micellization and surface activity are influenced by counter ions and additives. A closer look into the results depicted in Fig. 4 revealed that the critical micelle concentration (CMC) for AOT solution are lower than that obtained for CTAB which can be correlated to its better capability for IFT reduction. in detail, the results revealed that the AOT solutions has a sharper reduction in the IFT values around 500 ppm regardless of the oil type while for CTAB solution and acidic crude oil, there is no sharp reduction in IFT to determine the CMC point although for the CTAB solution and SMRAO the CMC values around 1000 ppm could be observed while further increase in the CTAB concentration from 1000 ppm to 2000 ppm was capable to slightly change the IFT from 2.6 mN/m to 2.3 MN/m. The reason for the lower Critical Micelle Concentration (CMC) value of the resinous synthetic oil, particularly when using AOT, may be attributed to the surface activity of the resin molecules. This activity enhances the effect of AOT in the solution, resulting in better interfacial tension (IFT) reduction even at a low concentration of 500 ppm. Furthermore, it is possible to relate the greater efficiency of SDBS compared to AOT to its chain-like structure, which has minimal branching. In contrast, AOT molecules are more branched. The branched structure of AOT molecules hinders their ability to pack efficiently at the interface, which consequently reduces the molecular concentration there and results in lower IFT capability. On the other hand, the chain-like structure of SDBS allows for a higher number of molecules to pack at the interface, leading to an increased surfactant concentration and, therefore, lower IFT values. In the next stage of this investigation, the impact of DPGW was examined on the IFT of aqueous solutions were prepared using AOT and CTAB in contact with the acidic crude oil and SMRAO. The measurements (see Fig. 5 ) revealed that replacing the DPGW with formation brine has a considerable impact on the IFT reduction regardless of the used oil types. In detail, the measurements revealed that using DPGW as the aqueous medium instead of formation brine was capable to change the IFT values from 33.5 to 23.6 mN/m and 26.2 to 19.9 mN/m for acidic crude oil and SMRAO, respectively. The reason behind the obtained results can be correlated to the ionic composition of the DPGW compared with the formation brine which was not only lower in the con centration but also was different from the type of ions. One of the distinct differences between the composition of the DPGW and formation brine is the presence of sulfate ions which has a considerable impact on the IFT reduction and wettability alteration especially considering its interaction with resin and asphaltene fractions which can act as the natural surfactants. Further analysis of the measured IFT values revealed that using DPGW instead of formation brine was capable to reduce the IFT value of the system to minimum value of 0.69 mN/m for the AOT solution with concentration of 2000 ppm in contact with SMRAO. The other point which can be extracted from the measured IFT values is that the impact of using DPGW instead of formation brine on the IFT reduction for CTAB solutions was higher than that values obtained for AOT solution. In detail, the application of DPGW was capable to reduce the IFT values for AOT (with concentration of 2000 ppm) from 0.85 mN/m to 0.69 MN for SMRAO and 1.1 mN/m to 0.95 mN/m for acidic crude oil which is a slight further reduction in IFT values. In contrast, for CTAB solutions, using DPGW instead of formation brine reduced the IFT values from 4.9 mN/m to .6 mN/m for acidic crude oil and 2.3 mN/m to 0.87 mN/m for SMRAO which means higher impact of using DPGW on the IFT reduction of CTAB surfactant. The reason of this observed trend can be correlated to the following reasons. The interaction between the anionic surfactant AOT and sulfate ions in the presence of asphaltenes and resins significantly affects IFT, with results showing dual effects depending on the concentration of salts and the specific composition of the oil and aqueous phases. In details, Sulfate ions can influence the performance of surfactants like AOT (an anionic surfactant) in an aqueous solution. Generally, the addition of salts (specifically Na₂SO₄) to an aqueous surfactant system can decrease the critical micelle concentration (CMC) of the mixture, thereby enhancing the spontaneity of micelle formation due to ionic strength effects. However, in the context of crude oil interactions, sulfate ions exhibit a more complex behavior. In detail, At high salt concentrations (e.g., 15,000 ppm MgCl₂ solution with added MgSO₄), a further addition of sulfate can lead to a reduction in IFT. Extremely low IFT values can also be achieved at high concentrations (50,000 ppm) of Na₂SO₄ or MgSO₄, particularly at a high pH, which promotes the in-situ production of natural surfactants (saponification). However, at low salt concentrations, the addition of magnesium sulfate (MgSO₄) can actually reduce the affinity of natural surfactants (asphaltenes and resins) toward the interface, leading to an increase in IFT. So, as a consequence of these possible facts and presence of other ions with lower concentrations compared with the formation brine, only a slight reduction in the IFT values was observed. But in contrast to the results obtained for the AOT, the results revealed a considerable impact of saline water type on the IFT of CTAB solutions. The reason of this observed trend can be due to this fact that the interaction between the cationic surfactant CTAB and sulfate ions generally leads to a significant reduction in interfacial tension (IFT), especially at lower salinities, and enhances the desorption of asphaltenic/resinous material from surfaces. This is primarily due to the formation of ion pairs and synergistic effects that modify the behavior of natural surfactants (asphaltenes and resins) at the oil-water interface. Besides, CTAB is a cationic surfactant, and sulfate is a divalentznion. The positive charge of the CTAB head group interacts with the negative charge of the sulfate ion to form ion pairs. So, the combination of CTAB and sulfate ions often results in a more significant IFT reduction compared to either agent alone. This synergy improves the overall efficiency of the surfactant system in mobilizing oil. On the other side, the specific ions (CTAB cations and sulfate anions) interact with the polar components (heteroatoms) of asphaltenes and resins. These interactions can affect the packing and arrangement of these molecules at the interface, thereby influencing the IFT value. 3.3. Effect of surfactants on contact angle In the next stage of this investigation and in the way of studying the wettability alteration mechanism, the effects of surfactants on the wettability alteration using contact angle measurements using the DPGW as the main saline water and aqueous medium was examined. The point is that since the effect of DPGW on the IFT reduction was better than the formation brine, only the effect of aqueous solutions prepared with the DPGW and activated with surfactant were used to find the contact angle variation and wettability alteration. The measured contact angle values tabulated in Tables 2 and 3 revealed that as the concentration of surfactants were increased, the contact angle values were reduced which means the movement of the rock surface toward water wet conditions. In detail, the measurements revealed that the contact angle values for distilled water and acidic crude oil and SMRAO oils were 141.2 o and 152.9 o , respectively. However, using DPGW instead of distilled water can change the contact angle values from 141.2 o and 152.9 o to 98.5 o and 9.1 o , respectively. The results also revealed that, as the surfactant were added to the saline water; it was possible to reduce the contact angle to minimum values of 49.1 o and 44.7 o for CTAB dissolved in DPGW in contact with acidic and SMRAO, respectively. However, for the solutions activated with AOT the situation was better and the contact angle values were reduced to 40.1 o and 39.7 o for acidic crude oil and SMRAO as the concentration of AOT was increased to 2000 ppm. The obtained trend for CTAB and AOT can be correlated to the following reasons. CTAB and sulfate ions both act as effective agents for altering wettability, generally by helping to transform an oil-wet rock surface towards a more water-wet state, a process critical for enhanced oil recovery. Their mechanisms often work synergistically in carbonate reservoirs. In more details, CTAB is a cationic (positively charged) surfactant. It strongly adsorbs onto negatively charged rock surfaces (like sandstone, mica, or certain sites on carbonates) or interacts with negatively charged carboxylate groups of crude oil components (like asphaltenes) adsorbed on the rock surface. This interaction forms ion-pairs, which desorb from the surface and are solubilized into the aqueous phase. As a consequence of removal of oil components makes the rock surface more water-wet. The other point is that, at low concentrations, CTAB initially might make the surface more oil-wet by forming a hydrophobic monolayer. However, as the concentration increases past the critical micelle concentration (CMC), it forms a hydrophilic bilayer, sharply reversing the wettability to water-wet. On the other hand, AOT is an anionic surfactant. It alters wettability by adsorbing onto the rock surface, which is often oil-wet due to adsorbed crude oil components (like carboxylic acids/asphaltenes). The surfactant molecules attach to the surface, displacing the oil components and exposing a more water-wet head group or forming a water-wet layer. Regardless of the surfactants effect on the wettability alteration, the presence of sulfate ions. On the other sides, the presence of sulfate ions can be considered as the other effective reason of wettability alteration. In details, Sulfate ions are highly active anions that can bond with positively charged sites, such as calcium ions (Ca 2+ ) on a carbonate rock surface (calcite). This interaction releases the adsorbed oil components (e.g., carboxylic acids) that were previously bonded with the Ca 2+ ions. As a consequence, the desorption of oil molecules increases the negative charge on the rock surface, enhancing its water-wetness and promoting the spontaneous imbibition of water. In the case of CTAB presence in the aqueous solution, the system would be more complicated. In detail the presence of the cationic CTAB molecules and sulfate ions works in tandem to desorb adsorbed carboxylate groups from the rock surface. On the other side, the sulfate ions help facilitate the approach of the cationic CTAB to the aged calcite surface by mitigating electrostatic repulsion, leading to more effective oil removal. The other possible reason behind the significant impact of CTAB and sulfate ions can be due to this fact that in systems involving a rock surface (e.g., calcite, which often has a negative charge due to adsorbed carboxylate groups), the co-presence of sulfate ions and CTAB can lead to a more water-wet surface. The sulfate ions can interact with any adsorbed calcium ions, while CTAB forms ion pairs with the negatively charged carboxylate groups on the surface, facilitating their desorption into the aqueous phase and thus making more CTAB available at the oil-water interface. But in the case of AOT, as sulfate ions are present with anionic surfactants like AOT, they can work synergistically. The sulfate ions help attenuate the positive charge of the rock surface, which reduces the electrostatic repulsion or promotes the approach of the negatively charged AOT molecules, thereby enhancing the overall wettability alteration effect. Table 2 The effect of CTAB on the wettability of the carbonate rock Acidic Crude Oil SMRAO CTAB Concentration (ppm) Contact Angle (degree) CTAB Concentration (ppm) Contact Angle (degree) 0 98.5 0 91.1 100 90.1 100 87.6 250 79.9 250 73.6 500 68.9 500 66.9 1000 57.9 1000 53.6 2000 49.1 2000 44.7 Table 3 The effect of AOT on the wettability of the carbonate rock Acidic Crude Oil SMRAO AOT Concentration (ppm) Contact Angle (degree) AOT Concentration (ppm) Contact Angle (degree) 0 98.5 0 91.1 100 88.8 100 88.1 250 73.6 250 71.1 500 60.5 500 58.7 1000 51.9 1000 49.9 2000 40.1 2000 39.7 Similarly, Xie et al. 51 also investigated the effect of nonionic and cationic surfactants on wettability alteration using 50 cores obtained from two different carbonate reservoirs. They reported that the nonionic surfactant enhanced oil recovery more than the cationic surfactant due to its lower interfacial tension. Their results revealed that nonionic surfactants resulted in greater wettability alteration towards water-wet conditions, which led to increased oil recovery. Besides, Seethepalli et.al. 52 reported that anionic surfactants have been more effective than cationic surfactants. They utilized various anionic surfactants, including SS-6656 and Alfoterra-35, -38, -63, -65, and − 68, alongside cationic surfactants such as DTAB. It was found that the anionic surfactants were able to change the wettability of the calcite surface to intermediate or water-wet conditions, achieving similar or greater effects than the cationic surfactants like DTAB. 3.4. Contact angle variation due to presence of NPs In this phase of current investigation, the effects of CuO and TiO 2 NPs on the wettability alteration of the optimum surfactant solution prepared with DPGW were examined individually and in combination form on the contact angle variation and wettability alteration. In this way, the concentration of CuO and TiO 2 were changed between 0-250 ppm and 0-500 ppm for CuO and TiO 2 , respectively (see Tables 4 and 5 ). The point is that, the optimum surfactant concentration for both surfactant of AOT and CTAB was selected at 1000 ppm since there was no significant difference between the contact angle of the solutions prepared with 2000 ppm and 1000 ppm while the expense of preparing such a solution for filed applications could be unreasonable. The measured contact angle values revealed that among the examined NPs, TiO 2 NPs has a better impact for contact angle variation and reduction toward more water-wet conditions. In detail, the application of TiO 2 with concentration of 500 ppm leading to contact angle value of about 27.7 o and 23.3 o for AOT solution in contact with the acidic crude oil and SMRAO while for CTAB solutions minimum contact angle values of 33.7 o and 30.1 o for acidic crude oil and SMRAO, respectively were obtained. Considering these results one can conclude that the addition of TiO 2 NPs into the AOT surfactant solution has a higher effect for wettability alteration than the CTAB solutions. In details, TiO 2 NPs and the surfactant AOT significantly alter wettability, primarily by transforming surfaces from oil-wet to more water-wet conditions. The combination of the two agents can have a synergistic effect, though in some specific cases, an antagonistic effect on wettability has been observed. In detail, TiO 2 NPs alter wettability by adsorbing onto the solid surface, dislodging oil molecules, and creating a more hydrophilic (water-wet) environment. In other words, NPs due to their small size and high surface-area-to-volume ratio can penetrate small pores and attach to the rock surface. This process mechanically dislodges trapped oil and inverts the rock's wetting preference from oil-wet to water-wet, reducing the oil-rock contact area. But, in the case of CTAB and TiO 2 NPs, CTAB molecules can adsorb onto the surface of the TiO 2 NPs, leading to surface modification. These modified nanoparticles then adsorb onto the rock or substrate surface more effectively, creating a strongly hydrophilic (water-wet) nano-textured layer. This layer displaces oil droplets more efficiently. The other possible mechanism is that CTAB also play a critical role in stabilizing the nanoparticles in the fluid, preventing them from aggregating and settling, which ensures better injectivity and transport through porous media (e.g., in a reservoir rock). As the last mechanism which is not related to the surfactant type is the disjoining pressure. The nanoparticles create a structural disjoining pressure (a repulsive force) in the thin film of water between the oil and the rock surface. This force helps to push the oil droplets away from the surface which makes the rock surface, more water-wet. In the last stage of this section, the impact of combining NPs with a concentration of 100 ppm for each NPs was examined on the wettability alteration of aqueous solutions prepared with 1000 ppm of AOT or 1000 ppm of CTAB dissolved in the DPGW. Table 4 The effect of TiO 2 -NPs on the wettability alteration 1000 ppm CTAB Acidic Crude Oil SMRAO TiO 2 Concentration (ppm) Contact Angle (Degree) TiO 2 Concentration (ppm) Contact Angle (Degree) 0 57.9 0 53.6 100 52.2 100 46.6 250 40.3 250 37.7 500 33.7 500 30.1 1000 ppm AOT Acidic Crude Oil SMRAO TiO 2 Concentration (ppm) Contact Angle (Degree) TiO 2 Concentration (ppm) Contact Angle (Degree) 0 51.9 0 49.9 100 44.4 100 40.2 250 35.1 250 31.1 500 27.7 500 23.3 The measurements revealed the significant synergistic effect of using these two NPs in a hybrid solution since the contact angle values were reduced to 39.9 o and 33.6 o for acidic crude oil and SMRAO in contact with the CTAB solution and 31.2 o and 26.6 o for the acidic crude oil and SMRAO in contact with the AOT solution. Considering the results of this section and those obtained for the individual application of NPs for wettability alteration, it seems that the hybrid application with lower concentration of NPs leading to better wettability alteration potential. So, it can be concluded that the combined application of the NPs no matter which surfactant being used can be considered as one of the most effective solutions for EOR purposes. Table 5 The effect of CuO-NPs on the wettability alteration 1000 ppm CTAB Acidic Crude Oil SMRAO CuO Concentration (ppm) Contact Angle (Degree) CuO Concentration (ppm) Contact Angle (Degree) 0 57.9 0 53.6 100 55.5 100 49.9 250 42.2 250 41.1 1000 ppm AOT Acidic Crude Oil SMRAO CuO Concentration (ppm) Contact Angle (Degree) CuO Concentration (ppm) Contact Angle (Degree) 0 51.9 0 49.9 100 44.3 100 43.3 250 39.1 250 37.7 Table 6 The effect of hybrid NPS solutions on the contact angle 100 ppm TiO2 + 100 ppm CuO CTAB AOT Acidic Crude Oil SMRAO Acidic Crude Oil SMRAO 39.9 o 33.6 o 31.2 o 26.6 o 3.5. Effect of optimum chemical formulation on tertiary oil recovery In the last stage of this investigation, the application of optimum chemical formulations was used to find their effects on the oil recovery. In this way, four optimum chemical formulations were selected to be used in the core flooding experiments. These chemical solutions were 1000 ppm AOT + 250 ppm TiO 2 NPs, 1000 ppm CTAB + 250 TiO 2 NPs, 1000 ppm AOT + 100 ppm TiO 2 , and 100 ppm CuO NPs using DPGW as the aqueous medium. The point is that the surfactant solutions with CuO were not used for core flooding experiments since they have a limited impact on the wettability alteration. In this way, only the hybrid chemical solutions prepared with CuO and TiO 2 NPs were used to find their impact on the tertiary oil recovery. The other point is that not only the injection of these four solutions for EOR purposes was examined, but also the soaking period of about 30 days was applied using these four solutions to see if they are capable of activating the wettability alteration to its maximum level. In other words, by applying a soaking period, it is possible to provide the chance for the chemical solution to enhance its ultimate impact on the pores and rock surface for wettability alteration, which is one of the main mechanisms during the chemical injection approach. The obtained results revealed that the used chemical solutions were capable of increasing the oil recovery in the range of 6.7–12.8% based on the original oil in place (OOIP) while introducing a soaking period of 30 days can increase the tertiary oil recovery to the range of 10.9–16.6% based on OOIP which comes from the ultimate activation of wettability alteration mechanism. In other words, as the chemical slug was injected into the core and then flooded with the DPGW as the sweeping fluid, the injected solution did not have enough time to activate the wettability alteration mechanisms since it is a time-consuming mechanism, while the IFT reduction is a fast mechanism. So, the injection of the chemical solutions without a soaking period can only use the potential of the chemical solution for IFT reduction and slightly the ability of wettability alteration. However, in the case of soaking, as the chemical slug was injected and then it was shut off, the chemicals had enough time to penetrate the majority of the pores and change its wettability since it is time time-consuming phenomenon along with the rapid IFT reduction. This is the net effect of these two factors can increase the tertiary oil recovery more than the values obtained from the situations where only conventional injection and sweeping were performed. Table 4 The effect of optimal chemical formulation and different injection patterns on tertiary oil recovery. No Permeability (mD) Porosity (%) Solutions Soaking (Shut-off) Secondary oil recovery % based on OOIP Tertiary oil recovery % based on OOIP 1 11.1 15.7 CTAB/TiO 2 -NPs No 34.5 6.7 2 9.6 18.2 CTAB/TiO 2 -NPs Yes (30 days) 38.9 10.9 3 8.3 14.1 AOT/TiO 2 -NPs No 45.2 10.1 4 10.2 16.6 AOT/TiO 2 -NPs Yes (30 days) 37.9 13.8 5 8.8 12.2 AOT/CuO/TiO 2 -NPs No 36.6 12.8 6 7.2 15.5 AOT/CuO/TiO 2 -NPs Yes (30 days) 40.2 16.6 7 12.2 19.1 CTAB/CuO/TiO 2 -NPs No 47.1 9.2 8 9.1 20.1 CTAB/CuO/TiO 2 -NPs Yes (30 days) 43.3 13.6 Conclusions In this study, we focused on the synergistic effects between two surfactants—cetrimonium bromide (CTAB) and dioctyl sulfosuccinate sodium (AOT)—and their interaction with titanium dioxide (TiO2) at concentrations ranging from 0 to 500 ppm, as well as copper oxide (CuO) nanoparticles (NPs) at concentrations from 0 to 250 ppm. We tested these combinations in contact with two types of oil: synthetic mixed resinous and asphaltenic oil (SMRAO) and acidic crude oil (ACO). The primary parameters investigated were interfacial tension (IFT), wettability alterations based on contact angle (CA) measurements, and core flooding experiments using the optimal chemical formulations to assess their effect on tertiary oil recovery. The results from these experiments revealed the following findings: 1. The IFT measurements indicated that using formation brine or DPGW affected the IFT values. Specifically, SMRAO showed lower IFT (19.9 mN/m) than ACO (23.6 mN/m). In solutions made with formation brine, the IFTs were higher for both oils (SMRAO at 26.2 mN/m and ACO at 33.5 mN/m). This can be attributed to the natural surfactant properties of resin and asphaltene fractions, which move toward the interface, reducing IFT values. 2. We also found that replacing DPGW with formation brine significantly influenced IFT reduction, particularly for SMRAO. This effect is likely due to better salting-in and salting-out phenomena that facilitate the movement of asphaltene and resin molecules toward the interface, increasing their concentration and lowering the IFT values. 3. Among the surfactants, AOT was found to be more effective for IFT reduction, achieving a minimum IFT value of 0.69 mN/m, regardless of whether DPGW or formation brine was used. However, the reduction was more pronounced in solutions prepared with DPGW. The IFT data also suggested that DPGW positively impacted the critical micelle concentration (CMC), lowering it to about 500 ppm for both surfactants compared to 1000 ppm when using formation brine. 4. The CA measurements demonstrated that substituting DPGW for distilled water decreased the CA values significantly for ACO (from 141.2°C to 98.5°C) and SMRAO (from 152.9°C to 91.1°C). However, saturated and aromatic compounds were observed to reduce the effectiveness of resin and asphaltene in altering rock surface wettability toward more oil-wet conditions. 5. Additional tests showed that AOT was particularly effective in changing wettability, with CA values reduced to 40.1° for ACO and 39.7° for SMRAO. Both the IFT and CA measurements indicated that solutions containing SMRAO achieved better IFT reduction and more effective wettability alteration, attributed to the surface-active properties of resin and asphaltene, acting as additional surfactants. 6. The CA measurements with CuO and TiO2 NPs demonstrated that dissolving these NPs as a secondary aqueous solution activator significantly modifies wettability, reducing CA values to 27.7°C for ACO and 23.3°C for SMRAO when combined with a 1000 ppm AOT solution. Although CuO also showed effectiveness, it was less impactful than TiO2 NPs for achieving more water-wet conditions, with CA values of 39.1°C and 37.7°C for ACO and SMRAO, respectively. 7. Investigating the combination of NPs at a concentration of 100 ppm each, dissolved in 1000 ppm of AOT and CTAB, demonstrated a significant reduction in CA values to 31.2°C and 26.6°C for ACO, and 39.9°C and 33.6°C for SMRAO, indicating a positive interaction between the NPs and the surfactants. This combination facilitated better wettability alteration for the optimal chemical formulations prepared with hybrid NPs alongside 1000 ppm of AOT or CTAB. 8. Finally, we conducted eight different core flooding experiments that revealed that using the optimal chemical formulation of 100 ppm CuO, 0 ppm TiO2, and 1000 ppm AOT in contact with SMRAO resulted in a 12.8% oil recovery based on original oil in place (OOIP). Additionally, after a 30-day soaking period, oil recovery improved to 16.6% of OOIP. This enhanced recovery can be attributed to the significant impact of wettability alteration achieved through the optimal chemical formulation, as the soaking period allows for a more effective alteration process. Declarations Funding and Competing interests No funding was received to assist with the preparation of this manuscript. Data availability The datasets used and/or analyzed during the current study available from the corresponding author (Dr. Seyednooroldin Hosseini) on reasonable request sent by email to [email protected] . References E. Ghaleh Golab, Evaluation of zwitterionic and polymeric surfactant adsorption for enhanced oil recovery in sandstone reservoirs with high salinity conditions, Journal of Petroleum Exploration and Production Technology 15 1–3,1(2025). Zhao, X. et al. In situ micro-emulsification during surfactant enhanced oil recovery: A microfluidic study. Journal of Colloid and Interface Science 620 , 465-477 (2022). E. Ghaleh Golab, R. Parvaneh, M. Vatankhah-Varnosfaderani & A. Nakhaee, Study on IFT, wettability and viscosity in different salinities of synthesized a new polymeric surfactant for improving oil recovery, Journal of Petroleum Exploration and Production Technology 14 (2024) 24990.4 Yao, Y., Wei, M. & Kang, W. (2021). Arif, M., Abu-Khamsin, S. A. & Iglauer, S. Wettability of rock/CO2/brine and rock/oil/CO2-enriched-brine systems: Critical parametric analysis and future outlook. Advances in colloid and interface science 268 , 91-113 (2019). Isah, A., Arif, M., Hassan, A., Mahmoud, M. & Iglauer, S. Fluid–rock interactions and its implications on EOR: Critical analysis, experimental techniques and knowledge gaps. Energy Reports 8 , 6355-6395 (2022). Hajibagheri, F., Lashkarbolooki, M., Ayatollahi, S. & Hashemi, A. The synergic effects of anionic and cationic chemical surfactants, and bacterial solution on wettability alteration of carbonate rock: an experimental investigation. 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S., Karimi, M. & Naser, J. Effect of different polar organic compounds on wettability of calcite surfaces. Journal of Petroleum Science and Engineering 180 , 569-583 (2019). Kumar, S. & Mandal, A. Studies on interfacial behavior and wettability change phenomena by ionic and nonionic surfactants in presence of alkalis and salt for enhanced oil recovery. Applied Surface Science 372 , 42-51 (2016). Arif, M., Abu-Khamsin, S. A., Zhang, Y. & Iglauer, S. Experimental investigation of carbonate wettability as a function of mineralogical and thermo-physical conditions. Fuel 264 , 116846 (2020). Yoo, H., Kim, Y., Lee, W. & Lee, J. An experimental study on acid-rock reaction kinetics using dolomite in carbonate acidizing. Journal of Petroleum Science and Engineering 168 , 478-494 (2018). Zhong, X., Li, C., Pu, H., Zhou, Y. & Zhao, J. X. Increased nonionic surfactant efficiency in oil recovery by integrating with hydrophilic silica nanoparticle. Energy & Fuels 33 , 8522-8529 (2019). Zhou, Y. et al. Surfactant-augmented functional silica nanoparticle based nanofluid for enhanced oil recovery at high temperature and salinity. ACS applied materials & interfaces 11 , 45763-45775 (2019). Lugo, D. M., Oberdisse, J., Lapp, A. & Findenegg, G. H. Effect of nanoparticle size on the morphology of adsorbed surfactant layers. The Journal of Physical Chemistry B 114 , 4183-4191 (2010). Ahmadi, M. A. & Sheng, J. Performance improvement of ionic surfactant flooding in carbonate rock samples by use of nanoparticles. Petroleum Science 13 , 725-736 (2016). Kumar, G., Kakati, A., Mani, E. & Sangwai, J. S. Stability of nanoparticle stabilized oil-in-water Pickering emulsion under high pressure and high temperature conditions: comparison with surfactant stabilized oil-in-water emulsion. Journal of Dispersion Science and Technology 42 , 1204-1217 (2021). Belhaj, A. F. et al. The effect of surfactant concentration, salinity, temperature, and pH on surfactant adsorption for chemical enhanced oil recovery: a review. Journal of Petroleum Exploration and Production Technology 10 , 125-137 (2020). Kumar, G., Kakati, A., Mani, E. & Sangwai, J. S. in SPE Canada Heavy Oil Conference. D011S003R005 (SPE). Sharma, T., Kumar, G. S., Chon, B. H. & Sangwai, J. S. Thermal stability of oil-in-water Pickering emulsion in the presence of nanoparticle, surfactant, and polymer. Journal of Industrial and Engineering Chemistry 22 , 324-334 (2015). Kim, I., Taghavy, A., DiCarlo, D. & Huh, C. Aggregation of silica nanoparticles and its impact on particle mobility under high-salinity conditions. Journal of Petroleum Science and Engineering 133 , 376-383 (2015). Choudhary, R., Khurana, D., Kumar, A. & Subudhi, S. Stability analysis of Al2O3/water nanofluids. Journal of Experimental Nanoscience 12 , 140-151 (2017). Al-Anssari, S., Barifcani, A., Wang, S., Maxim, L. & Iglauer, S. Wettability alteration of oil-wet carbonate by silica nanofluid. Journal of colloid and interface science 461 , 435-442 (2016). Maghzi, A., Mohammadi, S., Ghazanfari, M. H., Kharrat, R. & Masihi, M. Monitoring wettability alteration by silica nanoparticles during water flooding to heavy oils in five-spot systems: A pore-level investigation. Experimental Thermal and Fluid Science 40 , 168-176 (2012). Hou, B. et al. Mechanism of synergistically changing wettability of an oil-wet sandstone surface by a novel nanoactive fluid. Energy & Fuels 34 , 6871-6878 (2020). Rezvani, H., Riazi, M., Tabaei, M., Kazemzadeh, Y. & Sharifi, M. Experimental investigation of interfacial properties in the EOR mechanisms by the novel synthesized Fe3O4@ Chitosan nanocomposites. Colloids and Surfaces A: Physicochemical and Engineering Aspects 544 , 15-27 (2018). Kazemzadeh, Y., Sharifi, M., Riazi, M., Rezvani, H. & Tabaei, M. Potential effects of metal oxide/SiO2 nanocomposites in EOR processes at different pressures. Colloids and Surfaces A: Physicochemical and Engineering Aspects 559 , 372-384 (2018). Yang, Z. et al. Interfacial tension of CO2 and organic liquid under high pressure and temperature. Chinese Journal of Chemical Engineering 22 , 1302-1306 (2014). Adamson, A. W. & Gast, A. P. Physical chemistry of surfaces . Vol. 150 (Interscience publishers New York, 1967). Andreas, J., Hauser, E. & Tucker, W. Boundary tension by pendant drops1. The Journal of Physical Chemistry 42 , 1001-1019 (2002). Stauffer, C. E. The measurement of surface tension by the pendant drop technique. The journal of physical chemistry 69 , 1933-1938 (1965). Vonnegut, B. Rotating bubble method for the determination of surface and interfacial tensions. Review of scientific instruments 13 , 6-9 (1942). Demirbas, A. & Taylan, O. Recovery of gasoline-range hydrocarbons from petroleum basic plastic wastes. Petroleum Science and Technology 33 , 1883-1889 (2015). Demirbas, A., Alidrisi, H. & Balubaid, M. API gravity, sulfur content, and desulfurization of crude oil. Petroleum Science and Technology 33 , 93-101 (2015). Aske, N., Kallevik, H. & Sjöblom, J. Determination of saturate, aromatic, resin, and asphaltenic (SARA) components in crude oils by means of infrared and near-infrared spectroscopy. Energy & Fuels 15 , 1304-1312 (2001). Ficken, K. J., Wooller, M. J., Swain, D., Street-Perrott, F. A. & Eglinton, G. Reconstruction of a subalpine grass-dominated ecosystem, Lake Rutundu, Mount Kenya: a novel multi-proxy approach. Palaeogeography, Palaeoclimatology, Palaeoecology 177 , 137-149 (2002). Lashkarbolooki, M., Ayatollahi, S. & Riazi, M. Effect of salinity, resin, and asphaltene on the surface properties of acidic crude oil/smart water/rock system. Energy & fuels 28 , 6820-6829 (2014). Wu, J., Prausnitz, J. M. & Firoozabadi, A. Molecular‐thermodynamic framework for asphaltene‐oil equilibria. AIChE journal 44 , 1188-1199 (1998). Lashkarbolooki, M., Riazi, M., Ayatollahi, S. & Hezave, A. Z. Synergy effects of ions, resin, and asphaltene on interfacial tension of acidic crude oil and low–high salinity brines. Fuel 165 , 75-85 (2016). Bera, A., Kumar, T., Ojha, K. & Mandal, A. Adsorption of surfactants on sand surface in enhanced oil recovery: Isotherms, kinetics and thermodynamic studies. Applied Surface Science 284 , 87-99 (2013). Amin, J. S. et al. Investigating the effect of different asphaltene structures on surface topography and wettability alteration. Applied Surface Science 257 , 8341-8349 (2011). Soorghali, F., Zolghadr, A. & Ayatollahi, S. Effect of resins on asphaltene deposition and the changes of surface properties at different pressures: a microstructure study. Energy & fuels 28 , 2415-2421 (2014). Miller, R. Hydrocarbon class fractionation with bonded-phase liquid chromatography. Analytical Chemistry 54 , 1742-1746 (1982). Yarranton, H. W., Alboudwarej, H. & Jakher, R. Investigation of asphaltene association with vapor pressure osmometry and interfacial tension measurements. Industrial & engineering chemistry research 39 , 2916-2924 (2000). Xie, X., Weiss, W. W., Tong, Z. & Morrow, N. R. Improved oil recovery from carbonate reservoirs by chemical stimulation. SPE Journal 10 , 276-285 (2005). Seethepalli, A., Adibhatla, B. & Mohanty, K. K. Physicochemical interactions during surfactant flooding of fractured carbonate reservoirs. SPE journal 9 , 411-418 (2004). Additional Declarations No competing interests reported. Cite Share Download PDF Status: Posted Version 1 posted You are reading this latest preprint version Research Square lets you share your work early, gain feedback from the community, and start making changes to your manuscript prior to peer review in a journal. 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Also discoverable on Platform About Our Team In Review Editorial Policies Advisory Board Help Center Resources Author Services Accessibility API Access RSS feed Manage Cookie Preferences © Research Square 2026 | ISSN 2693-5015 (online) Privacy Policy Terms of Service Do Not Sell My Personal Information {"props":{"pageProps":{"initialData":{"identity":"rs-8232999","acceptedTermsAndConditions":true,"allowDirectSubmit":true,"archivedVersions":[],"articleType":"Article","associatedPublications":[],"authors":[{"id":589489481,"identity":"a6dba0d1-b2a6-4b15-a993-689f09960dac","order_by":0,"name":"Firooz Abbasi Larki","email":"","orcid":"","institution":"Islamic Azad University","correspondingAuthor":false,"prefix":"","firstName":"Firooz","middleName":"Abbasi","lastName":"Larki","suffix":""},{"id":589489482,"identity":"3fc4e789-64f3-45cb-979b-09783ef8089b","order_by":1,"name":"Seyednooroldin Hosseini","email":"data:image/png;base64,iVBORw0KGgoAAAANSUhEUgAAAZAAAAAyAQMAAABI0h/eAAAABlBMVEX///8AAABVwtN+AAAACXBIWXMAAA7EAAAOxAGVKw4bAAAA1UlEQVRIiWNgGAWjYJCCwxCK+QCQkJAhRQtbAkgLD1FamCEUjwGYJKhct/34w8MFNXfk+KXPfH51o8aCh4H98NEN+LSYnckxODzj2DNjyb7cbdY5x4AO40lLu4FXy4EchsM8bIcTN5zh3WacwwbUIsFjhl/L+ecPDvP8A2nheWac848YLTcSDA7ztoG1MD/ObSNKyxuglr7DxpI9bGbMuX0SPGwE/XI+/fFnnm+H5fiBlnzO+VYnx89++BheLciATQJMEqscBJg/kKJ6FIyCUTAKRg4AAC2QSUODFSz8AAAAAElFTkSuQmCC","orcid":"","institution":"Islamic Azad University","correspondingAuthor":true,"prefix":"","firstName":"Seyednooroldin","middleName":"","lastName":"Hosseini","suffix":""},{"id":589489483,"identity":"a3e88fab-a51f-4d88-a616-13f2d977c01a","order_by":2,"name":"Mohammad Abdideh","email":"","orcid":"","institution":"Islamic Azad University","correspondingAuthor":false,"prefix":"","firstName":"Mohammad","middleName":"","lastName":"Abdideh","suffix":""},{"id":589489484,"identity":"a97b1db7-c557-4d17-b9cc-3694bda007f8","order_by":3,"name":"Elias Ghaleh Golab","email":"","orcid":"","institution":"Islamic Azad University","correspondingAuthor":false,"prefix":"","firstName":"Elias","middleName":"Ghaleh","lastName":"Golab","suffix":""}],"badges":[],"createdAt":"2025-11-28 19:53:12","currentVersionCode":1,"declarations":"","doi":"10.21203/rs.3.rs-8232999/v1","doiUrl":"https://doi.org/10.21203/rs.3.rs-8232999/v1","draftVersion":[],"editorialEvents":[],"editorialNote":"","failedWorkflow":false,"files":[{"id":102493854,"identity":"f2b6fd0f-0094-4c1a-aa6b-73f4088c1aba","added_by":"auto","created_at":"2026-02-12 09:12:58","extension":"png","order_by":1,"title":"Figure 1","display":"","copyAsset":false,"role":"figure","size":228765,"visible":true,"origin":"","legend":"\u003cp\u003eContact angle measurements equipment\u003c/p\u003e","description":"","filename":"1.png","url":"https://assets-eu.researchsquare.com/files/rs-8232999/v1/590fb34f145e47751ad4a0a3.png"},{"id":102493851,"identity":"d3bc3abc-e31c-48a3-ba66-4fd1f841ea45","added_by":"auto","created_at":"2026-02-12 09:12:58","extension":"png","order_by":2,"title":"Figure 2","display":"","copyAsset":false,"role":"figure","size":139583,"visible":true,"origin":"","legend":"\u003cp\u003eFigure 3. The schamtic of core flooding equipment\u003c/p\u003e","description":"","filename":"3.png","url":"https://assets-eu.researchsquare.com/files/rs-8232999/v1/27309b60bc6421b903b1c771.png"},{"id":102493836,"identity":"8f33921a-3748-423a-aa67-c0e4fdd02f50","added_by":"auto","created_at":"2026-02-12 09:12:52","extension":"png","order_by":3,"title":"Figure 3","display":"","copyAsset":false,"role":"figure","size":37277,"visible":true,"origin":"","legend":"\u003cp\u003eFigure 4. The effects of surfactant type and concentration on the IFT of different oil types using formation brine\u003c/p\u003e","description":"","filename":"4.png","url":"https://assets-eu.researchsquare.com/files/rs-8232999/v1/06362eaa5e4b28a7d4a8ddc6.png"},{"id":102493832,"identity":"3f3ae614-96dd-4137-9df1-42975acedb11","added_by":"auto","created_at":"2026-02-12 09:12:44","extension":"png","order_by":4,"title":"Figure 4","display":"","copyAsset":false,"role":"figure","size":45247,"visible":true,"origin":"","legend":"\u003cp\u003eFigure 5. The effects of surfactant type and concentration on the IFT of different oil types using DPGW\u003c/p\u003e","description":"","filename":"5.png","url":"https://assets-eu.researchsquare.com/files/rs-8232999/v1/1d1945ea6b8ae9a3431b165e.png"},{"id":105209697,"identity":"668739fc-2b52-421f-94e5-0620ce801aca","added_by":"auto","created_at":"2026-03-23 13:28:10","extension":"pdf","order_by":0,"title":"","display":"","copyAsset":false,"role":"manuscript-pdf","size":1528365,"visible":true,"origin":"","legend":"","description":"","filename":"manuscript.pdf","url":"https://assets-eu.researchsquare.com/files/rs-8232999/v1/41168619-f51a-4bd8-8eff-010b59a0fbd9.pdf"}],"financialInterests":"No competing interests reported.","formattedTitle":"Synergy Between CTAB, AOT, TiO2 And CuO NPs for Surface Properties Modifications; Effects of Acidic Crude Oil and Syntehtic Mixed Resinous and Asphaltenic Oil and Saline Water","fulltext":[{"header":"1. Introduction","content":"\u003cp\u003eIn recent years, there has been considerable interest in using enhanced oil recovery (EOR) techniques to boost oil output from both active and depleted reservoirs, driven by decreasing oil production and increasing demand. Several methods have been suggested, each with distinct benefits. These include chemical injection to change wettability and lower interfacial tension (IFT), the use of nanoparticles (NPs) to alter surface characteristics, gas injection to initiate swelling mechanisms or aid in oil extraction through miscible or immiscible methods, and thermal techniques to mobilize heavy crude oils. Among the different possibel techniques, injecting chemicals inclduing alkaline, surfacatnt, polymers, NPs, etc are getting much interest due to their capabilities to activate severeal mechanims inclduing changing wettability \u003csup\u003e\u003cspan citationid=\"CR1\" class=\"CitationRef\"\u003e1\u003c/span\u003e,\u003cspan citationid=\"CR2\" class=\"CitationRef\"\u003e2\u003c/span\u003e\u003c/sup\u003e, viscosity modification, or IFT reduction \u003csup\u003e\u003cspan additionalcitationids=\"CR4\" citationid=\"CR3\" class=\"CitationRef\"\u003e3\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR5\" class=\"CitationRef\"\u003e5\u003c/span\u003e\u003c/sup\u003e. Among these chemicals, surfactants play a crucial role in EOR processes by altering the interaction between oil, water, and rock in reservoirs. These compounds are composed of two distinct parts: a hydrophilic (water-attracting) head and a hydrophobic (water-repelling) tail. This unique structure allows surfactants to reduce IFT between oil and water, making it easier to mobilize trapped oil. Surfactants are categorized based on the charge of their hydrophilic head to, a) anionic aurfactants which carry a negative charge and are effective in reducing IFT in alkaline conditions, making them suitable for certain oil types, b) cationic surfactants which possessing a positive charge, these surfactants are often used for their strong adsorption onto negatively charged mineral surfaces, enhancing oil displacement, c) nonionic surfactants which they do not carry a charge and can be effective across a wider range of pH and salinity levels, making them versatile for various EOR applications, and d) zwitterionic surfactants which possess both positive and negative charges concomitanatly capables them to tolerate different environmental conditions, providing benefits in specific EOR situations.\u003c/p\u003e \u003cp\u003eThe point is that surfacatnst can facilitate EOR purposes by activating primary mechanims of wettability alteration by modifying the wettability of rock surfaces from hydrophilic to hydrophobic (or vice versa), surfactants help to release oil that is otherwise trapped in the pores of the reservoir rock and reducing IFT between oil and water, which promotes the formation of in-situ micro-emulsions. This is the net effects of these two phenomena allows for more efficient oil mobilization. In the light fo these facts, the strategic application of surfactants in EOR can significantly enhance oil recovery rates, making it an essential aspect of modern oil extraction techniques \u003csup\u003e\u003cspan citationid=\"CR6\" class=\"CitationRef\"\u003e6\u003c/span\u003e\u003c/sup\u003e.\u003c/p\u003e \u003cp\u003eThe impact of surfactants on IFT reduction is well understood, but it\u0026rsquo;s crucial to delve deeper into the relationship between surfactants and carbonate wettability. While existing research has provided valuable insights, it has also highlighted remarkable variability in data outcomes. This inconsistency signals that there is much more to uncover regarding how different surfactants influence carbonate wettability. Given that this area of study is not only fundamental to enhancing our understanding of oil recovery processes but also vital for optimizing environmental applications, it is imperative that we conduct more comprehensive investigations. By doing so, we can pave the way for more reliable and efficient use of surfactants in various industries, ultimately driving innovation and progress. The evidence is there; further exploration in this field is not just desirable but necessary for future advancements. For example, the contact angle (CA) on a carbonate surface treated with 100 ppm CTAB was reported as 102\u0026deg; \u003csup\u003e7\u003c/sup\u003e, while other reports revealed that a CA of 131\u0026deg; \u003csup\u003e8\u003c/sup\u003e for the same concentration and type of surfactant, highlighting the considerable data variability.\u003c/p\u003e \u003cp\u003eBesides, Derikvand et al. \u003csup\u003e9\u003c/sup\u003e found that a CA of 81\u0026deg; on a carbonate surface modified with CTAB solution with concentration of 300 ppm, while another carbonate sample being contacted to 330 ppm of CTAB revealed a CA of 35\u0026deg; \u003csup\u003e8\u003c/sup\u003e. Moreover, they reported that there is ample difference between the impact of SDBS and CTAB on wettability alteration. Based on the results obtained by Hajibagheri et al. \u003csup\u003e7\u003c/sup\u003e, the lowest CA was obtained for SDBS solution with concentration of 1,000 ppm led to CA value of 73\u0026deg;, while a much lower CA value of about 30\u0026deg; was obtained if CTAB solution with similar concentration being used \u003csup\u003e\u003cspan citationid=\"CR7\" class=\"CitationRef\"\u003e7\u003c/span\u003e\u003c/sup\u003e. According to these findings it seems that the findings are inconsistent through the wetting behavior of carbonate surfaces being contacted with surfactants which can be not only correlated to the rock mineralogy, surface roughness, the structure and texture of the surface, the operating conditions concerning pressure and temperature, and the surface chemistry of the rock or mineral surfaces but also to surface cleaning technique which can introduce bias into the measured CA values \u003csup\u003e\u003cspan citationid=\"CR10\" class=\"CitationRef\"\u003e10\u003c/span\u003e,\u003cspan citationid=\"CR11\" class=\"CitationRef\"\u003e11\u003c/span\u003e\u003c/sup\u003e. The point is that although there are large numbers of investigations correlated the emulsions stability and surfactant adsorption capabilities zeta potential \u003csup\u003e\u003cspan additionalcitationids=\"CR13 CR14\" citationid=\"CR12\" class=\"CitationRef\"\u003e12\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR15\" class=\"CitationRef\"\u003e15\u003c/span\u003e\u003c/sup\u003e, only a limited number of reports existed about the chemical functional groups and wetting behavior \u003csup\u003e\u003cspan additionalcitationids=\"CR16 CR17\" citationid=\"CR15\" class=\"CitationRef\"\u003e15\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR18\" class=\"CitationRef\"\u003e18\u003c/span\u003e\u003c/sup\u003e. Despite existing knowledge, the exact factors that affect how surfactants change the wettability of carbonate surfaces\u0026mdash;taking into account different mineral compositions and surface traits\u0026mdash;are still not well understood and require additional investigation. It's important to highlight that carbonate rocks can have considerable differences in their mineral makeup; even samples with comparable mineralogy can display distinct wetting properties. Research has indicated that carbonate samples from the same formation may behave differently due to variations in local minerals, pore structures, and surface roughness. \u003csup\u003e18\u003c/sup\u003e.\u003c/p\u003e \u003cp\u003eAlongside the well-established impacts of surfactants on rock wettability changes and the reduction of IFT, there has been a growing interest in the use of NPs for altering surface properties in recent decades. This increased focus is due to the distinct advantages NPs provide in surface modification via various mechanisms. \u003csup\u003e19\u0026ndash;21\u003c/sup\u003e These mechanisms primarily include their adsorption onto rock surfaces\u003csup\u003e\u003cspan citationid=\"CR22\" class=\"CitationRef\"\u003e22\u003c/span\u003e\u003c/sup\u003e which changes wetting conditions and enhances the thermal stability of the systems \u003csup\u003e23,\u003cspan citationid=\"CR23\" class=\"CitationRef\"\u003e24\u003c/span\u003e\u003c/sup\u003e. Recently, the use of NPs has gained traction as EOR agents in the oil and gas industry because they can maintain fluid stability over extended periods\u003csup\u003e\u003cspan citationid=\"CR25\" class=\"CitationRef\"\u003e25\u003c/span\u003e,\u003cspan citationid=\"CR26\" class=\"CitationRef\"\u003e26\u003c/span\u003e\u003c/sup\u003e. The appeal of NPs lies in their unique characteristics, such as a high surface area-to-volume ratio, extremely small size, low toxicity, and cost efficiency, with silica and clay NPs being common examples. \u003csup\u003e27,28\u003c/sup\u003e. These NPs can act as effective sacrificial agents, reducing the adsorption of surfactants and their corresponding loss in reservoir environments. \u003csup\u003e29,30\u003c/sup\u003e. Additionally, surfactants are often prone to degradation in the harsh conditions of oil reservoirs; here, NPs significantly help by improving the thermal stability of EOR systems. They also enhance the long-term stability of nanofluids, which is vital for effective field application. When used together with low-salinity surfactant flooding, NPs greatly lessen surfactant adsorption on reservoir rock surfaces, promoting a transition from an oil-wet to a water-wet state. While NPs alone show remarkable potential for changing wettability and boosting oil recovery, larger NPs can agglomerate and precipitate under high temperature and salinity conditions, which complicates their practical use. Thus, it is essential to modify the surfaces of these particles to produce thermally and kinetically stable nanofluids. Some research teams suggest that the alteration of wettability is the key mechanism behind EOR processes.\u003csup\u003e\u003cspan additionalcitationids=\"CR30\" citationid=\"CR29\" class=\"CitationRef\"\u003e29\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR30\" class=\"CitationRef\"\u003e31\u003c/span\u003e\u003c/sup\u003e.\u003c/p\u003e \u003cp\u003eRecent studies have highlighted the influence of silica NPs on contact angle measurements, revealing how variations in their concentration can lead to significant changes. These findings indicate that silica NPs play a crucial role in altering reservoir wettability, successfully shifting it from an oil-wet state to a water-wet state. This shift in wettability is essential for enhancing oil recovery processes and optimizing reservoir management.\u003c/p\u003e \u003cp\u003eResearch conducted by Hou et al. \u003csup\u003e31\u003c/sup\u003e focuses on the intricate micro-mechanisms responsible for altering the wettability of oil-wet sandstone surfaces, an essential aspect of enhancing oil recovery processes. The study specifically investigates the effects of positively charged calcium carbonate NPs and cationic-anionic gemini surfactants on these surfaces.\u003c/p\u003e \u003cp\u003eThe findings reveal significant alterations in wettability as a result of these treatments. More precisely, the researchers documented a remarkable decrease in the contact angle of oil droplets on the modified surfaces. Initially, the contact angle measured 130\u0026deg; for untreated oil-wet sandstone, indicating a strongly hydrophobic surface. However, after treatment with calcium carbonate NPs, this angle dropped to 60\u0026deg;. Further treatment with gemini surfactants reduced the contact angle even more, leading to values of 45\u0026deg; and eventually reaching as low as 36\u0026deg; when the surfaces were treated with the resulting nanofluids. Such reductions demonstrate a substantial transition towards more hydrophilic properties, which is crucial for enhancing oil mobilization and recovery.\u003c/p\u003e \u003cp\u003eIn addition to the improvements in wettability, the reduction of IFT between oil and water is highlighted as a vital factor influencing oil recovery. Lower IFT can facilitate better displacement of oil from the pores of the sandstone, thereby contributing to more efficient extraction processes. Such insights underscore the importance of using advanced materials and strategies to tackle challenges associated with oil recovery from complex geological formations. The combination of modified wettability and reduced IFT presents a promising approach for enhancing oil extraction efficiency in various geological settings. This research, therefore, not only expands our understanding of surface chemistry but also opens new avenues for developing more effective techniques in the oil and gas industry. \u003csup\u003e32,33\u003c/sup\u003e. Rezvani et al. \u003csup\u003e32\u003c/sup\u003e showed that the integration of seawater with a chitosan-coated Fe\u003csub\u003e3\u003c/sub\u003eO\u003csub\u003e4\u003c/sub\u003e nanocomposite significantly reduced the interfacial tension (IFT) of crude oil, decreasing it from 22.49 mN/m to 14.47 mN/m as the nanocomposite concentration increased. In a similar study, Kazemzadeh et al. \u003csup\u003e33\u003c/sup\u003e achieved a substantial reduction in the IFT of an oil-water system, decreasing it from 39 mN/m (using distilled water) to 13.2 mN/m by employing a synthesized TiO\u003csub\u003e2\u003c/sub\u003e/SiO\u003csub\u003e2\u003c/sub\u003e nanocomposite. These results highlight the essential roles of modifying wettability and reducing interfacial tension in enhancing the effectiveness of (EOR strategies. This investigation aims to comprehensively assess the effects of two powerful surfactants, sodium cetrimonium bromide (CTAB) and sodium bis-(2-ethylhexyl) sulfosuccinate (AOT), using diluted Persian Gulf water (DPGW) as a testing medium. The study is particularly notable as it explores both acidic crude oil and synthetic mixed resinous and asphaltenic oil (SMRAO) for the first time. By analyzing these combinations, the impact of chemical formulations\u0026mdash;including surfactants and nanoparticles\u0026mdash;on interfacial tension (IFT) reduction and wettability alteration, which are critical factors in enhancing tertiary oil recovery through core flooding experiments can be evaluted. The research will systematically investigate a range of surfactant concentrations from 0 to 2000 ppm and nanoparticle concentrations between 0 to 500 ppm for TiO2 and CuO (0-250 ppm), along with hybrid solutions at a concentration of 1000 ppm for each NPs and optimum surfacatnt concnetration. The goal is to observe how these components interact and influence IFT and wettability. In addition, various injection strategies will be examined to identify the most effective method for tertiary oil recovery. This will involve an extended 30-day soaking period designed to enhance the effects of wettability alteration, ensuring our findings contribute valuable insights to the field of EOR techniques. By positioning this study at the forefront of this area, the aim of this investigation was set to optimize the sequence of chemical formulation injections to achieve maximum efficiency in oil recovery processes.\u003c/p\u003e"},{"header":"2. Experimental procedure","content":"\u003cdiv id=\"Sec3\" class=\"Section2\"\u003e\n \u003ch2\u003e2.1. Materials\u003c/h2\u003e\n \u003cp\u003eA sample of crude oil with a specific gravity of 0.86 and a total acid number (TAN) of 1.45 was graciously provided by the National Iranian South Oil Company (NISOC) asphaltene and resin fractions of 8.5% and 11.1%, respectively. This sample was utilized to extract the resin and asphaltene fractions, resulting in a synthetic oil sample. Chemicals such as CTAB and AOT were obtained from Sigma Aldrich (USA), boasting a purity greater than 97%, and were used directly without any additional processing or purification to prepare the solutions. Additionally, TiO2 and CuO nanoparticles were sourced from Borhan Company in Iran. For the saline water, it was collected from the Persian Gulf and then diluted with distilled water in equal proportions (50%-50% in volume), ensuring it\u0026apos;s a suitable source for solution preparation.\u003c/p\u003e\n \u003cp\u003eThe other point to note is that the necessary Persian Gulf water for dilution to prepare the chemical solutions was collected from Asaluyeh Port. This water maintained the following composition: sodium (13,360 ppm), potassium (505 ppm), magnesium (1,580 ppm), calcium (438 ppm), chloride (25,012 ppm), and sulfate (3,410 ppm), with a total pH of 8.1.\u003c/p\u003e\n\u003c/div\u003e\n\u003cdiv id=\"Sec4\" class=\"Section2\"\u003e\n \u003ch2\u003e2.3. Contact angle and IFT measurement\u003c/h2\u003e\n \u003cp\u003eIn this investigation, a pendant drop method was employed, a technique derived from the sessile drop approach, to study the properties of liquid-solid interfaces. Specifically, this method allows for the precise measurement of CA, which is crucial for understanding wettability and surface interactions. To enhance the accuracy of our measurements, we integrated a drop shape analysis technique, known as the tangent method. This approach involves analyzing the curvature of the drop at its contact point with the surface, enabling us to determine the average contact angle with greater precision. This work was conducted using a device supplied from Fanavari Atiyeh Pouyandegan Exir Co. in Arak, Iran, which capable the operator to measure the CA and IFT with an acceptable level of accuracy A visual representation of the setup and measurements can be found in Fig.\u0026nbsp;2, highlighting the intricacies of the pendant drop method and the tangent method in action \u003csup\u003e\u003cspan class=\"CitationRef\"\u003e34\u003c/span\u003e\u003c/sup\u003e ) (see Fig.\u0026nbsp;\u003cspan class=\"InternalRef\"\u003e1\u003c/span\u003e).\u003c/p\u003e\n \u003cp\u003eThe pendant drop method is a sophisticated technique widely used in various scientific and engineering applications, particularly in the study of surface and interfacial phenomena. This method consists of two primary interconnected sections: drop suspension and image processing/capturing, each playing a critical role in ensuring accurate measurements and observations.\u003c/p\u003e\n \u003cp\u003eThe first section, drop suspension, is vital for the successful formation and manipulation of the droplet at the nozzle\u0026apos;s tip. It employs an advanced XYZ positioning stage, which allows the operator to finely control the position of the droplet in relation to the substrate, such as a rock surface. This degree of control enables precise positioning of the droplet, whether in an upward or downward direction, which is crucial for various experimental setups.\u003c/p\u003e\n \u003cp\u003eTo achieve optimal droplet formation at the nozzle tip, the system is equipped with an automatic injection mechanism. This mechanism typically comprises a 500 \u0026micro;L glass syringe manufactured by Hamilton, USA, paired with a stainless steel U-shaped flat-end needle. The syringe\u0026apos;s design allows for controlled and consistent delivery of the fluid, ensuring that the droplet is formed with the desired volume and characteristics.\u003c/p\u003e\n \u003cp\u003eThe effective functioning of the XYZ positioning system is essential, as it delicately moves the thin rock section toward the droplet. This careful approach is paramount to capturing the droplet without causing any sudden impacts. Abrupt contact between the droplet and the rock surface can lead to significant deviations in the measurements of contact angles, which are crucial for analyzing the wettability and surface interactions. If the droplet were to strike the surface violently, it could cause the oil to spread uncontrollably on the rock, skewing the results of the experiment. The second section, image processing and capturing, involves sophisticated imaging techniques to obtain high-resolution images of the droplet at the moment of contact. This data is critical for analyzing the droplet\u0026apos;s behavior, including its shape, size, and interface with the substrate. Advanced image processing algorithms may be employed to assess the droplet\u0026apos;s contact angle accurately, facilitating a deeper understanding of the interactions occurring at the oil-rock interface.\u003c/p\u003e\n \u003cp\u003eOverall, the pendant drop method is a careful and meticulously designed experimental technique that provides invaluable insights into interfacial properties and fluid dynamics. By ensuring precise control during drop suspension and utilizing advanced imaging techniques, researchers can obtain reliable and reproducible data that contribute to advancements in various fields, including materials science, geology, and chemical engineering.\u003c/p\u003e\n \u003cp\u003eThe U-shaped needle was employed due to the lower density of the crude oil phase compared to the aqueous solution. This design allows the oil droplet to remain suspended at the tip of the nozzle, ensuring precise placement beneath the rock surface. The aqueous solution is housed in a sophisticated aquarium made of stainless steel and quartz glass, providing an unobstructed view for the imaging system, which includes a high-resolution camera and macro lens. Once the oil droplet is accurately positioned beneath the rock, we can measure the contact angle, offering critical insights into whether the wettability has shifted under various conditions. This methodology not only enhances our understanding of the interactions at play but also contributes significantly to advancements in oil recovery techniques. The pendant drop method is a well-established technique that combines both accuracy and simplicity for measuring interfacial tension (IFT) in various binary systems, particularly those involving synthetic oils and aqueous solutions. This method is favored due to its relatively straightforward setup and the high level of precision it offers in determining the physical properties of fluids at the interface and uses the following equation:\u003c/p\u003e\n \u003cdiv id=\"Equ1\" class=\"Equation\"\u003e\n \u003cdiv class=\"mathdisplay\" id=\"FileID_Equ1\" name=\"EquationSource\"\u003e$$\\:\\gamma\\:=\\frac{\\varDelta\\:\\rho\\:\\:g{\\:D}^{2}}{H}$$\u003c/div\u003e\n \u003cdiv class=\"EquationNumber\"\u003e1\u003c/div\u003e\n \u003c/div\u003e\n \u003cp\u003eWhere \u0026Delta;\u0026rho; represents the difference in density between the drop and the bulk phases, g is the acceleration due to gravity, and H is a shape-dependent parameter. In Eq.\u0026nbsp;\u003cspan class=\"InternalRef\"\u003e1\u003c/span\u003e, the value of H depends on the shape factor, denoted as S\u0026thinsp;=\u0026thinsp;d/D, where D is the equatorial diameter and d is the diameter at a distance D from the top of the drop \u003csup\u003e\u003cspan class=\"CitationRef\"\u003e35\u003c/span\u003e\u0026ndash;\u003cspan class=\"CitationRef\"\u003e38\u003c/span\u003e\u003c/sup\u003e.\u003c/p\u003e\n \u003cp\u003eIn the process, an oil drop is carefully suspended at the tip of a specially designed capillary nozzle. The diameter of this nozzle is chosen to ensure that it facilitates the formation of the desired drop shape, which is typically spherical or nearly so, depending on the balance of forces acting on it. The formation of the drop is a critical step, as its shape is directly related to the interfacial tension between the two immiscible phases involved. Once the drop is formed, capturing its image becomes essential for further analysis. This is achieved using a Charge-Coupled Device (CCD) camera equipped with a macro lens. The macro lens allows for a detailed and magnified view of the pendant drop, ensuring that the subtleties of its shape are visible and measurable. The image capture is typically performed under controlled lighting conditions to minimize reflections and enhance clarity. After acquiring the images of the drop, the next step involves transferring these images to specialized software designed for image analysis. The software utilizes algorithms to process the images, enabling the extraction of critical geometrical parameters of the drop, such as its radius and height. These parameters are then used to calculate the interfacial tension values based on established equations.\u003c/p\u003e\n \u003cp\u003eThe equation commonly used in this context relates the shape of the drop to the interfacial forces at play, allowing for the precise calculation of IFT from the measured drop dimensions. By applying this method to various binary systems, researchers can gain insights into how different synthetic oils interact with water-based solutions, which is crucial for applications in industries. Overall, the pendant drop method stands out as an effective means for quantifying interfacial tension, providing valuable data that can inform both theoretical studies and practical applications in fluid dynamics and material interactions.\u003c/p\u003e\n \u003cp\u003eIn this study, we placed significant emphasis on ensuring the accuracy of the measurements related to IFT and contact angles. The maximum uncertainty for the IFT was carefully determined and found to be approximately\u0026thinsp;\u0026plusmn;\u0026thinsp;0.2 mN/m. This value was derived from conducting at least three independent measurements for each data point, allowing for a reliable assessment of the results. Similarly, for both contact angle and IFT measurements, each data point underwent rigorous testing, with three measurements taken to guarantee accuracy and repeatability. This meticulous approach enhances the overall trustworthiness of our findings.\u003c/p\u003e\n\u003c/div\u003e\n\u003cdiv id=\"Sec5\" class=\"Section2\"\u003e\n \u003ch2\u003e2.4. Core flooding experiment\u003c/h2\u003e\n \u003cp\u003eThe core flooding experiments were conducted using a specially designed apparatus capable of handling pressures up to 600 bar and temperatures reaching 150\u0026deg;C (Fig. \u003cspan class=\"InternalRef\"\u003e3\u003c/span\u003e, APEX Technologies Co., Arak, Iran).\u003c/p\u003e\n \u003cp\u003eThe described equipment is essential for studying fluid injection processes in oil recovery. It features several key components:\u003c/p\u003e\u003cspan\u003e\n \u003cp\u003e1. High-Pressure Injection Pump: This pump plays a vital role in injecting fluids, such as crude oil, synthetic oil, and aqueous solutions, into a core sample.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e2. Accumulator: This component stores the necessary fluids for the injection process. By keeping these fluids ready in appropriate accumulators, the system can ensure injections occur in the correct sequence and at precise timings.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e3. Core Holder: This is where the core sample is placed for testing. The high-pressure pump injects fluids into this holder, allowing researchers to observe the effects of different liquids on the core sample.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e4. Heating Oven: This may be used to maintain the core sample at specific temperatures for various tests.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e5. Data Acquisition System: This system monitors and records the injection process and the core\u0026rsquo;s response, providing valuable data for analysis.\u003c/p\u003e\n \u003c/span\u003e\n \u003cp\u003eBy controlling the injection rates, researchers can effectively push the prepared solutions through the core. This allows for detailed examination of how different fluids can enhance oil recovery, particularly in mobilizing trapped oil droplets. Understanding these interactions is crucial for advancing techniques in oil extraction and improving overall recovery rates.\u003c/p\u003e\n \u003cp\u003eTo carry out core flooding experiments effectively, follow a systematic procedure that focuses on accurately simulating reservoir conditions and optimizing oil recovery.\u003c/p\u003e\u003cspan\u003e\n \u003cp\u003e1. Calculate Permeability and Porosity: Begin with determining the permeability and porosity of the core sample to understand how fluids will flow through it. These properties are essential for predicting the behavior of fluids in the reservoir.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e2. Water Injection for Saturation: Perform an initial water injection to ensure the core sample is fully saturated. This should be done at a flow rate of 0.3 cc/min, which closely matches the typical flow velocity found in reservoirs, specifically around 1 ft/day.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e3. Inject Oil to Reach Irreducible Water Saturation: Next, introduce oil at a flow rate of either 0.2 or 0.3 cc/min. This step aims to achieve irreducible water saturation, which is the point at which water can no longer be removed from the pore spaces by additional oil injection.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e4. Calculate Oil and Water Saturation: Following the oil injection, assess the saturation levels of oil and water, specifically under conditions reflective of a depleted reservoir. This will provide insight into how much oil remains accessible for recovery.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e5. Simulate Secondary Oil Recovery: Introduce an aqueous solution to replicate the secondary oil recovery process. This step is critical in analyzing how effective this recovery method can be in enhancing oil extraction.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e6. Conduct Chemical Injection: Carry out the chemical injection, ensuring the slug size does not exceed 0.3 pore volumes (PV). The chemical solutions are designed to enhance the oil recovery process by modifying the properties of the fluids within the core.\u003c/p\u003e\n \u003c/span\u003e \u003cspan\u003e\n \u003cp\u003e8. Continue Injection with Saline Water: Finally, maintain the injection process with saline water to push the chemical slug through the core. This stage aims to maximize oil recovery by ensuring that all injected materials are effectively triggering the displacement of oil.\u003c/p\u003e\n \u003c/span\u003e\n\u003c/div\u003e\n\u003cdiv id=\"Sec6\" class=\"Section2\"\u003e\n \u003ch2\u003e2.2. Extraction of Asphaltene and Resin\u003c/h2\u003e\n \u003cp\u003eIn recent years, there has been a growing emphasis among researchers on isolating specific components from crude oil to create synthetic oils for various scientific experiments and measurements. Crude oil is comprised of a complex mixture of compounds, which can introduce uncertainties and impact the reliability of experimental outcomes. As a result, this study is focused on extracting resin and asphaltene fractions, recognized as the most active components of crude oil. These fractions function as natural surfactants, making it possible to develop resinous and asphaltenic synthetic oils that can be utilized in experimental settings. This targeted approach aims to enhance the precision and clarity of research findings in the field. Crude oil is composed of four principal fractions: resins, asphaltenes, saturates, and aromatics. The asphaltene and resin fractions are especially significant due to their surfactant-like properties, which can modify surface characteristics, particularly those of rock surfaces and interfacial tension. These alterations can affect various processes in fields such as petroleum engineering and reservoir optimization by influencing oil recovery and fluid behavior in reservoirs. Understanding the roles of these fractions is crucial for enhancing the efficiency of extraction and production methods in the oil industry. \u003csup\u003e39\u003c/sup\u003e. The stability of crude oil/water emulsions is heavily influenced by the presence of various fractions in a solution. This is primarily due to their unique structural characteristics and the presence of heteroatoms within their molecular composition. These factors play a crucial role in modulating IFT, which ultimately affects the stability and behavior of the emulsions. Understanding these interactions is a key to optimize the properties of crude oil/water emulsions in various applications. \u003csup\u003e40\u003c/sup\u003e, \u003csup\u003e41\u003c/sup\u003e. To effectively differentiate between asphaltene and resin fractions, it is essential to utilize the hydrogen-to-carbon (H/C) ratio criterion. This ratio serves as a useful indicator of the molecular structure of these two components, which are often found together in crude oil and other petroleum products.\u003c/p\u003e\n \u003cp\u003eThe H/C ratio is a fundamental measure in organic chemistry that provides insight into the degree of branching in a molecule\u0026rsquo;s structure. Specifically, when the H/C ratio is close to 1, it indicates a non-branched structure, which is characteristic of certain heavier molecular fractions. On the other hand, a significant deviation from this ratio suggests a branched structure, which affects the physical and chemical properties of the molecules. Typically, resin fractions exhibit an H/C ratio that ranges between 1.2 and 1.7. This range reflects the higher degree of branching and complexity in the resin molecules, which generally possess more functional groups, such as naphthenic acids. These acids, which can impact the acidity and solubility of the resin fractions, contribute to their distinct chemical behavior in different environments. Conversely, the H/C ratio for asphaltene fractions tends to fall between 0.9 and 1.2. Asphaltene molecules are less branched and tend to have a more complex aromatic structure, which results in a lower H/C ratio. This can influence their solubility and behavior in petroleum systems, often leading to challenges such as precipitation or stability issues in crude oils.\u003c/p\u003e\n \u003cp\u003eDespite their similarities, there are notable distinctions between resin and asphaltene molecules. Resins are typically smaller in size compared to asphaltenes, which allows them to be more fluid and less viscous. The higher branching in resin molecules contributes to their ability to dissolve in lighter oils, making them more compatible in certain refining processes. This structural difference not only affects their physical behavior but also plays a significant role in the overall processing and utilization of petroleum products. Understanding these differences, particularly through the lens of the H/C ratio, provides valuable insights into the composition and characteristics of crude oil, aiding in the efficient processing, treatment, and application of the various fractions derived from it..\u003csup\u003e42\u003c/sup\u003e.\u003c/p\u003e\n \u003cp\u003eThe IP 143/90 method was employed to isolate the resin and asphaltene components. Subsequently, both fractions were dissolved in toluene to form synthetic oils for studies focused on resinous and asphaltenic characteristics. It is noteworthy that while the resin and asphaltene fractions play significant roles due to their intricate structures and surface activity, their impact on lowering IFT and modifying wettability across different operating conditions has not been extensively explored. \u003csup\u003e43\u003c/sup\u003e\u003c/p\u003e\n \u003cp\u003eThese two fractions primarily contain hydroxyl groups, esters, acids, carbonyl functions, and long paraffinic chains, along with naphthenic rings and polar functions in their structures \u003csup\u003e\u003cspan class=\"CitationRef\"\u003e44\u003c/span\u003e,\u003cspan class=\"CitationRef\"\u003e45\u003c/span\u003e\u003c/sup\u003e. However, despite their similar chemical compositions, they differ in terms of aromaticity, size, polarity, and even physical appearance \u003csup\u003e46\u003c/sup\u003e. By the way, by employing a standard method to separate the asphaltene fraction using n-heptane at a precise ratio of 40:1, we can set the stage for deeper analysis. This initial step, followed by thorough purification using Soxhlet recycling, ensures that we obtain a high-quality product suitable for our investigations.\u003c/p\u003e\n \u003cp\u003eMoreover, what remains after removing the asphaltenes\u0026mdash;the de-asphalted residue\u0026mdash;is not just waste; it presents an invaluable opportunity. By utilizing column chromatography for the isolation of the resin fraction, we can unlock additional insights that have been elaborated upon in previous studies. Therefore, this methodical approach not only enhances our understanding of crude oil components but also paves the way for innovative applications in synthetic oil research. Embracing these techniques can lead to significant advancements in a field that promises both academic and practical benefits.. \u003csup\u003e47,48\u003c/sup\u003e.\u003c/p\u003e\n \u003cp\u003eThe process of separating different components from de-asphalted oil through a silica gel column is both intricate and essential for obtaining desired fractions. Initially, the de-asphalted oil, characterized by its complex hydrocarbon composition, is blended with n-heptane. This mixture forms a thick, molten-like residue that serves as a suitable feedstock for the adsorption process.\u003c/p\u003e\n \u003cp\u003eFollowing the preparation of the mixture, it is introduced into a silica gel column. The choice of silica gel with a mesh size of 35\u0026ndash;70 is significant, as it adheres to ASTM (American Society for Testing and Materials) standards for adsorption processes. This carefully calibrated mesh size allows for effective separation based on molecular size and polarity. As the mixture traverses the column, the different components interact with the silica gel, allowing for selective adsorption.\u003c/p\u003e\n \u003cp\u003eTo enhance the separation and purification, the column is then rinsed with a solvent solution composed of 70% n-heptane and 30% toluene. This step is crucial for eliminating saturates and aromatics that could interfere with the subsequent extraction of valuable compounds. The combination of n-heptane and toluene works synergistically; n-heptane, a high-purity hydrocarbon solvent, effectively dissolves non-polar compounds, while toluene, being more polar, assists in solubilizing certain aromatic compounds.\u003c/p\u003e\n \u003cp\u003eAfter rinsing, the next phase of the extraction process involves the use of a ternary solvent mixture consisting of acetone, dichloromethane, and toluene in a specific ratio of 40:30:30. This mixture is strategically chosen for its ability to selectively extract resins from the silica gel column. Each solvent plays an essential role: acetone provides moderate polarity, enhancing solubility for a range of organic compounds; dichloromethane, with its excellent extraction capabilities, helps to dissolve more challenging substances, and toluene contributes additional aromatic solubilization.\u003c/p\u003e\n \u003cp\u003eThe outcome of this meticulously designed process is a series of purified fractions, each rich in specific hydrocarbon types. These fractions can then be further analyzed or utilized in various applications, from fuel production to the creation of specialty chemicals, underscoring the importance of effective separation techniques in petroleum refining and chemical engineering. \u003csup\u003e34,49,50\u003c/sup\u003e (see Table \u003cspan class=\"InternalRef\"\u003e1\u003c/span\u003e).\u003c/p\u003e\n \u003cdiv class=\"gridtable\"\u003e\u0026nbsp;\u003ctable id=\"Tab1\" border=\"1\"\u003e\n \u003ccaption language=\"En\"\u003e\n \u003cdiv class=\"CaptionNumber\"\u003eTable 1\u003c/div\u003e\n \u003cdiv class=\"CaptionContent\"\u003e\n \u003cp\u003eElemental analysis of heteroatoms of resin and asphlatene fractions\u003c/p\u003e\n \u003c/div\u003e\n \u003c/caption\u003e\n \u003ccolgroup cols=\"7\"\u003e\u003c/colgroup\u003e\n \u003cthead\u003e\n \u003ctr\u003e\n \u003cth align=\"left\" rowspan=\"2\"\u003e\n \u003cp\u003eH/C ratio\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\" colspan=\"4\"\u003e\n \u003cp\u003ewt % of heteroatoms of resin and asphaltene fractions\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\" rowspan=\"2\"\u003e\n \u003cp\u003eFractions\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eTotal acid number\u003c/p\u003e\n \u003c/th\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eS, O and N\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eS\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eO\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eN\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\u0026nbsp;\u003c/th\u003e\n \u003c/tr\u003e\n \u003c/thead\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e1.16\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e12.12\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e3.81\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e8.31\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003eAsphaltene\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.58\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e1.51\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e10.67\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e6.81\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e3.87\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.00\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003eResin\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.69\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n \u003c/div\u003e\n \u003cp\u003eA detailed look at Table\u0026nbsp;\u003cspan class=\"InternalRef\"\u003e2\u003c/span\u003e indicates that the asphaltene fraction exhibits less branching than the resin fraction. The asphaltene fraction has a hydrogen-to-carbon (H/C) ratio or aromaticity index of 1.16, while the resin fraction has an H/C ratio or aromaticity of around 1.51. This increased branching in the resin structure relative to that of the asphaltene fraction enhances its surface activity. As a result, the resin fraction is more adept at interacting with other charged particles and surfaces, which improves its ability to reduce interfacial tension (IFT) and modify wettability. Generally, both asphaltene and resin fractions contain heteroatoms, such as sulfur and oxygen, which possess negative charges. This feature makes resin molecules akin to surfactant molecules, as they also exhibit distinct \u0026quot;head\u0026quot; and \u0026quot;tail\u0026quot; regions.\u003c/p\u003e\n\u003c/div\u003e"},{"header":"3. Results and discussions","content":"\u003cdiv id=\"Sec8\" class=\"Section2\"\u003e \u003ch2\u003e3.1. Compatibility test for the surfactant solutions\u003c/h2\u003e \u003cp\u003eIn the first stage of this study, the compatibility of the chemicals regardless of their impact on the wettability, IFT or tertiary oil recovery must be examined. In this way, different chemical solutions using two surfactant and two NPs were prepared by changing the concentration of surfactants in the range of 0-2000 ppm while the concentration of NPs were changed between 0-500 ppm for TiO\u003csub\u003e2\u003c/sub\u003e and 0-250 ppm for CuO. The measurements revealed that as the concentrations of AOT and CTAB was increased to 1000 ppm, stabilized NPs for more than 2 months could be obtained for maximum concentration of 250 ppm and 500 ppm for CuO and TiO\u003csub\u003e2\u003c/sub\u003e, respectively while further increase in the surfactant concentration leading to precipitation of the both NPs with similar concentrations. The point is that as the measurements were extended, the results revealed that the NPs precipitation vanished as the NPs concentrations were reduced to 100 ppm while the surfactant concentration for both of them was 2000 ppm. In other words, it can be concluded that the operator has two options to prevent the NPs precipitation in the prepared solution which the first one is to fix the surfactant concentration to 1000 ppm and then select the NPs concentration in the range of 0-500 ppm and 0-250 ppm for TiO\u003csub\u003e2\u003c/sub\u003e and CuO, respectively without any risk of precipitation or fix the surfactant concentration at 2000 ppm while the NPs concentration must not be exceeded 100 ppm regardless of the NPs type. As a consequence of these contradicting trends, the operator must carefully examine the effect of each combination on wettability alteration and IFT reduction and then select the optimum chemical formulation for EOR purposes.\u003c/p\u003e \u003cp\u003eThe other point is that the performed measurements using different saline water showed that the obtained thresholds for stability of the NPs in the aqueous solution was similar for the examined formation brine and DPGW with a slight difference. In detail, regardless of the used type of saline water, addition of 1000 ppm of surfactant led to stabilization of NPs in the solution with their maximum studied concentration in the current work.\u003c/p\u003e \u003cp\u003eBut, for the formation brine only as the surfactant concentration reached to 1000 ppm, the NPs got stabilized while for DPGW, the addition of 500 ppm of surfactant regardless of the surfactant type, the NPs got stabilized. In detail, it seems that the D PGW has higher capability to stabilized the NPS under lower surfactant concentrations probably due to its ionic composition which can act as a kind of smart water or due to the presence of lower amounts of ions which can reduce the repulsive forces existed in the solution and provide more stabilized networks of NPs, surfactant and ions leading to easier stabilization of NPs in the aqueous solution. The other reason could be correlated to the lower IFT values for the solution prepared with SPGW which will be examined the next stages for confirmation.\u003c/p\u003e \u003cp\u003eTo sum up, the reason behind this observed trend can be due to the following phenomena. The first possible reason comes from the ability of the surfactant to reduce the IFT which directly affects the easier movement of the particles and repulsive forces. In detail, surfactants generally increase nanoparticle stability by providing electrostatic and/or steric repulsion, while the addition of sulfate ions (electrolytes) generally decreases stability by screening electrostatic repulsion. The other reason can be correlated to this fact that the presence of ions in a solution screens the electrostatic repulsion between charged nanoparticles. The higher the ionic concentration (e.g., from added sulfate salts), the more compressed the electrostatic double layer around the particles becomes. This allows the particles to approach each other closely enough for attractive van der Waals forces to cause aggregation. Moreover, in some complex systems, certain combinations of nanoparticles and surfactants may show a synergistic effect on stability, potentially related to enhanced interfacial elasticity, but this is highly system-specific. The overall stability depends on whether the repulsive forces (steric and/or remaining electrostatic repulsion due to strong surfactant adsorption) are sufficient to overcome the attractive forces under the given ionic strength.\u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec9\" class=\"Section2\"\u003e \u003ch2\u003e3.2. Effect of surfactants on the IFT\u003c/h2\u003e \u003cp\u003eIn the second phase of this investigation, the effect of surfactants including their types and concentration prepared with formation brine and DPGW were examined. In this way, the concentration was changed between 0-2000 ppm for each surfactant considering the formation brine and DPGW as the aqueous media for dissolving the surfactants. Also, the prepared solutions were contacted with acidic crude oil and SMRAO to find the interaction existed between the oil and the chemicals including surfactants and ionic composition of the aqueous solution.\u003c/p\u003e \u003cp\u003eIn the first stage of this investigation, the impact of surfactant dissolution in formation brine in contact with two different oil types was investigated. The measurements depicted in Fig.\u0026nbsp;\u003cspan refid=\"Fig3\" class=\"InternalRef\"\u003e4\u003c/span\u003e revealed that for both surfactants regardless of the oil type, an increase in the surfactant concentration from 0 to 2000 ppm has a reducing impact on IFT although the effect of AOT for IFT reduction was more dominant. In details, the results demonstrated that using AOT with concentration of 2000 ppm dissolved in formation can reduce the IFT value to minimum value of 1.1 and 0.85 mN/m for acidic crude oil and SMRAO, respectively while the dissolution of CTB with concentration of 2000 ppm in formation brine reduced the IFT to minimum values of 4.5 and 2.3 mN/m for acidic crude oil and SMRAO, respectively, which is about 4 and 3 times higher than that values obtained for AOT. The reason of this observed trend can be correlated to this fact that generally; AOT (anionic) is often more effective at reducing interfacial tension (IFT) than CTAB (cationic) due to its chemical nature and the way AOT can pack at the interface. In detail, due to the bulky structure of the AOT compared with CTAB, it is possible for AOT molecules to interact with the formation brine ions to reduce the surface charges in a way that the higher number of AOT molecules being packed in the interface. As a consequence of higher concentration of AOT molecules in the interfaces, lower IFT values can be obtained. In other words, AOT has a negatively charged head group and two branched hydrophobic tails, which contribute to its unique properties, such as forming stable reverse micelles in organic solvents. The AOT IFT reduction mechanism can be correlated to its specific structure allows for effective packing and disruption of interfacial forces, which is crucial for significant IFT reduction. Its performance can be impacted by factors like the presence of ions and other chemicals, which affect its packing and adsorption at the interface. However, in the case of CTAB, the single-chain structure and positive charge lead to different aggregation and adsorption behaviors compared to the double-chained AOT. Its micellization and surface activity are influenced by counter ions and additives.\u003c/p\u003e \u003cp\u003eA closer look into the results depicted in Fig.\u0026nbsp;\u003cspan refid=\"Fig3\" class=\"InternalRef\"\u003e4\u003c/span\u003e revealed that the critical micelle concentration (CMC) for AOT solution are lower than that obtained for CTAB which can be correlated to its better capability for IFT reduction. in detail, the results revealed that the AOT solutions has a sharper reduction in the IFT values around 500 ppm regardless of the oil type while for CTAB solution and acidic crude oil, there is no sharp reduction in IFT to determine the CMC point although for the CTAB solution and SMRAO the CMC values around 1000 ppm could be observed while further increase in the CTAB concentration from 1000 ppm to 2000 ppm was capable to slightly change the IFT from 2.6 mN/m to 2.3 MN/m.\u003c/p\u003e \u003cp\u003eThe reason for the lower Critical Micelle Concentration (CMC) value of the resinous synthetic oil, particularly when using AOT, may be attributed to the surface activity of the resin molecules. This activity enhances the effect of AOT in the solution, resulting in better interfacial tension (IFT) reduction even at a low concentration of 500 ppm. Furthermore, it is possible to relate the greater efficiency of SDBS compared to AOT to its chain-like structure, which has minimal branching. In contrast, AOT molecules are more branched. The branched structure of AOT molecules hinders their ability to pack efficiently at the interface, which consequently reduces the molecular concentration there and results in lower IFT capability. On the other hand, the chain-like structure of SDBS allows for a higher number of molecules to pack at the interface, leading to an increased surfactant concentration and, therefore, lower IFT values.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003cp\u003eIn the next stage of this investigation, the impact of DPGW was examined on the IFT of aqueous solutions were prepared using AOT and CTAB in contact with the acidic crude oil and SMRAO. The measurements (see Fig.\u0026nbsp;\u003cspan refid=\"Fig4\" class=\"InternalRef\"\u003e5\u003c/span\u003e) revealed that replacing the DPGW with formation brine has a considerable impact on the IFT reduction regardless of the used oil types. In detail, the measurements revealed that using DPGW as the aqueous medium instead of formation brine was capable to change the IFT values from 33.5 to 23.6 mN/m and 26.2 to 19.9 mN/m for acidic crude oil and SMRAO, respectively. The reason behind the obtained results can be correlated to the ionic composition of the DPGW compared with the formation brine which was not only lower in the con centration but also was different from the type of ions. One of the distinct differences between the composition of the DPGW and formation brine is the presence of sulfate ions which has a considerable impact on the IFT reduction and wettability alteration especially considering its interaction with resin and asphaltene fractions which can act as the natural surfactants.\u003c/p\u003e \u003cp\u003eFurther analysis of the measured IFT values revealed that using DPGW instead of formation brine was capable to reduce the IFT value of the system to minimum value of 0.69 mN/m for the AOT solution with concentration of 2000 ppm in contact with SMRAO. The other point which can be extracted from the measured IFT values is that the impact of using DPGW instead of formation brine on the IFT reduction for CTAB solutions was higher than that values obtained for AOT solution. In detail, the application of DPGW was capable to reduce the IFT values for AOT (with concentration of 2000 ppm) from 0.85 mN/m to 0.69 MN for SMRAO and 1.1 mN/m to 0.95 mN/m for acidic crude oil which is a slight further reduction in IFT values. In contrast, for CTAB solutions, using DPGW instead of formation brine reduced the IFT values from 4.9 mN/m to .6 mN/m for acidic crude oil and 2.3 mN/m to 0.87 mN/m for SMRAO which means higher impact of using DPGW on the IFT reduction of CTAB surfactant. The reason of this observed trend can be correlated to the following reasons.\u003c/p\u003e \u003cp\u003eThe interaction between the anionic surfactant AOT and sulfate ions in the presence of asphaltenes and resins significantly affects IFT, with results showing dual effects depending on the concentration of salts and the specific composition of the oil and aqueous phases. In details, Sulfate ions can influence the performance of surfactants like AOT (an anionic surfactant) in an aqueous solution. Generally, the addition of salts (specifically Na₂SO₄) to an aqueous surfactant system can decrease the critical micelle concentration (CMC) of the mixture, thereby enhancing the spontaneity of micelle formation due to ionic strength effects. However, in the context of crude oil interactions, sulfate ions exhibit a more complex behavior. In detail, At high salt concentrations (e.g., 15,000 ppm MgCl₂ solution with added MgSO₄), a further addition of sulfate can lead to a reduction in IFT. Extremely low IFT values can also be achieved at high concentrations (50,000 ppm) of Na₂SO₄ or MgSO₄, particularly at a high pH, which promotes the in-situ production of natural surfactants (saponification). However, at low salt concentrations, the addition of magnesium sulfate (MgSO₄) can actually reduce the affinity of natural surfactants (asphaltenes and resins) toward the interface, leading to an increase in IFT. So, as a consequence of these possible facts and presence of other ions with lower concentrations compared with the formation brine, only a slight reduction in the IFT values was observed.\u003c/p\u003e \u003cp\u003eBut in contrast to the results obtained for the AOT, the results revealed a considerable impact of saline water type on the IFT of CTAB solutions. The reason of this observed trend can be due to this fact that the interaction between the cationic surfactant CTAB and sulfate ions generally leads to a significant reduction in interfacial tension (IFT), especially at lower salinities, and enhances the desorption of asphaltenic/resinous material from surfaces. This is primarily due to the formation of ion pairs and synergistic effects that modify the behavior of natural surfactants (asphaltenes and resins) at the oil-water interface. Besides, CTAB is a cationic surfactant, and sulfate is a divalentznion. The positive charge of the CTAB head group interacts with the negative charge of the sulfate ion to form ion pairs. So, the combination of CTAB and sulfate ions often results in a more significant IFT reduction compared to either agent alone. This synergy improves the overall efficiency of the surfactant system in mobilizing oil. On the other side, the specific ions (CTAB cations and sulfate anions) interact with the polar components (heteroatoms) of asphaltenes and resins. These interactions can affect the packing and arrangement of these molecules at the interface, thereby influencing the IFT value.\u003c/p\u003e \u003cp\u003e \u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec10\" class=\"Section2\"\u003e \u003ch2\u003e3.3. Effect of surfactants on contact angle\u003c/h2\u003e \u003cp\u003eIn the next stage of this investigation and in the way of studying the wettability alteration mechanism, the effects of surfactants on the wettability alteration using contact angle measurements using the DPGW as the main saline water and aqueous medium was examined. The point is that since the effect of DPGW on the IFT reduction was better than the formation brine, only the effect of aqueous solutions prepared with the DPGW and activated with surfactant were used to find the contact angle variation and wettability alteration. The measured contact angle values tabulated in Tables\u0026nbsp;\u003cspan refid=\"Tab2\" class=\"InternalRef\"\u003e2\u003c/span\u003e and \u003cspan refid=\"Tab3\" class=\"InternalRef\"\u003e3\u003c/span\u003e revealed that as the concentration of surfactants were increased, the contact angle values were reduced which means the movement of the rock surface toward water wet conditions. In detail, the measurements revealed that the contact angle values for distilled water and acidic crude oil and SMRAO oils were 141.2\u003csup\u003eo\u003c/sup\u003e and 152.9\u003csup\u003eo\u003c/sup\u003e, respectively. However, using DPGW instead of distilled water can change the contact angle values from 141.2\u003csup\u003eo\u003c/sup\u003e and 152.9\u003csup\u003eo\u003c/sup\u003e to 98.5\u003csup\u003eo\u003c/sup\u003e and 9.1\u003csup\u003eo\u003c/sup\u003e, respectively. The results also revealed that, as the surfactant were added to the saline water; it was possible to reduce the contact angle to minimum values of 49.1\u003csup\u003eo\u003c/sup\u003e and 44.7\u003csup\u003eo\u003c/sup\u003e for CTAB dissolved in DPGW in contact with acidic and SMRAO, respectively. However, for the solutions activated with AOT the situation was better and the contact angle values were reduced to 40.1\u003csup\u003eo\u003c/sup\u003e and 39.7\u003csup\u003eo\u003c/sup\u003e for acidic crude oil and SMRAO as the concentration of AOT was increased to 2000 ppm.\u003c/p\u003e \u003cp\u003eThe obtained trend for CTAB and AOT can be correlated to the following reasons. CTAB and sulfate ions both act as effective agents for altering wettability, generally by helping to transform an oil-wet rock surface towards a more water-wet state, a process critical for enhanced oil recovery. Their mechanisms often work synergistically in carbonate reservoirs. In more details, CTAB is a cationic (positively charged) surfactant. It strongly adsorbs onto negatively charged rock surfaces (like sandstone, mica, or certain sites on carbonates) or interacts with negatively charged carboxylate groups of crude oil components (like asphaltenes) adsorbed on the rock surface. This interaction forms ion-pairs, which desorb from the surface and are solubilized into the aqueous phase. As a consequence of removal of oil components makes the rock surface more water-wet. The other point is that, at low concentrations, CTAB initially might make the surface more oil-wet by forming a hydrophobic monolayer. However, as the concentration increases past the critical micelle concentration (CMC), it forms a hydrophilic bilayer, sharply reversing the wettability to water-wet. On the other hand, AOT is an anionic surfactant. It alters wettability by adsorbing onto the rock surface, which is often oil-wet due to adsorbed crude oil components (like carboxylic acids/asphaltenes). The surfactant molecules attach to the surface, displacing the oil components and exposing a more water-wet head group or forming a water-wet layer.\u003c/p\u003e \u003cp\u003eRegardless of the surfactants effect on the wettability alteration, the presence of sulfate ions. On the other sides, the presence of sulfate ions can be considered as the other effective reason of wettability alteration. In details, Sulfate ions are highly active anions that can bond with positively charged sites, such as calcium ions (Ca\u003csup\u003e2+\u003c/sup\u003e) on a carbonate rock surface (calcite). This interaction releases the adsorbed oil components (e.g., carboxylic acids) that were previously bonded with the Ca\u003csup\u003e2+\u003c/sup\u003e ions. As a consequence, the desorption of oil molecules increases the negative charge on the rock surface, enhancing its water-wetness and promoting the spontaneous imbibition of water.\u003c/p\u003e \u003cp\u003eIn the case of CTAB presence in the aqueous solution, the system would be more complicated. In detail the presence of the cationic CTAB molecules and sulfate ions works in tandem to desorb adsorbed carboxylate groups from the rock surface. On the other side, the sulfate ions help facilitate the approach of the cationic CTAB to the aged calcite surface by mitigating electrostatic repulsion, leading to more effective oil removal. The other possible reason behind the significant impact of CTAB and sulfate ions can be due to this fact that in systems involving a rock surface (e.g., calcite, which often has a negative charge due to adsorbed carboxylate groups), the co-presence of sulfate ions and CTAB can lead to a more water-wet surface. The sulfate ions can interact with any adsorbed calcium ions, while CTAB forms ion pairs with the negatively charged carboxylate groups on the surface, facilitating their desorption into the aqueous phase and thus making more CTAB available at the oil-water interface.\u003c/p\u003e \u003cp\u003eBut in the case of AOT, as sulfate ions are present with anionic surfactants like AOT, they can work synergistically. The sulfate ions help attenuate the positive charge of the rock surface, which reduces the electrostatic repulsion or promotes the approach of the negatively charged AOT molecules, thereby enhancing the overall wettability alteration effect.\u003c/p\u003e \u003cp\u003e \u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab2\" border=\"1\"\u003e \u003ccaption language=\"En\"\u003e \u003cdiv class=\"CaptionNumber\"\u003eTable 2\u003c/div\u003e \u003cdiv class=\"CaptionContent\"\u003e \u003cp\u003eThe effect of CTAB on the wettability of the carbonate rock\u003c/p\u003e \u003c/div\u003e \u003c/caption\u003e \u003ccolgroup cols=\"4\"\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c4\" colnum=\"4\"\u003e\u003c/div\u003e \u003cthead\u003e \u003ctr\u003e \u003cth align=\"left\" colspan=\"2\" nameend=\"c2\" namest=\"c1\"\u003e \u003cp\u003eAcidic Crude Oil\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colspan=\"2\" nameend=\"c4\" namest=\"c3\"\u003e \u003cp\u003eSMRAO\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003c/thead\u003e \u003ctbody\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eCTAB Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003eContact Angle (degree)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003eCTAB Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eContact Angle (degree)\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e98.5\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e91.1\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e90.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e87.6\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e79.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e73.6\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e500\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e68.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e500\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e66.9\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e1000\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e57.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e1000\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e53.6\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e2000\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e49.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e2000\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e44.7\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003c/tbody\u003e \u003c/colgroup\u003e \u003c/table\u003e\u003c/div\u003e \u003c/p\u003e \u003cp\u003e \u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab3\" border=\"1\"\u003e \u003ccaption language=\"En\"\u003e \u003cdiv class=\"CaptionNumber\"\u003eTable 3\u003c/div\u003e \u003cdiv class=\"CaptionContent\"\u003e \u003cp\u003eThe effect of AOT on the wettability of the carbonate rock\u003c/p\u003e \u003c/div\u003e \u003c/caption\u003e \u003ccolgroup cols=\"4\"\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c4\" colnum=\"4\"\u003e\u003c/div\u003e \u003cthead\u003e \u003ctr\u003e \u003cth align=\"left\" colspan=\"2\" nameend=\"c2\" namest=\"c1\"\u003e \u003cp\u003eAcidic Crude Oil\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colspan=\"2\" nameend=\"c4\" namest=\"c3\"\u003e \u003cp\u003eSMRAO\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003c/thead\u003e \u003ctbody\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eAOT Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003eContact Angle (degree)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003eAOT Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eContact Angle (degree)\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e98.5\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e91.1\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e88.8\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e88.1\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e73.6\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e71.1\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e500\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e60.5\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e500\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e58.7\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e1000\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e51.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e1000\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e49.9\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e2000\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e40.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e2000\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e39.7\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003c/tbody\u003e \u003c/colgroup\u003e \u003c/table\u003e\u003c/div\u003e \u003c/p\u003e \u003cp\u003eSimilarly, Xie et al. \u003csup\u003e51\u003c/sup\u003e also investigated the effect of nonionic and cationic surfactants on wettability alteration using 50 cores obtained from two different carbonate reservoirs. They reported that the nonionic surfactant enhanced oil recovery more than the cationic surfactant due to its lower interfacial tension. Their results revealed that nonionic surfactants resulted in greater wettability alteration towards water-wet conditions, which led to increased oil recovery.\u003c/p\u003e \u003cp\u003eBesides, Seethepalli et.al. \u003csup\u003e52\u003c/sup\u003e reported that anionic surfactants have been more effective than cationic surfactants. They utilized various anionic surfactants, including SS-6656 and Alfoterra-35, -38, -63, -65, and \u0026minus;\u0026thinsp;68, alongside cationic surfactants such as DTAB. It was found that the anionic surfactants were able to change the wettability of the calcite surface to intermediate or water-wet conditions, achieving similar or greater effects than the cationic surfactants like DTAB.\u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec11\" class=\"Section2\"\u003e \u003ch2\u003e3.4. Contact angle variation due to presence of NPs\u003c/h2\u003e \u003cp\u003eIn this phase of current investigation, the effects of CuO and TiO\u003csub\u003e2\u003c/sub\u003e NPs on the wettability alteration of the optimum surfactant solution prepared with DPGW were examined individually and in combination form on the contact angle variation and wettability alteration. In this way, the concentration of CuO and TiO\u003csub\u003e2\u003c/sub\u003e were changed between 0-250 ppm and 0-500 ppm for CuO and TiO\u003csub\u003e2\u003c/sub\u003e, respectively (see Tables\u0026nbsp;\u003cspan refid=\"Tab7\" class=\"InternalRef\"\u003e4\u003c/span\u003e and \u003cspan refid=\"Tab5\" class=\"InternalRef\"\u003e5\u003c/span\u003e). The point is that, the optimum surfactant concentration for both surfactant of AOT and CTAB was selected at 1000 ppm since there was no significant difference between the contact angle of the solutions prepared with 2000 ppm and 1000 ppm while the expense of preparing such a solution for filed applications could be unreasonable.\u003c/p\u003e \u003cp\u003eThe measured contact angle values revealed that among the examined NPs, TiO\u003csub\u003e2\u003c/sub\u003e NPs has a better impact for contact angle variation and reduction toward more water-wet conditions. In detail, the application of TiO\u003csub\u003e2\u003c/sub\u003e with concentration of 500 ppm leading to contact angle value of about 27.7\u003csup\u003eo\u003c/sup\u003e and 23.3\u003csup\u003eo\u003c/sup\u003e for AOT solution in contact with the acidic crude oil and SMRAO while for CTAB solutions minimum contact angle values of 33.7\u003csup\u003eo\u003c/sup\u003e and 30.1\u003csup\u003eo\u003c/sup\u003e for acidic crude oil and SMRAO, respectively were obtained. Considering these results one can conclude that the addition of TiO\u003csub\u003e2\u003c/sub\u003e NPs into the AOT surfactant solution has a higher effect for wettability alteration than the CTAB solutions.\u003c/p\u003e \u003cp\u003eIn details, TiO\u003csub\u003e2\u003c/sub\u003e NPs and the surfactant AOT significantly alter wettability, primarily by transforming surfaces from oil-wet to more water-wet conditions. The combination of the two agents can have a synergistic effect, though in some specific cases, an antagonistic effect on wettability has been observed. In detail, TiO\u003csub\u003e2\u003c/sub\u003e NPs alter wettability by adsorbing onto the solid surface, dislodging oil molecules, and creating a more hydrophilic (water-wet) environment. In other words, NPs due to their small size and high surface-area-to-volume ratio can penetrate small pores and attach to the rock surface. This process mechanically dislodges trapped oil and inverts the rock's wetting preference from oil-wet to water-wet, reducing the oil-rock contact area.\u003c/p\u003e \u003cp\u003eBut, in the case of CTAB and TiO\u003csub\u003e2\u003c/sub\u003e NPs, CTAB molecules can adsorb onto the surface of the TiO\u003csub\u003e2\u003c/sub\u003e NPs, leading to surface modification. These modified nanoparticles then adsorb onto the rock or substrate surface more effectively, creating a strongly hydrophilic (water-wet) nano-textured layer. This layer displaces oil droplets more efficiently. The other possible mechanism is that CTAB also play a critical role in stabilizing the nanoparticles in the fluid, preventing them from aggregating and settling, which ensures better injectivity and transport through porous media (e.g., in a reservoir rock). As the last mechanism which is not related to the surfactant type is the disjoining pressure. The nanoparticles create a structural disjoining pressure (a repulsive force) in the thin film of water between the oil and the rock surface. This force helps to push the oil droplets away from the surface which makes the rock surface, more water-wet.\u003c/p\u003e \u003cp\u003eIn the last stage of this section, the impact of combining NPs with a concentration of 100 ppm for each NPs was examined on the wettability alteration of aqueous solutions prepared with 1000 ppm of AOT or 1000 ppm of CTAB dissolved in the DPGW.\u003c/p\u003e \u003cp\u003e \u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab4\" border=\"1\"\u003e \u003ccaption language=\"En\"\u003e \u003cdiv class=\"CaptionNumber\"\u003eTable 4\u003c/div\u003e \u003cdiv class=\"CaptionContent\"\u003e \u003cp\u003eThe effect of TiO\u003csub\u003e2\u003c/sub\u003e-NPs on the wettability alteration\u003c/p\u003e \u003c/div\u003e \u003c/caption\u003e \u003ccolgroup cols=\"4\"\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c4\" colnum=\"4\"\u003e\u003c/div\u003e \u003cthead\u003e \u003ctr\u003e \u003cth align=\"left\" colspan=\"4\" nameend=\"c4\" namest=\"c1\"\u003e \u003cp\u003e1000 ppm CTAB\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003c/thead\u003e \u003ctbody\u003e \u003ctr\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c2\" namest=\"c1\"\u003e \u003cp\u003eAcidic Crude Oil\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c4\" namest=\"c3\"\u003e \u003cp\u003eSMRAO\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eTiO\u003csub\u003e2\u003c/sub\u003e Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003eContact Angle (Degree)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003eTiO\u003csub\u003e2\u003c/sub\u003e Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eContact Angle (Degree)\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e57.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e53.6\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e52.2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e46.6\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e40.3\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e37.7\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e500\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e33.7\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e500\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e30.1\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colspan=\"4\" nameend=\"c4\" namest=\"c1\"\u003e \u003cp\u003e1000 ppm AOT\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c2\" namest=\"c1\"\u003e \u003cp\u003eAcidic Crude Oil\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c4\" namest=\"c3\"\u003e \u003cp\u003eSMRAO\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eTiO\u003csub\u003e2\u003c/sub\u003e Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003eContact Angle (Degree)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003eTiO\u003csub\u003e2\u003c/sub\u003e Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eContact Angle (Degree)\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e51.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e49.9\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e44.4\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e40.2\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e35.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e31.1\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e500\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e27.7\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e500\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e23.3\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003c/tbody\u003e \u003c/colgroup\u003e \u003c/table\u003e\u003c/div\u003e \u003c/p\u003e \u003cp\u003eThe measurements revealed the significant synergistic effect of using these two NPs in a hybrid solution since the contact angle values were reduced to 39.9\u003csup\u003eo\u003c/sup\u003e and 33.6\u003csup\u003eo\u003c/sup\u003e for acidic crude oil and SMRAO in contact with the CTAB solution and 31.2\u003csup\u003eo\u003c/sup\u003e and 26.6\u003csup\u003eo\u003c/sup\u003e for the acidic crude oil and SMRAO in contact with the AOT solution. Considering the results of this section and those obtained for the individual application of NPs for wettability alteration, it seems that the hybrid application with lower concentration of NPs leading to better wettability alteration potential. So, it can be concluded that the combined application of the NPs no matter which surfactant being used can be considered as one of the most effective solutions for EOR purposes.\u003c/p\u003e \u003cp\u003e \u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab5\" border=\"1\"\u003e \u003ccaption language=\"En\"\u003e \u003cdiv class=\"CaptionNumber\"\u003eTable 5\u003c/div\u003e \u003cdiv class=\"CaptionContent\"\u003e \u003cp\u003eThe effect of CuO-NPs on the wettability alteration\u003c/p\u003e \u003c/div\u003e \u003c/caption\u003e \u003ccolgroup cols=\"4\"\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c4\" colnum=\"4\"\u003e\u003c/div\u003e \u003cthead\u003e \u003ctr\u003e \u003cth align=\"left\" colspan=\"4\" nameend=\"c4\" namest=\"c1\"\u003e \u003cp\u003e1000 ppm CTAB\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003c/thead\u003e \u003ctbody\u003e \u003ctr\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c2\" namest=\"c1\"\u003e \u003cp\u003eAcidic Crude Oil\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c4\" namest=\"c3\"\u003e \u003cp\u003eSMRAO\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eCuO Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003eContact Angle (Degree)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003eCuO Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eContact Angle (Degree)\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e57.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e53.6\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e55.5\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e49.9\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e42.2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e41.1\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colspan=\"4\" nameend=\"c4\" namest=\"c1\"\u003e \u003cp\u003e1000 ppm AOT\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c2\" namest=\"c1\"\u003e \u003cp\u003eAcidic Crude Oil\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c4\" namest=\"c3\"\u003e \u003cp\u003eSMRAO\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eCuO Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003eContact Angle (Degree)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003eCuO Concentration (ppm)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eContact Angle (Degree)\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e51.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e0\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e49.9\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e44.3\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e100\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e43.3\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e39.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e250\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e37.7\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003c/tbody\u003e \u003c/colgroup\u003e \u003c/table\u003e\u003c/div\u003e \u003c/p\u003e \u003cp\u003e \u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab6\" border=\"1\"\u003e \u003ccaption language=\"En\"\u003e \u003cdiv class=\"CaptionNumber\"\u003eTable 6\u003c/div\u003e \u003cdiv class=\"CaptionContent\"\u003e \u003cp\u003eThe effect of hybrid NPS solutions on the contact angle\u003c/p\u003e \u003c/div\u003e \u003c/caption\u003e \u003ccolgroup cols=\"4\"\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c4\" colnum=\"4\"\u003e\u003c/div\u003e \u003cthead\u003e \u003ctr\u003e \u003cth align=\"left\" colspan=\"4\" nameend=\"c4\" namest=\"c1\"\u003e \u003cp\u003e100 ppm TiO2\u0026thinsp;+\u0026thinsp;100 ppm CuO\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003c/thead\u003e \u003ctbody\u003e \u003ctr\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c2\" namest=\"c1\"\u003e \u003cp\u003eCTAB\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colspan=\"2\" nameend=\"c4\" namest=\"c3\"\u003e \u003cp\u003eAOT\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003eAcidic Crude Oil\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003eSMRAO\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003eAcidic Crude Oil\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eSMRAO\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e39.9\u003csup\u003eo\u003c/sup\u003e\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c2\"\u003e \u003cp\u003e33.6 \u003csup\u003eo\u003c/sup\u003e\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c3\"\u003e \u003cp\u003e31.2 \u003csup\u003eo\u003c/sup\u003e\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003e26.6 \u003csup\u003eo\u003c/sup\u003e\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003c/tbody\u003e \u003c/colgroup\u003e \u003c/table\u003e\u003c/div\u003e \u003c/p\u003e \u003c/div\u003e \u003cdiv id=\"Sec12\" class=\"Section2\"\u003e \u003ch2\u003e3.5. Effect of optimum chemical formulation on tertiary oil recovery\u003c/h2\u003e \u003cp\u003eIn the last stage of this investigation, the application of optimum chemical formulations was used to find their effects on the oil recovery. In this way, four optimum chemical formulations were selected to be used in the core flooding experiments. These chemical solutions were 1000 ppm AOT\u0026thinsp;+\u0026thinsp;250 ppm TiO\u003csub\u003e2\u003c/sub\u003e NPs, 1000 ppm CTAB\u0026thinsp;+\u0026thinsp;250 TiO\u003csub\u003e2\u003c/sub\u003e NPs, 1000 ppm AOT\u0026thinsp;+\u0026thinsp;100 ppm TiO\u003csub\u003e2\u003c/sub\u003e, and 100 ppm CuO NPs using DPGW as the aqueous medium. The point is that the surfactant solutions with CuO were not used for core flooding experiments since they have a limited impact on the wettability alteration. In this way, only the hybrid chemical solutions prepared with CuO and TiO\u003csub\u003e2\u003c/sub\u003e NPs were used to find their impact on the tertiary oil recovery. The other point is that not only the injection of these four solutions for EOR purposes was examined, but also the soaking period of about 30 days was applied using these four solutions to see if they are capable of activating the wettability alteration to its maximum level. In other words, by applying a soaking period, it is possible to provide the chance for the chemical solution to enhance its ultimate impact on the pores and rock surface for wettability alteration, which is one of the main mechanisms during the chemical injection approach.\u003c/p\u003e \u003cp\u003eThe obtained results revealed that the used chemical solutions were capable of increasing the oil recovery in the range of 6.7\u0026ndash;12.8% based on the original oil in place (OOIP) while introducing a soaking period of 30 days can increase the tertiary oil recovery to the range of 10.9\u0026ndash;16.6% based on OOIP which comes from the ultimate activation of wettability alteration mechanism. In other words, as the chemical slug was injected into the core and then flooded with the DPGW as the sweeping fluid, the injected solution did not have enough time to activate the wettability alteration mechanisms since it is a time-consuming mechanism, while the IFT reduction is a fast mechanism. So, the injection of the chemical solutions without a soaking period can only use the potential of the chemical solution for IFT reduction and slightly the ability of wettability alteration. However, in the case of soaking, as the chemical slug was injected and then it was shut off, the chemicals had enough time to penetrate the majority of the pores and change its wettability since it is time time-consuming phenomenon along with the rapid IFT reduction. This is the net effect of these two factors can increase the tertiary oil recovery more than the values obtained from the situations where only conventional injection and sweeping were performed.\u003c/p\u003e \u003cp\u003e \u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab7\" border=\"1\"\u003e \u003ccaption language=\"En\"\u003e \u003cdiv class=\"CaptionNumber\"\u003eTable 4\u003c/div\u003e \u003cdiv class=\"CaptionContent\"\u003e \u003cp\u003eThe effect of optimal chemical formulation and different injection patterns on tertiary oil recovery.\u003c/p\u003e \u003c/div\u003e \u003c/caption\u003e \u003ccolgroup cols=\"8\"\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e \u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e \u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c4\" colnum=\"4\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c5\" colnum=\"5\"\u003e\u003c/div\u003e \u003cdiv align=\"left\" class=\"colspec\" colname=\"c6\" colnum=\"6\"\u003e\u003c/div\u003e \u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c7\" colnum=\"7\"\u003e\u003c/div\u003e \u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c8\" colnum=\"8\"\u003e\u003c/div\u003e \u003cthead\u003e \u003ctr\u003e \u003cth align=\"left\" colname=\"c1\"\u003e \u003cp\u003eNo\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c2\"\u003e \u003cp\u003ePermeability (mD)\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c3\"\u003e \u003cp\u003ePorosity (%)\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c4\"\u003e \u003cp\u003eSolutions\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c5\"\u003e \u003cp\u003eSoaking (Shut-off)\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c6\"\u003e\u0026nbsp;\u003c/th\u003e \u003cth align=\"left\" colname=\"c7\"\u003e \u003cp\u003eSecondary oil recovery % based on OOIP\u003c/p\u003e \u003c/th\u003e \u003cth align=\"left\" colname=\"c8\"\u003e \u003cp\u003eTertiary oil recovery % based on OOIP\u003c/p\u003e \u003c/th\u003e \u003c/tr\u003e \u003c/thead\u003e \u003ctbody\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e11.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e15.7\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eCTAB/TiO\u003csub\u003e2\u003c/sub\u003e-NPs\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c5\"\u003e \u003cp\u003eNo\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c6\"\u003e\u0026nbsp;\u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c7\"\u003e \u003cp\u003e34.5\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c8\"\u003e \u003cp\u003e6.7\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e9.6\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e18.2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eCTAB/TiO\u003csub\u003e2\u003c/sub\u003e-NPs\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c5\"\u003e \u003cp\u003eYes (30 days)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c6\"\u003e\u0026nbsp;\u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c7\"\u003e \u003cp\u003e38.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c8\"\u003e \u003cp\u003e10.9\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e3\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e8.3\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e14.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eAOT/TiO\u003csub\u003e2\u003c/sub\u003e-NPs\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c5\"\u003e \u003cp\u003eNo\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c6\"\u003e\u0026nbsp;\u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c7\"\u003e \u003cp\u003e45.2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c8\"\u003e \u003cp\u003e10.1\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e4\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e10.2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e16.6\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eAOT/TiO\u003csub\u003e2\u003c/sub\u003e-NPs\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c5\"\u003e \u003cp\u003eYes (30 days)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c6\"\u003e\u0026nbsp;\u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c7\"\u003e \u003cp\u003e37.9\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c8\"\u003e \u003cp\u003e13.8\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e5\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e8.8\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e12.2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eAOT/CuO/TiO\u003csub\u003e2\u003c/sub\u003e-NPs\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c5\"\u003e \u003cp\u003eNo\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c6\"\u003e\u0026nbsp;\u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c7\"\u003e \u003cp\u003e36.6\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c8\"\u003e \u003cp\u003e12.8\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e6\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e7.2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e15.5\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eAOT/CuO/TiO\u003csub\u003e2\u003c/sub\u003e-NPs\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c5\"\u003e \u003cp\u003eYes (30 days)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c6\"\u003e\u0026nbsp;\u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c7\"\u003e \u003cp\u003e40.2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c8\"\u003e \u003cp\u003e16.6\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e7\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e12.2\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e19.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eCTAB/CuO/TiO\u003csub\u003e2\u003c/sub\u003e-NPs\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c5\"\u003e \u003cp\u003eNo\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c6\"\u003e\u0026nbsp;\u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c7\"\u003e \u003cp\u003e47.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c8\"\u003e \u003cp\u003e9.2\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003ctr\u003e \u003ctd align=\"left\" colname=\"c1\"\u003e \u003cp\u003e8\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e \u003cp\u003e9.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c3\"\u003e \u003cp\u003e20.1\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c4\"\u003e \u003cp\u003eCTAB/CuO/TiO\u003csub\u003e2\u003c/sub\u003e-NPs\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c5\"\u003e \u003cp\u003eYes (30 days)\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"left\" colname=\"c6\"\u003e\u0026nbsp;\u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c7\"\u003e \u003cp\u003e43.3\u003c/p\u003e \u003c/td\u003e \u003ctd align=\"char\" char=\".\" colname=\"c8\"\u003e \u003cp\u003e13.6\u003c/p\u003e \u003c/td\u003e \u003c/tr\u003e \u003c/tbody\u003e \u003c/colgroup\u003e \u003c/table\u003e\u003c/div\u003e \u003c/p\u003e \u003c/div\u003e"},{"header":"Conclusions","content":"\u003cp\u003eIn this study, we focused on the synergistic effects between two surfactants\u0026mdash;cetrimonium bromide (CTAB) and dioctyl sulfosuccinate sodium (AOT)\u0026mdash;and their interaction with titanium dioxide (TiO2) at concentrations ranging from 0 to 500 ppm, as well as copper oxide (CuO) nanoparticles (NPs) at concentrations from 0 to 250 ppm. We tested these combinations in contact with two types of oil: synthetic mixed resinous and asphaltenic oil (SMRAO) and acidic crude oil (ACO). The primary parameters investigated were interfacial tension (IFT), wettability alterations based on contact angle (CA) measurements, and core flooding experiments using the optimal chemical formulations to assess their effect on tertiary oil recovery. The results from these experiments revealed the following findings:\u003c/p\u003e\n\u003cp\u003e1. The IFT measurements indicated that using formation brine or DPGW affected the IFT values. Specifically, SMRAO showed lower IFT (19.9 mN/m) than ACO (23.6 mN/m). In solutions made with formation brine, the IFTs were higher for both oils (SMRAO at 26.2 mN/m and ACO at 33.5 mN/m). This can be attributed to the natural surfactant properties of resin and asphaltene fractions, which move toward the interface, reducing IFT values.\u003c/p\u003e\n\u003cp\u003e2. We also found that replacing DPGW with formation brine significantly influenced IFT reduction, particularly for SMRAO. This effect is likely due to better salting-in and salting-out phenomena that facilitate the movement of asphaltene and resin molecules toward the interface, increasing their concentration and lowering the IFT values.\u003c/p\u003e\n\u003cp\u003e3. Among the surfactants, AOT was found to be more effective for IFT reduction, achieving a minimum IFT value of 0.69 mN/m, regardless of whether DPGW or formation brine was used. However, the reduction was more pronounced in solutions prepared with DPGW. The IFT data also suggested that DPGW positively impacted the critical micelle concentration (CMC), lowering it to about 500 ppm for both surfactants compared to 1000 ppm when using formation brine.\u003c/p\u003e\n\u003cp\u003e4. The CA measurements demonstrated that substituting DPGW for distilled water decreased the CA values significantly for ACO (from 141.2\u0026deg;C to 98.5\u0026deg;C) and SMRAO (from 152.9\u0026deg;C to 91.1\u0026deg;C). However, saturated and aromatic compounds were observed to reduce the effectiveness of resin and asphaltene in altering rock surface wettability toward more oil-wet conditions.\u003c/p\u003e\n\u003cp\u003e5. Additional tests showed that AOT was particularly effective in changing wettability, with CA values reduced to 40.1\u0026deg; for ACO and 39.7\u0026deg; for SMRAO. Both the IFT and CA measurements indicated that solutions containing SMRAO achieved better IFT reduction and more effective wettability alteration, attributed to the surface-active properties of resin and asphaltene, acting as additional surfactants.\u003c/p\u003e\n\u003cp\u003e6. The CA measurements with CuO and TiO2 NPs demonstrated that dissolving these NPs as a secondary aqueous solution activator significantly modifies wettability, reducing CA values to 27.7\u0026deg;C for ACO and 23.3\u0026deg;C for SMRAO when combined with a 1000 ppm AOT solution. Although CuO also showed effectiveness, it was less impactful than TiO2 NPs for achieving more water-wet conditions, with CA values of 39.1\u0026deg;C and 37.7\u0026deg;C for ACO and SMRAO, respectively.\u003c/p\u003e\n\u003cp\u003e7. Investigating the combination of NPs at a concentration of 100 ppm each, dissolved in 1000 ppm of AOT and CTAB, demonstrated a significant reduction in CA values to 31.2\u0026deg;C and 26.6\u0026deg;C for ACO, and 39.9\u0026deg;C and 33.6\u0026deg;C for SMRAO, indicating a positive interaction between the NPs and the surfactants. This combination facilitated better wettability alteration for the optimal chemical formulations prepared with hybrid NPs alongside 1000 ppm of AOT or CTAB.\u003c/p\u003e\n\u003cp\u003e8. Finally, we conducted eight different core flooding experiments that revealed that using the optimal chemical formulation of 100 ppm CuO, 0 ppm TiO2, and 1000 ppm AOT in contact with SMRAO resulted in a 12.8% oil recovery based on original oil in place (OOIP). Additionally, after a 30-day soaking period, oil recovery improved to 16.6% of OOIP. This enhanced recovery can be attributed to the significant impact of wettability alteration achieved through the optimal chemical formulation, as the soaking period allows for a more effective alteration process.\u003c/p\u003e"},{"header":"Declarations","content":"\u003cul\u003e\n \u003cli\u003eFunding and Competing interests\u003c/li\u003e\n\u003c/ul\u003e\n\u003cp\u003eNo funding was received to assist with the preparation of this manuscript.\u003c/p\u003e\n\u003cul\u003e\n \u003cli\u003eData availability\u003c/li\u003e\n\u003c/ul\u003e\n\u003cp\u003eThe datasets used and/or analyzed during the current study available from the corresponding author (Dr. Seyednooroldin Hosseini) on reasonable request sent by email to \u0026nbsp;[email protected]\u003cstrong\u003e\u003cem\u003e\u003cu\u003e.\u003c/u\u003e\u003c/em\u003e\u003c/strong\u003e\u003c/p\u003e"},{"header":"References","content":"\u003col\u003e\n \u003cli\u003eE. 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The synergic effects of anionic and cationic chemical surfactants, and bacterial solution on wettability alteration of carbonate rock: an experimental investigation. \u003cem\u003eColloids and Surfaces A: Physicochemical and Engineering Aspects\u003c/em\u003e \u003cstrong\u003e513\u003c/strong\u003e, 422-429 (2017).\u003c/li\u003e\n \u003cli\u003eDehaghani, A. H. S., Hosseini, M., Tajikmansori, A. \u0026amp; Moradi, H. A mechanistic investigation of the effect of ion-tuned water injection in the presence of cationic surfactant in carbonate rocks: an experimental study. \u003cem\u003eJournal of Molecular Liquids\u003c/em\u003e \u003cstrong\u003e304\u003c/strong\u003e, 112781 (2020).\u003c/li\u003e\n \u003cli\u003eDerikvand, Z., Rezaei, A., Parsaei, R., Riazi, M. \u0026amp; Torabi, F. 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The asphaltene and resin fractions of crude oil, regardless of the oil type, greatly influence surface phenomena. In light of these facts, the current investigation aims to assess the impacts of two surfactants—dioctyl sulfosuccinate sodium (AOT) and cetrimonium bromide (CTAB)— (with concentration of 0-2000 ppm) along with titanium oxide (TiO\u003csub\u003e2\u003c/sub\u003e) (with concentration of 0-500 ppm) and copper oxide (CuO) nanoparticles (NPs) (with concentration of 0-250 ppm) on interfacial tension (IFT) reduction and wettability alteration, using contact angle (CA) analysis for two types of acidic crude oil (ACO) and synthetic mixed resinous and asphaltenic oil (SMRAO). The measurements revealed that AOT is more efficient for IFT reduction, especially when using 50% diluted Persian Gulf water (DPGW). It was found that replacing distilled water (DW) with DPGW has a significant effect on IFT reduction by reducing the IFT values from 33.5 and 26.2 mN/m for ACO and SMRAO to 23.6 and 19.9 mN/m for ACO and SMRAO in contact with DPGW, respectively, likely due to the presence of sulfate ions and other ions that can function as “smart water.” In essence, the results indicated that the use of DPGW enhances the surface activity of the aqueous solution, and the addition of surfactants maximizes this effect by reducing the IFT value to minimum values of 0.95 and 0.69 mN/m for AOT solutions with concentration of 2000 ppm dissolved in DPGW in contact with ACO and SMRAO, respectively. In the second stage, the effects of surfactants on wettability alteration were investigated through contact angle measurements. These tests demonstrated a substantial impact of DPGW and the dissolved surfactants on wettability alteration. Specifically, the individual effect of DPGW led to a reduction in CA from 141.2° and 152.9° for ACO and SMRAO with DW, down to 98.5° and 91.1°, respectively which was toward neutral or mixed wettability conditions. Further measurements indicated that the presence of surfactants can enhance wettability alteration capabilities, with AOT showing a greater effect, resulting in contact angles of 40.1° and 39.7° for ACO and SMRAO, respectively. Notably, both IFT and CA measurements indicated that systems dealing with SMRAO experienced better IFT reduction and more effective wettability alteration, attributed to the surface-active nature of the resin and asphaltene, which act as additional surfactants. Moreover, the acidic nature of these fractions may provide additional opportunities for in-situ soap production and saponification processes that function as surfactants. The presence of NPs, specifically TiO\u003csub\u003e2\u003c/sub\u003e and CuO at concentrations of 0-500 ppm and 0-250 ppm, respectively, showed an improved potential for wettability alteration, trending toward a more water-wet condition, with TiO2 (500 ppm) in AOT (1000 ppm) solutions demonstrating superior results with CA values of 27.7\u003csup\u003eo\u003c/sup\u003e and 23.3\u003csup\u003eo\u003c/sup\u003e for ACO and SMRAO, respectively. Besides, the synergistic impact of these two NPs were examined on the wettability alteration using a solution activated with 1000 ppm of CTAB and AOT with concomitant presence of 100 ppm of TiO\u003csub\u003e2\u003c/sub\u003e and 100 ppm of CuO on the CA values. The measurements revealed a significant reduction in CA with lower amount of NPs demonstrating an excellent synergistic effect of chemicals with each other with minimum CA values of 31.2\u003csup\u003eo\u003c/sup\u003e and 26.6\u003csup\u003eo\u003c/sup\u003e for ACO and SMRAO, respectively, for AOT solution and those NPs. Finally, several optimum chemical formulations along with the solutions prepared with hybrid NPs were used to perform core flooding experiments revealed the possibility of producing 12.8 % based on original oil in place (OOIP) and 16.6% based on OOIP if 30 days of soaking are replaced with quick flooding, since wettability alteration can reach its ultimate impact during 30 days of soaking.\u003c/p\u003e","manuscriptTitle":"Synergy Between CTAB, AOT, TiO2 And CuO NPs for Surface Properties Modifications; Effects of Acidic Crude Oil and Syntehtic Mixed Resinous and Asphaltenic Oil and Saline Water","msid":"","msnumber":"","nonDraftVersions":[{"code":1,"date":"2026-02-12 09:10:22","doi":"10.21203/rs.3.rs-8232999/v1","editorialEvents":[{"type":"communityComments","content":0}],"status":"published","journal":{"display":true,"email":"[email protected]","identity":"researchsquare","isNatureJournal":false,"hasQc":true,"allowDirectSubmit":true,"externalIdentity":"","sideBox":"","snPcode":"","submissionUrl":"/submission","title":"Research Square","twitterHandle":"researchsquare","acdcEnabled":true,"dfaEnabled":false,"editorialSystem":"","reportingPortfolio":"","inReviewEnabled":false,"inReviewRevisionsEnabled":true}}],"origin":"","ownerIdentity":"555fba4d-058b-4249-af59-25ce27e7b9ca","owner":[],"postedDate":"February 12th, 2026","published":true,"recentEditorialEvents":[],"rejectedJournal":[],"revision":"","amendment":"","status":"posted","subjectAreas":[{"id":62719623,"name":"Physical sciences/Chemistry"},{"id":62719624,"name":"Earth and environmental sciences/Environmental sciences"},{"id":62719625,"name":"Physical sciences/Materials science"}],"tags":[],"updatedAt":"2026-03-23T13:26:09+00:00","versionOfRecord":[],"versionCreatedAt":"2026-02-12 09:10:22","video":"","vorDoi":"","vorDoiUrl":"","workflowStages":[]},"version":"v1","identity":"rs-8232999","journalConfig":"researchsquare"},"__N_SSP":true},"page":"/article/[identity]/[[...version]]","query":{"redirect":"/article/rs-8232999","identity":"rs-8232999","version":["v1"]},"buildId":"XKTyCvWXoU3ODBz1xrDgd","isFallback":false,"isExperimentalCompile":false,"dynamicIds":[84888],"gssp":true,"scriptLoader":[]}