Study on interfacial tension, wettability and viscosity in different salinities of synthesized a new polymeric surfactant for improving oil recovery | Scientific Reports

Scientific Reports volume 14, Article number: 24990 (2024) Cite this article

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Over 50% of the original oil in place (OOIP) is immobile or trapped in the reservoir. Therefore, today, more efficient methods have been introduced in the tertiary oil recovery sector as a scheme of enhanced oil recovery (EOR). Due to the decline of conventional hydrocarbon reserves, polymers are increasingly used in EOR methods, such as surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding. SP flooding has a complex formulation and design, leading to undesirable phase separation if improperly mixed. Polymeric surfactants are a promising alternative to SP flooding. They consist of hydrophobic groups attached to hydrophilic polymers, which help to improve the mobility ratio and reduce interfacial tension (IFT). This paper examines the rheological and synthesis properties of a new polymeric surfactant produced through bond co-polymerization reaction using different hydrolyzed polyacrylamide (HPAM) ratios and a zwitterion hydrophobic group. The synthesized hydrophobically modified zwitterionic polyacrylamide (HMZPAM) was characterized by FTIR and HMNR analysis. HMZPAM performed better than other substances in IFT, viscosity, wettability, oil recovery, and resistance to different one and two-valence cations. The results indicate that HPAM reduced the IFT to 13.65, while HMZPAM reduced it to 0.441 mN/m. Wettability change evaluated on a rock carbonate/crude oil/HMZPAM system that changed the water-wet state of the primary oil-wet rock carbonate to strongly water-wet state as wettability change measurements showed a decrease in contact angle from 62.76 to 21.23 degree. Comparative studies on the effectiveness of HPAM and HMZPAM were also conducted according to the measurement of viscosity and shear rate in the presence of salt, which indicates the higher shear rate and viscosity of HMZPAM. Core flooding tests revealed that HMZPAM resulted in better additional recovery due to microscopic displacement, resulting in a total oil recovery of 84%, compared to 48% of residual oil saturation for HPAM. Also, salts decreased oil recovery in HPAM injection but increased oil recovery in HMZPAM injection.

In chemical-enhanced oil recovery (CEOR) techniques, chemicals such as polymers, surfactants, and alkalines are injected individually or simultaneously into the reservoir to extract trapped oil1,2,3,4,5,6. The main objective in any field operation is to optimize or maximize production from the field at minimum cost7. Surfactants are used to reduce the interfacial tension (IFT), wettability alteration, and capillary force against the surfactant solution entry into the rock matrix (oil-wet rock) to facilitate oil mobilization. Surfactants are highly sensitive to the complex salinity and temperature of the reservoir8,9,10,11,12. Ionic liquids (ILs), known as green chemicals, have been considered a potential alternative to surfactants as some have surface activity and a pronounced effect on micelle formation13. To enhance oil recovery (EOR), it is necessary for ILs, like surfactants, to reduce the IFT between water and oil14. Although the usefulness of these chemicals is undeniable, their toxic effects have attracted much attention. Ionic liquids are currently not widely used in industrial applications because the continued development and use of these solvents may lead to accidental spills and contamination15,16. Injecting alkalines into the reservoir is another way to react with organic acids in the oil and produce a natural surfactant, reducing the cost of expensive surfactants1. The primary purpose of polymers in EOR is to decrease the mobility ratio between water and oil by increasing the viscosity of the injected water as the displacing phase. This reduction in the water-to-oil mobility ratio decreases fingering and, ultimately, results in better sweep efficiency. For this purpose, the employed polymers should possess certain features, such as high molecular weight, suitable resistance to mechanical degradation (shear rate), high salinity tolerance, sufficient thermal resistance, and complete water solubility1,5,17. Hydrolyzed polyacrylamide (HPAM) is a polymer widely used in EOR, but it is highly sensitive to shear rate, temperature, and high salinity8,12,18. Therefore, new compounds should be applied in CEOR. Simultaneous injection of alkaline-surfactant-polymer (ASP) and surfactant-polymer (SP) flooding can encounter issues such as interactions between polymer and surfactant, loss of surfactant through solubilization in the oil phase, or adsorption on the surface4,6,10,17.

The purpose of injecting polymeric surfactants in CEOR is to combine the benefits of both polymers and surfactants while avoiding the complications that arise from chemical interactions between two different substances. Polymeric surfactants are created by polymerizing active surface monomers or by polymerizing a hydrophobic or hydrophilic branch19,20,21. Polymeric surfactants can be synthesized by adding a hydrophobic group to the polyacrylamide structure. The hydrophobic groups act as thickening agents, increasing the viscosity of the polymer3,22. As the new polymer has both hydrophilic and hydrophobic parts, its surface properties, such as IFT and wettability, may also change20,21. Polymeric surfactants exhibit a critical concentration known as the critical association concentration (CAC). Above this concentration, the viscosity of polymeric surfactants increases significantly. At the CAC, hydrophobic groups tend to accumulate in the aqueous solution due to intermolecular interactions. This results in the formation of polymolecular aggregates, which in turn leads to the thickening of the substance, providing great shear stability, excellent thermal stability, and resistance to salinity4,11,12,21,23. Elraies et al. (2011) synthesized a polymeric surfactant by attaching different sulfonate groups of sodium methyl ester sulfonate (SMES) to a hydrophobic group of acrylamide monomers. They found that polymeric surfactants outperformed surfactant/polymer blends in many EOR areas20. Babu et al. (2016) synthesized a polymeric surfactant with SMES and different surfactant ratios to acrylamide. They investigated the function of the synthesized PMES as a chemical agent for EOR by measuring the IFT between PMES solution and crude oil, contact angle, and rheological behavior against the sandstone surface. The contact angle results showed that the PMES solution could change the wettability from oil-wet to water-wet. It was also found that adding NaCl to the PMES solution reduced the IFT by 0.002 mN/m. Their studies in core flooding experiments showed that the synthesized polymeric surfactants were inexpensive, environmentally friendly, easy to produce, and had significant potential for CEOR24. Kumar et al. (2017) synthesized an anionic polymeric surfactant from SMES from jatropha oil by the free radical polymerization reaction with acrylamide as a monomer. They evaluated the polymeric surfactant by rheological tests, including viscosity measurement and analysis of viscoelastic properties in the presence of NaCl salt at different temperatures, to determine the suitability of the polymeric surfactant for use in EOR. Their results showed that the viscosity of the solution decreased in the low shear rate regime and increased in the high shear rate regime25. Mehrabianfar et al. (2020) investigated and introduced a new natural polymeric surfactant from the Acanthephyllum plant, which improved the IFT and interfacial tension (ST) between water-oil and water-air26. Imuetinyan et al. (2022) assessed the effectiveness of a low-cost saponin-based natural surfactant (SBNS) for EOR. Experimental results revealed that SBNS significantly decreased the IFT at the oil-water interface. Oil displacement tests demonstrated that SBNS increased oil recovery compared to the original oil in place (OOIP)27.

The polarity of the saline solution was increased, and the hydrodynamic size of the polymer was increased. As a result, these polymers containing hydrophobic compositions have good potential to control the mobility of displacement fluids in reservoirs with high salinity and concentrations of divalent ions8,17,20. According to recent research, few studies have investigated the effect of salinity, especially divalent salinity, on the rheological properties of polymers, the IFT, and the wettability of reservoir rock, and EOR. Al-Sabagh et al. (2016) investigated the effect of the formation of water and seawater on apparent viscosity. Their results showed that salinity reduced the apparent viscosity of polymer solutions23. Lu et al. (2018) investigated the effect of salinity on the apparent viscosity of HPAM and HMPAM. They used NaCl and CaCl2 salts with concentrations ranging from 0 to 15,000 and 0 to 2000 mg/L, respectively. The results showed that with increasing salinity, the apparent viscosity of the two polymers decreased, and the effect of salt on reducing the viscosity of HPAM was greater than that of HMPAM28. Xu et al. (2019) investigated the effect of salinity on the apparent viscosity of HPAM and HMPAM. They used NaCl and CaCl2 salts ranging from 0 to 50,000 and 0 to 4000 mg/L, respectively. Their results were almost similar to those of Lu et al.29. Eslahati et al. (2020) investigated the effect of divalent salts on a new natural surfactant (alfalfa species) for EOR applications. IFT and contact angle were performed between the oil phase, rock surface, alfalfa natural surfactant, and surfactant-ion hybrid aqueous solutions30. Despite studies on the injection of ASP and SP, it is better to study new polymers with new properties that are resistant to problems such as instability to salinity and ions. Therefore, the study was performed on a new polymeric surfactant resistant to salinity and harsh conditions, improving IFT and wettability conditions29. A summary of the literature studied on the reduction of IFT, in addition to the alteration of wettability and the adsorption of molecules on solid surfaces in CEOR, is presented in Table 1. All the tests were done using crude oil and distilled water.

Prior research has examined the impact of diverse polymers and polymeric surfactants on surface properties such as IFT, wettability change, and viscosity. According to the author’s best knowledge, a newly synthesized polymeric surfactant was presented for the first time in the current work. Its application on surface properties and oil in the presence of monovalent and divalent ions was studied. Finally, core flooding experiments were performed to analyze the performance of EOR. These studies can effectively contribute to understanding the mechanism of HMZPAM and its promising application in EOR. In EOR mechanisms, the chemical system’s ability to lower IFT values and alter wettability and viscosity is considered an essential factor. HMZPAM injection reduces the IFT of aqueous oil and changes the wettability, thereby increasing the amount of oil that can be extracted from the residual oil saturation.

The study materials comprised acrylamide (98% purity), polyvinylpyrrolidone, sodium chloride, ammonium persulfate, magnesium chloride, sodium hydroxide, acrylic acid, and a zwitterion [2-(methacryloyloxy) ethyl] dimethyl (3-sulfopropyl) ammonium hydroxide (95% purity) which were procured from Sigma Aldrich. Ethanol and methanol with experimental purity were purchased from Merck.

Formation water, core, and crude oil were obtained from a reservoir located in southwest Iran. The core had a diameter of 4 inches and a length of 6 inches. The laboratory converted it into cores with smaller diameters and lengths (1*4 inches) using a core cutter apparatus with a permeability of 11.96 md and a porosity between 77 and 78. To measure wettability, slabs with a thickness of two to three millimeters were cut from the cores using a cutting machine (Fig. 1). The total salinity of the prepared formation water was 128,903 mg/l, which contains 43,639 mg/l Na+ and K+, 78,100 mg/l Cl−, 5600 mg/l Ca2+, 486 mg/l Mg2+, 780 mg/l SO42−, and 244 mg/l HCO3−. Additionally, the oil had an API of 34 and a viscosity of 13.1 cp. at room temperature (30 °C). Table 2 shows the specifications and composition of the crude oil provided by the operating oil company.

Core and slice samples for flooding and wettability tests.

Sodium acrylate is synthesized by combining sodium hydroxide and acrylic acid in a 1:1 ratio at a temperature between 2 °C and 5 °C in the presence of nitrogen. To achieve this, sodium hydroxide is dissolved in pure methanol, and acrylic acid is gradually added to the system. After 30 min, nitrogen is removed, and the methanol is evaporated until completely dry, resulting in a white powder. The product is then purified using chloroform. Finally, an FTIR test is performed using the reference test by Sigma Aldrich.

To synthesize HPAM and HMZPAM, a combination of acrylamide (AM), sodium acrylate (NaAA), and a hydrophobic branch (for HMZPAM only) are used in the molar percentages outlined in Table 3. For this purpose, a mixture of ethanol and deionized water is prepared in the presence of nitrogen. Sodium acrylate and acrylamide are dissolved in a solution of water and alcohol with a ratio of 1:3. HMZPAM [2-(methacryloyloxy) ethyl] dimethyl-(3-sulfopropyl) ammonium hydroxide is added as the hydrophobic branch. The mixture is deoxygenated by bubbling with nitrogen for 30 min. Polyvinylpyrrolidone is added to the solution. The clear solution is placed in an oil bath at 55 °C with steady rotation. The polymer particles cause the solution to turn milky in color. The solution is then centrifuged to separate the clear liquid from the deposited portion. Ethanol is added, and the mixture is centrifuged again. The alcohol is then removed, and the polymer is dried at 55 °C. The chemical structures and reactions of the two polymers are shown in Figs. 2 and 3, respectively.

chemical reactions of two polymers.

Molecular structures of (a) HPAM and (b) HMZPAM.

AV-III NMR apparatus manufactured by Bruker Company is used to perform HNMR tests. FTIR tests are conducted using the RX1 apparatus manufactured by Perkin Elmer Company with a tableting method involving KBr.

The Brookfield DVT-III apparatus measures viscosity and shear rate with controlled stress under different conditions. Viscosity at 30 °C and the shear rate range for viscosity in the fixed shear rate range between 1 S−1 and 400 S−1 are selected. To test the resistance of HPAM and HMZPAM at concentrations ranging from 2500 to 90,000 mg/l, NaCl, MgCl2, and CaCl2 are solubilized separately with each polymer sample at a constant concentration of 2000 mg/l. The viscosity of the polymer solutions at 30 °C is then obtained.

IFT and wettability are essential parameters in CEOR, which are always considered parameters of capillary pressure and number changes. The pendant drop technique is a widely used for measuring IFT between liquid-liquid and gas-liquid under high pressure and temperature conditions31,32,33. The analysis of IFT measurement is typically conducted by injecting a drop from a needle (with an external and internal diameter of 1.1 mm and 700 microns, respectively) into a bulk phase. Figure 4-a indicates the schematic configuration of the IFT measurement system. The contact angle method is used to measure the state of wettability and evaluate the variation and optimal value of wettability. In this method, thin parts are placed inside the solution chamber, and crude oil is placed on the thin parts with a syringe with an external diameter of 1.1 mm. Figure 4-b shows the contact angle measuring device purchased from the Technology Company of Atiyeh Poyandegan Xsir Arak.

Schematic of the experimental apparatus used to measure (a) IFT34 and (b) wettability35.

Core flooding tests were conducted using the CF-E30 flooding apparatus manufactured by Fars EOR Corporation at a temperature of 70 °C. The injected fluid had a flow rate of 1.29 ft3/day36,37. To begin with, the core is completely washed off with toluene and then dried in the oven. In the first stage, the core is saturated with the brine and then saturated with the oil36. After saturating with oil, water, and polymer, solutions were injected in two steps. HPAM and HMZPAM were injected at a concentration of 2500 mg/l in the absence and presence of different salt solutions. Salt solutions are prepared by NaCl at 4000 mg/l and CaCl2, K2SO4, and MgCl2 at 2000 mg/l.

X-ray diffraction spectroscopy (XRD) is used to identify the reservoir rock. The general identification of the constituent minerals and the specific identification of the core sample is carried out using the advanced θ-2θ diffraction apparatus of the Advance-D8 model manufactured by Bruker Axs Company with copper-bearing anode radiation with a wavelength of 1.54 A = Kα. General XRD studies are conducted at a range angle of 2θ, which equals 4 to 70 degrees, with an angular velocity of 1.2 degrees per minute on a powder sample of 75 microns. As shown in Fig. 5, the rock is of dolomite carbonate type, and 50% constitutes this type of mineral.

XRD Analysis of the reservoir core

Figure 6-a displays the FTIR spectrum for the HPAM synthesized in the laboratory. The absorption peaks at 3401.61 cm-1 and 3195.6 cm-1 indicate the presence of [N-H], while 2940.65 cm-1 indicates the presence of [-CH3]. Additionally, 1671.81 cm-1 indicates the presence of [C = O], and peaks at 1405.32 cm-1, 1329 cm-1, and 1122.54 cm-1 indicate the presence of [C-N] in the composition.

FTIR spectrum for the (a) HPAM and (b) HMZPAM polymers.

Figure 6-b shows the laboratory’s FTIR spectrum for synthesized HMZPAM. As seen in the figure, absorption peaks at 3422.94 cm-1 and 3235.60 cm-1 indicate the presence of [N-H], 2930.51 cm-1 represents [CH3], 2366.71 cm-1 and 2343.44 cm-1 indicates the presence of quaternary nitrogen [N+-(R)4], 1654.78 represents [-C = O-C-], 1405.32 cm-1, 1329 cm-1 and 1122.54 cm-1 indicate the presence of [CN], peak at 1050.95 cm-1 represents [S = O] and 625.75 cm-1 represents [C-S] in the composition38,39.

HNMR spectrum for HPAM and HMZPAM are shown in Fig. 7. This figure indicates that the absorption peak at the range of 4.50 ppm to 5.5 ppm is related to the deionized water, at the range of 2.15 ppm to 2.45 ppm is associated with CHCOONH2 and CHCOONa, at the range of 1.40 ppm to 1.60 ppm is related to CH2 and at the range of 1.01 ppm to 1.05 ppm is associated with CH3, while in Fig. 7-b, the absorption peak at the range of 2.50 ppm to 2.90 ppm is related to CH2NHR and at the range of 3.50 ppm to 3.80 ppm is associated with CH2SO3R12.

HNMR spectrum for (a) HPAM (b) HMZPAM.

The apparent viscosity, a crucial property of polymeric solutions, was evaluated for both polymers at concentrations ranging from 250 to 4000 mg/l in the presence of 10,000 mg/l of NaCl salt and at a temperature of 30 °C. The results indicate that the apparent viscosity increases with increasing concentration, as shown in Fig. 8. Additionally, HMZPAM has a more significant effect on viscosity than HPAM. The structure of HMZPAM contains hydrophobic groups, which cause the polymer molecules to be closer together, resulting in more molecular contacts. This leads to an increase in the volume of the molecular network and a significant increase in viscosity compared to HPAM solution24. As shown in Fig. 8, both polymers have a CAC of approximately 800 mg/l. Liu et al. (2015) also calculated the CAC for HMPAM and HPAM polymers and found similar results. This suggests that the polymers’ behavior is identical at low concentrations. However, as the concentration of HMZPAM increases and the polymer chain elongates, the viscosity significantly increases. Therefore, the CAC of both polymers is almost equal as it occurs at low concentrations40.

Apparent viscosity of HPAM and HMZPAM polymers in the presence of 10,000 mg/l of NaCl salt at 30 °C.

The impact of various salts, such as NaCl, MgCl2, and CaCl2, on the viscosity of polymers at a concentration of 2000 mg/l was examined. Figure 9 illustrates that as the NaCl concentration increases, the HPAM solution’s viscosity decreases from 110 cp. at 2500 to 30 cp at 20,000 mg/l, with a steep slope. The viscosity decreases as salinity increases, but the decrease is less steep, reaching a viscosity of 15 cp at a concentration of 90,000 mg/l. Investigating the viscosity of the HMZPAM solution in the presence of NaCl salt showed that the viscosity of solution at the concentration of 2500 mg/l of NaCl salt is 410 cp, indicating a significant decrease with increasing the NaCl salt concentration, and the viscosity of the solution at the concentration of 20,000 mg/l of NaCl salt is about 108 cp; with further increasing of the salt concentration to 40,000 mg/l, the viscosity increased to 120 cp. At a concentration of 50,000 mg/l of NaCl salt, the viscosity is approximately 180 cp. Furthermore, as the solution salinity increases, the viscosity also increases. When the concentration of NaCl was increased to 60,000 mg/l, the viscosity increased rapidly, reaching 255 cp. This trend continues, with the viscosity reaching 530 cp. at a concentration of 90,000 mg/l.

Viscosity of HPAM and HMZPAM polymers at a constant concentration of 2000 mg/l at different concentrations of NaCl at 30 °C.

The viscosity of the HPAM solution decreased as salinity increased. This may be due to the negative charges present in the hydrolyzed polyacrylamide structure (-COO-) being surrounded and shielded by the cations present in the saline solution, causing the HPAM chain to compress and significantly reducing the viscosity of the HPAM solution12. Initially, the viscosity of the HMZPAM solution decreased due to the shielding of salt cations by the negative charges (-COO-) present in the polymer structure. However, an increase in viscosity was observed at a high concentration of 20,000 mg/l. Increasing the salinity of the solution leads to an increase in ionic strength. This, in turn, causes hydrophobic groups in the polymer chains to create three-dimensional networks, as shown in Fig. 10. These networks’ formation increases the polymer molecule’s volume, ultimately leading to an increase in the viscosity of the polymeric solution12.

Schematic design of intermolecular associations of HMZPAM with the presence of salts.

At 2500 mg/l of NaCl salt, the initial viscosity of the HMZPAM solution is significantly higher than that of the HPAM solution. This is due to the increased solution polarity caused by adding salt to the aqueous HMZPAM solution, which enhances the association of the hydrophobic groups. The hydrodynamic size of the polymer increases, resulting in attractive rheological properties that enhance salt resistance and increase the system’s viscosity8,19,20,21.

Figure 11 shows the effects of two-valence salts (MgCl2 and CaCl2) on viscosity. The presence of two-valence cations causes a more significant reduction in the viscosity of HPAM polymer compared to one-valence cations. The viscosity of the HMZPAM solution initially decreases but then increases, although it remains lower than when NaCl is present in the system. Two-valence salts absorb two groups of COO- in the polymeric chain simultaneously due to possessing two positive charges. This results in a more compact elasticity of the HPAM molecule than when it reacts with Na+. Cations with two positive charges are more reactive than those with only one positive charge. Therefore, the polymeric chain is more compressed, and hydrophobic groups have less freedom of movement. As a result, they are less able to form three-dimensional networks, resulting in lower viscosity when NaCl salt is present in the solution12,41 (Fig. 12). Conversely, Ca2+ cation reduces viscosity to a more considerable extent than Mg2+. Because of the higher reactivity of Ca2+ compared to Mg2+, greater viscosity reduction occurs.

Viscosity of HPAM and HMZPAM at the constant concentration of 20,000 mg/l at different concentrations of CaCl2 and MgCl2 at 30 °C.

Schematic design of complexation behavior of HPAM with Ca2+ 39.

The viscosity of polymer solutions was investigated at 2000 and 4000 mg/l concentrations in the presence of K2SO4, CaCl2, MgCl2, and NaCl, each at 2500 mg/l, at different shear rates. Figure 13 shows that increasing the polymer concentration reduces the shear rate volume under constant stress. The viscosity of the HPAM solution decreased as the shear rate increased. Initially, the decrease was steep, but then the slope decreased until it reached 0.15 and 0.31 cp at concentrations of 2000 and 4000 mg/l, respectively. At shear rates close to 100 S-1, the viscosity became almost constant.

Shear thickening behavior of HPAM and HMZPAM at two concentrations (2000 and 4000 mg/l), total salinity is 10,000 mg/l, and concentration of each salt is 2500 mg/l.

The impact of shear rate on the viscosity of HMZPAM solution was examined. Figure 13 illustrates that the findings can be categorized into two sections. In the first section, the viscosity of HMZPAM decreases as the shear rate increases, similar to the behavior of the HPAM solution. In the second section, which occurs at shear rates higher than 100 S−1, the viscosity reduction process is reversed. After reaching a critical shear rate value, the viscosity reduction effect exhibits a reverse flow behavior, showing shear thickening characteristics in the aqueous phase. In EOR applications, shear-thinning or pseudoplastic behavior is considered beneficial. As the concentration of the HMZPAM increases, the molecules entangle with each other due to Van der Waals forces, forming aggregates. Due to the increased presence of HMZPAM molecules in the solution, the micelles formed are more likely to overlap and entangle, resulting in a transient network, so an increase in viscosity was observed 42,43. As the shear rate increases, the viscosity increases, reaching 0.85 cp and 1.06 cp for concentrations of 2000 mg/l and 4000 mg/l, respectively, at 400 S−1. This increase in viscosity is due to the formation of three-dimensional networks by the hydrophobic section present in the polymer structure, which increases the solution’s resistance to shear rate44.

Oil/water IFT is one of the key factors influencing oil recovery from carbonate reservoirs. Reducing IFT can shift the capillary forces to more favorable conditions for more oil recovery and less residual oil saturation45. The IFT between brine/oil solution at 500 to 2000 mg/l concentrations for all four salts was initially investigated. As shown in Fig. 14, with increasing salinity concentration, IFT decreases. Increasing the salinity leads to an increase in the ionic strength of the solutions as well as a decrease in the IFT, which indicates an inverse relationship between the IFT and the ionic strength values, so the divalent salts of MgCl2 CaCl2 further reduce the IFT due to the ionic strength33. According to Fig. 14, it is clear that the lowest level of IFT is related to CaCl2 salt, so at a concentration of 2000 mg/l, the IFT of CaCl2 salt is reduced to 13.06 mN/m. The effect of salt and its concentration on the IFT of water and oil was not the same, considering the related literature on different oil samples and not proceeding based on a stable process. Taking the type and composition of the crude oil into consideration, the results show that the effect of salt and its concentration on the interfacial tension of water and oil was different23.

IFT between brine and crude oil.

In the following, for investigating the effect of polymers in the presence and absence of salt (4000 mg/l of NaCl salt and 2000 mg/l of each of the other three salts) on IFT reduction between water and oil, polymer solutions with concentrations of 500 to 3500 mg/l were prepared. As shown in Fig. 15, at 500 to 1500 mg/l of HPAM, with increasing concentration, IFT decreases from 23.67 to 19.97 mN/m. Then, with increasing concentration, IFT indicates a very slight decrease, and at the concentration of 2000 mg/l, it becomes almost constant and equal to 19.64 mN/m.

IFT between HPAM and crude oil in the presence and absence of the salts (4000 mg/l of NaCl + 2000 mg/l of divalent ions).

The effect of HMZPAM on IFT reduction is shown in Fig. 16. When increasing the polymer concentration, the decreasing slope of IFT is high and then decreases by about 1.011 at the concentration of 1500 mg/l. Then, the decreasing slope of IFT lowered, reaching 0.708 mN/m at a concentration of 2500 mg/l and becoming almost constant at higher concentrations. The results showed that HMZPAM could reduce the IFT between water and oil more than HPAM due to the presence of hydrophobic groups in its structure. The presence of the hydrophobic group in the polymeric structure of HMZPAM has led this polymer to function like a surfactant, which is due mainly to the added hydrophobic group to its chain and also because its main chain, which is acrylamide and very hydrophilic and has a high solubility in water. As a result, IFT was significantly reduced in HMZPAM compared to HPAM, which has no hydrophobic group46.

IFT between HMZPAM and crude oil in the presence and absence of the salts (4000 mg/l of NaCl + 2000 mg/l of divalent ions).

Figures 15 and 16 demonstrate that salt reduces IFT even further. This means that the effect of the polymer on reducing IFT is more significant in the presence of salt than in its absence. For instance, at a concentration of 2500 mg/l of both polymers, the IFT for HMZPAM decreased from 0.708 to 0.446 mN/m in the presence of different salinities, and for HPAM, it decreased from 19.64 to 13.66 mN/m. It can be argued that this reduction is due to the simultaneous effect of salts and polymers on the decrease of IFT. Comparing two polymers, HMZPAM with salts indicated IFT activities better than HPAM, which could be due to the presence of hydrophilic groups in the chemical structure of HMZPAM46.

The use of polymeric surfactant in the context of oil recovery is crucial. It dramatically affects the wettability of the solid surface because changing rock wettability from oil-wet to water-wet increases oil recovery47.

In the present study, for wettability tests, concentrations of 500 to 3500 mg/l of two polymers were examined in the presence and absence of K2SO4, CaCl2, MgCl2, and NaCl. Initial wettability was determined by dropping oil and pure water on the rock’s surface. The oil spread out on the surface, while the water did not, indicating that the rock is oil-wet, as shown in Fig. 17. The cause of oil-wet reservoir rocks is the deposition of organic compounds in oil on the rock surface. These compounds are usually naphthenic acids, mainly asphaltene and resins in crude oil. Due to negative groups in their structure, these compounds establish an electrostatic bond with the positive charge on the stone’s surface and are connected to its surface40,48,49.

Wettability of the reservoir core after being saturated by crude oil in the presence of a drop of pure water and an oil drop.

According to Table 4, it is clear that the contact angle of the HMZPAM in the presence and absence of salinity is less than the contact angle of the HPAM, which indicates the potential effect of HMZPAM on the change of wettability from oil-wet to water-we, thus can be a good candidate for EOR applications. When using HPAM polymer, due to having a negative group (-COO−) in its structure, it absorbs the positive charge of the stone surface (cations). It replaces the negative resin group, asphaltene, and especially naphthenic acids on the stone’s surface. In this polymer’s presence, the stone surface’s wettability changes to neutral wet. Investigating the effect of HMZPAM on the change of reservoir rock wettability showed that because the polymeric surfactant has a zwitterionic structure, it reacts with the negative group of naphthenic acids, asphaltene, and resin by the positive charge of its tetravalent nitrogen N+ (R)4 and instead of positive ions The stone binds with the negative group of these compounds. It releases them from the surface of the stone. By having the negative group in its polymer structure (COO− and SOO−), it replaces the negative group of naphthenic acid, asphaltene, and resin on the surface of the stone and, with the positive charge of the surface of the stone, establishes a bond and separates them from the surface of the stone in this way, causing a change in wettability much more than HPAM and making the stone strongly water-wet.

Based on the wettability, IFT, and viscosity results of polymeric solutions at concentrations ranging from 500 to 3500 mg/L, the optimal concentrations for two polymers were between 2500 and 3500 mg/L. The results for concentrations between 2500 and 3500 mg/L were similar, so a concentration of 2500 mg/L was selected for injection.

Figures 18 and 19 illustrate the pressure drops observed during water and polymer injection. The figures show that polymers without salt had higher pressure drops due to their higher viscosity compared to polymers with salt. It is worth noting that HMZPAM has a higher viscosity than HPAM, resulting in a higher pressure drop.

Pressure drop through the injection of water and HPAM in the presence and absence of the salts.

Pressure drop through the injection of water and HMZPAM in the presence and absence of the salts.

Figures 20 and 21 show the results of injecting polymeric solutions with a concentration of 2500 mg/l into a dolomite carbonate core. As shown in Fig. 20, with increasing the volume of the injected fluid, the oil recovery increased and became almost constant (recovery practically equal to 46%) in 0.8 of the pore volume. In this regard, the amount of oil recovery increased by increasing the injected pore volume of HPAM. As Fig. 21 shows, the oil recovery increased by increasing the volume of the injected fluid, and by increasing the injection volume of HMZPAM, the oil recovery also increased. By comparing Figs. 20 and 21, it is observed that the injection of the HMZPAM indicated higher production efficiency compared to HPAM. Because HMZPAM has a hydrophobic group in its structure, it reduces more IFT, further wettability alteration towards water wet, and increases the viscosity of the polymer solution more than HPAM. Increasing the viscosity of the polymer solution of HMZPAM causes a better mobility ratio and increased sweep and microscopic displacement of oil, resulting in more recovery. Figures 20 and 21 demonstrate an increase in the oil recovery by adding two polymers when NaCl is present at a concentration of 4000 mg/l, and CaCl2, K2SO4, and MgCl2 are each present at a concentration of 2000 mg/l. In contrast, the presence of salt in the HPAM solution resulted in a decrease in oil recovery, as shown in Fig. 20. This is due to the polymer’s susceptibility to salinity, which compresses its molecular structure (as shown in Fig. 12) and dramatically reduces its viscosity. The presence of salt cations causes a wettability alteration that makes the surface more water-wet. This results in a decrease in the IFT, although the reduction is not significant enough to affect oil recovery. As for HPAM polymers, increased viscosity is the main factor that leads to increased production and controls water mobility.

Oil recovery increasing by the injection of HPAM in the presence and absence of the NaCl salt at 4000 mg/l and CaCl2, K2SO4 and MgCl2 at 2000 mg/l.

Oil recovery increasing by the injection of HMZPAM in the presence and absence of the NaCl salt at 4000 mg/l and CaCl2, K2SO4, and MgCl2 at 2000 mg/l.

Figure 21 shows the increase in oil recovery by injecting HMZPAM solution in the presence and absence of salt. The addition of salinity compared to HPAM has increased oil recovery in the presence of the synthesized polymer. Examining the mechanism of the process and the results of other tests indicated that the presence of salt decreased the viscosity of the polymeric solution. However, due to the presence of the hydrophobic group as well as the creation of high initial viscosity, the reduction of viscosity due to the presence of salt is not enough that the solution does not have the appropriate viscosity to improve mobility, and this amount of viscosity is also suitable for enhanced oil recovery. In the presence of salt, the IFT of this solution decreased more than when salt was not present. Regarding wettability alteration, the presence of salts, especially divalent cations, along with the hydrophobic zwitterionic group of this polymer, led to significant changes in the water-wet condition. As a result, due to suitable viscosity and wettability, alteration from oil-wet to water-wet oil recovery increased50.

This paper synthesized and introduced HMZPAM as a new polymeric surfactant. Some critical characteristics and properties of the HMZPAM in EOR were obtained and compared with HPAM as a usual polymer in EOR. The main conclusions are obtained as follows:

Increasing the concentration of the polymer in the solution causes an increase in viscosity, and HMZPAM also produces a much higher viscosity than HPAM due to the presence of hydrophobic groups in its structure and higher molecular contacts.

The presence of salts in the polymer solution significantly reduces the viscosity of HPAM, and divalent salts reduce the viscosity more.

The presence of salt in the HMZPAM solution up to a concentration of 20,000 mg/l causes a decrease in viscosity, and above that, it causes a significant increase in viscosity and also divalent salts have a greater reducing effect on viscosity than monovalent salts.

The CAC of both polymers was approximately equal to 800 mg/L, as the behavior of the polymers is similar at low concentrations.

Shear rate decreased the viscosity of the polymeric solution, and HMZPAM indicated a higher stress resistance due to the formation of three-dimensional networks by the hydrophobic part in its structure.

HMZPAM decreased the IFT between polymeric solution and crude oil more than HPAM due to the presence of hydrophobic groups, and also, the presence of salts increased the ability of the polymer to decrease IFT.

Both polymers led to the wettability alteration to water wet. Still, HMZPAM performed better, and the presence of salts increased the polymer’s ability to alter wettability to water wet.

HMZPAM had much more performance in enhancing oil recovery than HPAM, and the presence of salts decreased oil recovery in HPAM injection but increased oil recovery in HMZPAM injection.

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

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Department of Petroleum Engineering, EOR Research Center, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran

Elias Ghaleh Golab & Mohammad Vatankhah-Varnosfaderani

Institute of Petroleum Engineering, School of Chemical Engineering, College of Engineering, University of Tehran, Tehran, Iran

Ronak Parvaneh, Siavash Riahi & Ali Nakhaee

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Elias Ghaleh Golab and Ronak Parvaneh: wrote the main manuscript text, Siavash Riahi, Mohammad Vatankhah-Varnosfaderani and Ali Nakhaee : reviewed the manuscript.

Correspondence to Elias Ghaleh Golab or Siavash Riahi.

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Golab, E.G., Parvaneh, R., Riahi, S. et al. Study on interfacial tension, wettability and viscosity in different salinities of synthesized a new polymeric surfactant for improving oil recovery. Sci Rep 14, 24990 (2024). https://doi.org/10.1038/s41598-024-75027-7

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Received: 29 November 2023

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Published: 23 October 2024

DOI: https://doi.org/10.1038/s41598-024-75027-7

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