Introduction

Most oil and gas reserves worldwide are located in carbonate reservoirs1,2. There are typically natural fractures in carbonate reserves3,4,5, which makes waterflooding in carbonate reservoirs challenging. Without surfactants, around 80% of the original hydrocarbon in place (OOIP) remains in carbonate reservoirs6,7. Since the wettability of carbonate reservoirs is neutral-wet or oil-wet in most hydrocarbon reserves8, enhanced recovery methods, such as chemical flooding are essential to improve hydrocarbon production. Chemical flooding is based on changing fluid-rock properties to either reduce the interfacial tension or improve the sweep efficiency of an injected fluid9. For instance, alkaline–surfactant (AS) flooding is an enhanced oil recovery (EOR) method that reduces residual hydrocarbon saturation by changing reservoir rock wettability properties10. Accordingly, investigating the optimal performance of such chemical compounds (e.g., alkaline), either alone or combined, has been an active line of research in recent years11,12,13.

The EOR depends on several factors, such as mud loss, formation damage, and ideal well completion14,15,16. Conventional flooding processes and gas injection are typically used to stabilize the reservoir pressure17,18. Furthermore, advances in hydraulic fracturing have shed insight into multi-scale fluid dynamics, particularly in unconventional reservoirs. Theoretical models that focus on the interplay of fractured networks and flow mechanisms provided an improved recovery approach19. After non-economization and the end of the secondary recovery, there is still a lot of oil remained in a reservoir that can be produced20,21,22. One of the best methods of oil recovery is the flooding of alkaline chemicals and surfactants. Water is often injected which improves oil recovery by displacing oil23. Knowing how fluid moves through micro- and nanoporous media has also given us important information about how reservoirs behave. Using pore network frameworks and molecular dynamics simulations, recent studies have shown how interactions between surfaces and pore structures at the nanoscale affect recovery efficiency24. To reduce the interfacial tension between oil and water, alkali and surfactant may be injected25. Alkaline prevents surfactant adsorption on rock surfaces and, therefore, enhances the interfacial tension between water and oil phases26.

If the surfactant concentration remains near or above a critical concentration, it will be most effective6. Ramos et al.27 recently proposed a new surfactant-polymer formulation for oil recovery, which provided for new synergies in EOR processes, especially in offshore oil fields. In another study, Kesarwani et al.28 proposed an anionic surfactant and showed that it resulted in 50% crude oil recovery using flooding and about 30% excess oil recovery using the designed ASP slug. Anionic surfactants are better adsorbed on carbonates than other surfactants29.

Pi et al.30 conducted a study on the creation of water droplet flow in oil, the penetration of alkaline solution into crude oil, and the increase of oil recovery from alkaline flooding using a sand model, the results of which showed that the oil mobility was relatively low. Hosseini et al.31 studied the impact of chemicals on surface tension and wettability, finding that non-ionic surfactants significantly influenced wettability to water moisture, and alkaline-non-ionic surfactant injection significantly improved recovery compared to other solutions. Dehghan et al.32 conducted a study using a sulfonate-based surfactant and two other commercial surfactants in a sandstone reservoir. One alkaline substance that was utilized was sodium metaborate. Saturated sandstone plug samples were subjected to surface tension and wettability testing. The outcomes demonstrated that the effectiveness of spontaneous oil recovery throughout the absorption and drainage processes was enhanced by the sulfonate-based surfactant.

Panthi and Mohanty33 showed that the ASP process minimized surfactant retention in shallow reservoirs. Habib et al.34 studied the impact of alkali on surfactant flooding, using sodium hydroxide and sodium carbonate alkalis, and showed reduced interfacial tension and increased oil yield. Roustaei et al.35 demonstrated that hydrophobic nanoparticles in two cores significantly enhanced oil recovery, with light oil recovery reaching 54% and medium oil recovery reaching 41.65%. In another study, Dos Santos Francisco36 investigated the surfactant carriers for enhanced oil recovery and found that chitosan derivatives in the surfactant solution increased oil recovery based on minimizing surfactant losses. Surfactant flooding in EOR involves decreasing interfacial tension (IFT) and adjusting wettability, with ionic liquids being surface active agents for EOR. Hezave et al.37 showed minimizing the IFT even under high temperature and salinity conditions. In another study, Debnath et al.38 conducted on increasing oil recovery using low-salinity brine injection, showed that the amount of oil recovered in carbonates is higher than in sandstones, and increasing temperature increases the efficiency of low-salinity brine. Also, Luo et al.39 studied the effects of produced gas reinjection on oil recovery, and it was found that optimal injection of gas could lead to more excess oil recovery.

Weiss and Xie40 used the results of the imbibition test to investigate the significance of permeability and surfactant concentration in surfactant treatments. It was established that cores with higher permeability had higher imbibition rates and incremental oil recovery. Additionally, oil recovery from cores with permeabilities less than 1 mD was stopped. Given this information, the lower limit for effective surfactant treatments is 1 mD.

In chemical flooding, critical micelle concentration (CMC) is an important characteristic of a surfactant. It is the concentration of a surfactant above which aggregates of surfactant molecules (called micelles) start forming. Bagrezaie and Pourafshary41 evaluated the adsorption of surfactants. Core flooding experiments on sandstone core samples showed that the addition of hydrophilic nanoparticles reduced surfactant adsorption on rock surfaces. In addition, it also improves surfactant flooding performance and increases oil recovery in reservoir conditions.

Results of adsorption tests showed that CMC occurred at the 2450 mg/L point of the surfactant concentration. Yin et al.42 investigated the effect of surfactant concentration on oil recovery. The results showed that increasing the required volume before IFT reduction may be used to promote oil recovery in a heterogeneous reservoir because ASP flooding cannot improve oil recovery by reducing IFT until the threshold viscosity is reached. When alkali is reduced or removed from the ASP system to produce high viscosity, oil recovery is reduced due to reduced oil displacement efficiency. The weak base alkalinity of ASP can ensure that the framework has sufficient viscosity to run medium and low permeability sections and achieve optimal oil recovery, even when the IFT only approaches 10 − 2 in mN/m. Rabbani et al.43 looked at the impact of perceived wettability in determining the efficacy of surfactant flooding. Numerous flooding tests were carried out using limestone core plug samples that varied in their visible wetting characteristics—highly, moderately, and slightly oil-wet. The findings of this experiment demonstrated that the effectiveness of surfactant flooding increased with the degree of oil-wetness of the tight carbonate rocks. The intensely oil-wet core had the most recovery, while the weakly oil-wet core demonstrated the least incremental oil recovery due to surfactant flooding. In another study, Rezaei et al.44 conducted for the effect of nanoparticles on oil recovery and it was found that nanoparticles with an optimal weight% can be effective in EOR and high salinity along with nanoparticles with a high concentration percentage have the inverse effect. Mofrad et al.45 developed a new EOR technique using smart water and surfactant injection in oil-wet carbonate reservoirs. The study found that combining smart water and surfactants increased variables for oil recovery by 28%, 42%, and 58%, respectively. The combination of smart water and surfactants resulted in higher oil recovery compared to solo surfactants or smart water flooding. Massarweh and Abushaikha46 discussed surfactant characteristics and phase behavior, the function of surfactants in oil recovery, surfactant adsorption on reservoir rock, and the use of surfactants in EOR at both the laboratory and field scales. Finally, this review discussed the impact of oil viscosity, rock wettability, surface tension (IFT), and capillary pressures on modifying the mobility ratio between displaced fluids on surfactant flooding. Rajabi et al.47 studied the effects of chemical solutions on wettability alteration and utilized a nano-alkaline-surfactant liquid to reduce interfacial tension. The nano-surfactant-alkaline fluid was made by combining sodium carbonate, cetyl trimethyl ammonium bromide, and Nano silica particles. Using a blend of nanoparticles and surfactant-alkaline, the greatest wettability modification was accomplished. Additionally, the interfacial tension (IFT) between solutions and crude oil was examined, with the nano-surfactant obtaining the greatest decrease. Jalali et al.48 investigated how a novel natural surfactant obtained from the leaves of Cordia myxa leaf could improve oil recovery in carbonate rock. Experimental research was done to determine how this natural surfactant affected wettability and IFT. According to this study, new surfactant flooding improves oil recovery percentages compared to flooding and lessens residual oil saturation in porous material.

There is a major knowledge gap in the combined use of alkali and surfactants to reduce IFT and modify wettability in carbonate reservoirs. This study demonstrates the relationship between chemical flooding and geological heterogeneity (including pore structures and mineral composition), which is critical in managing recovery processes in such complex conditions. The efficiency of these treatments can be greatly impacted by the current lack of thorough knowledge of how these effects vary among various types of carbonate rocks, pore structures, and mineral compositions. More thorough research is also required to examine the stability and effectiveness of these treatments over the long term in reservoir settings, as well as any potential environmental effects of adding alkaline and surfactant chemicals to the subsurface environment. This study will contribute to increased insight into subsurface processes and improved subsurface reservoir recovery techniques and EOR methods with an emphasis on complex carbonate reservoirs. This study examines how chemical flooding and alkaline surfactants can improve oil recovery in carbonate formations. Laboratory studies are conducted to investigate the effects of chemical flooding on rock wettability in two stages (before and after contact with alkaline surfactant solution). The efficacy of the flooding process under reservoir conditions is evaluated using numerical simulations. This work combines laboratory testing and numerical simulations to provide field-relevant insights into the optimal concentrations of alkaline surfactants and their long-term performance, ensuring environmentally sustainable and economically feasible EOR applications. The study also identifies the optimal concentration of alkaline surfactant to promote wettability and maximize oil recovery.

Materials and methods

Core sample and crude oil properties

In this study, three core samples 3.5 cm in diameter and 8 cm in length were selected from a core plug (1.016 cm in diameter and 100 cm in length) collected from the Asmari reservoir. The core samples used in this study had an average porosity of 13.6% and a permeability of 15 mD. The oil used in the experiment was sampled before entering the desalination plant, and all its characteristics, such as density, water content, pour point, total sulfur, and its components, were measured and recorded before the experiment. This sample was prepared from the Asmari reservoir with an API grade of 30.13 among medium (relatively light) oils. Table S1 lists some salient characteristics of the oil used in the experiments, In Table 1 we report the composition of the live oil sample, residual oil, and associated gas. As well as molecular weight and specific gravity of C12+ and residual oil. The oil sample was taken under the temperature of 121 °F and pressure of 491 psi (gauge) and the acid number for the oil sample was 2.7 (mg KOH/g oil).

Table 1 Composition of live oil sample, residual oil, and associated gas.
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In addition, plugging devices, contact angle measurement, an oven, and core flooding were used for laboratory measurements of water injection and alkaline surfactant solution. The chemicals sodium hydroxide, sodium carbonate, and sodium dodecyl sulfate (SDS) used were products of the German company Merck. Oil from one of the oilfields in southern Iran was used for analysis in the experiments.

SARA stands for “Saturates, Asphaltenes, Resins, and Aromatics.” This technique is used to examine the chemical makeup of petroleum products, such as crude oil. Each of these four components’ percentage in the sample is determined by the SARA. There are reports of the analysis of the SARA test for the oil sample that show the sample was saturated with 45.5% of its available capacity, Aromatics 40.2%, Resins 10.2%, and Asphaltene 4.2%. Two types of alkalis were used to measure changes in alkaline–surfactant contact angles; (1) sodium hydroxide and sodium carbonate and (2) Sodium di-sulfate was also used as a surfactant in the experiments. To prepare solutions they were placed in distilled water with 99% purity and then the exact concentration of each solution was prepared. Concentrations of alkaline solution (0–8000 mg/L) and SDS (0–2000 mg/L) were selected based on reservoir compatibility and the results of the first tests. To reduce the IFT, SDS was added into the solution with the range including its CMC value. Alkaline concentrations were calculated based on published data concerning similar carbonate reservoirs of the Persian Gulf. The chemicals were first measured, next added to distilled water, and mixed to become homogeneous with a mixer. Finally, to approach the reservoir conditions, the solution was placed in an oven at 81 °C (178 °F). We used NaCl, KCl, MgCl2.6H2O, NaHCO3, CaCl2, Na2SO4, MgCl2.6H2O and salts with details presented in Table S2.

It was assumed that all the salts were easily hydrolyzed to prepare the seawater. After reaching the desired salinity of, hydrogen carbonate and potassium, the ionic strength was balanced by adding halite to the solution. Note that the excess amount of and produced by other reactions was considered. The composition of Persian Gulf seawater used in the secondary stage is reported in Table S3.

Mineralogical analysis with XRD

To assess the semi-quantitative mineral composition of the examined carbonate core, the X-ray diffraction (XRD) method was used. The diameter and length of the cores used in this experiment were 3.5 cm and 8 cm, respectively. The XRD analysis revealed that dolomite was dominant (65% dolomite and 35% calcite). The outcome of the XRD analysis is summarized in Fig. S1. The pattern of XRD peaks in this investigation did not considerably overlap because complicated mineral combinations were not present, which improved the precision of quantification in phase analysis. Dolomite and calcite in our investigation exhibited very clear patterns, but if other minerals were present, careful semi-quantitative and more probabilistic methods could be required.

Preparation of core samples and oil-wetting cross-section

The petrophysical properties measured on three core samples are reported in Table 2. The core samples were aged in crude oil at 81 °C and under 491 psi reservoir pressure for 20 days, simulating a wet reservoir. The consistency of the petrophysical properties of porosity and permeability before and after aging was tested; likewise, the aging procedures were repeated under identical conditions to validate repeatability. In so doing, the core samples matched the conditions found within the reservoir. After a thorough cleaning, the core samples were placed in an oven at 80 °C to dry. The cross-section was removed from the oil after 20 days and washed with the decline to remove solid and heavy oil particles. Decalin, which is a weaker solvent, was used to wash the samples so that the wettability of the rock did not change.

Table 2 Characteristics of carbonate reservoir core samples used in this study.
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To accurately measure the fluid-solid contact angle the surface of the cut cross-sections was thoroughly polished. Considering that in this study the boundary of the three phases was fixed and the drop was placed on the surface, static contact angles were measured to measure the wettability values. Young’s equation was used as a basis for measuring static contact angles, and in this quantitative calculation, it was assumed that the surface forces are thermodynamically stable. The surface of the sections was polished using a grinding machine and then washed with distilled water at 80 °C to remove all fine particles from the surface of the rock. The cross-sections were placed in the oven at 80 °C for 24 h to dry again. The dried cross-section was exposed to oil and became oil-wet. This step was performed to match the core sample with the reservoir rock and was one of the critical stages of the study. The entire cross-section was placed in the reservoir oil for 20 days to become oil-wet. After soaking, the sample was washed with detergent to remove cross-sectional asphaltene particles. Fig. S2 shows the cross-sectional area before and after oil wetting.

The oil-wetting cross-section was placed in alkaline and surfactant solutions for 72 h to the injection stage and the effect of the injection fluid on the rock surface was placed in an oven at 80 °C. This step was conducted to let necessary reactions among oil, chemical solution, and water occur. The goal of putting solutions in the oven at reservoir temperature was to accelerate the processes and keep reservoir conditions stable.

Contact angle and IFT measurements

The static contact angle may be measured based on Young’s equation 49, by assuming the surface forces are thermodynamically stable. From the mechanical balance of surface forces or interfacial tension. Equation 1a and 1b show this relationship50.

$${\upsigma _{{\text{os}}}}={\upsigma _{{\text{ws}}}}+{\upsigma _{{\text{ow}}}}\;\cos (\uptheta )$$
(1a)
$$\cos (\uptheta )={\upsigma _{{\text{ws}}}} - {\upsigma _{{\text{os}}}}/{\upsigma _{{\text{ow}}}}$$
(1b)

where σos (N/m) is the surface force between oil and a solid surface, σws (N/m) is the water and solid surface tension and σow is the surface tension between oil and water.

The contact angle may range from zero to 180°, depending on the relative inclination of the two fluids to the surface. A contact angle less than 90° indicates that the surface is water-wet. If the cross-section has the same tendency toward the two phases, the wettability is neutral with contact angle near 90°. Contact angles above 90° refer to oil-wet conditions51.

The contact angle was measured by placing an oil drop on the cross-section with an alkaline solution present. Using a camera and microscope to capture an image of the drop on the solid surface (core surface). The IFT test was performed between solutions that contain different concentrations of SDS and crude oil. The goal of this test was to evaluate the CMC of SDS. All measurements were conducted under ambient pressure and room temperature conditions. The IFT between oil and various solutions was assessed using the rising bubble pendant drop method. The camera begins to record the shape of the drop as the oil droplet emerges from the needle. The drop image was then captured at a precise moment when it detached from the needle, and it was then examined using the pendant drop method.

The effect of two types of alkaline with different alkaline strengths on rock wettability was investigated. To investigate changes in contact angle, two types of alkaline sodium carbonate and sodium hydroxide were used. The alkaline concentration varied from zero to 8000 mg/L. The cross-sections of the oil were placed in the alkaline solution for soaking for three days, and then, using the same solution, the contact angle was measured. Accordingly, in the investigation of the effect of alkali on the contact angle of SDS, a constant concentration of 4000 mg/L was used for sodium carbonate. Surfactant concentrations similar to those used here were also used in an alkaline-free surfactant solution.

Core flooding experiments

To eliminate all salts and hydrocarbon components found in the core samples, toluene and methanol were used separately and in a Soxhlet to clean each core plug. The Soxhlet process relies on the gradual diffusion of a heated solvent through the core. The washing procedure was carried out until the extracted solution’s color became colorless. A core-flooding device was used to determine the permeability of each core. At first, we measured the permeability of cores by formation waterflooding after that plugs were aged in crude oil at the reservoir temperature for a month to imitate the actual condition of the reservoir. Each core plug was cleaned and saturated with the formation water, then saturated with the crude oil at reservoir temperature. The salient properties of the cores are reported in Table 2. Laboratory flood tests were performed using these solutions. Therefore, three oil-saturated cores containing formation water saturation were used for the core flooding test, and a 3.5-pore volume of Persian Gulf seawater was injected in the first step as secondary flooding. In addition, a 2.5-pore volume of a different concentration of alkaline–surfactant solution was injected into the core as tertiary flooding. The selected solution from earlier experimental tests were injected into each core that was put into the core holder. The constant rate of 0.2 ml/min used for all injections was sufficient to prevent the capillary end effect.

Water and alkaline-surfactant flooding simulations

Exponents of the Corey equation was considered for the history-matching process in the STARS module, which was utilized to match the values for water and oil. The Corey equation for oil and water is shown in equations 2 and 3.

$$\:{\text{K}}_{\text{r}\text{w}}\left({\text{S}}_{\text{w}}\right)=\:{\text{K}}_{\text{r}\text{w}}^{\text{*}}{\left(\frac{{\text{S}}_{\text{w}}-\:{\text{S}}_{\text{w}\text{r}}}{1-{\text{S}}_{\text{w}\text{r}}-\:{\text{S}}_{\text{o}\text{r}\text{w}}}\right)}^{{\text{n}}_{\text{w}}}$$
(2)
$$\:{\text{K}}_{\text{r}\text{o}}\left({\text{S}}_{\text{w}}\right)=\:{\text{K}}_{\text{r}\text{o}}^{\text{*}}{\left(\frac{1-{\text{S}}_{\text{w}}-\:{\text{S}}_{\text{o}\text{r}}\:}{1-\:{\text{S}}_{\text{w}\text{r}}-\:{\text{S}}_{\text{o}\text{r}\text{w}}}\right)}^{{\text{n}}_{\text{o}}}$$
(3)

where: Krw is the water relative permeability, Kro is the oil relative permeability, Swr is the residual water saturation, Sw is the water saturation, Sorw is residual oil saturation after water flooding, Swr is the residual water saturation, Sorw is the residual oil saturation after water flooding, nw is Corey’s exponent for water, no is Corey’s exponent for oil, \(\:{\text{K}}_{\text{r}\text{w}}^{\text{*}}\) is Corey’s endpoint for relative permeability of water, water, Kro* is Corey’s endpoint for relative permeability of oil.

A sodium dodecyl sulfate (SDS) anionic surfactant was used to measure its effect on reservoir rock wettability changes. Sodium dodecyl sulfate (SDS) with a concentration ranged from zero to 2000 mg/L was used in the experiments.

A Cartesian system was considered to simulate the process that happened in the laboratory. The CMG-STARS simulator (version 2023.1, https://www.cmgl.ca/software/stars) was used for the simulation of the water and AS flooding processes. The simulation model was made horizontally with two vertical wells (producer well and injector well) according to the experimental setup: an injector on the left and a producer on the right. Bottom hole pressure (BHP) and surface water rate (STW) were 14.7 psi and 0.2 cc/min respectively and the desired length of the core in this experiment was considered to be 8.05 cm. The conventional detail of the essential grid system (Nx = 20, Ny = 5, Nz = 3) is described. Grid sensitivity analysis was performed to ensure the numerical simulations were properly resolved. Several different grid arrangements, Nx = 10–40, were used to balance computational expense and solution accuracy. The grid size used in the simulations presented, Nx = 20, Ny = 5, Nz = 3, provided a good enough resolution of the nature of the flow with less computational artifact. This configuration allowed capillary end effects and numerical dispersion to be bounded within an acceptable limit. For the computer simulation of the core flood test shown in Fig. S3, we used the STARS module within the CMG software package. The simulation consisted of several main steps, summarized in the following. At each step, the reservoir and fluid properties need to be entered.

First, we built a static model; using the core plugin data. In addition to creating grids and assigning rock and fluid attributes, the modeling domain was also specified. We then assigned each grid’s specific attributes, such as porosity and permeability. We next created a fluid model based on the fluid properties of oil, water, and gas used in the experiments and derived from the core samples. Properties like density, viscosity, and phase behavior were specified to accurately simulate fluid flow. After that, we modified fluid characteristics, such as pressure based on the core data. In a flooding test, the pressure might not be directly monitored, but the temperature is typically ascertained from the test parameters. This is because tiny, easily pressured oil samples are typically used for flooding tests. In contrast, oil viscosity or other characteristics may be used to measure pressure. Because of this, using modified values for temperature and pressure enhanced the relevance and accuracy of flooding test results, particularly when taking into account the impact of pressure on the characteristics and behavior of oil. Rock characteristics, including porosity, permeability, and rock type, were identified using the data from the core plugs. For each grid cell, initial state settings (including pressure and saturation for each grid cell and modifying rock attributes such as porosity, permeability, and rock type) were set. Input IFT values for different fluids were coupled to effectively depict phase interactions and capillary pressure effects since interfacial tension (IFT) measurements are used in multiphase simulations. Based on the location of the core inlet and outflow, injection sites were placed in the grid cells. Production and injection rates as well as their intervals, were characterized as injection point attributes. Based on the core data, the simulation was run to forecast fluid behavior and flow. To evaluate the simulations numerical results were compared to experiment test results. The CMG program produced 3D visualizations and graphical outputs to describe simulation findings, that provided us a visual representation of how fluids flow inside the reservoir. We also assessed the performance of the selected solutions in the simulation. We examined IFT changes in grid block (10, 3, 2) at the tertiary stage. In Fig. S3, the three layers of different colors indicate that there are three phases of water, oil, and gas in the core.

Results and discussions

MC measurement

The amount of critical micelle concentration is an important parameter in surfactant flooding. No further decrease in surface tension was noticed after the increment in the surfactant concentration beyond the value of CMC. An increase in the content of surfactant enhanced the concentration of monomers at the interface, which later formed the micelles. Hydrophobic and hydrophilic parts of the surfactant tend to adsorb at the interface. The surfactant monomers start to aggregate from either their hydrophilic head or hydrophobic tail to each other above this concentration and create a micelle to reduce the free energy of the system. In this investigation, conductivity meters and IFT setup were employed to measure the CMC of the surfactant, with results presented in Fig. 1-a,b. Two different trend lines were intersected at the CMC concentration. Results indicate that the prepared surfactant’s CMC is near 2500 mg/L (or 0.25 weight%).

Fig. 1
figure 1

(a) Conductivity and (b) IFT against SDS solution concentrations.

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The contact angle was measured in this work to study the changes in wettability affected by sodium hydroxide and sodium carbonate. Optimal solution concentrations were achieved to record the best performance. The crossover indicates that CMC is equal to 2500 mg/L.

Electrokinetic of carbonate rock

Figure S4: The initial appearance of an oil drop on a rock surface, showing that the reservoir rock is oil-wet. The oil drop formed an angle of θ = 155° with the rock surface, indicating that the rock is entirely oil-wet. The cross-section of the rock became completely oil-wet, which could be due to the adsorption of carboxylate on the rock surface. Carboxylates or asphaltenes have negative charges and tend to be adsorbed on solid surfaces with positive charge52. The cross-section of the carbonate rock also carried a positive charge. Therefore, the carboxylate in crude oil was absorbed on the rock surface and made the carbonate rock surface oil-wetting. Although surfactants were found in a wide range of oil cuts, they were mostly reported in heavy cuts (resins and asphaltene). These substances contain polar compounds of nitrogen, oxygen, and sulfur, which are often acidic. These materials contain large numbers of carboxylic acids. These compounds have a polar head (water-wet) and a non-polar head (oil-wet). The water-wet head was attracted to the rock, and the oil-wet head remained out, causing the system to become oil-wet. In AS solutions, since the pH is high, the carbonate surface has negative charge. In addition, as alkaline concentration increases, the carbonate surface becomes more negatively charged. Thus, the repulsive forces between these carboxylic oil components and the negatively charged carbonate surface increase, leading to the detachment of the oil molecules. This can be attributed to the fact that, with an increased alkaline concentration, SDS cannot reach the negatively charged carbonate surface, as shown in Fig. 2d and e. This is because both carbonate surface and SDS have negative charge.

Effect of alkaline on contact angle

Alkaline solutions changed the wettability of the rock by in-situ generation of surfactants. Figure 2-a: Contact angle vs. sodium carbonate concentration. In this way, the contact angle of the rock cross-section was reduced from 155° in distilled water to 70° in an 8000-mg/L solution. The increasing trend was accompanied by a decrease in the contact angle so that at a concentration of 4000 mg/L the contact angle decreased from 110° to 70° and the rock became water-wet. Sodium hydroxide is a strong base, and in high concentrations, it increased the pH to 13.5, which favored the hydrolysis of acidic oil. Figure 2-b shows changes in contact angle and concentration. The contact angle decreased to 81° as the sodium hydroxide concentration increased to 2000 mg/L. Then, by increasing the concentration of sodium hydroxide to 8000 mg/L, the contact angle increased to 130°. At the concentration of 2000 mg/L sodium hydroxide, we observed changes from oil-wet to water-wet. Surfactants enhance oil recovery by reducing interfacial tension and changing wettability.

Figure 2-c displays a graph of the variations in contact angle at various surfactant doses. As can be seen, with increasing the concentration of surfactant, the contact angle decreased, from 155° to the minimum value of 92° at the concentration of 1500 mg/L. Then, with increasing concentration up to 2000 mg/L, the contact angle increased to 115°. Despite the change in concentration, the rock-fluid contact angle had little change and did not show much tendency to change.

The variation of the contact angle in the surfactant solution with different concentrations of sodium carbonate is shown in Fig. 2-d. As the concentration of sodium carbonate as an average base increased from 500 to 4000 mg/L, the contact angle decreased from 139° to 78° at the minimum point, and then increased again. The reason for the change in the trend of increasing the contact angle after the minimum point was the formation of micelles in the solution and the neutralization of the influence of the solution on the rock surface or the contact angle. The formation of micelles, especially at higher surfactant concentrations above the CMC, can result in changes in the viscosity and flow characteristics of the injected solution. Such phenomena may also affect injectivity in the field since solutions become more viscous and possibly cannot penetrate the reservoir as effectively. Besides, micelles can also affect oil mobility by the action of surfactant in reducing interfacial tension, hence giving an easy displacement of oil from reservoir rock. In contrast, if the concentration becomes too high, micelle formation can develop which could block pores and potentially affect fluid flow hence recovery efficiency. By comparing the optimum point of contact for the alkaline-free surfactants to that after the alkaline-surfactants, it was found that the optimal contact point is a suitable point for flooding due to the wettability change from strong oil (strongly oil-wet) to strong (strongly) water-wet at 4000 mg/L sodium hydroxide and a constant concentration of 2000 mg/L SDS. Therefore, the 2000 mg/L concentration was used as the optimal concentration of surfactant in the presence of alkali. By producing the surfactant in place, the alkaline solution thoroughly prepared the surfactant solution for the wettability changes. While the addition of alkali and surfactants in enhanced oil recovery enhances the oil displacement and wettability, the large-scale application of these chemicals has to be weighed against their potential environmental impacts. If the alkali application is not well controlled, especially with high concentrations of sodium hydroxide and sodium carbonate, there is a chance that it may present some risks to the local ecosystem. Likewise, large-scale application of surfactants such as SDS may lead to toxicity problems in water bodies. This would necessarily imply that their disposal methods would involve neutralization processes. Similarly, any surfactant solutions or alkali resulting from the treatment should not reach the environment untreated; research into substitutes such as biodegradable surfactants and alkalis also holds great promise in reducing field operation impacts on the environment from such chemicals. Figure 2-e. shows the variations in the contact angle of 2000 mg/L SDS with sodium hydroxide.

Fig. 2
figure 2

Contact angle variation with different conditions shows the wettability alteration. (a) Sodium carbonate at different concentrations decreases the contact angle, showing increased water-wet states. (b) Sodium hydroxide decreases the contact angle by increasing its concentration and thus is found to promote wettability alteration. (c) SDS surfactant decreases the contact angle progressively with higher concentration, showing its efficiency as a surfactant. (d) The combined effect of sodium carbonate and constant SDS concentrations shows a synergistic reduction in contact angle. (e) Sodium hydroxide at constant SDS concentrations shows significant wettability improvement with increasing alkaline concentrations. Error bars indicate variability across three independent experiments.

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The contact angle and wettability of alkaline solutions can be altered by in-place surfactant production. Acidic oil is crude oil that has acidic chemicals, whereas alkalis are substances with a pH higher than 7. A chemical reaction may happen when acidic oil and alkali come into contact. The development of surfactants can come about as a result of this process. The alkali-oil interaction creates surfactants that alter reservoir rock surface characteristics, and as a result, decrease the contact angle. Sodium carbonate is a relatively strong or moderate alkaline solution with a pH between 9 and 11. Therefore, when the concentration exceeded 4000 mg/L, due to the high production of surfactant, the wettability variations leveled off.

Figure 3 shows the position of the oil drop on the rock surface at different concentrations. As shown in Figs. 2-a and 7-a, the optimum concentration of sodium carbonate is 4000 mg/L with an average contact angle of about 110°. With increasing the concentration of sodium hydroxide due to in-place surfactant production, the contact angle decreased, and the minimum value was recognized as the optimal point of the solution. At concentrations above 2000 mg/L, the contact angle increased again due to strong hydrolysis and incomplete surfactant production.

Figure 3-b shows how the oil drop was placed on the rock surface. Initially, the contact angle decreased and then increased with increasing surfactant concentration (Fig. 2-c). The reason for the increase in contact angle after the minimum point is probably because of the formation of micelles. When the surfactant concentration in water reached a specific value, a spherical density (micelles) of the associated molecule formed. At this concentration, due to the accumulation of surfactant molecules and the protrusion of the polar head, the surfactant molecules could also be adsorbed on the surface of the oil rock and therefore could change the rock wettability depicted in Fig. 3-c. The use of absorption inhibitors is one of the most important ways to reduce surfactant absorption in carbonates53. The contact angle of the oil surface was by sodium carbonate solution to weak water wet. Then, with increasing concentration, this wettability was recovered and changed to oil wet.

Figure 3-d. shows how oil droplets were placed on the rock cross-section at different concentrations of sodium carbonate and constant SDS concentrations. The effect of the sodium hydroxide in the surfactant solution on the contact angle was significant. By increasing the concentration of sodium hydroxide at a constant SDS concentration, the contact angle first decreased to a minimum point and then increased again. The contact angle decreased from 142◦ to 33◦ for sodium hydroxide at 4000 mg/L, at which point the wettability changed. In this section, increasing the concentration of sodium hydroxide caused an increase in the production of in-place surfactant, which changed the wettability of the rock from oil to water. When the contact angle reached 33°, the wettability changed from strongly oil-wet to strongly water-wet. Figure 3-e shows how the oil drop is placed on the surface of the rock sample.

Fig. 3
figure 3

Effect of alkaline and surfactant solutions on the oil contact angle, reflecting the wettability change in rock surface: (a) sodium carbonate can decrease the contact angle of oil significantly, thus increasing water-wetness; (b) sodium hydroxide enhances the water-wet condition by decreasing the oil contact angle; (c) SDS surfactant has a high efficiency in reducing oil deposition with a low contact angle. (d) The mixture of sodium carbonate and SDS has the best wettability alteration, which is reflected by the lowest contact angle. (e) The combination of sodium hydroxide and SDS gives close wettability improvements. Error bars show data scattering of three independent experiments.

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The effect of alkaline on the contact angle of SDS

Alkaline was used as the active ingredient to improve the efficiency of the surfactant. Mechanisms of alkaline that are similar to those of surfactant flooding. Figure 4-a shows the impact of 4000 mg/L sodium carbonate on the contact angle of various SDS concentrations, for a concentration of 1500 mg/L of SDS; the contact angle of 87° was observed. As the concentration increased, the contact angle began to increase. Figure 4-b also shows the effect of sodium hydroxide on the surfactant solution. In terms of changes in wettability (contact angle), the effect of a 2000-mg/L sodium hydroxide concentration on the surfactant solution was similar to that of sodium carbonate with a similar trend. Compared to the surfactant solution with sodium carbonate, the minimum point of contact angle in the solution containing sodium hydroxide was smaller.

Fig. 4
figure 4

Interactive effects of fixed alkaline concentrations on the efficiency of SDS for wettability alteration: (a) Sodium carbonate, 4000 mg/L, presents very significant contact angle reduction while coupled with the different SDS concentrations, showing strong synergistic effect; (b) in the presence of NaOH (2000 mg/L), the contact angle is dramatically decreased coupled with SDS, showing NaOH could be one potential wettability alteration. Error bars reflect the three repetitions for each experiment.

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The effect of constant alkaline concentration on the surfactant micelle solution was negligible and caused a small change in the minimum contact angle. The addition of alkali to SDS was done at a volume of 1200 mg/L. With the addition of alkaline to the solution of SDS, the alkaline reacted with the acidic oil to produce surfactant, resulting in a faster micelle formation (due to more surfactant in the solution). Comparing Figs. 2-d and 3-d with Figs. 2-e and 3-e showed that in this test, sodium hydroxide had a more significant effect on the surfactant solution than sodium carbonate. Because sodium hydroxide is a stronger base than sodium carbonate and has a stronger hydrolysis power, it caused a greater change in the contact angle.

Oil recovery in core flooding

Three solutions gave the most favorable contact angles, all less than the initial value, and were selected for further investigations. Table S4 lists the selected three of the most suitable solutions used for the core flood test.

Figure 5: Injection of different concentrations of surfactant solutions and respective oil recovery factors for all three cores. According to Fig. 5, we observed that the recovery factor initially increased with the injection of seawater and an alkaline surfactant, which was due to oil production without water or the production of a small amount of oil with water. When the seawater is injected for the first time, no oil is produced until the breakthrough occurs. In the second part, the recovery factor decreased significantly due to the breakthrough effect resulted in less oil production. The better the performance of the fluid in terms of wettability change and IFT reduction in the second part, the more oil will be produced, and the recovery factor will become constant at larger pore volumes. Pressure diagrams from the flood test, (Fig. 5), reveal that in each stage of the test, a sudden drop in pressure signifies the breakthrough of the injected fluid from the core.

Fig. 5
figure 5

Pore volume, pressure, and recovery for (a) 2000 mg/L SDS + 4000 mg/L Sodium Hydroxide injection (b) 2000 mg/L Sodium Hydroxide + 1000 mg/L SDS injection, and (c) 2000 mg/L SDS + 4000 mg/L Sodium Carbonate injection.

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Table 3 summarizes the selected solution and the result of experimental flooding tests in two steps. The secondary recovery factor for core number 2 is maximum equal to 35.2. In the third stage, the amount of recovery for 2000 mg/L SDS + 4000 mg/L Sodium Hydroxide flooding in Core No. 1 has the greatest value.

Table 3 Experimental results for different EOR processes in three cores.
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History matching of selected solution flooding

Following the history matching of the flooding process, exponents of 3.8 and 2.1 for the relative permeabilities of water and oil in the Corey equation were determined. In all of our simulations, these numbers provided the best fit for the recovery. A good match is observed between experimental and simulation results as shown in Fig. 6.

Fig. 6
figure 6

Result of history matching for (a) 2000 mg/L SDS + 4000 mg/L Sodium Hydroxide injection (b) 2000 mg/L Sodium Hydroxide + 1000 mg/L SDS injection (c) 2000 mg/L SDS + 4000 mg/L Sodium Carbonate injection.

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Due to the change in wettability from oil-wet to water-wet with the onset of alkaline-surfactant flooding, more residual oil was produced from the core. Because the rock was oil-wet, when seawater was injected into the rock, the water moved through the pores and the oil remained in the walls of the porous space. With the alkaline-surfactant injection, the wettability changed to water-wet. Therefore, the water moved through the pore wall and increased the mobility of the remaining oil in the core, which improved the oil recovery. Figure 7 illustrates the JBN method’s interpretation of the relative permeability curve for water and oil. Figure 7 depicts the cross-point location as determined by the water and oil permeability curves, demonstrating that wettability alteration occurred in all cases and helped to sweep the residual oil to produce and that Sor decreased as the core’s wettability went towards water wet.

There are some reasons for the dispersion seen in Fig. 7. Its experimental data for relative permeability (Kro and Krw) as a function of water saturation (Sw). Initially, the results might vary because relative permeability measurements are very sensitive to experimental variables such as sample heterogeneity, flow instability, and the precision of saturation measurement methods. Second, in comparison to the secondary recovery stage, the tertiary recovery stage adds more variability because it includes more intricate fluid-fluid and rock-fluid contacts (frequently brought on by chemical floods). Lastly, even though the numerical simulations are designed to fit the experimental data, they have issues matching the scatter seen in the tertiary recovery experimental data. Notwithstanding this disarray, the simulated data trends generally match the experimental data trends, offering valuable information on the healing process.

Fig. 7
figure 7

Curves before and after tertiary recovery by using the JBN method for (a) 2000 mg/L SDS + 4000 mg/L Sodium Hydroxide injection (b) 2000 mg/L Sodium Hydroxide + 1000 mg/L SDS injection (c) 2000 mg/L SDS + 4000 mg/L Sodium Carbonate injection.

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IFT reduction investigation in grid block (10 3 2)

The trend of IFT changes for this grid block shows that after the injection of about half a pore, the fluid reaches this grid and IFT starts to decrease. The results obtained from this part of the simulation are consistent with the laboratory results, and the fluid that is more successful in reducing IFT gives a higher recovery value in the laboratory results (Fig. 8). Figure 8 shows the reduction in interfacial tension (IFT) for several injection methods seen in the grid block (10, 3, 2). The data indicate that IFT begins to decrease as the fluid approaches this specific grid block, approximately half of the pore capacity of fluid injection. The results demonstrate that, in contrast to the other injection schemes, the 2000 mg/L SDS + 4000 mg/L sodium hydroxide scheme results in the lowest values and the most pronounced reduction in IFT. There is a slight difference in the trends of IFT reduction and the degree of reduction varies significantly for each of the tested schemes. These differences are significant as they affect the recovery factor directly. Fluids that reduce IFT to a greater extent perform better in terms of recovery factor as seen in both simulation and laboratory analysis. For instance, the combination of 2000 mg/L Sodium Hydroxide and 1000 mg/L SDS can reduce IFT to a certain extent but it is not as efficient as the best practice while the combination of 2000 mg/L SDS and 4000 mg/L Sodium Carbonate has a relatively higher IFT profile all through the injection process thus making it less effective. The following findings also support the 2000 mg/L SDS + 4000 mg/L Sodium Hydroxide injection scheme as the most effective means of achieving the maximum level of IFT reduction which is crucial in improving oil recovery. The simulation results are in good agreement with experimental data which strengthens the validity of the analysis and substantiates the findings.

Fig. 8
figure 8

Interfacial tension variation in grid block (10 3 2) at tertiary stage.

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Conclusions

The use of alkaline sodium hydroxide and sodium carbonate significantly affected rock surface wettability, with sodium carbonate causing a downward trend and a stronger water-wet state than sodium hydroxide. The addition of alkaline to a surfactant solution inhibited its production, leading to faster micelle formation. Additionally, sodium hydroxide, a stronger base, significantly impacted the surfactant solution due to its hydrolysis power. The study found that increasing sodium hydroxide concentration from 500 mg/L to 4000 mg/L reduced the contact angle from 142◦ to 33◦, causing a significant change in wettability from oil-wet to water-wet and resulting in weak water-wet wettability due to micelle formation. The oil recovery process from the core sample was enhanced by injecting an alkaline surfactant and altering the wettability to water-wet, leading to increased oil production and a stabilizing slope in the post-injection phase. The CMG-STARS simulator was employed in this investigation to create a model in Cartesian space for the carbonate core. The model was utilized to contrast the outcomes of the experiment. The findings of the simulation and experiment were found to be matching, and the manufacturing history was drawn to confirm this. To approach the laboratory results, several input data sets had to be modified for the simulator.