Experimental Study on SiO₂ Nanoparticles-Assisted Alpha-Olefin Sulfonate Sodium (AOS) and Hydrolyzed Polyacrylamide (HPAM) Synergistically Enhanced Oil Recovery

Abstract

The purpose of this study is to investigate the use of SiO₂ nanoparticles in assisting with surfactants and polymers for tertiary oil recovery, with the aim of enhancing oil recovery. The article characterizes the performance of SiO₂ nanoparticles, including particle size, dispersion stability, and zeta potential, evaluates the synergistic effects of nanoparticles with alpha-olefin sulfonate sodium (AOS) surfactants and hydrolyzed polyacrylamide (HPAM) on reducing interfacial tension and altering wettability, and conducts core flooding experiments in rock cores with varying permeabilities. The findings demonstrate that the particle size decreased from 191 nm to 125 nm upon the addition of SiO₂ nanoparticles to AOS surfactant, but increased to 389 nm upon the addition of SiO₂ nanoparticles to HPAM. The dispersibility experiment showed that the SiO₂ nanoparticle solution did not precipitate over 10 days. After adding 0.05% SiO₂ nanoparticles to AOS surfactant, the zeta potential was −40.2 mV, while adding 0.05% SiO₂ nanoparticles to 0.1% HPAM resulted in a decrease in the zeta potential to −25.03. The addition of SiO₂ nanoparticles to AOS surfactant further reduced the IFT value to 0.19 mN/m, altering the rock wettability from oil-wet to strongly water-wet, with the contact angle decreasing from 110° to 18°. In low-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for enhanced oil recovery increased the recovery rate by 24.5% over water flooding. The recovery rate increased by 21.6% over water flooding in low-permeability rock core experiments after SiO₂ nanoparticles were added and surfactants and polymers were utilized for oil displacement. This is because the nanoparticles blocked small pore throats, resulting in increased resistance and hindered free fluid flow. The main causes of this plugging are mutual interference and mechanical entrapment, which cause the pressure differential to rise quickly. In high-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for oil recovery increased the recovery rate by 34.6% over water flooding. Additionally, the recovery rate increased by 39.4% over water flooding with the addition of SiO₂ nanoparticles and the use of AOS surfactants and HPAM for oil displacement. Because SiO₂ nanoparticles create wedge-shaped structures inside highly permeable rock cores, they create structural separation pressure, which drives crude oil forward and aids in diffusion. This results in a comparatively small increase in pressure differential. Simultaneously, the nanoparticles change the rock surfaces’ wettability, which lowers the amount of crude oil that adsorbs and improves oil recovery.

1. Introduction

The petroleum industry has had a profound impact on the global energy sector and economy over the past few decades. The growth in global population and industrial activities has led to a sharp increase in energy demand. Traditional oil recovery techniques include chemical flooding, gas injection, low-salinity water flooding, and thermal–chemical methods, which enhance recovery rates by reducing interfacial tension, adjusting wettability, and promoting emulsification, among other mechanisms [1,2,3]. Traditional enhanced oil recovery (EOR) methods have been successful in many reservoirs but may no longer be effective under complex reservoir conditions [4,5]. Since the 1980s, nanofluids have been widely employed in EOR, with the material, concentration, shape, and size of nanoparticles playing a crucial role in improving recovery rates. The small particle size, high surface area, numerous active sites, and small size effect of nanomaterials help to effectively displace residual oil within the pores of tight oil reservoirs. Researchers have conducted studies to enhance recovery rates using nanofluids based on different chemical properties of nanoparticles, including silicon dioxide, zirconium oxide, aluminum oxide, and iron oxide [6,7,8,9,10]. SiO₂ nanoparticles can be adsorbed on the rock surface. Due to their large specific surface area and high dispersion, they can form a covering layer and change the chemical properties of the rock surface. This causes a surface that has an affinity for oil to become more hydrophilic, changing the wettability from lipophilic to hydrophilic.

Binks and colleagues [11] found that the use of hydrophilic silica nanoparticles and cationic surfactant di-C10DMAB (didodecyldimethylammonium bromide) could stabilize foam. With an increase in surfactant concentration, they found that foam stability first increased to a maximum value before declining to a steady state. The synergistic mechanism between nanoparticles and surfactants can address foam-related issues in oil displacement applications. Metal nanocrystal catalysts can be highly dispersed in heavy oil and promote desulfurization and chain scission reactions of heavy oil macromolecules by significantly increasing the specific surface area and providing a large number of active sites, thereby reducing the viscosity of heavy oil and improving recovery rate [12,13,14]. Hendraningrat and other researchers [15] conducted a series of studies on nanofluid displacement by varying parameters such as rock core permeability, rock wettability, and nanofluid concentration. Ma and colleagues [16] grafted surfactants onto nanoparticles and found that the nanomaterials and surfactants exhibited a synergistic effect, reducing interfacial tension and enhancing oil recovery. Yoon [17] and his team synthesized a stable emulsion system composed of colloidal silica particles, cationic surfactant (DTAB), and anionic polymer (PSS-co-MA). The presence of PSS-co-MA increased the zeta potential of silica nanoparticles and enhanced the stability of the dispersion. Simultaneously, DTAB adsorbed on the nanoparticle surfaces increased their hydrophobicity, allowing them to adsorb at the oil–water interface and stabilize the emulsion. Zargartalebi and others [18] investigated the impact of silica nanoparticles on surfactant performance. They found that nanoparticles could enhance the interfacial tension between surfactants and oil, effectively improving oil displacement efficiency, particularly with hydrophobic nanoparticles. Sun and his team [19] utilized SDS to transform hydrophobic silica nanoparticles into partially hydrophobic ones, stabilizing foam and increasing its stability under reservoir conditions. Core flooding experiments showed that foam stabilized by nanoparticles was more stable than foam stabilized by surfactants alone. Ahmadi and Sheng [20] utilized hydrophilic and hydrophobic silica nanoparticles to reduce surfactant adsorption on carbonate rock surfaces. They reported a 45% reduction in surfactant adsorption on rock surfaces, possibly due to the formation of hydrogen bonds between the negatively charged headgroups of the surfactant and the hydroxyl groups on the silica nanoparticle surfaces. Ahmadi and their research group [21,22,23] utilized silica nanoparticles on sandstone and carbonate rock samples, demonstrating their ability to reduce surfactant adsorption while, simultaneously, increasing recovery rates. This reduction in adsorption and interfacial tension means this technology is the preferred choice for chemical flooding to enhance recovery rates. However, further investigation is needed into the synergistic interactions among surfactants, polymers, and nanoparticles. Therefore, there is a need for further research on how rock properties affect nanofluid-based oil recovery.

Previous studies have recognized the potential of nanoparticles in enhancing oil re covery; however, the majority of these studies have concentrated on the application of SiO₂ nanoparticles exclusively, without thoroughly investigating the synergistic effects of SiO₂ nanoparticles, surfactants, and polymers. Research on the effect is still lacking. In order to improve oil recovery, this study intends to explore the synergistic effects of SiO₂ nanoparticles with surfactants and polymers. Very high stability, the results of interfacial tension, and wettability alterations indicate the potential advantages of adding nanoparticles. Core flooding experiments demonstrate that SiO₂ nanoparticles with surfactants flood oil more effectively than surfactants and polymers. The effect of improving oil recovery is better when utilized in combination with polymers. This study proves that SiO₂ nanoparticles have a good synergistic effect with alpha-olefin sulfonate sodium (AOS) surfactant and HPAM, and can be utilized to increase oil recovery. This research provides a theoretical framework and practical recommendations for the combined use of nanoparticles, surfactants, and polymers to enhance oil recovery.

2. Experiments

2.1. Materials and Instruments

2.1.1. Materials

The experimental crude oil utilized in this study is dehydrated and degassed crude oil sourced from a low-permeability reservoir in a certain oilfield. The crude oil has a viscosity of 6.5 mPa·s at 45 °C and a density of 0.807 g/cm³. The surfactant utilized is AOS, provided by Aladdin Bio-Chem Technology Co., Ltd., Shanghai, China. The partially hydrolyzed polyacrylamide (HPAM) utilized has an average molecular weight of 2 × 10⁷ g/mol and a hydrolysis degree of 26%. It was supplied by Baomo Co., Ltd., Dongying, China. The hydrophilic SiO₂ nanoparticles have an average particle size of 15 nm and a purity of 99.5%. They were purchased from Aladdin Bio-Chem Technology Co., Ltd., Shanghai, China. The water utilized in the experiments is simulated formation injection water with a total dissolved solids (TDS) concentration of 5819.36 mg/L. Its major ion composition includes Ca²⁺ (335.62 mg/L), Mg²⁺ (41.5 mg/L), Na⁺ + K⁺ (2297.18 mg/L), Cl⁻ (1355.12 mg/L), SO₄²⁻ (898.37 mg/L), and CO₃²⁻ + HCO₃²⁻ (252.33 mg/L). The core samples utilized in the experiments have dimensions of φ2.5 cm × 10 cm and were custom-made in the laboratory. They exhibit permeabilities of 80 mD and 150 mD.

2.1.2. Instruments

We utilized a DSA25 fully automatic contact angle goniometer from Kruss GmbH, Hamburg, Germany, a MCR301 interfacial rheometer from Anton Paar GmbH, Graz, Austria, a Thermo Nicolet 380 scanning electron microscope from Thermo Fisher Scientific, Waltham, MA, USA, a Nanbrook Omni laser particle size analyzer from Nanbrook, Lincolnton, NC, USA, and core displacement apparatus, a temperature-controlled chamber, an electronic balance, and vernier calipers from Jiangsu Lianyou Technology Co., Ltd., Wuxi, China.

2.2. Methods

2.2.1. Configuring Nanofluids

In order to ensure the thorough dispersion and uniformity of SiO₂ nanoparticles in the water medium, SiO₂ nanoparticles are first suspended in synthetic formation water and stirred by ultrasonic waves for 2 h to form a SiO₂ nanoparticles suspension.

Subsequently, SiO₂ nanofluid and AOS surfactant were mixed at the desired concentration, and ultrasonic stirring was performed for 15 min to promote uniform mixing of the surfactant and the SiO₂ nanofluid.

An appropriate amount of HPAM solution was prepared, and a certain volume of the HPAM solution was added to the pre-prepared SiO₂ nanofluid. The mixture of HPAM and SiO₂ nanoparticles was stirred for 3 h and left to stand overnight, resulting in SiO₂–polymer composite material.

2.2.2. Particle Size Distribution and Stability Experiments

The experiment was conducted at a temperature of 45 °C. The average hydrated particle size and zeta potential of the SiO₂ solution and SiO₂/AOS surfactant suspension were measured using a Nanbrook Omni laser particle sizer.

2.2.3. Interfacial Tension Experiments

At 45 °C, interfacial tension measurements between different solutions and crude oil were taken using the MCR301 interfacial tension analyzer. The instrument was operated at a rotational speed of 4500 rpm, and images were processed every 2 min to obtain dynamic oil–water interfacial tension values until the interfacial tension stabilized.

2.2.4. Wettability Experiments

The DSA25 fully automatic contact angle analyzer was employed to investigate the impact of nanofluids on the wettability of solid surfaces. Glass slides were immersed in heptane/crude oil for one week, subsequently cleaned with heptane until colorless, and then air-dried for 1–2 days. The glass slides were then individually immersed in nanofluid and surfactant solutions. After two days, a single water droplet was dispensed onto the surface of each glass slide using a syringe, and the slides were adjusted to a horizontal position. The contact angle of the water droplet on the glass slide surface was measured using a contact angle measurement instrument, and images of the contact angle were captured and saved.

2.2.5. Oil Displacement Experiments

The core displacement experiment followed the industry standard SY/T5345-2007 [24]. We dried the rock core and recorded its dry weight. Then, we subjected the core to vacuum saturation with water for two days, removed the excess surface water, and measured the wet weight. We calculated the core’s porosity. Then, we sealed the core with plastic wrap and applied a confining pressure of 5 MPa for conducting water permeability testing. After wiping the surface of the core and draining any remaining water from the pipes, we prepared for oil saturation. We injected saturated oil at a rate of 0.05 mL/min and determined the volumes of bound water and oil saturation. Then, water was flooded at a rate of 0.05 mL/min at 45 °C until water saturation reached 98%. Subsequently, we performed different oil displacement methods as per the experimental setup. We analyzed and compared the results, and recorded pressure differentials, changes in water saturation, and recovery rates. The schematic diagram of the oil displacement apparatus is shown in Figure 1.

3. Results

3.1. Nanofluid Stability

First, the stability of the nanofluid was visually observed using a method of visual inspection. Different concentrations of SiO₂ nanofluids were prepared using simulated formation water and placed in an aging chamber at 45 °C for 10 days. The appearance of the nanofluids before and after aging was observed. As shown in Figure 2, it can be seen that there was no precipitation in the SiO₂ solutions at different concentrations after 10 days of aging.

To further understand the stability of the nanofluids, zeta potential measurements were conducted using the Nanbrook Omni laser particle size analyzer. Generally, a larger absolute value of zeta potential indicates better stability of the solution [25]. The test results shown in Figure 3 indicate that the absolute values of zeta potential for different SiO₂ nanofluids were all above 25 mV. When the SiO₂ concentration was 0.05%, the zeta potential value was −39.7 mV, indicating that this concentration resulted in the most stable nanofluid. The addition of AOS surfactant to the 0.05% SiO₂ nanofluid increased the zeta potential value to −40.2. The surfactant enhanced stability by adsorbing onto the surface of the nanoparticles, resulting in increased electrostatic spatial stability. However, when 0.1% HPAM was added to the 0.05% SiO₂ nanofluid, the zeta potential value decreased to −25.03. This was due to the long polymer chains of HPAM attaching to the SiO₂ nanoparticles, leading to the formation of larger clusters within the nanofluid. In order to prove its hydrophilicity, we subsequently measured the contact angles of the three systems. The contact angles of SiO₂, SiO₂/HPAM, and SiO₂/AOS were 59°, 31°, and 18°, respectively, all showing hydrophilicity, mainly because SiO₂ nanoparticles are adsorbed on the rock surface and have a large specific surface area and high dispersion. They can be adsorbed on the rock surface and form a covering layer, which can significantly improve the wettability of the rock surface.

3.2. Particle Size Analysis

As shown in Figure 4, after adding AOS surfactant to SiO₂ nanofluid, the particle size decreased from 191 nm to 125 nm. As an anionic surfactant, AOS has a hydrophilic sulfonate group and a hydrophobic alkyl chain. When added to the SiO₂ nanofluid, the sulfonate groups can be adsorbed on the surface of the SiO₂ nanoparticles, while the hydrophobic alkyl groups face the outside. The formation of this adsorption layer will reduce the electrostatic repulsion between nanoparticles, rendering it more difficult for the nanoparticles to agglomerate and deposit, thereby reducing particle size expansion. After SiO₂ nanofluid is added to HPAM, the particle size expands to 389 nm. HPAM is a high-molecular polymer. Its long-chain structure can interact with SiO₂ nanoparticles, which will cause attraction between nanoparticles and form large clusters, thus reducing the electrostatic repulsion between nanoparticles and strengthening the interaction between nanoparticles. The attractive force causes the nanoparticles to aggregate and the particle size to expand.

3.3. Interfacial Tension

At 45 °C, the ability of SiO₂ solution, AOS surfactant solution, and SiO₂-AOS surfactant solution to reduce IFT values was compared. As shown in Figure 5, SiO₂ solution and AOS surfactant solution reduce the IFT to 1.01 mN/m and 0.74 mN/m, respectively. When SiO₂ is present in the AOS surfactant solution, the IFT value is further reduced to 0.19 mN/m. The existence of synergy between SiO₂ nanoparticles and AOS surfactant has been demonstrated. AOS surfactant is a molecule with a hydrophobic tail and a hydrophilic head. At the interface between water and oil, molecules of AOS surfactant form a thin film, with the hydrophobic tail oriented toward the oil phase and the hydrophilic head oriented toward the water phase. This arrangement reduces the interfacial tension between water and oil, making them more prone to mixing and emulsification. When SiO₂ nanoparticles and AOS surfactant are utilized together, their actions can mutually enhance, lowering interfacial tension and improving oil displacement efficiency.

3.4. Wettability

From Figure 6, it can be observed that the SiO₂ nanofluid reduced the contact angle from 121° to 59°. The AOS surfactant solution changed the contact angle from 115° to 25°. When SiO₂ was added to the AOS surfactant, the contact angle decreased from 110° to 18°. This indicates that with the addition of SiO₂ nanofluid to AOS surfactant, the wettability changes from hydrophobic to strongly hydrophilic. The small size of SiO₂ nanoparticles allows them to fill the tiny gaps in the rock pores, altering the pore structure, enhancing pore connectivity, and reducing surface tension within the pores. This alteration facilitates easier oil flow within the rock pores. Nano SiO₂ nanoparticles adsorb onto the rock surfaces, providing a large surface area and high dispersion capability. They adhere to the rock surfaces, forming a covering layer that modifies the rock’s chemical properties. This alteration changes the wettability from initially oil-wet to water-wet. AOS surfactants, on the other hand, create a thin film at the oil–water interface, reducing the interfacial tension. These combined effects result in increased wettability, rendering surfaces that were originally oil-attractive more inclined to interact with water [26,27].

3.5. Displacement Efficiency

Through core flooding experiments, the synergistic effects between SiO₂ nanoparticles and AOS surfactant and HPAM were investigated. Four sets of core flooding experiments were conducted on sandstone cores with two different permeabilities. These experiments compared oil displacement using AOS surfactant and HPAM in cores with different permeabilities and oil displacement using AOS surfactant and HPAM after the addition of nanoparticles. As indicated in Figure 7 and Figure 8, the core permeabilities are 80 mD and 150 mD, respectively. In all experiments, an initial water flooding step was conducted to reach a water saturation of 100%, followed by subsequent polymer flooding stages. Figure 7a represents the oil displacement curve of AOS surfactant and HPAM in low-permeability cores. After primary water flooding, a 24.5% increase in tertiary oil recovery was achieved through AOS surfactant and HPAM. Figure 7b shows the oil displacement curve of AOS surfactant and HPAM with the addition of SiO₂ nanoparticles in low-permeability cores. After primary water flooding, a 21.6% increase in tertiary oil recovery was observed. However, compared to Figure 7a, Figure 7b displays a noticeable increase in pressure difference during the polymer flooding stage following the nanoparticle-enhanced surfactant and polymer flooding, resulting in an overall lower recovery compared to the AOS surfactant and HPAM flooding. Therefore, there is suspicion that SiO₂ nanoparticles have plugged the small pore throats in the core, and these plugged pores are causing increased resistance. Feng et al. [28], using nuclear magnetic resonance method, found that the larger the displacement pressure difference is, the smaller the throat operating radius is. If the small pores within the core samples are obstructed by SiO₂ nanoparticles, fluid flow becomes restricted. This implies that certain pore spaces remain inaccessible to the fluid flow, resulting in reduced recovery rates. As the fluid cannot penetrate all pore spaces, it indicates that nanoparticle interference at the small pore throats is the primary reason for decreased permeability in low-permeability rock cores. Pore throat blockage primarily occurs due to mechanical entrapment and mutual interference. Mechanical entrapment arises when the particle size of the injected components exceeds the pore throat size they are traversing. Mutual interference occurs when pore throats larger than individual nanoparticles are obstructed by these nanoparticles. As nanofluid flows from the pores into the throats, the reduced flow area leads to a rapid increase in pressure. Small water molecules flow faster than nanoparticles, causing nanoparticle accumulation at the throat entrance [29].

Figure 8a represents the oil displacement curve of AOS surfactant and HPAM in high-permeability cores. After primary water flooding, a 34.6% increase in tertiary oil recovery was achieved through AOS surfactant and HPAM. Figure 8b shows the oil displacement curve of AOS surfactant and HPAM with the addition of SiO₂ nanoparticles in high-permeability cores. After primary water flooding, a 39.4% increase in tertiary oil recovery was observed. The results indicate that, compared to Figure 8a, Figure 8b exhibited a significant increase in recovery rates after injecting SiO₂ nanoparticles into high-permeability cores. Additionally, the addition of nano-sized SiO₂ particles in Figure 8b showed a similar rising trend in pressure differentials, but the increase in pressure difference is not obvious.

According to the structural separation pressure gradient mechanism, nanoparticles self-organize into ordered layers with a wedge-shaped structure at the oil–water–solid three-phase contact zone. The existence of this layered nanoparticle structure generates structural separation pressure within the wedge-shaped three-phase region, resulting in higher pressure inside the wedge compared to the outside. Consequently, the capillary pressure gradually increases, causing the oil–nanofluid interface to advance, diffuse across the rock surface, peel away from the surface, and, thereby, facilitate the removal of crude oil, As shown in Figure 9 [30,31]. Simultaneously, changes in wettability have a significant impact on reservoir properties during the nanofluid displacement process. Alterations in wettability are a critical aspect of the oil displacement mechanism during nanofluid flooding. Nanoparticles can interact with the rock surface, forming a monomolecular thin film. This film alters the wettability of the rock surface, substantially reducing the adsorption of crude oil to the rock surface. This effect, in turn, enhances crude oil recovery rates and reduces water injection pressures. However, these methods may not yield the same results in low-permeability rock cores.

4. Conclusions

• The addition of SiO₂ nanoparticles to the AOS surfactant reduced the particle size to 125 nm. This reduction occurred because AOS molecules adsorbed onto the surface of SiO₂ nanoparticles, diminishing the electrostatic repulsive forces between the nanoparticles. However, upon introducing HPAM, the particle size expanded to 389 nm. This expansion was attributed to the long-chain structure of HPAM, which led to particle aggregation and increased attractive forces;
• SiO₂ nanofluids of varying concentrations underwent a 10-day aging process without exhibiting any precipitation, and their appearance remained stable. Zeta potential measurements revealed that the 0.05% concentration of SiO₂ nanofluid exhibited the highest zeta potential value of −39.7 mV, indicating the greatest stability. The addition of SiO₂ nanoparticles to AOS surfactant resulted in a stability of −40.2 mV. However, upon adding SiO₂ nanoparticles to HPAM polymer, the zeta potential decreased to −25.03 mV, indicating reduced stability;
• The SiO₂ solution and AOS surfactant solution individually reduced the interfacial tension (IFT) values to 1.01 mN/m and 0.74 mN/m, respectively. However, when SiO₂ was added to the AOS surfactant solution, the IFT value was further reduced to 0.19 mN/m. This change in IFT values led to a shift in rock wettability from being oil-wet to strongly water-wet, with the contact angle decreasing from 110° to 18°. These results indicate the presence of a synergistic effect between SiO₂ nanoparticles and AOS surfactant;
• In low-permeability rock cores, AOS surfactant and HPAM enhance oil recovery rates, but the addition of SiO₂ nanoparticles reduces this effectiveness as the nanoparticles obstruct small pore spaces, increasing resistance and impeding fluid flow. In high-permeability rock cores, the combination of SiO₂ nanoparticles with AOS surfactant and HPAM significantly improves oil recovery with a relatively minor increase in pressure differential. This is because, in high-permeability rock cores, nanoparticles form a layered structure in the three-phase interface of rock–crude oil–displacement fluid, which generates structural separation pressure, increases osmotic pressure, and is affected by Brownian motion and electrostatic interaction, thereby pushing the oil-–nanofluid interface forward, thereby further improving the recovery rate. Additionally, nanoparticles alter the wettability of the rock surface, reducing crude oil adhesion and promoting increased oil recovery.