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Article

The Role of Amphiphilic Nanosilica Fluid in Reducing Viscosity in Heavy Oil

by
Yuejie Wang
1,
Wei Zheng
2,3,*,
Hongyou Zhang
4,
Chenyang Tang
2,3,
Jun Zhang
1,
Dengfei Yu
1,
Xuanfeng Lu
5,6 and
Gang Li
5,6
1
CNOOC China Limited-Pengbo Operating Company, Tianjin 300459, China
2
National Key Laboratory of Offshore Oil and Gas Exploitation, Beijing 102209, China
3
CNOOC Research Institute Co., Ltd., Beijing 100028, China
4
CNOOC Tianjin Branch, Binhai New Area, Tianjin 300450, China
5
National Engineering Research Center for Oil & Gas Drilling and Completion Technology, School of Petroleum Engineering, Yangtze University, Wuhan 430100, China
6
Hubei Key Laboratory of Oil and Gas Drilling and Production Engineering, Yangtze University, Wuhan 430100, China
*
Author to whom correspondence should be addressed.
Energies 2024, 17(11), 2625; https://doi.org/10.3390/en17112625
Submission received: 26 March 2024 / Revised: 24 May 2024 / Accepted: 24 May 2024 / Published: 29 May 2024
(This article belongs to the Special Issue Advances in the Development of Unconventional Oil and Gas Resources)
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Abstract

:
Heavy oil accounts for a considerable proportion of the world’s petroleum resources, and its exploitation helps to mitigate reliance on conventional oil resources and diversify energy supply. However, due to the high viscosity and high adhesion characteristics of heavy oil, conventional methods such as thermal recovery, emulsification, and dilution have significant limitations and cannot meet the growing demands for heavy oil production. In this study, 3-propyltrimethoxysilane (MPS) was used to modify and graft amphiphilic surfactants (AS) onto nanosilica to prepare a salt-resistant (total mineralization > 8000 mg/L, Ca2+ + Mg2+ > 1000 mg/L) and temperature-resistant (250 °C) nanosilicon viscosity reducer (NSD). This article compares amphiphilic surfactants (AS) as conventional viscosity-reducing agents with NSD. FTIR and TEM measurements indicated successful bonding of 3-propyltrimethoxysilane to the surface of silica. Experimental results show that at a concentration of 0.2 wt% and a mineralization of 8829 mg/L, the viscosity reduction rates of thick oil (LD-1) before and after aging were 85.29% and 81.36%, respectively, from an initial viscosity of 38,700 mPa·s. Contact angle experiments demonstrated that 0.2 wt% concentration of NSD could change the surface of reservoir rock from oil-wet to water-wet. Interfacial tension experiments showed that the interfacial tension between 0.2 wt% NSD and heavy oil was 0.076 mN/m. Additionally, when the liquid-to-solid ratio was 10:1, the dynamic and static adsorption amounts of 0.2 wt% NSD were 1.328 mg/g-sand and 0.745 mg/g-sand, respectively. Furthermore, one-dimensional displacement experiments verified the oil recovery performance of NSD at different concentrations (0.1 wt%, 0.15 wt%, 0.2 wt%, 0.25 wt%) at 250 °C and compared the oil recovery efficiency of 0.2 wt% NSD with different types of demulsifiers. Experimental results indicate that the recovery rate increased with the increase in NSD concentration, and 0.2 wt% NSD could improve the recovery rate of heavy oil by 22.8% at 250 °C. The study of nano-demulsification oil recovery systems can effectively improve the development efficiency of heavy oil.

1. Introduction

The extraction of heavy/extraheavy oil reservoirs is currently one of the key areas in oilfield development and a critical direction for increasing heavy oil production [1,2,3]. These reservoirs typically have significant depth, oil layer thicknesses of 30–50 m, and high viscosity under reservoir conditions [4,5,6]. Improving the recovery rate of heavy oil is a persistent goal aimed at cost reduction and efficiency improvement. This goal has been a significant bottleneck and primary focus in exploring and developing heavy/extraheavy oil reservoirs [7,8,9]. Methods for heavy oil (including heavy and extraheavy oil) extraction mainly include thermal methods, solvent-based methods, and chemical methods. Thermal methods, including steam injection, steam drive, and combustion, are among the most common methods used for heavy oil extraction [10,11,12]. These methods require large amounts of thermal energy to heat the heavy oil in the ground to reduce its viscosity so that it can be pumped out [13,14]. Such energy consumption not only has a negative impact on the environment but also increases production costs [15,16,17]. Conventional large-scale heavy oil extraction methods typically involve energy-intensive processes such as steam throughput recovery and hot water drives. These methods require large amounts of thermal energy to heat the heavy oil in the ground to reduce its viscosity so that it can be pumped out. Such energy consumption not only has a negative impact on the environment but also increases production costs.
Nanoviscosity reduction technology, as a new technology, involves using nanoparticles or nanostructures to reduce the viscosity of fluids [18]. This technology is widely applied in the petroleum industry, especially in the extraction of heavy (including heavy and extraheavy) oil, where high viscosity is a challenge. Reducing viscosity helps improve the recovery rate and reduce production costs [19]. Despite the potential advantages of nanoviscosity reduction methods in heavy oil extraction, they also face disadvantages in terms of high costs, sustainability issues, potential toxicity and environmental risks, and technical challenges [20]. Therefore, the development and application of nanoviscosity reduction methods require a comprehensive consideration of their advantages and disadvantages, as well as effective management and control measures to ensure their safety, sustainability, and environmental friendliness [21].
Nassar et al. studied the catalytic effects of three different types of metal oxide nanoparticles, Fe2O3, Co3O4, and NiO, to achieve viscosity reduction in heavy oil. By reducing the reaction temperature from 500 °C to 380 °C, 330 °C, and 317 °C, they achieved a 14% increase in recovery rate and a 69% reduction in viscosity [22]. Huibers et al. analyzed the changes in wettability of two sandstone surfaces using silicon nanoparticles to enhance recovery rates in light and heavy oil samples [23]. Additionally, Lashari and Ganat and Aliabadian et al. improved the stability, rheological properties, and recovery rate of nanoparticles using graphene oxide and nanosheets in combination with silica nanoparticles [24]. Patel et al. studied the effects of three metal oxide nanocrystals on viscosity reduction in heavy oil. They observed viscosity reductions ranging from 50% to 70% with the three types of nanoparticles [25]. Desouky et al. were able to reduce heavy oil viscosity by 90% using a hydrothermal process in a reservoir in Egypt, although the application conditions were stringent [26]. Fontal et al. synthesized and evaluated iron magnetic fluids based on magnetite (Fe3O4) nanoparticles to reduce the viscosity of extraheavy oil. The results show that in the presence of magnetic fluids, the viscosity of extraheavy oil could be reduced to 81.78% [27]. Li et al. used microwave heating combined with nanocatalytic materials to realize heavy oil cracking, and the results show that the resin and asphaltene content was reduced by 17.3 wt% at a water content of 30 wt% under a microwave heating power of 666 w, a microwave heating temperature of 65 °C, and a nickel nanocatalyst concentration of 2.3 wt% [28]. Ahmadi et al. used nanomaterials as appropriate reagents for increasing foam stability for enhanced oil recovery. Significant improvements in foam stability, reduction in heavy oil viscosity by 73.27%, and the enhancement of recovery by 20% were achieved when the material concentrations were 1000 ppm and 500 ppm, respectively [29]. Zhou et al. developed a novel nanofluid based on silicon quantum dots (SiQDs) for the effective recovery of Bakken oil, which can achieve 25.72% heavy oil recovery [30]. Dong et al. prepared silica nanoparticles from dye diatomaceous earth filter aid waste and silanized them with octadecyltrichlorosilane to form hydrophobic silica nanoparticles by solution impregnation. Polystyrene/hydrophobic nanosilica (PS/hSiO2) composite fiber membranes with a rough surface and low surface energy were prepared by electrostatic spinning. The prepared PS/hSiO2 has a water contact angle of up to 166.6°, with superhydrophobicity and excellent adsorption capacity for various common oils. The maximum oil absorption of transformer oil can reach 136.4 g/g [31]. Xue et al. prepared a superhydrophobic coating using chitosan, Fe3O4 nanoparticles, and octadecylamine, achieving an oil–water separation efficiency of more than 92% [32]. Urazov et al. investigated the effect of NiO precursors on the composition of the products of the catalytic cracking of tall oils by catalyzing the cleavage of the macromolecular structure of the heavy oil in high-temperature environments, leading to viscosity reduction in the heavy oil [33]. Mukhamatdinov et al. investigated the chemical changes in the asphaltene subcomponent composition of thick oils in the presence of oil-soluble Co-based catalysts, which led to a reduction in the asphaltene structure of heavy oils by breaking the -C-S-C- bonds in the asphaltene molecules, resulting in a decrease in the viscosity of heavy oils [34].
In previous studies, the effects of different metal or metal oxide nanoparticles, including iron, nickel, copper, magnetite, alumina, and titanium dioxide, on the viscosity of heavy oil have been investigated [33,34,35,36]. However, existing nanomaterials are mostly used to catalyze the cleavage of asphaltene structures to achieve viscosity reduction when used in conjunction with viscosity reduction on heavy oil, which needs to be used at high temperatures, and the effect is often not added at low temperatures [37,38,39,40,41,42]. In other studies, silica has been used for viscosity reduction by emulsification, but with some drawbacks. Conventional nanomaterials often lack the ability to withstand both high temperatures and high salinity, leading to deactivation and poor performance during thermal recovery. In terms of nonmetallic nanomaterials, nanosilica, due to its unique structure, can be modified and grafted with corresponding functional groups to achieve effects such as spontaneous water entry into the colloidal and asphaltene layers of heavy oil, reducing viscosity, emulsifying, and reversing wetting [43,44,45,46,47,48].
This article proposes the development of amphiphilic silicon-based nanoparticles (NSD) using nano-SiO2 as a base to address these challenges. By modifying the surface of nano-SiO2 and introducing amphiphilic functional groups, the aim is to achieve high viscosity reduction, low losses, and alterations in wetting behavior.

2. Materials and Methods

2.1. Materials

This study utilized nanosilica from W.R. Grace and 3-propyltrimethoxysilane (MPS) from Shanghai Aladdin Bio-Chem Technology Co., Ltd. (Shanghai, China). Additionally, it employed chemicals such as ethanol, sodium lauryl ether sulfate, ammonia, and formaldehyde, all sourced from China National Pharmaceutical Group Corporation Chemical Reagent Co., Ltd. (Shanghai, China). The water used had a simulated underground salinity of 8829 mg/L with calcium and magnesium ions at 1500 mg/L. Stratigraphic water fractions are shown in Table 1. The oil used for the experiment is thick oil from Bohai oil field, 50 °C, shear rate 5 s−1 viscosity is 38,700 mPa·s, relative density is 0.9762 g/cm3, and the specific chemical components are shown in Table 2. Quartz sand was used to simulate reservoir core oil level experiments, with a measured permeability of 3000–3500 mD. All concentrations in this study were weight-based.

2.2. Methods

2.2.1. Material Synthesis

Nanosilica as the main material of viscosity reducers has the advantages of high specific surface area, tunability, chemical stability, environmental friendliness, and scalability, which makes it suitable to be used as the main component of viscosity reducer in heavy oil extraction. The reason for using MPS is its modification of the silica surface to obtain silica particles with functionalized coverage [49].
Common methods for surface modification of nanoparticles include physical methods and chemical methods. Physical methods involve using techniques such as microwave irradiation and plasma treatment to modify the surface of nanoparticles, introducing reactive functional groups that may be difficult to generate through chemical methods, thus facilitating the reaction of modifying agents on the nanoparticle surface. Wang et al. have utilized methane modification via physical methods to enhance the catalytic activity of Ni@SiO2 nanoparticles [50]. Similarly, Nga et al. employed physical methods using SiO2 to adjust the surface properties of materials [51]. However, physical methods in high-energy environments during usage may disrupt the spatial structure of macromolecular materials, hindering their binding with nanoparticles. Therefore, we employ chemical methods to prepare SiO2-based nanoviscosity reducers.
First, 2.5 g of nanosilica is added to 47.5 g of ethanol and sonicated for 30 min to obtain a uniform dispersion. Next, 0.5 g of MPS is dissolved in 49.5 g of ethanol to prepare the MPS solution. The pretreated nanosilica solution is mixed with the MPS solution, and the mixture is stirred and heated to 60 °C. During the reaction, 0.5 g of chloroform is gradually added as the reaction medium. The reaction temperature and stirring time (4 h) are maintained to allow the coupling reaction between MPS and the nanosilica surface. Subsequently, 5 g of the selected amphiphilic surfactant is dissolved in 45 g of ethanol to obtain a solution of grafting material, which is added to the modified mixture. The reaction temperature and stirring time (4 h) are maintained. The reaction mixture is centrifuged to separate the precipitate, which is the grafted nanomaterial. The precipitate is washed with solvents such as ethanol/chloroform to remove unreacted MPS and other impurities. The washed nanomaterial is further washed in an ammonia solution to remove residual MPS from the surface. The washed nanomaterial is treated in a formaldehyde solution for cross-linking to enhance its stability. Finally, the synthesized nanomaterial is added to water and sonicated for 30 min to prepare a nano-demulsifier with a solid content of 5 wt%.

2.2.2. Optimization of Synthesis Conditions

Parameters such as reaction temperature, reaction time, and reaction pressure are adjusted to achieve the desired particle size, morphology, and dispersion of silica nanoparticles. By precisely controlling the reaction conditions, the adverse effects of too high or too low temperature and pressure on the formation of nanomaterials can be avoided.

2.2.3. Determination of Viscosity Reduction Rate

First, test the initial viscosity μ0 at 50 °C. Next, mix 70 g of heavy oil with 30 g of microsphere solution, maintain a constant temperature for 1 h, adjust the rotation speed to 250 r/min, and stir for 2 min. Finally, at 50 °C and a shear rate of 2 s−1, measure the viscosity μ of the heavy oil emulsion. The formula for the viscosity reduction rate is as follows:
f = μ 0 − μ μ 0 × 100 %
In the equation, f represents the overall viscosity reduction rate, μ0 is the viscosity of heavy oil at 50 °C in mPa·s, and μ is the viscosity of the heavy oil emulsion after viscosity reduction in mPa·s.

2.2.4. Infrared Spectroscopy Measurement (FTIR)

After grinding approximately 30 mg of KBr powder in an agate mortar for about 3 min, it was transferred to a grinding apparatus and pressed using a pellet press. The pressed KBr pellet was then placed into the infrared spectrometer for scanning, and the resulting spectrum was saved as the background spectrum. Another 30 mg of KBr powder was weighed, and simultaneously, a small amount of modified nanosized silicon dioxide sample was added. The two were mixed thoroughly, ground for 3 min, and pressed into a pellet. The infrared spectrum of the modified nanosized silicon dioxide was obtained by scanning using KBr as the background.

2.2.5. Transmission Electron Microscopy Measurements (TEM)

Samples were prepared by vacuum drying of the modified materials at 100 °C. The morphology and dimensions of the nanomaterial were verified using a scanning electron microscope (TEM). The instrument used is a Tecnai G2 F20 transmission electron microscope from Thermo Fisher Scientific (Waltham, MA, USA).

2.2.6. Contact Angle Measurement

The quartz slides underwent a 48 h soak in hydrochloric acid, followed by washing and drying. A heavy oil dilution solution was prepared by mixing heavy oil and n-heptane in an 8:2 ratio. The dried quartz slides were immersed in the diluted heavy oil solution and placed in a 50 °C oven for 14 days. The oil-wetted angle was measured using a DSA25S fully automatic contact angle analyzer. The instrument used is a KRUSS DSA25 standard contact angle measuring instrument from KRUSS GmbH (Hamburg, Germany). Another set of oil-wetted slides were soaked in the test solution for 48 h, and the water-wetted angle was measured using the pendant drop method. Each test was conducted three times, with water droplets injected at different positions on the slides, and the results were averaged.

2.2.7. Static Adsorption Experiment

The procedure involves preparing nanomaterial solutions with varying mass concentrations in simulated water. The initial concentration (C0, mol/L) of the material in each solution is measured. Subsequently, 10 g of 70–90 mesh oil sand is placed in a conical flask, and the material solution is added. After thorough shaking and sealing, the flasks were placed in a temperature-controlled oscillator at 50 °C for 24 h at 170 r/min to allow the nanomaterials to adsorb onto the surface of the quartz sand. The oscillator was stopped, the flask was set aside for phase separation, and the remaining solution was dried in an oven. The mass of the remaining solid particles is measured, and the equilibrium concentration (C) is calculated. The static adsorption amount is then calculated based on the difference between the initial and equilibrium concentrations using Formula (2).
Q = ( C 0 − C ) V G × 10 − 3
In the equation, Q represents the static adsorption amount in mg/g; V is the volume of the solution in mL; C0 is the initial concentration of the solution in mg/L; C is the equilibrium concentration of the solution in mg/L; and G is the mass of the quartz sand in grams.

2.2.8. Dynamic Adsorption Experiment

Porous media analog cores were prepared according to the stratigraphic conditions of the Bohai oil field. Simulated water is injected into the middle container, and the system is thermostated at 50 °C for 4 h. Water flooding is then performed at a rate of 0.5 mL/min until the injection pressure stabilizes. Subsequently, the solution is continuously injected at 0.5 mL/min until the concentration of the material in the effluent approaches the injection concentration. Water flooding is resumed until the concentration in the effluent approaches zero. During displacement, effluent is collected every 10 mL, dried to remove water, and the mass of the remaining solid particles is measured to calculate the concentration. Utilizing the principle of material balance, the total loss of the material in the core is calculated based on Formula (3).
A r = C 0 V f − ∑ i = 1 n C i V i W
In the formula, Ar stands for the total adsorption loss in mg/g, C0 is the injection concentration in percentage, Vf represents the injection volume in mL, Ci, and Vi, respectively, denote the concentration and volume of the i-th effluent sample in percentage and mL, n is the total number of samples, and W is the dry weight of the core in grams.

2.2.9. Evaluation Methods for Oil Displacement Performance

The porous media model was kept at a constant temperature for 1 h, and permeability was measured with water. Subsequently, the porous model was saturated with heavy oil. After the temperature and pressure of the model stabilize, the backpressure is set to 4 MPa, and steam injection is initiated at the set temperature for the oil displacement experiment. The experimental flow is shown in Figure 1. In the water-driven oil experiments, the modeled water output, oil production, and water production were measured. Subsequently, 1 PV of the material solution was injected into the porous media model along with steam and finally switched to steam drive. During the oil displacement experiment, the effluent volume, oil production, and water production of the model are measured. The experiment is stopped when the water cut in the produced liquid reaches 98%.

2.2.10. Long-Term Stability Testing

The prepared NSD materials were stored at room temperature and 50 °C for a long period of time and tested after 30, 60, and 90 days of storage, respectively. The experimental results are shown in Table 3, and the viscosity reduction rate of the NSD system on thick oil was 83.12%, 82.52%, and 80.12% after 30 d, 60 d, and 90 d of storage at room temperature, respectively, and it can be found that the different times of placing at room temperature have less effect on the viscosity reduction effect of NSD. The long-term stability of the system can be maintained for more than 90 days.

3. Results and Discussion

3.1. Nanomaterial Characterization

3.1.1. Particle Size Distribution

Utilizing the Dynamic Light Scattering (DLS) technique, the size distribution of nano-materials at 0.2 wt% is determined by measuring the intensity of particle scattered light and the time delay. As shown in Figure 2, in the unmodified state (A), the nanomaterials are distributed across different particle sizes due to their tendency to agglomerate. After modification (B), the particle size distribution of the system is mainly concentrated between 40–80 nm, indicating a relatively uniform distribution without significant agglomeration.
This change can be attributed to the hydrolysis of the silicon-based surface modifier, which forms R-Si-OH groups that chemically bond with the hydroxyl groups on the surface of nanosilica, creating a hydroxyl-modified layer. This layer enhances the hydrophilicity of the nanomaterial surface, improving its dispersion in water and reducing agglomeration between silica molecules. Additionally, amphiphilic groups may form a modified layer on the surface of nanomaterials, exhibiting both hydrophilic and hydrophobic properties. This enhances the compatibility of nanomaterials with different solvents and improves their dispersion performance in various solvents.

3.1.2. Material Characterization

Infrared spectroscopy analysis verified the structural features of the nanoscale microspheres. In the wavelength range of 400 to 4000 cm−1, as shown in Figure 3, the infrared spectra of SiO2 exhibit absorption peaks at 460 cm−1, 800 cm−1, 1100 cm−1, and 3400 cm−1. These peaks represent the Si-O-Si bond’s bending, symmetric stretching, and asymmetric stretching vibrations, respectively. The peak at 3400 cm−1 corresponds to the hydroxyl groups on the SiO2 surface. The silicon-based surface modifier’s hydrolysis forms a Si-OH oligomer, establishing hydrogen bonds with SiO2 surface -OH groups. During heating, these Si-OH groups undergo dehydration reactions, forming covalent bonds with the substrate. At the interface, only one of the three silicon hydroxyl groups generated by the modifier’s hydrolysis bonds with the substrate’s surface hydroxyl groups, while the other two Si-OH groups may condense with other silane Si-OH groups or remain free. In the modified curve A, new absorption peaks appeared near 2960–2840 cm−1 for -CH3 and -CH2 groups, new absorption peaks at 1600–1700 cm−1 for ester groups (O-C=O), and a C-O-C absorption band at 1310–1020 cm−1 (shown in line B). The appearance of these structures corresponds to those in sodium dodecyl ether sulfate. This indicates the successful combination of MPS and sodium dodecyl ether sulfate onto the surface of SiO2 microspheres.
The microstructure of NSD was studied using Transmission Electron Microscopy (TEM). Observations were made before and after modification, as shown in Figure 4. Aggregation was observed in the silica nanoparticles solution, which indicates significant agglomeration between the nanoparticles due to mutual attraction and aggregation. In synthetic viscosity-reducing materials, aggregation between particles seems to be reduced. This reduction may be attributed to the surface modifier increasing the spatial hindrance between particles, hindering the aggregation of nanoparticles. The experiment found that the particle size was primarily concentrated around 50 nm, consistent with previous particle size distribution experimental results.

3.2. Performance Evaluation

3.2.1. Wettability

Testing the change in material surface wettability is crucial as it relates to the interaction between the material and the rock surface in subsurface environments. In some studies, the reduction in wettability angle after using nanosilica materials ranges between 20° and 60°, demonstrating significant improvement in wettability [52,53,54,55]. Additionally, Hendraningrat and Torsæter achieved a change in contact angle from 54° to 21° using metal oxides such as TiO2. It is evident that the range of wettability angle reduction depends on the modification method of the nanoparticles, the conditions of use, and the initial wettability of the reservoir rock [56]. As shown in Figure 5, the initially untreated oil sand surface is hydrophobic with a contact angle of 111°, making it difficult for water droplets to penetrate the sandstone. After the application of the AS viscosity reducer, the contact angle becomes 45.5°. After NSD immersion treatment, the contact angle decreases to 6.5°, transforming the material surface from hydrophobic to hydrophilic. This indicates that nanomaterials can alter the sandstone surface from hydrophobic to hydrophilic, changing the capillary forces from resistance to driving forces during water flooding. This enhances the ability of water phase infiltration in the formation, ultimately improving the recovery of heavy oil.

3.2.2. Static Adsorption Performance

Measuring adsorption loss provides insights into the anchoring capability of NSD in reservoirs. This is crucial for evaluating its effectiveness under complex reservoir conditions and for oil field development and enhancing oil recovery. The adsorption loss of nanosilica on rock surfaces typically ranges from 1 mg/g-sand to 10 mg/g-sand [57,58,59]. In some studies, Zhou conducted experiments by controlling different materials under varying concentrations, pH, and ionic strengths, discovering that the adsorption loss of surfactants can fluctuate between 0.01 mg/g-sand and 50 mg/g-sand [60]. Therefore, this range depends on various factors, including the surface modification of the nanoparticles, the chemical properties of the solution (such as pH and ionic strength), and the mineral composition of the rock. The relationship between NSD and AS concentration and adsorption loss was investigated at a liquid–solid ratio of 10:1 and an adsorption time of 15 h. The NSD concentration and adsorption loss were studied at a liquid–solid ratio of 10:1. The results in Figure 6 show that an increase in NSD concentration leads to a significant increase in adsorption loss, gradually reaching saturation. The material accumulates on the sand surface and the loss increases because the adsorption rate is higher than the desorption. NSD has a final adsorption capacity of 1.3 mg/g-sand and AS has a final adsorption capacity of 16 mg/g-sand. the use of SiO2 greatly reduces the loss of viscosity reducer and contributes to the reduction in dosage, cost savings, and environmental protection.
In addition, to further explore the dynamic adsorption properties of NSD and to guide the enhancement of nanomaterials. We prepared a porous media model simulating the original reservoir conditions (2.5 cm diameter, 30 cm length, and 3150 mD permeability). Assessing the adsorption characteristics at different NSD concentrations, the relationship between dynamic adsorption and injection pore volume multiples is shown in Figure 7. As NSD concentration slowly increases, adsorption loss gradually increases, reaching saturation at 15 pore volume injections (PV). Subsequent water flooding leads to NSD separation, reducing adsorption. The dynamic adsorption capacity of the 0.2% system is 0.745 mg/g.
Through the two experiments, it is evident that the static saturation adsorption losses are significantly greater than the dynamic adsorption losses. The notable difference between static and dynamic adsorption lies in the extensive contact between NSD and the oil sand particles during static adsorption experiments, promoting saturation. In dynamic adsorption experiments, the contact area between microspheres and oil sand surfaces is relatively smaller. The low viscosity of NSD results in its preferential passage through dominant channels during displacement in the core. This poses a challenge in reaching low-permeability zones, limiting the saturation adsorption achievable near rock surfaces. Additionally, there exists a continuous equilibrium between adsorption and desorption within the simulated core. During water injection, substances adsorbed on the rock are flushed and desorbed, resulting in static saturation adsorption losses that significantly exceed dynamic adsorption losses.

3.2.3. Viscosity-Reducing Performance

The viscosity reduction rate can be used to test the viscosity reduction effect of NSD on heavy oil. In Ameri’s study, the viscosity of heavy oil decreased by 40% to 60% after using silica nanoparticles. The study found that surface modification of the nanoparticles significantly enhances the viscosity reduction effect [61]. Another experimental report showed that, under high-temperature and high-salinity conditions, the viscosity reduction rate of modified silica nanoparticles could reach 50% to 77% [62]. This high-efficiency viscosity reduction under such conditions demonstrates the adaptability of nanoparticles in complex environments. Therefore, this experiment examined the effect of different concentrations of NSD in different solvent systems at different salinities after aging for 8 h at different temperatures. The experimental temperature was 50 °C, and the results are shown in Figure 8. The viscosity reduction rate decreases with increasing NSD concentration. The tested concentrations were 0.05%, 0.1%, 0.15%, 0.2%, and 0.25%, with viscosity reduction rates of 26.50%, 46.83%, 67.16%, 85.29%, and 91.41%, respectively. After aging NSD at 250 °C for 8 h, the viscosity reduction rates were 13.18%, 39.25%, 51.55%, 81.36%, and 84.37%, respectively. The viscosity reduction rate of the AS viscosity reducer was only 55.68% at 0.2 wt%, with an obvious “deactivation” phenomenon after aging at high temperature. The viscosity reduction performance of NSD after aging was not much different from that of NSD before aging, which indicated that the system had good temperature resistance and excellent viscosity reduction effect.

3.2.4. Moisture Content Performance

Understanding the emulsification performance of viscosity reducers is crucial as it provides important guidance for optimizing their applications. This ensures effective viscosity reduction during complex pumping processes. To study the effect of heavy oil water content on the viscosity reduction effect of NSD, we kept the concentration of the nanomaterial at 0.2% and the testing temperature at 50 °C. The oil-to-water ratio was varied to 8:2, 7:3, 6:4, and 5:5, respectively, to evaluate the viscosity reduction effect. The experimental results, as shown in Figure 9, indicate that when the oil-to-water ratio is 7:3, the viscosity reduction rate reaches 85.29%. With a further increase in water content, the viscosity of the system continues to decrease. This is attributed to the significant influence of water content on the emulsification performance of the material. The viscosity of highly stable emulsions is mainly determined by the viscosity of the external aqueous phase and is almost independent of the viscosity of the heavy oil. As the water content increases, the system transitions to an O/W-type emulsion.

3.2.5. Interfacial Tension

Studying the ability of viscosity reducers to reduce interfacial tension helps one understand their mechanism of action at the oil–water interface. The lower the interfacial tension, the easier it is to transfer heavy oil from the pores in the formation. Silica nanoparticles used in enhanced oil recovery (EOR) typically result in a significant reduction in the interfacial tension (IFT) between heavy oil and water. This property is crucial for increasing oil recovery efficiency. According to existing research literature, the use of silica nanoparticles in EOR processes can reduce the IFT between heavy oil and water to a range of 10–100 mN/m [55,59,60]. Therefore, it is crucial to study the interfacial tension between NSD and heavy oil at different concentrations. The experimental results, as shown in Figure 10, indicate that at a concentration of 0.1%, the interfacial tension is 0.231 mN/m, indicating a relatively high interfacial tension. As the system concentration increases, the interfacial tension gradually decreases, reaching a state of lower interfacial tension. When the material concentration is 0.2%, the interfacial tension is 0.087 mN/m. This is because NSD can adsorb onto the oil–water interface, thereby reducing the interfacial tension. The reduction in interfacial tension is beneficial for maintaining the stability of the emulsion.

3.2.6. Oil Recovery Efficiency

Based on the above experiments, it can be concluded that NSD material exhibits good viscosity reduction and interfacial tension reduction effects. Nanosilica has shown significant potential in enhancing oil recovery. Studies indicate that most nano-silica-based nanofluids can increase oil recovery by 5% to 18% under water flooding conditions [63,64,65,66]. During water flooding, the incremental oil recovery rate can reach up to 15% of the geological reserves [67,68,69]. Most of these studies were conducted in low-ionic-strength aqueous solutions, demonstrating that nanofluids can effectively improve oil recovery in such environments. However, these conditions differ from actual reservoir environments, which typically contain high ionic strength and various ions, especially divalent cations such as calcium and magnesium. These ions can interact with the surface of the nanoparticles, leading to particle agglomeration and reduced effectiveness. A few studies, such as those by Hendraningrat and Torsæter, have evaluated the performance of nanosilica in aqueous solutions containing divalent cations [70]. These studies found that further modification is needed to enhance the stability and oil recovery performance of nanosilica in such conditions. Therefore, conducting displacement experiments simulating actual reservoir conditions is essential to study the performance of viscosity reducers in complex oilfield environments. Four sets of experiments were conducted to investigate the displacement ability of NSD at different concentrations. The experimental temperature was 250 °C, and the experimental method involved multistage slug injection. As shown in Figure 11 and Table 4, with the increase in steam injection volume at 250 °C, the water content and recovery rate of heavy oil also increased. This is because the injection of high-temperature steam reduces the viscosity gradient in the formation, alleviates the resistance to heavy oil flow, and improves the fluidity and collection efficiency of heavy oil, resulting in a recovery rate of 31.8 at this stage. When the NSD solution was injected, the recovery rate increased with the concentration of NSD. When the test concentrations of NSD were 0.1%, 0.15%, 0.2%, and 0.25%, the heavy oil recovery rates were 36.3%, 44.2%, 49.2%, and 50.3%, respectively. This is mainly because the dispersion of NSD in heavy oil improves the dispersibility of oil and water, making it easier for heavy oil and water to form emulsions. The formation of emulsions helps reduce the viscosity of heavy oil, improve its fluidity, and enhance the recovery rate. Additionally, the recovery rate between NSD concentrations of 0.2% and 0.25% only increased by 0.9%. Therefore, to control extraction costs, it is not necessary to increase the concentration of NSD beyond 0.2%.

4. Conclusions

This study presents a method for preparing nanomaterials tailored for heavy oil, which integrates the coupling agent method, surfactant method, and grafting polymerization method in chemical modification. Compared with traditional methods, this approach enables the aggregation of materials with higher molecular weights, rendering them more adaptable. This marks progress in the exploitation of unconventional heavy oil resources, particularly in heavy oil extraction.
  • Our experimental results show that at a concentration of 0.2 wt% and a salinity of 8829 mg/L, the viscosity reduction rates of thick oil (LD-1) before and after aging are 85.29% and 81.36%, respectively. The NSD material was stabilized for more than 90 days under different conditions. Compared with the AS viscosity reducer, 0.2 wt% NSD material has a 29.61% increase in viscosity reduction and better temperature resistance. Achieving higher viscosity reduction rates effectively improves the fluidity and recoverability of heavy oil in reservoirs, thus enhancing oilfield development and production efficiency.
  • Contact angle experiments demonstrate that 0.2 wt% concentration of NSD changes the reservoir rock surface from oil-wet to water-wet; interface tension experiments show that the interfacial tension between 0.2 wt% NSD and thick oil is 0.076 mN/m.
  • The dynamic and static adsorption capacities of 0.2 wt% NSD were 1.328 mg/g-sand and 0.745 mg/g-sand, respectively, at a liquid–solid ratio of 10:1. The static adsorption loss of NAD was reduced by 8.2 mg/g-sand as compared with that of the AS viscosity reducer. This indicates a lower loss during reservoir flow.
  • One-dimensional displacement experiments validated the oil displacement performance of NSD at different concentrations (0.1 wt%, 0.15%, 0.2 wt%, 0.25 wt%) at 250 °C and compared the oil recovery efficiency of 0.2 wt% NSD with different types of viscosity reducers. The experimental results show that the recovery rate increases with the concentration of NSD, and the recovery rate of thick oil with 0.2 wt% NSD at 250 °C can be increased by 22.8%. The study of nanoviscosity reduction drive systems can effectively improve the development of heavy oil.
This study primarily investigates the extraction of unconventional heavy oil in the Bohai Sea region of China. By validating the excellent performance of the silica-based viscosity reducer prepared under various conditions including low temperature, high temperature, low salinity, and high salinity, the superiority of the viscosity reducer is confirmed. Through observing the interfacial activity, viscosity reduction effects, and oil displacement performance between the nanomaterials and heavy oil, the results demonstrate that the viscosity reducer not only performs well in various environments but also incurs minimal losses in reservoirs. However, this study has not thoroughly explored the effectiveness of the viscosity reducer in regions significantly different from the Bohai Sea region of China. Therefore, further exploration in this field is necessary, and plans are underway to expand the scope of research to various geographical locations to verify the universality and applicability of the viscosity reducer.
Scaling up the synthesis of nanomaterials from the laboratory scale to the commercial scale may pose technical challenges. Scalable preparation processes and production equipment need to be developed for large-scale, stable, and sustainable production. Perceived barriers to the commercial application of NSD may include doubts about its performance and safety, as well as a lack of awareness of its market demand and application potential. Future research directions can be based on these findings to strengthen the research on product performance and safety, expand application areas, improve market awareness and acceptance, and promote the healthy development of the nanosilica industry.
In summary, future research directions for nanosilica will involve various aspects such as performance optimization, functionality expansion, environmental friendliness improvement, multidisciplinary cross-applications, intelligent applications, nanobiotechnology, safety assessment, and industrial applications to meet the growing market demand and scientific research challenges.

Author Contributions

Conceptualization, W.Z.; data curation, D.Y.; funding acquisition, W.Z.; investigation, C.T.; methodology, W.Z.; resources, J.Z.; software, Y.W. and H.Z.; supervision, G.L.; validation, Y.W.; visualization, Y.W. and X.L.; writing—original draft, Y.W.; writing—review and editing, X.L. All authors have read and agreed to the published version of the manuscript.

Funding

This research was supported by the National Natural Science Foundation of China, grant number 52074038.

Data Availability Statement

The data presented in this study are available on request from the corresponding author.

Acknowledgments

We gratefully acknowledge Lifeng Chen for their pivotal role in providing the necessary funding for this research endeavor. Without their generous support, this work would not have been possible.

Conflicts of Interest

Authors Yuejie Wang, Jun Zhang and Dengfei Yu were employed by the CNOOC China Limited-Pengbo Operating Company. Author Hongyou Zhang is employed by CNOOC Tianjin Branch. Authors Wei Zheng and Chenyang Tang were employed by the CNOOC Research Institute Co., Ltd. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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Figure 1. Schematic of core flooding apparatus.
Figure 1. Schematic of core flooding apparatus.
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Figure 2. The particle size distribution of nanomaterials before and after modification.
Figure 2. The particle size distribution of nanomaterials before and after modification.
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Figure 3. Infrared spectra before and after material modification: A is nanosilica; B is a synthesized nanomaterial.
Figure 3. Infrared spectra before and after material modification: A is nanosilica; B is a synthesized nanomaterial.
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Figure 4. TEM microstructure of nanomaterials before and after modification: (a) is nanosilica; (b) is synthesized viscosity-reducing nanomaterial.
Figure 4. TEM microstructure of nanomaterials before and after modification: (a) is nanosilica; (b) is synthesized viscosity-reducing nanomaterial.
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Figure 5. Effect of materials on wettability: (a) untreated initial oil sand surface, (b) the contact angle after 0.2 wt% AS treatment, and (c) the contact angle after 0.2 wt% NSD treatment, with the green line marking the contact angle.
Figure 5. Effect of materials on wettability: (a) untreated initial oil sand surface, (b) the contact angle after 0.2 wt% AS treatment, and (c) the contact angle after 0.2 wt% NSD treatment, with the green line marking the contact angle.
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Figure 6. Effect of different material concentrations on adsorption capacity: (a) NSD material and (b) AS viscosity-reducing material.
Figure 6. Effect of different material concentrations on adsorption capacity: (a) NSD material and (b) AS viscosity-reducing material.
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Figure 7. Relationship between dynamic adsorption capacity and pore volume multiple of nanomaterial injection.
Figure 7. Relationship between dynamic adsorption capacity and pore volume multiple of nanomaterial injection.
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Figure 8. Viscosity-reducing properties of the material on heavy oil: (a) NSD at 25 °C, (b) NSD at 250 °C for 8 h, (c) AS at 25 °C, and (d) AS at 250 °C for 8 h.
Figure 8. Viscosity-reducing properties of the material on heavy oil: (a) NSD at 25 °C, (b) NSD at 250 °C for 8 h, (c) AS at 25 °C, and (d) AS at 250 °C for 8 h.
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Figure 9. The effect of oil–water ratio on the viscosity reduction effect of nanomaterials.
Figure 9. The effect of oil–water ratio on the viscosity reduction effect of nanomaterials.
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Figure 10. Interfacial tension between different concentrations of nanomaterials and heavy oil: (a) 0.1%, (b) 0.15%, (c) 0.2%, and (d) 0.25%.
Figure 10. Interfacial tension between different concentrations of nanomaterials and heavy oil: (a) 0.1%, (b) 0.15%, (c) 0.2%, and (d) 0.25%.
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Figure 11. The oil displacement effect of different NSD concentrations on heavy oil at 250 °C: (a) 0.1%, (b) 0.15%, (c) 0.2%, and (d) 0.25%.
Figure 11. The oil displacement effect of different NSD concentrations on heavy oil at 250 °C: (a) 0.1%, (b) 0.15%, (c) 0.2%, and (d) 0.25%.
Energies 17 02625 g011
Table 1. Ion composition of oilfield formation water.
Table 1. Ion composition of oilfield formation water.
Ion TypeNa+K+Mg2+Ca2+Cl−SO42−HCO3−Total Salinity
Ion Content
(mg/L)		24482316728324256663248829
Table 2. Chemical composition of Bohai thick oil.
Table 2. Chemical composition of Bohai thick oil.
w (Saturated Hydrocarbons)/%w (Aromatic Hydrocarbons)/%w (Resin Content of Heavy Oil)/%w (Asphaltene)/%
28.1437.5319.7914.54
Table 3. Long-term stability of NSD.
Table 3. Long-term stability of NSD.
MaterialsConcentration/%Retention Time/dReduction Rate/%
NSD0.23083.12
0.26082.52
0.29080.12
Table 4. The oil shift test of NSD at different concentrations was summarized.
Table 4. The oil shift test of NSD at different concentrations was summarized.
TestNSD
Concentration (wt%)		Steam Temperature (°C)Saturated Oil
(mL)		Oil Saturation
(%)		Oil Recovery (%)
Steam FloodingNSD FloodingPoststeam
Flooding		Additional Increment
A0.125050.480.631.836.337.25.4
B0.1550.880.932.044.247.915.9
C0.250.680.730.949.253.722.8
D0.2550.580.632.350.355.222.9
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Wang, Y.; Zheng, W.; Zhang, H.; Tang, C.; Zhang, J.; Yu, D.; Lu, X.; Li, G. The Role of Amphiphilic Nanosilica Fluid in Reducing Viscosity in Heavy Oil. Energies 2024, 17, 2625. https://doi.org/10.3390/en17112625

AMA Style

Wang Y, Zheng W, Zhang H, Tang C, Zhang J, Yu D, Lu X, Li G. The Role of Amphiphilic Nanosilica Fluid in Reducing Viscosity in Heavy Oil. Energies. 2024; 17(11):2625. https://doi.org/10.3390/en17112625

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Wang, Yuejie, Wei Zheng, Hongyou Zhang, Chenyang Tang, Jun Zhang, Dengfei Yu, Xuanfeng Lu, and Gang Li. 2024. "The Role of Amphiphilic Nanosilica Fluid in Reducing Viscosity in Heavy Oil" Energies 17, no. 11: 2625. https://doi.org/10.3390/en17112625

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