Synergistic Effects of Nano-SiO₂ on Emulsion Film Stability and Non-Newtonian Rheology of Offshore Oil-Based Drilling Fluids

Abstract

The ocean harbors vast potential for oil and gas resources, positioning offshore drilling as a critical approach for future energy exploration. However, high-temperature and high-pressure offshore reservoirs present formidable challenges, as conventional water-based drilling fluids are prone to thermal degradation and rheological instability, leading to wellbore collapse and stuck-pipe incidents. Offshore oil-based drilling fluids (OBDFs), typically water-in-oil emulsions, offer advantages in wellbore stability, lubricity, and contamination resistance, yet their stability under extreme high-temperature conditions remains limited. This study reveals the enhancement of offshore OBDFs performance in harsh conditions by employing nano-SiO₂ to synergistically improve emulsion film stability and non-Newtonian rheological behavior while systematically elucidating the underlying mechanisms. Nano-SiO₂ forms a composite film with emulsifiers, reducing droplet size, enhancing mechanical strength, and increasing thermal stability. Optimal stability was observed at an oil-to-water ratio of 7:3 with 2.5% nano-SiO₂ dispersion and 4.0% emulsifier. Rheological analyses revealed that nano-silica enhances electrostatic repulsion, reduces plastic viscosity, establishes a network structure that increases yield stress, and promotes pronounced shear-thinning behavior. Macroscopic evaluations, including fluid loss, rheological performance, and electrical stability, further confirmed the improved high-temperature stability of offshore OBDFs with nano-SiO₂ at reduced emulsifier concentrations. These findings provide a theoretical basis for optimizing offshore OBDFs formulations and their field performance, offering breakthrough technological support for safe and efficient drilling in ultra-high-temperature offshore reservoirs.

1. Introduction

Approximately 70% of the world’s oil and gas field reserves are contained in oil and gas fields in the ocean [1]. In recent years, the increasing saturation of onshore oil and gas exploration and production has prompted many nations to intensify their efforts in developing offshore resources. Consequently, the marine environment is emerging as a crucial frontier for the strategic exploitation of global oil and gas reserves [2,3]. A significant proportion of the world’s major oil and gas discoveries have originated from marine exploration zones [4]. Owing to their abundant hydrocarbon potential, they are regarded as promising targets for future energy exploration and development [5]. Particularly in the South China Sea, where the estimated geological reserves of natural gas are approximately 1.6 × 10¹³ m³, accounting for about one-third of China’s total oil and gas resources [6,7].

Drilling remains the most direct and efficient approach for oil and gas exploration and development [8,9]. The exploitation of marine oil and gas reserves relies heavily on offshore drilling fluids, which are indispensable for ensuring safe and efficient well construction [10]. Unlike conventional onshore drilling, offshore operations—particularly those targeting ultra-high-temperature, high-pressure reservoirs—often encounter thermal degradation and rheological instability when using traditional water-based drilling fluids, frequently resulting in wellbore collapse and stuck-pipe incidents [11]. Offshore oil-based drilling fluids employ oil as a continuous phase and are formulated with high-temperature stabilizers, emulsifiers, and other functional additives, thereby exhibiting distinct technical advantages. Such fluids have been extensively applied in regions including the Bohai Bay Basin and the South China Sea.

Offshore oil-based drilling fluids, owing to their superior thermal stability, wellbore stability, and lubricity, have become an indispensable technical choice for oil and gas development [12]. Currently, common oil-to-water ratios used in field operations include 75:25 and 80:20. However, adjusting the proportion of the dispersed phase can reduce costs, but this also leads to issues such as aging at high temperatures and decreased offshore drilling fluid stability [13,14]. High temperatures can intensify the thermal motion of emulsifier molecules, causing them to pack more loosely at the oil–water interface and potentially resulting in their desorption from the interface, thereby reducing the strength of the oil–water interface film [15,16]. As a result, the likelihood of droplet collisions and coalescence. Moreover, high temperatures are capable of elevating the thermal energy of emulsion droplets. As a consequence, the collision rates of these droplets are accelerated, thereby hastening the process of droplet coalescence. Following droplet coalescence, the collision frequency experiences a further increase, which accelerates water precipitation from the oil phase. This series of events ultimately disrupts the stability of the emulsion system and leads to oil–water separation [17]. On the other hand, under high-temperature conditions, offshore drilling fluid treatment agent molecules are prone to breakage or complete inactivation, disrupting the offshore drilling fluid’s network structure and forming thick but non-compact mud cakes, which increase offshore drilling fluid loss [18].

Oil-in-water emulsion is a key component of offshore oil-based drilling fluids, consisting of oil as the continuous phase and water as the dispersed phase. It is formed through the addition of emulsifiers and other additives, including loss reducers, weighting agents, and wetting agents, to yield an oil–water miscible system. The stability of oil-in-water emulsions is primarily maintained by primary emulsifiers and auxiliary emulsifiers. The primary emulsifier is generally a surfactant with strong oil affinity, and its function is to decrease the interfacial tension between oil and water and construct a boundary film on the droplet surface. The mechanical strength and stability of the boundary film are further optimized by the auxiliary emulsifier through the adjustment of the hydrophilic-lipophilic balance (HLB) value of the system. The HLB value represents a dimensionless parameter used to characterize the relative strengths of hydrophilicity and lipophilicity in surfactants. Generally, when the HLB value ranges between 3 and 6, a water-in-oil (W/O) emulsion is formed, whereas an HLB value between 8 and 18 is conducive to the formation of an oil-in-water (O/W) emulsion. For most oil-in-water emulsions, the HLB value of the primary emulsifier is generally between 3.5 and 6.0, while the HLB value of the auxiliary emulsifier is typically greater than 7. The auxiliary emulsifier and primary emulsifier form a more tightly packed mixed adsorption layer at the interface through hydrophobic interactions and electrostatic repulsion. As a result of this arrangement, the interfacial tension is reduced, and droplet coalescence is inhibited [19].

Currently, research on improving the stability of oil-in-water emulsions primarily focuses on the development of high-temperature-resistant emulsifier systems, with the core mechanism involving the synergistic action of primary and auxiliary emulsifiers to enhance interfacial membrane characteristics. Among these, primary emulsifiers primarily enhance interfacial adsorption capacity and thermal stability through molecular structural reinforcement (e.g., introducing sulfonic acid groups, amide groups, etc.); Kamal et al. optimized the structure of zwitterionic surfactants by introducing sulfonic acid groups. Experimental results showed that these groups possess high bond energy (strong S-O bond stability), enabling them to withstand temperatures above 90 °C without undergoing thermal decomposition or hydrolysis reactions [20]. Long et al. used fatty acids and polyamine compounds as the main emulsifier raw materials, introducing multiple amide groups to form hydrogen bonds with water molecules, thereby enhancing the rigidity of the main emulsifier molecules and reducing the risk of bond breakage caused by free rotation at high temperatures [21]. The synergistic effect of the auxiliary emulsifier manifests as improved interfacial rheology and the formation of a composite interfacial film with the primary emulsifier. Shen et al. selected the high molecular weight polymer XN-OSE, which has a long-chain structure, as an auxiliary emulsifier. This emulsifier can regulate the spatial distribution of the main emulsifier, enhance intermolecular entanglement, and maintain the rheological properties of the emulsion at high temperatures [22]. Hou et al. found that under high-temperature conditions, quaternary ammonium salt co-emulsifiers can interact with the primary emulsifier through ionic bonds and hydrogen bonds, strengthening the interfacial membrane and reducing the risk of droplet coalescence [23]. Studies on different types of emulsifiers indicate that the synergistic interaction between primary and auxiliary emulsifiers can improve the strength and stability of the interfacial film, significantly enhancing the stability of oil-in-water emulsions under high-temperature conditions.

However, emulsions formed by high-speed stirring with emulsifiers typically only maintain short-term stability. During long-term storage, droplets tend to coalesce and increase in size, and simply increasing the emulsifier dosage is insufficient to maintain stability [24]. Additionally, in practical applications, high temperatures can cause irreversible damage to the molecular structure of emulsifiers, such as chemical bond hydrolysis and the breaking of intermolecular hydrogen bonds, leading to the breakdown of the emulsifier’s amphiphilic structure. This structural damage is time-dependent, causing the interfacial membrane strength to weaken continuously and ultimately disrupting the stability of emulsion [25]. Therefore, relying solely on traditional emulsifiers is no longer sufficient to meet complex engineering requirements, necessitating the exploration of new methods or the addition of auxiliary components to enhance the emulsion’s stability and adaptability.

In recent years, nano-SiO₂ has found extensive application in enhancing emulsion performance owing to its stable physicochemical properties and highly tunable structural characteristics [26]. For instance, Binks et al. utilized positively charged aluminum oxide to encapsulate nano-SiO₂ and combine it with anionic surfactants in an acidic environment, gradually reducing the surface charge of the nanoparticles. As the charge approached zero, the particles were adsorbed onto the oil–water interface, thereby reinforcing the interfacial film [27]. For oil-in-water emulsions, studies by Pal et al. have shown that the hydrophilic ends of surfactants bond to nano-SiO₂, whereas the hydrophobic ends are oriented toward the oil phase, thereby inducing alterations in the surface wettability of nano-SiO₂. The adsorption of more hydrophilic nano-SiO₂ onto the rock surface renders it hydrophilic, thereby decreasing the flow resistance of the emulsion in pores and enhancing the wetting coefficient [28]. Moreover, in the cosmetics industry, nano-SiO₂ adsorbs onto the surface of emulsion droplets to form a tightly packed particle layer and serves as a carrier to encapsulate lipophilic (e.g., vitamin E, tocopheryl acetate) or hydrophilic active ingredients, thereby safeguarding them against oxidation and photodegradation [29].

Although research on the synergistic effects between nano-SiO₂ and emulsifiers has advanced, most focus on traditional systems with limited consideration for offshore oil-based drilling fluids (OBDFs). Investigations into high-temperature offshore environments remain scarce. In fact, nano-SiO₂ shows great potential in enhancing emulsion high-temperature stability by reducing emulsion droplet size, strengthening oil–water interfacial films, and improving non-Newtonian rheological properties—this helps cut emulsifier dosage and optimize OBDF formulations. To this end, this study uses optical microscopy, contact angle testing, high-speed centrifugation, and dynamic light scattering to explore how nano-SiO₂ and emulsifier concentration affect oil–water interfacial tension, emulsion kinetic stability, electrical stability, and rheological properties. It clarifies the synergistic mechanism of nano-SiO₂ and emulsifiers at the oil–water interface and characterizes nano-SiO₂’s influence on non-Newtonian fluid rheology via macroscopic rheology. Based on this, an offshore OBDF was prepared. Its performance under high-temperature and high-pressure (HTHP) conditions was evaluated by testing rheological properties, mud cake formation, and HTHP fluid loss rate, aiming to provide theoretical guidance for optimizing oil-in-water (O/W) emulsion and OBDF formulations.

2. Materials and Methods

2.1. Materials and Instruments

Materials included: No. 3 White Oil (CNPC, Beijing, China); anhydrous CaCl₂, CaO (Sinopharm Chemical Reagent Co., Ltd., Shanghai, China); hydrophilic nano-SiO₂ (McLean Biochemical Technology Co., Ltd., Shanghai, China); and barite (Hewo Petroleum Engineering Technology Co., Ltd., Chengdu, China), which was used to regulate the system’s density and rheological properties. The main bentonite in the offshore drilling fluid was montmorillonite (Huai’an Tengfei Bentonite Development Co., Ltd., Zhangjiakou, China). Additives included thickening agents (Shengli Oilfield Petrochemical Co., Ltd., Dongying, China), gelling agents (Dongying Shiprui Petroleum Engineering Technology Co., Ltd., Dongying, China), fluid loss control agents (Hongqingtai Petroleum Additives Co., Ltd., Shenzhen, China), oil-based stabilizers (Tianzheng Petroleum Technology Co., Ltd., Xi’an, China), and pH regulators (Bazhou Sanyuan Petroleum Additives Co., Ltd., Korla, China). Oleic acid (Shantou Xilong Technology Co., Ltd., Shantou, China) was the primary emulsifier, reacting with aqueous Ca²⁺ to form calcium oleate (C₃₆H₆₆CaO₄). The anionic oleate anions generated during this process have surfactant properties, suitable for water-in-oil (W/O) emulsions. The auxiliary emulsifier was Span-80 (Hai’an Petrochemical Factory, Nantong, China), a typical nonionic surfactant with an HLB value of 4.3.

The instruments employed comprise the Hitachi SU8010 scanning electron microscope (Hitachi, Tokyo, Japan), utilized for analyzing the elemental composition, content, and surface morphology of samples; IKA C-MAG HS 7 magnetic stirrer (Eckerl & Söhne, Staufen, Germany), used to effectively mix offshore drilling fluid, emulsions, and various additives to ensure homogeneous mixing and stability; the Leica DM6B optical microscope (Leica Microsystems GmbH, Wetzlar, Germany), employed to observe the microscopic structure of emulsions; and the OCA25 optical contact angle measuring instrument (Detta Physical Instruments GmbH, Feldstadt, Germany), used to measure the contact angle of emulsion droplets. The Zeta Plus 90 Bi-But zeta potential analyzer (Brookhaven Instruments Corporation, Holtsville, NY, USA) was used to determine the size and distribution of emulsion micelle particles; the Chuangmeng 1212 high-temperature and high-pressure filtrate loss tester (Chuangmeng Instrument Co., Ltd., Qingdao, China) was employed to test the water loss and wall-forming properties of the offshore drilling fluid system; the ZNN-D6 six-speed rotary viscometer (Rongjida Instrument Technology Co., Ltd., Shanghai, China) was utilized to detect macroscopic rheological properties; and the XGRL-4A high-temperature roller heating furnace (Chuangmeng Instrument Co., Ltd., Qingdao, China) was used to evaluate the aging performance of the offshore drilling fluid system under high-temperature conditions.

2.2. Emulsion and Offshore Drilling Fluid Preparation

2.2.1. Method for Preparing an Emulsion

Emulsions are crucial for enhancing the rheological properties and promoting the stability of offshore oil-based drilling fluid (OBDF) systems. Their primary components include base oil (No. 3 white oil), the aqueous phase, and hydrophilic nano-SiO₂. During preparation, Span-80 (primary emulsifier) and oleic acid (auxiliary emulsifier) are mixed at a 1:1 ratio (total concentration 1.0–6.0%), then combined with No. 3 white oil (oil phase) and stirred at 10,000 rpm for 30 min using a magnetic stirrer to ensure thorough dissolution.

Next, hydrophilic SiO₂ particles (particle size range: 7–40 nm) were added to the aqueous phase to form a nano-SiO₂ dispersion with a mass concentration of 30 wt%. After adding a 26% CaCl₂ solution, stirring at 20,000 rpm and ultrasonic dispersion for 1 h produced a stable dispersion. Finally, the oil phase was mixed with the nano-SiO₂ dispersion and stirred for 30 min to obtain an emulsion. To ensure emulsion stability, the oil-to-water ratio and other components were optimized. The final formulation was determined as follows: oil-to-water ratio 7:3, oil phase 224 mL, aqueous phase 96 mL, total amount of primary and auxiliary emulsifiers 3.2–19.2 g, nano-SiO₂ 0.48–4.8 g, and (24.96 g CaCl₂) saline.

2.2.2. Offshore Drilling Fluid Preparation Method

The offshore oil-based drilling fluid (OBDF) was prepared by mixing the aforementioned emulsion with various additives. First, the emulsion was stirred using a magnetic stirrer (rotation speed 10,000 rpm). Bentonite was added during the initial stirring phase; once it was fully dispersed, calcium oxide (CaO) was added and ensured to dissolve completely. Subsequently, the remaining additives and barite were added sequentially to ensure uniform distribution of all components. Continuous stirring was maintained throughout the process, with total preparation time lasting 50 min. During preparation, the pH value of the offshore oil-based drilling fluid sample must have been controlled within the range of 8–10 to ensure stable particle dispersion. All operations were conducted at room temperature. For the aging performance test, the sample must first have been heated at 150 °C for 16 h. Subsequently, the properties of the aged offshore oil-based drilling fluid were evaluated.

2.3. Testing Methods for Emulsions and Offshore Drilling Fluids

2.3.1. Microstructure

The Leica DM6B optical microscope equipped with a built-in camera was chosen to characterize the morphology of the emulsion. During microscope operation, the sample was first stirred, and 1 mL of the sample was taken and placed onto a glass slide to ensure uniform distribution and prevent bubble interference. A glass coverslip was then placed over the sample for observation. The focus was adjusted by rotating the focus knob until the sample came into clear view, and the image was captured. Subsequently, Image J 1.54p (data visualization) software was used to process and analyze the emulsion images, ultimately yielding the particle size distribution curve of the emulsion droplets.

2.3.2. Contact Angle Testing

The surface of the glass slide was cleaned with anhydrous ethanol and fixed on the measurement platform of the optical contact angle measuring instrument (model OCA25). Subsequently, 5 μL of the emulsion droplet was added, the microscope was adjusted to obtain a clear image, and the shape of the droplet was captured using the camera. The measurement was repeated three times, the average was taken, and its standard deviation was computed. When the standard deviation is ≤1.2°, the contact angle test data for that emulsion group is considered reliable.

2.3.3. Degree of Phase Separation

The emulsion was placed in a container and stirred for 15 min using a magnetic stirrer at a speed of 500 rpm. It was allowed to stand for 2 min, the layering of the liquid phases was observed, and the height of each layer was recorded. When the layering phenomenon was less pronounced and the layering height was smaller, it was an indication that the emulsion possessed better stability. Repeat three times, the average is calculated, and the standard deviation is computed. When the standard deviation is ≤3%, the phase separation stability data for that emulsion group is considered reliable. The test results are characterized by the oil separation rate, as follows:

$$f=(v_1/v_2)\times 100\%=h_1/h_2\times 100\%$$

(1)

In Equation (1), $f$ represents the oil separation rate (%); $v_1$ denotes the volume of separated oil (mL); $v_2$ is the total volume (mL); $h_1$ is the height of separated oil (cm), and $h_2$ is the total height (cm).

2.3.4. Rheological Properties

According to the American Petroleum Institute (API) standard measurement protocol, the rheological properties of offshore oil-based drilling fluids from different samples were tested using a ZNN-D6 six-speed rotary viscometer. Specifically, PV (plastic viscosity), AV (apparent viscosity), and YP (yield stress) were tested, and the corresponding calculations required the use of Equations (2) and (3), respectively. First, the rotational speed was adjusted to 600 rpm, and the measurement was initiated only after the reading had stabilized. Then, the rotational speed was switched to 300 rpm, and we waited until the reading stabilized before measuring again. This process was repeated three times, the average was calculated, and the standard deviation was determined. When the standard deviation was ≤2, the phase separation stability data for that emulsion group was considered reliable. The calculation formulas for $AV$, $PV$, and $YP$ are as follows:

$$AV={\displaystyle \frac{1}{2}}\varnothing 600$$

(2)

$$PV=\varnothing 600-\varnothing 300$$

(3)

$$YP=\varnothing 300-PV$$

(4)

In these equations, $AV$ denotes the apparent viscosity (cP), $PV$ represents the plastic viscosity (cP), $\varnothing$ is the viscometer dial reading, $YP$ is the yield point (lbs/100 ft²), $\varnothing 600$ is the dial reading at 600 rpm, and $\varnothing 300$ is the dial reading at 300 rpm.

For all the aforementioned measurements and calculations, the Herschel–Bulkley model (abbreviated as the H-B model) was employed to fit the relationship between shear stress and shear rate, and the derived relationship was visualized as a graph using Origin 2024 software. The Herschel–Bulkley model is as follows:

$$\tau ={\tau }_0+K\cdot {\gamma }^n$$

(5)

where $\tau$ denotes the shear stress (Pa); ${\tau }_0$ represents the yield stress (Pa), defined as the minimum stress required to initiate fluid flow. $K$ is the rheological index (Pa·sⁿ), also referred to as the flow consistency index, which characterizes the viscosity behavior of the fluid. $\gamma$ denotes the shear rate (s⁻¹); n is the flow index, which describes the relationship between shear stress and shear rate. When $n$ = 1, the model reduces to the Newtonian fluid model; when n < 1, it represents a pseudoplastic fluid (shear thinning); when n > 1, it corresponds to a thixotropic fluid (shear thickening).

2.3.5. Characterization of the Zeta-Potential

Zeta potential measurements were performed using a zetaPALS electrophoretic light scattering analyzer (Brookhaven Instruments Corporation, Holtsville, NY, USA). During testing, 2 mL of the emulsion sample was first taken and filtered through an oil-compatible polytetrafluoroethylene (PTFE) filter membrane to remove aggregates, then diluted with ethanol at a 1:400 ratio (for uniform dispersion). The diluted sample was injected into a dedicated electrophoretic cuvette, and a 10–20 V/cm electric field was applied. Each sample was tested three times (20–80 particle signals per run) to record electrophoretic mobility. Using the Smoluchowski equation, the measured mobility was substituted with parameters such as the water-in-oil (W/O) emulsion’s dielectric constant and viscosity (ethanol’s room-temperature physical parameters were used due to the high dilution ratio) to calculate the zeta potential of W/O emulsion droplets. Results were averaged from three measurements; data was considered reliable if the standard deviation was ≤5 mV.

2.3.6. High Temperature and High-Pressure Filtration Performance

The Qingdao Chuangmeng 1212 high-temperature, high-pressure filter loss tester was used to test the filter loss performance of the offshore drilling fluid, with a pressure difference of 3.5 MPa, a temperature of 150 °C, and a filter paper diameter of 2.5 inches. Nitrogen cylinders were used as the pressure source to increase the high pressure. The fluid loss of the offshore drilling fluid was recorded at 5, 10, 15, 20, and 30 min intervals. This process was repeated three times, the average was calculated, and the standard deviation was determined. If the standard deviation was ≤0.2 mL, the fluid loss data for that group was considered valid. Subsequently, an electronic caliper was utilized to measure the filter cake thickness. Following each measurement, the sample was rotated by 90°, and the measurement was repeated three times; the average was calculated, and the standard deviation was determined. When the standard deviation was ≤0.5 mm, the mud cake thickness measurement data for that group was considered valid.

2.3.7. Microstructure of Mud Cake

Following the fluid loss test, the filter cake was dried at 60 °C for 1 h and mounted onto the measurement platform of a scanning electron microscope. The microstructure of the dried filter cake was observed and imaged at an acceleration voltage of 20 kV. Microstructural analysis primarily involved gold spraying technology, which operates by using X-rays to excite surface elements of the sample, inducing the emission of characteristic photoelectrons. Through analysis of the energy of these photoelectrons, the elemental composition of the filter cake was determined, thereby facilitating the revelation of its composition, structure, and properties.

2.3.8. Electrical Stability Test

Electrical stability testing is primarily conducted to assess the emulsion stability and oil wettability of offshore oil-based drilling fluids. The Fann 21200 Electrical Stability Tester (Fann Instrument Company, Houston, TX, USA) was employed for the measurements, and its core component consisted of a pair of parallel plate electrodes. Before measurement, the electrodes were inserted into the emulsion to ensure complete coverage of their surfaces, after which the measurement was initiated. A sinusoidal alternating voltage was applied to the electrodes, and the voltage changes were monitored until a stable reading was obtained on the display. After the data were recorded, the measurement was repeated three times, and the average was calculated. When the standard deviation of the three measurements was ≤15 V, the demulsification voltage data for that group was considered valid.

3. Results and Discussion

3.1. Mechanism of Synergistic Action Between Nano-SiO₂ and Emulsifier

3.1.1. The Mechanism of Emulsion Stability

Figure 1 illustrates the mechanism by which nano-SiO₂ and emulsifiers synergistically stabilize emulsions, with electrostatic repulsion and the formation of composite films being the key factors affecting emulsion stability. Specifically, nano-SiO₂ can spontaneously undergo the following reaction under alkaline pH conditions:

$$\equiv Si-OH+O{H}^{-}\to \equiv Si-O^{-}+H_{2}O$$

(6)

As can be seen from Equation (6), nano-SiO₂ carries a negative charge in the emulsion. In an alkaline environment, it interacts with the anionic component of the negatively charged primary emulsifier through electrostatic repulsion, accelerating its diffusion to the surface of water droplets. This promotes the uniform distribution of water droplets, reduces droplet aggregation and coalescence, thus enhancing the stability of the emulsion [30].

On the other hand, nano-SiO₂ can be adsorbed by the auxiliary emulsifier through hydrogen bonding, and its surface is transformed from hydrophilic to hydrophobic. Owing to the difference in hydrophobicity between the anionic component of the primary emulsifier and the modified nano-SiO₂, the two naturally distribute on opposite sides of the oil–water interface film, forming a composite membrane resembling a “shell.” When compared to liquid films formed solely by surfactants, higher strength and thickness are exhibited by composite membranes. Furthermore, more nano-SiO₂ and main emulsifiers are accumulated at the oil–water interface, which enables the composite membrane to significantly reduce interfacial free energy and further enhance the stability of the emulsion system [31].

3.1.2. Mechanism of Loss Control

Figure 2 illustrates the filter loss control mechanism. Due to their extremely small size, nano-SiO₂ can bridge and fill micro-pores, preventing fluid loss and maintaining wellbore stability. Research has shown that adding nano-SiO₂ to emulsions can reduce filtration loss in offshore oil-based drilling fluids by 50–70%, with particularly significant effects in low-permeability formations such as shale. For sandstone formations with higher porosity and permeability, the filtration loss of offshore drilling fluid occurs more rapidly. Nano-SiO₂-coated emulsion droplets can block high-permeability channels, redirecting fluids to low-permeability or untouched areas, thereby effectively controlling offshore drilling fluid flow and reducing filtration loss [32].

3.2. Emulsion Performance Analysis

3.2.1. Microscopic Morphology of Emulsion Droplets

The average particle size distribution of the emulsion droplets obtained through Image J image analysis is shown in Figure 3a,b. As the concentration of the emulsifier increases, a significant decrease in the droplet size is observed. However, when the concentration reaches 4.0%, the rate of decrease in droplet size slows down and eventually stabilizes. This indicates that emulsifier molecules at the interface reach saturation, and excess emulsifier molecules begin to form micelles in the continuous phase, resulting in stable dispersion effects [33,34].

Figure 4a–e show optical microscope images of the base emulsion (4% surfactant) after the addition of different concentrations of nano-SiO₂ dispersion. With an increase in the concentration of the nano-SiO₂ dispersion, a significant decrease in the droplet size and a narrowing of the size distribution are observed. When the concentration reaches 2.5%, the particle size decreases by 32.9%, and the number of small droplets increases, improving film strength and effectively inhibiting droplet coalescence. When the concentration reaches 5.0%, the film strength is maximized; however, excessive nano-SiO₂ leads to enhanced particle-particle interactions, causing flocculation and limiting the further reduction in particle size [35,36].

3.2.2. Rheological Properties of Emulsions

Figure 5 and Figure 6 show the shear stress changes in oil-in-water emulsions after adding different doses of emulsifier and nano-SiO₂ dispersions, respectively. Comparative analysis indicates that increasing the emulsifier dosage has little effect on the rheological properties of the emulsion system. Observing the $K$ values in Figure 7a reveals that for emulsions with varying emulsifier concentrations, the overall viscosity exhibits a trend of first decreasing and then increasing before and after high-temperature aging, respectively. The viscosity reaches its minimum at an emulsifier concentration of 4.0%. Meanwhile, the $n$ values are generally below 1.0 (Figure 8a), indicating that the emulsion is a non-Newtonian fluid exhibiting shear thinning behavior—a characteristic where viscosity decreases with increasing shear rate, consistent with the rheological behavior of emulsions in offshore oil-based drilling fluid systems [37]. As the concentration of emulsifiers increases, more emulsifier molecules adsorb at the oil–water interface, enhancing the hydrophobicity of the droplet surface and repulsive force. However, when the emulsifier concentration is excessive, some emulsifier molecules form micelles, leading to an increase in system viscosity. After aging, the overall viscosity decreases, which is related to the ordered arrangement of emulsifier molecules under high temperature or shear force [38,39]. Therefore, an emulsifier concentration of 4.0% results in the lowest system viscosity, indicating optimal emulsion stability.

As shown in Figure 6, an increase in shear stress was observed upon adding different concentrations of nano-SiO₂ dispersion to the emulsion both before and after aging, and this increase became more significant as the concentration of the nano-SiO₂ dispersion increased. Observing Figure 7b, it can be observed that the $K$ values before and after aging both show an increasing trend, and the $K$ values after aging are significantly lower than those before aging. This indicates that as the concentration of the nano-SiO₂ dispersion increases, the viscosity of the system gradually rises, and more particles are adsorbed onto the droplet surface. Due to the interaction between the continuous phases, a network structure forms around the droplets, thereby increasing the viscosity of the emulsion [40,41]. As the temperature increases, the thermal motion of emulsifier molecules is intensified, resulting in a more orderly arrangement of the oil–water interface. This arrangement enhances the binding between emulsifier molecules and nano-SiO₂ and improves droplet dispersion. This weakens the network structure formed by nano-SiO₂, ultimately resulting in a decrease in system viscosity. Comparing the $n$ values in Figure 8a,b, it is observed that the $n$ value further decreases after adding nano-SiO₂, which can be attributed to the disruption of the network structure under shear stress, causing the emulsion to gradually transition from an expansive fluid to a pseudoplastic fluid. As the concentration increases, when the concentration of the nano-SiO₂ dispersion reaches 1.0%, the change in $n$ values slows down relatively, indicating that the network structure has basically formed [42,43].

3.2.3. Degree of Separation of Emulsion Phase

The kinetic stability of the emulsion can be characterized by its oil separation rate. Figure 9 and Figure 10 show the oil separation rates of the emulsion at different time intervals. As shown in Figure 9, within the first 3 min, the oil separation rates of all four emulsifier formulations exceeded 40%, indicating that the membranes formed by the emulsifiers were relatively weak. Under centrifugal force, oil and water droplets were prone to rupture, leading to oil–water separation [44].

Figure 10 demonstrates the effect of different concentrations of nano-SiO₂ dispersions on the oil separation rate of the emulsion. As the concentration of nano-SiO₂ increases, the upper layer of the emulsion gradually turns white, indicating that more nano-SiO₂ binds with the auxiliary emulsifier, altering the wettability and enhancing its dispersion effect in the oil phase. Experimental results show that when the nano-SiO₂ concentration is below 1.0%, the oil separation rate exceeds 40%, as the concentration is insufficient to effectively stabilize the oil–water interface, resulting in poor droplet stability. However, when the concentration increases to 2.5% and 5.0%, the oil separation rate is lower within 10 min, at 26% and 29%, respectively. This indicates that the composite film formed by nano-SiO₂ and the emulsifier has high mechanical strength. However, excessive nano-SiO₂ can form flocculation on the droplet surface, increasing the droplet’s weight and making it more prone to settling, thereby leading to a reduction in the overall stability of the emulsion and increasing the oil separation rate [45,46].

3.2.4. Emulsion Contact Angle Test

Based on experimental results, Figure 10a–d illustrate the trend of contact angle variation with emulsifier concentration. At an emulsifier concentration of 1.0%, the contact angle was 29.1°. As the emulsifier concentration increased, the contact angle exhibited a slight decreasing trend, indicating that the emulsifier forms a film on the droplet surface: hydrophilic chains are distributed within the droplet, while hydrophobic chains are exposed to the oil phase, thereby reducing the interfacial tension between oil and water.

Figure 10e,f present the contact angles after the addition of nano-SiO₂ dispersion. When a 0.5% nano-SiO₂ dispersion was incorporated, the contact angle decreased from 24.4° to 19.8°, representing an 18.8% reduction. This indicates that the emulsifier altered the wettability of the nano-SiO₂ surface, enabling it to adsorb at the oil–water interface. The enhanced hydrophobic interactions significantly lowered the surface tension. As the nano-SiO₂ dispersion concentration increased from 1.0% to 2.5%, the contact angle decreased by 40.9%. This was due to more hydrophobic nano-SiO₂ particles adsorbing at the interface and synergistically interacting with emulsifier molecules to enhance hydrophobicity. When the concentration exceeded 2.5%, the contact angle decreased by only 1.2%, representing an 11.1% reduction. This phenomenon can be explained by the following mechanism: particle aggregation leads to flocculation. When flocculants adsorb at the oil–water interface, the hydrophobic properties of internal particles are “shielded” and cannot directly contribute to the oil–water interface. This results in a sustained but smaller decrease in contact angle compared to the dispersed state [47,48].

3.2.5. Characterization of the Zeta-Potential of Emulsions

To investigate the adsorption of emulsifiers and nano-SiO₂ at the oil–water interface, the changes in zeta potential were monitored and are presented in Figure 11. All measured zeta potentials were below −60 mV, indicating good emulsion stability. When the emulsifier concentration increased from 1.0% to 6.0%, the absolute value of the zeta potential showed a gradual increase, reaching 65 mV, 154 mV, 205 mV, and 320 mV, respectively, with growth rates of 136.9%, 33.1%, and 56.1%. This suggests that more negatively charged emulsifier molecules adsorb at the interface, thereby enhancing electrostatic repulsion between droplets and the improvement of stability. When the concentration approaches 4.0%, adsorption sites tend to saturate, and the growth rate of electrostatic repulsion slows down. When the emulsifier is in excess, negatively charged micelles form, further increasing the charge density of the dispersed phase, leading to a slight increase in the growth rate of the zeta potential [49].

After adding the nano-SiO₂ dispersion solution, the absolute value of the zeta potential further increases. As the concentration of the nano-silica dispersion solution gradually increases from 0.5% to 5.0%, the growth rates are 48.2%, 52.9%, and 19.5%, respectively. This indicates that when the concentration of the nano-SiO₂ dispersion solution increases from 0.5% to 2.5%, the dissociated negative charges directly act on the droplet surface, increasing the charge density and thereby enhancing the electrostatic repulsive force between droplets. However, when the concentration of the nano-SiO₂ dispersion exceeds 2.5%, the growth rate decreases significantly. This phenomenon can be attributed to the fact that excess nano-SiO₂ partially distributes in the continuous phase to form free flocs, which contribute weakly to the surface charge of the droplets, leading to a slower increase in the zeta potential [50,51].

3.3. Offshore Drilling Fluid Analysis

3.3.1. Offshore Drilling Fluid Formulation

Based on the comparative experiments of the emulsion formulations mentioned above, we ultimately selected 4% and 6% emulsifier, as well as emulsions prepared using 4% emulsifier combined with 2.5% nano-SiO₂ dispersion and 4% emulsifier combined with 5.0% nano-SiO₂ dispersion as the base emulsions. On this basis, we added barite, organic soil, CaO, and one filter loss reduction agent to prepare the four offshore oil-based drilling fluid formulations shown in

Table 1. Formulation of offshore oil-based drilling fluids.

Treatment Agent	Characteristics	Unit	Dosage
No. 3 white oil	oil phase	mL	224
Deionized water	liquid phase	mL	96
Span-80	Main emulsifier	g	12.8/19.2
Oleic acid	Co-emulsifier	g	12.8/19.2
Nano-SiO2	Nanoparticles	g	2.4/4.8
Organic soil	lipophilic colloid	g	4
CaCl2	salts	g	24.96
CaO	PH control agent	g	4
Filter loss reduction agent	Sulfonated asphalt	g	12
Barite	Aggravating agent	g	325

, laying the groundwork for further investigation into the synergistic effects of emulsifier and nano-SiO₂ on the offshore oil-based drilling fluid system.

3.3.2. Offshore Drilling Rheological Properties

As shown in Figure 12, the shear rate and shear stress of offshore drilling fluids with different formulations exhibit a positive correlation. To facilitate the description of changes in the macroscopic properties of offshore drilling fluids with different formulations, their rheological properties are characterized by apparent viscosity (AV), plastic viscosity (PV), and yield stress (YP). As shown in Figure 13, comparing Formulations 1 and 2, when the emulsifier concentration increased from 4% to 6%, the AV value rose by 6.6%. This is because excess emulsifier forms micelles in the oil phase. Due to their inherent viscosity and hydrophobic interactions, these micelles increase the system’s viscosity, thereby elevating the AV value. PV also increased by 5.7%, indicating that micelle aggregation intensified the frictional resistance within the system. YP similarly exhibited an upward trend, attributable to micelle entanglement. During flow, stronger intermolecular forces (such as hydrogen bonding and hydrophobic association) must be overcome, thereby increasing the flow resistance of offshore oil-based drilling fluids (OBDFs) [52,53].

When comparing Formulations 2, 3, and 4, the addition of 2.5% nano-SiO₂ dispersion significantly increased AV. This is because nano-SiO₂ particles form a network structure around droplets, enhancing the system’s viscosity and stability. Meanwhile, PV decreased by 14.3%, attributable to nano-SiO₂ strengthening electrostatic repulsion between droplets and acting as a lubricant to reduce frictional resistance. The increase in YP is due to the network structure enhancing gel strength, thereby improving the system’s ability to resist deformation under external forces. However, when the addition of nano-SiO₂ dispersion reaches 5.0%, excessive nano-SiO₂ reacts with solid particles through flocculation, causing AV to continue rising but at a slower rate. PV increases because flocculation disrupts the electrostatic balance of the system, resulting in larger floc particles and increased friction within the system; YP also further increases, indicating enhanced gel structural strength. However, the system’s fluidity significantly decreases. In actual drilling operations, even though the increased YP enhances rock-carrying capacity, insufficient fluidity can impair drilling efficiency, thereby weakening the positive effects of high strength [54,55].

3.3.3. Offshore Drilling Fluid Electrical Stability Performance

The addition of different doses of nano-SiO₂ dispersion and emulsifier resulted in varying degrees of change in the electrical stability of the offshore drilling fluid, as shown in Figure 14a. The demulsification voltage increased gradually from Formulation 1 to Formulation 4, with a maximum increase of 96.7%. The increase from Formulation 1 to 2 was 19.6%, and from Formulation 1 to 3, it was 70.7%. This indicates that both the emulsifier and nano-SiO₂ can improve the system’s electrical stability. In formulation 2, a 6% emulsifier concentration led to the formation of micelles, whose negative surface charge interacted with the negative charge on the droplet surface, further enhancing the electrostatic repulsive force and thereby increasing the demulsification voltage. In formulation 3, nano-SiO₂ and emulsifier co-adsorb on the droplet surface, reinforcing the oil–water interface membrane and significantly improving the system’s electrical stability. However, in formulation 4, although the demulsification voltage continues to increase, the growth rate slows down, indicating that excessive nano-SiO₂ leads to increased viscosity and flocculation, thereby reducing the system’s stability [56,57].

Figure 14b shows the changes in electrostatic stability after aging at 150 °C. The demulsification voltage of Formulations 2, 3, and 4 all showed slight increases, with increases of 5.8%, 4.0%, 15.5%, and 9.3%, respectively. This indicates that high temperatures promote the ordered arrangement of emulsifier molecules, enabling them to bind more fully with the adsorption sites of nano-SiO₂, further enhancing the mechanical strength and density of the droplet surface [58].

3.3.4. High-Temperature and High-Pressure Filtration Performance of Offshore Drilling Fluid

As shown in Figure 15, as the emulsifier concentration increases according to Equation (2), the number of micelles increases, viscosity rises, flow rate slows down, and filtrate loss decreases by 36.1%. Figure 16 shows that when the emulsifier concentration is 4% and 6%, the cake thickness remains at 5 mm, indicating that the emulsifier reduces fluid loss by increasing viscosity but has little effect on mud cake.

From Formulation 1 to Formulation 3, the addition of 2.5% nano-SiO₂ dispersion significantly reduced filtrate loss by 69.5%, while mud cake thickness decreased by 50%. This effect can be attributed to the multifunctional role of nano-SiO₂: first, nano-SiO₂ forms a network structure around droplets, enhancing system viscosity and slowing fluid flow; second, the encapsulated droplets effectively block high-permeability channels, reducing fluid loss at the source; third, nano-SiO₂ fills the microscopic pores on the mud cake surface and forms composites with particles such as bentonite, which tightly pack under high temperature and pressure, causing the mud cake to thin out and further reduce fluid loss. However, when nano-SiO₂ is present in excess (Formulation 4), the solid phase content of the system increases, triggering flocculation reactions. The distribution of flocculants in the continuous phase enhances the system’s network structure, further increasing viscosity. However, due to the uneven size of the flocculants, this not only affects the arrangement and distribution of nano-SiO₂ and emulsifier on the droplet surface but also reduces the density of the mud cake, causing its thickness to increase by 20% and resulting in a no longer significant decrease in fluid loss [59,60].

3.4. Microstructure of Mud Cakes

Figure 17 shows the mud cake morphology of Formulation 1 and Formulation 3. It was found that the mud cake with only 4% emulsifier added (Figure 17a) had a rough and irregular surface, with numerous pores and irregular protrusions and depressions of varying sizes. However, after adding 2.5% nano-SiO₂ dispersion, as shown in Figure 17b, the mud cake surface becomes smoother, featuring smaller pores and a more compact structure. This indicates that an appropriate amount of nano-SiO₂, owing to its small particle size, can penetrate the mud cake, seal the small pores, and render the structure of the mud cake denser and more uniform. Consequently, the fluid loss under high-temperature and high-pressure conditions is reduced [61,62].

4. Conclusions

• This study reveals the enhancement mechanism of nano-SiO₂ on the rheological behavior of emulsion interfacial films and non-Newtonian fluids at both macro- and micro-scales: nano-SiO₂ adsorbs at the oil–water interface, forms a composite film with main and auxiliary emulsifiers to strengthen the mechanical strength of emulsion interfacial films, thereby inhibiting droplet coalescence; via hydrophobic interactions with emulsifiers’ hydrophobic groups, it reduces droplet surface tension and decreases droplet size to improve droplet dispersibility in the oil phase; and forms a network structure around droplets through inter-droplet electrostatic repulsion to enhance emulsion rheological properties and structural stability at elevated temperatures. Furthermore, under shear stress, the nano-SiO₂ network structure is disrupted, making the emulsion gradually transition from an expansive fluid to a pseudoplastic fluid and exhibit the characteristic shear-thinning behavior of non-Newtonian fluids.
• The emulsion formulation containing 4% emulsifier and 2.5% nano-SiO₂ dispersion was selected as optimal. Compared to the 4% emulsifier formulation, it reduced the average droplet size by 42.1% while only decreasing the centrifugal oil separation rate by 26%. It also exhibited excellent rheological properties and pronounced shear-thinning behavior at elevated temperatures. The introduction of 2.5% nano-SiO₂ dispersion significantly reduced the interfacial tension between oil and water, decreased the contact angle by 55.7%, and lowered the zeta potential well below the stability threshold of −60 mV. This indicates enhanced overall emulsion performance and improved emulsion stability.
• After incorporating bentonite and various additives to form offshore oil-based drilling fluids (OBDFs), nano-SiO₂ promotes the compact arrangement of solid particles, significantly enhancing the overall viscosity and structural stability of the system. Compared to conventional offshore oil-based drilling fluid formulations, the addition of nano-SiO₂ enables the formation of a denser mud cake, resulting in superior thermal stability and filtration performance. Filtration loss is reduced by 69.5%.