Study on Permeability Enhancement and Heat Transfer of Oil Sands Reservoir Based on Hydrophobic Nanofluids

Abstract

The development of nanofluid-assisted heavy oil extraction can address critical challenges in global energy sustainability, particularly for ultra-heavy oil reserves characterized by high viscosity and low permeability. This study investigates the dual role of hydrophobic nanofluids in enhancing reservoir permeability and heat transfer efficiency. Through advanced triaxial shear seepage experiments and heat transfer experiments, the permeability and thermal conductivity of oil sands cores treated with hydrophobic silica-based nanofluids (0–0.15 wt%) were quantitatively analyzed. The results showed that the permeability increased by up to 536.59% (from 33.18 mD to 211.22 mD) after nanofluid treatment, which was attributed to nanoparticle-induced pore throat modification and reduced interfacial tension. At the same time, the thermal conductivity has increased by up to 132% (from 0.25 W/m·K to 0.58 W/m·K), significantly improving the heat transfer efficiency. There is a linear relationship between the concentration of nanofluids and the thermal conductivity, and the relationship between the thermal conductivity, and the strain of oil sands is established. This work provides a scientifically grounded framework for scaling nanofluid applications in field trials, offering a transformative pathway to reduce energy intensity and improve recovery rates in ultra-heavy oil exploitation.

1. Introduction

With the continuous development and progress of human science and technology, petroleum resources have risen as the primary strategic material and are directly related to the economic lifeline of a country. As an important unconventional energy source, ultra-heavy oil sands are widely distributed and have huge reserves, and are an alternative energy source for the future. The ultra-heavy oil sands reservoirs are mostly low-permeability reservoirs. Nanofluid drag reduction technology is an effective process measure suitable for reservoir drag reduction in low permeability reservoirs [1].

Nanoparticles are an emerging functional material with a dimension of nanoscale (0.1–100 nm) in three-dimensional spaces. Most of the nanoparticles used in oilfield development are silicon nanoparticles, which can be used to configure nanofluids, which are a new class of fluids made from nanoparticles dispersed in a base fluid (usually water). Since the 1960s, researchers have been studying the application of nanotechnology in the petroleum industry and have made major breakthroughs. Nanofluids have a variety of uses in enhanced oil recovery [2], and the addition of stable nanofluids to the injection solution can enhance oil recovery. Nanofluids can also be used to depressurize and increase the injection of low-permeability reservoirs.

At present, most of the nanofluids used in permeation enhancement studies are prepared from hydrophobic SiO₂ nanoparticles and surfactants, which are stably dispersed by physical actions [3]. Hydrophobic SiO₂ nanoparticles have strong hydrophobicity, which adsorbs on the rock wall to produce a nano-scale hydrophobic adsorption layer, reducing the flow resistance and water injection pressure of the injected water. Moreover, the surface of the surface-modified hydrophobic SiO₂ nanoparticles still has unsaturated residual bonds and hydroxyl groups in different bonding states. Also, the surface activity is very high, which will be firmly adsorbed on the rock surface and has strong erosion resistance, which can greatly improve the development effect of water injection.

Gao et al. [4] conducted a laboratory study on decompression and drag reduction with water-based hydrophobic nanosilica dispersions and found that hydrophobic nanomaterials can effectively improve the core permeability. The nanodispersion with a concentration of 0.1% can increase the permeability by 39%. Xiong et al. [5] found that the aqueous permeability of ultra-low permeability cores increased by 2.6 times after treatment with nanodrag reducing agents. Field tests were carried out in Jiangsu Oilfield, and the field test results showed that the nanomaterial drag reduction system had a good application effect after being applied in high-pressure under injection wells. Liu et al. [6] prepared small-size strongly adsorbed hydrophobic nanosilica particles using an in situ surface modified functional group pathway. They added dispersants to stably disperse them in water, so that the water-based nano-polysilicon fluid has a hydrophobic–hydrophilic bilayer structure with a particle size distribution of 5–8 nm. Through the core displacement test, it was found that the water injection pressure of the ultra-low permeability well could be effectively reduced, and the injection pressure was reduced by 57.42%. Suleimanov et al. [7] showed that the addition of nanoparticles to an oil displacement agent increased the efficiency of porous media by 35%, and homogeneous porous media by 17%, compared to surfactants alone.

At present, the research focus of nanofluids is mostly on sandstone reservoirs and carbonate reservoirs, and less attention is paid to low-permeability oil sand reservoirs. Qu et al. [8] applied the nanoparticle process to the Shishen 100 block of Shengli Oilfield. The reservoir is composed of deltaic pre-turbidite sandstone with a permeability of between 30 and 50 mD, an underground crude oil viscosity of 0.5–3.26 mPa s, and a formation temperature of 60–70 °C. The experimental results showed that the decompression efficiency was 100%. After implementation, the water injection pressure was reduced from 30 MPa to 25 MPa. Wang et al. [9] studied the effects of nanoparticle injection rate and pore size on decompression, they and verified it by core displacement experiments. The experimental results show that the antihypertensive ability of nanoparticles shows great antihypertensive efficiency, which initially increases and then decreases with the increase in injection rate. Mohammad et al. [10] investigated the effects of salinity, nanofluid concentration, and rock type (i.e., limestone and dolomite surfaces) on changes in the wettability of oil-wet carbonate matrices under environmental conditions.

Due to their excellent thermophysical properties, nanofluids have been widely used in many engineering fields. In terms of the heat transfer characteristics of oil sands reservoirs, the relationship between heat transfer properties and porosity, water saturation, temperature, and other variables are mainly studied. Cervenan et al. [11] studied the thermal conductivity and specific heat of the Athabasca oil sands as a function of water saturation. Agar et al. [12] studied the coefficient of thermal expansion of the Athabasca oil sands, the coefficient of thermal pore pressure generation, etc. Hepler and His [13] studied the evolution of thermal conductivity, heat capacity, and thermal diffusivity with temperature, water saturation, and porosity of the Alberta oil sands in Canada. In terms of enhanced heat transfer by nanofluids, the effects of nanofluids on the heat conduction and convection parameters of porous media are mainly studied. Heris et al. [14] investigated the convective heat transfer properties of water-based Al₂O₃ nanofluids. Saeedinia et al. [15] investigated the thermodynamic and rheological properties of oil-based CuO nanofluids. Ganvir et al. [16] studied the convective heat transfer performance and thermophysical properties of nanofluids, and they found that nanofluids can effectively reduce thermal resistance and enhance heat transfer performance. In this paper, hydrophobic nanofluid extrusion is used to induce artificial micro-fractures to promote seepage and heat transfer in heavy oil reservoirs, so as to achieve the efficient recovery of ultra-heavy oil.

2. Materials and Methods

2.1. Materials

2.1.1. Silica Nanoparticles and Nanofluid

Nano silica (SiO₂) is a non-toxic, odorless, non-polluting inorganic non-metallic material. Nano silica is chemically stable and has good hydrophilicity. It can also be used as an ultraviolet and infrared reflective material. After titanate surface treatment, LLSi-07 has good hydrophobicity. It is a high-purity spherical granular silica powder produced by chemical seed precipitation method, which has the characteristics of activity, good wear resistance, specific gravity, and easy dispersion. Commercial hydrophobic silica (SiO₂) nanoparticles (

Table 1. Silica nanoparticles.

Items	Metric Values
Appearance	White powder
Silicon oxide content (%)	98
Average particle size (nm)	20
Specific surface area (m2/g)	≥600

) with a specific surface area greater than 600 m²/g were used in the experiment. Hydrophobic silica particles were purchased from Foshan Blue Ridge Chemical Co., Ltd., located in Foshan City, China. Compared with other nanoparticles, the silica nanoparticles used in this study are hydrophobic, with a larger particle size, a larger specific surface area, and a larger contact area with other substances, and the nanoparticles can better adsorb on the rock pore wall, thereby reducing pressure and increasing injection. The nanoparticle parameters in Table 1 are the original parameters.

Generally, the size of nanoparticles is between 1~100 nm, which makes it easy for nanoparticles to penetrate reservoirs. The particle size distribution of nanoparticles obeys normal distribution, and the narrower the particle size distribution, the easier it is to use to enhance oil recovery. The large surface area of nanoparticles in nanosize leads to high surface energy, which determines the adsorption capacity of nanoparticles in porous media and the aggregation of nanoparticles. The aggregation of nanoparticles can be mitigated by the addition of surfactants. Hydrophobic nanoparticles are usually prepared by the acoustic wave method because they are not easily dispersed in the aqueous phase.

2.1.2. Core

The cores used in the experiment were 8 artificially prepared oil sands based on the reservoir characteristics of the Fengcheng Oilfield block in Xinjiang. Fengcheng Oilfield is located at the northern end of the northwest margin of the Junggar Basin, about 130 km northeast of Karamay City, and is administratively subordinate to Karamay City, Xinjiang. It is surrounded by Hara Alat Mountain to the north, Xiazi Street to the east, and Wuerhe Town to the west. The ground altitude is 280 m~530 m, with an average of about 380 m. Due to the differential weathering, the terrain is undulating, the remnant mound and broken walls can be seen everywhere, and the gullies are vertical and horizontal, forming a wind erosion landform known as “wind into a city”. This area belongs to the continental arid climate, the temperature difference is −40 °C~40 °C, the rainfall is low, and the evaporation is large. Fengcheng Oilfield is located on the Mesozoic super overlying extermination zone on the upper wall of the Xiahongbei fault in the Wuxia fault fold belt, which is a slip–slip fold-front fault-related anticline zone tectonic pattern. This is affected by the two hidden faults of the Permian in the front edge, and the concave and convex phases in the basement are alternately arranged, and the buried depth increases to the south-east. Since the end of the Carboniferous period, the Wuxia fault zone has experienced the succession of the Late Hercynian movement, the Indosinian movement, and the Yanshan movement.

In bearing development, the final coverage of Yanshan at the end of the period is finalized. Permian, Triassic, Jurassic, and Cretaceous strata were deposited on the Carboniferous basement in this area, and the Tertiary and Quaternary strata were developed locally. The heavy oil reservoirs in this area are mainly distributed in the Jurassic area, and are in unconformable contact with the overlying Cretaceous Tuyulu Group and the underlying strata. The Jurassic developed the Lower Badaowan Formation, the Sangonghe Formation and the Upper Qigu Formation, and the Xishanyao Formation and the Toutunhe Formation are missing. The Upper and Lower Cerean are in angular unconformity contact, among which the Lower Badaowan Formation and the Upper Qigu Formation are the main oil-bearing strata in this area. Among them, oil sands Core 1 and Core 2 were soaked in NaCl solution with 3% mass fraction as the control group. Core 3 and Core 4 were soaked with nanofluids at a concentration of 0.05 wt%; Core 5 and Core 6 were soaked with nanofluids at a concentration of 0.1 wt%; Core 7 and Core 8 were treated with nanofluid immersion at a concentration of 0.15 wt%. The soaking time is 48 h. The core properties are given in

Table 2. Core properties.

Core Number	Diameter (mm)	Length (mm)	Weight (g)	Density (g/cm3)	Volume (cm3)
1-1	25.18	52.3	47.04	1.81	26.03
1-2	25.1	52.4	47.04	1.82	25.91
1-3	25.02	52.36	47	1.83	25.73
1-4	25.04	51.8	44.03	1.73	25.50
1-5	25.06	52.8	47.03	1.81	26.03
1-6	25.1	53.2	46.71	1.78	26.31
1-7	25.02	52.5	46.47	1.80	25.80
1-8	25.16	53.02	46.96	1.78	26.35

. The core mineral compositions are given in

Table 3. Core mineral composition.

Mineral Type	Non-Clay Minerals
	Quartz	Feldspar	Dolomite	Calcite	Anhydrite	Plaster	Pyrite	Siderite
Mass Percentage (%)	34.9	20.3	6.3	1.6	1.3	0.3	1.4	3.2
Mineral type	Clay minerals
	Aemon mixed layer	Illite	Kaolinite	Chlorite
Mass Percentage (%)	1.5	9.8	8.3	11.1

.

2.2. Experimental Method

2.2.1. Preparation of Nanofluids

In this experiment, hydrophobic nanoparticles were selected for the preparation of nanofluids, and a certain number of grams were weighed with an electronic balance during the experiment. Then, the measured nanoparticles were dissolved in the base solution, and the nanofluids were obtained by appropriate stirring and ultrasonic dispersion.

The preparation protocol is as follows:

(1)

Prepare or prepare base solution: NaCl solution with 3% mass fraction.

(2)

Weighing nanoparticles: Weigh the specified number of grams of nanoparticles and add them to the base solution prepared in advance, and then add a certain quality of cetyltrimethylammonium bromide solid particles.

(3)

Stirring: Stir slightly with a clean glass rod for 5 min to help the nanoparticles dissolve in the base solution.

(4)

Ultrasonic dispersion (Figure 1): Use an ultrasonic homogenizer (Figure 1b) to disperse for 2 h, the ultrasonic power is 240 W. The ultrasonic dispersion instrument model is SCIENTZ-1500F, manufactured by Ningbo Xinzhi Biotechnology Co., Ltd. (Ningbo, China) and the equipment is located at Northwest University, Xi’an City, Shaanxi Province, China. In order to avoid the overheating of ultrasonic, stop for 10 min after 15 min of ultrasonic each time to cool down the nanofluid naturally, complete the configuration after 8 times of ultrasonic, and then measure the PH value of the nanofluid with a PH meter. By interfering with the agglomeration and sedimentation of nanoparticles by ultrasound, dispersed and stable nanofluids can be obtained.

According to the above steps, three nanofluids with different concentrations were configured, which were 0.05, 0.01, and 0.15 wt%, respectively.

2.2.2. Triaxial Shear Seepage Experiment

The triaxial shear permeability tester used in this experiment is a SLB-6A stress–strain-controlled triaxial shear permeability tester, which can control the triaxial test with equal stress and strain, and can carry out stress path test and permeability test. The instrument manufacturer is Nanjing Zhongzhiyan Measurement and Control Technology Co., Ltd. (Nanjing, China), and the equipment is located at Northwest University, Xi’an City, Shaanxi Province, China. Each part of the instrument is controlled by a single-chip microcomputer, and each part can work independently, and can also exchange data with the computer for centralized data acquisition and processing. This instrument belongs to the multi-functional flexible control triaxial tester. The computer and the controller use multiple communication methods for data exchange to complete the functional requirements proposed in the overview. Each controller can transmit the data during the experiment to the computer according to the instructions of the PC. The computer draws the curves in real time, saves the data, and outputs the data in an Excel format after the test. The aim of this study was to study the effect of nanofluid concentration on the permeability of oil sands reservoirs. The experimental setup is shown in Figure 2. The main technical parameters include the following:

• Axial force: 0–60 kN, measurement accuracy: ±1% (10–95% FS);
• Control mode:
  • Equal strain control: 0.002–4 mm/min ± 10%;
  • Equal stress control: 0 kN~60 kN, control accuracy ± 1%;
• Soil sample specifications: Φ101 × 200, Φ61.8 × 125, Φ39.1 × 80, Φ25 × 50 mm;
• Surrounding pressure: 0–1.99 MPa, control accuracy: ±0.5%FS, set value (0.01~1.95 MPa);
• Counter pressure: 0–0.99 MPa, control accuracy: ±0.5%FS, set value (0.01~0.99 MPa);
  • Constant pressure difference control permeability;
  • Constant flow permeation (0.02~30 mL/min);
• Volume change: 0–480 mL, digital display.

In the case of triaxial loading, a certain confining pressure is applied to the core (both lateral and axial), then pore pressure, and finally axial strain is applied until the undisturbed oil sands are destroyed. The specific operation steps of the test are as follows:

(1)

The oil sands cores were soaked in 3% NaCl solution and 0.05, 0.1, and 0.15 wt% nanofluids, respectively (

Table 4. Experimental arrangement.

Core Number	Nanofluid Concentration/wt%	Confining Pressure/MPa	Pore Pressure/MPa	Effective Confining/MPa
1	0 (3%NaCl)	1	0.5	0.5
2	0 (3%NaCl)	2	1	1
3	0.05	1	0.5	0.5
4	0.05	2	1	1
5	0.1	1	0.5	0.5
6	0.1	2	1	1
7	0.15	1	0.5	0.5
8	0.15	2	1	1

).

(2)

According to the test requirements, be familiar with the functions of each valve of the instrument and the flow direction of the inlet and outlet liquid of the pipeline.

(3)

Determine the predetermined confining pressure value and pore pressure value of this test (Table 4).

(4)

Install the cores and energize each controller, and preheat for 10–20 min.

(5)

After the core is put into the pressure chamber (Figure 3), the confining pressure is raised to the specified value, the pore pressure is loaded to the specified value. After a period of consolidation, the permeability of the rock sample is tested, the permeability was tested by the steady-state method, and the differential pressure was 0.5 MPa following Darcy’s law. Then, the strain loading mode (loading rate of 0.1 mm/min) is used for triaxial compression after the permeability test is completed, and the loading is stopped when the axial strain is 3%, 6%, 9%, and 12%. The permeability of the rock sample is tested until the axial strain is 12%, the permeability test is completed, and the experiment is over. A total of five permeability tests are required.

2.2.3. Thermal Conductivity Experiment

Thermal conductivity is the heat flux per unit temperature gradient, which indicates the strength of the heat conductivity of a substance, and it is the most direct factor affecting heat conductivity and convection. The transient hot wire method [17], the quasi-steady plate method [18], and the hot needle method [19] are the three most commonly used methods to measure thermal conductivity, among which the transient hot wire method has the highest measurement accuracy due to short measurement time. There was no thermal convection interference caused by temperature gradient in the measurement process, and temperature information is characterized by the bridge circuit. In this study, the thermal conductivity of nanofluids was measured by the transient hot wire method, and the experimental instrument was XIAXI TC3000E thermal conductivity tester (Figure 4), the instrument manufacturer is Xi’an Xiaxi Electronic Technology Co., Ltd. (Xi’an, China), and the equipment is located at Northwest University, Xi’an City, Shaanxi Province, China. The test cores are No. 1, 3, 5, 7 and the main parameters of the instrument are shown in

Table 5. The main parameters of the thermal conductivity tester.

Technical Indicators	Parameters
Resolution	0.005 W/(m·K)
Measuring range	0.001~10 W/(m·K)
Repeatability	±3%
Accuracy	±3%
Temperature range	−160~150 °C

.

After nanofluid treatment, the oil sands cylindrical core was processed into two semi-cylindrical specimens with flat and parallel end faces (Figure 5), and the thermal conductivity of the core was measured by the hot wire method. The metal wire is placed in the middle of the specimen and then heated by electricity, and a long cylindrical transient temperature field with the heated wire as the axis is formed in the test piece. According to the principle of thermal conductivity inversion, the thermal conductivity of the specimen is calculated by using the measured temperature value.

3. Results and Discussion

3.1. Increased Permeability of Nanofluids

Eight artificially prepared oil sands standard cores (Φ2.5 cm × 5 cm) were selected to carry out the triaxial shear seepage experiment, and the samples were soaked with nanofluids. After 48 h of core immersion, they were removed for triaxial seepage shear experiment. Among which, the effective confining pressure of oil sands samples 1, 3, 5, and 7 was 0.5 MPa, and the effective confining pressures of oil sands samples 2, 4, 6, and 8 were 1 MPa, and the influence of nanofluids on oil sands permeability was studied.

Figure 6 shows the relationship between the axial strain and the permeability of the oil sands under an effective confining pressure of 0.5 MPa. With the increase in axial strain, the permeability of Core 1 gradually decreases and is much smaller than that of the oil sands sample after nanofluid treatment. The permeability of the Core 3 and Core 5 increases first and then decreases, and the permeability of the Core 7 increases with the axial strain, and the permeability changes very little. When the effective confining pressure is 0.5 MPa, the greater the concentration of nanofluid, the better the permeability enhancement effect of the oil sands reservoir.

It can be seen from Figure 7 that with the increase in nanofluid concentration, the permeability of oil sands under each axial strain gradually increases, which proves that nanofluids can effectively improve the permeability of oil sands reservoirs. The permeability is greatest when the axial strain is 3%. Compared with the Core 1 (3 wt % NaCl), the permeability of the nanofluid-treated core was significantly increased. When the axial strain is 0, the permeability of Core 3 is 416.86% higher than that of Core 1, the permeability of Core 5 is 452.77% higher than that of Core 1, and the permeability of Core 7 is 536.59% higher than that of Core 1.

Figure 8 shows the relationship between the axial strain and the permeability of the oil sands under an effective confining pressure of 1 MPa. With the increase in axial strain, the permeability of Core 2, Core 6, and Core 8 gradually decreases, and the permeability of Core 4 increases first and then decreases. The permeability of Core 4 is the largest, and the permeability of Core 2 is the smallest, indicating that the nanofluids can effectively improve the permeability of the oil sands reservoir. When the effective confining pressure is 1 MPa, the nanofluid concentration with the best effect on the permeability enhancement effect of the oil sands reservoir is 0.05 wt%. Compared with Core 2 (3 wt% NaCl), the permeability of the nanofluid-treated core was significantly increased, and when the axial strain is 0, the permeability of Core 4 is 45.32% higher than that of Core 2, the permeability of Core 6 is 49.96% higher than that of Core 2, and the permeability of Core 8 is 48.72% higher than that of Core 2.

3.2. Increased Thermal Conductivity of Nanofluids

The thermal conductivity of the core after treatment with brine and different nanofluids was measured by the hot wire method.

Figure 9 shows the relationship between the thermal conductivity and nanofluid concentration of oil sands. With the increase in nanofluid concentration, the thermal conductivity of oil sands gradually increases. Compared with the sample of 0% nanofluid concentration, the thermal conductivity of the nanofluid-treated core was significantly increased. The thermal conductivity of nanofluid concentrations of 0.05, 0.1, and 0.15 wt% cores are increased by 66.36%, 165.62%, and 133.82%, respectively, compared with the untreated cores. The optimal concentration of nanofluids to enhance the thermal conductivity of oil sands reservoirs is 0.05 wt%.

The linear relationship was fitted according to the relationship curve between the nanofluid concentration and the thermal conductivity:

$$k=am+b,$$

(1)

where a, b is constant, k is the thermal conductivity, and m is the nanofluid concentration. In this experiment, a = 2.478 and b = 0.2879 were obtained.

Cervenan et al. [11] used a steady-state hot plate instrument to determine the thermal conductivity of some reconstituted Athabasca oil sands specimens at room temperature and atmospheric pressure. The relationship between thermal conductivity and water saturation is established as follows:

$$k=1.27-2.25\varphi +2.9\sqrt{S_w},$$

(2)

where k is the thermal conductivity, ϕ is the porosity (%), and S_w is the water saturation (%).

Gao et al. [20] established the relationship between the water saturation of the oil sands and the bulk strain. It is assumed that the gas saturation is negligible, and during the water injection the increase in the pore volume of RVE is equal to the increase in the volume of water. The water saturation S_w is as follows:

$$S_w={\displaystyle \frac{V_w}{V_p}}={\displaystyle \frac{V_{p0}{S}_{w0}+V_0{\epsilon }_v}{V_{p0}+V_0{\epsilon }_v}}={\displaystyle \frac{V_0{\varphi }_0{S}_{w0}+V_0{\epsilon }_v}{V_0{\varphi }_0+V_0{\epsilon }_v}}={\displaystyle \frac{{\varphi }_0{S}_{w0}+{\epsilon }_v}{{\varphi }_0+{\epsilon }_v}},$$

(3)

where V₀ is the volume of the representative volume unit (RVE) before dilatation of the oil sands (m³), and V_p0 is the initial pore volume (m³). After water injection dilatancy expansion, RVE volume changes to V (m³), and the pore volume is V_p (m³), S_w0 is the initial saturation (%), ϕ₀ is the initial porosity (%), and ε_v is the bulk strain.

Bringing Equation (3) into Equation (2), we can obtain the relationship between thermal conductivity and the bulk strain:

$$k=1.27-2.25\varphi +2.9\sqrt{{\displaystyle \frac{{\varphi }_0{S}_{w0}+{\epsilon }_v}{{\varphi }_0+{\epsilon }_v}}}.$$

(4)

4. Conclusions

Through the triaxial shear seepage experiment and thermal conductivity experiment on eight artificially prepared oil sands cores after nanofluid treatment, the influence of nanofluids on oil sands reservoirs is studied, and the main conclusions are as follows:

The hydrophobic nanofluids function well in increasing the permeability, and the permeability of the oil sands reservoir after nanofluid treatment increases significantly. When the effective confining pressure is 0.5 MPa, the larger the concentration of the nanofluid, the better the permeability enhancement effect. The permeability of the oil sands reservoir is 536.59% higher than that of the untreated reservoir, and the nanofluid concentration is 0.15 wt%. When the effective confining pressure is 1 MPa, the nanofluid concentration with the best permeability enhancement effect on oil sands reservoir is 0.05 wt%.

Nanofluids have the effect of enhancing heat transfer in oil sands reservoirs. The thermal conductivity of nanofluid concentrations of 0.05, 0.1, and 0.15 wt% cores are increased by 66.36%, 165.62%, and 133.82%, respectively, compared with the untreated cores. There is a linear relationship between the concentration of nanofluids and the thermal conductivity, and the relationship between the thermal conductivity and the strain of oil sands is established.

This work can guide nanofluid injection protocols for specific reservoir geomechanics and establish a data-driven framework for nanofluid deployment, bridging laboratory insights to scalable field applications in challenging heavy oil systems.