Investigation of the Temperature Effect on Oil–Water–Rock Interaction Mechanisms During Low-Salinity Water Flooding in Tight Sandstone Reservoirs

Abstract

Temperature is a key factor in regulating interfacial behaviors and enhancing oil recovery during low-salinity water flooding in tight sandstone reservoirs. This study systematically investigates the synergistic mechanisms of temperature and salinity on ion exchange, wettability alteration, interfacial tension, and crude oil desorption. The experimental results show that elevated temperature significantly strengthens the oil–water–rock interactions induced by low-salinity water, thereby improving oil recovery. At 70 °C, the release of divalent cations such as Ca²⁺ and Mg²⁺ from the rock surface is notably enhanced. Simultaneously, the increase in interfacial electrostatic repulsion is evidenced by a shift in the rock–brine zeta potential from −3.14 mV to −6.26 mV. This promotes the desorption of polar components, such as asphaltenes, from the rock surface, leading to a significant change in wettability. The wettability alteration index increases to 0.4647, indicating a strong water-wet condition. Additionally, the reduction in oil–water interfacial zeta potential and the enhancement in interfacial viscoelasticity contribute to a further decrease in interfacial tension. Under conditions of 0.6 PW salinity and 70 °C, non-isothermal core flooding experiments demonstrate that rock–fluid interactions are the dominant mechanism responsible for enhanced oil recovery. By applying a staged injection strategy, where 0.6 PW is followed by 0.4 PW, the oil recovery reaches 34.89%, which is significantly higher than that achieved with high-salinity water flooding. This study provides critical mechanistic insights and optimized injection strategies for the development of high-temperature tight sandstone reservoirs using low-temperature waterflooding.

1. Introduction

As conventional oil reservoirs are gradually depleted and global energy demand continues to grow, the development of tight sandstone reservoirs becomes increasingly important. However, because tight sandstone formations have low permeability, high water saturation, and complex pore structures, traditional oil recovery methods can hardly achieve high enhanced oil recovery (EOR) performance [1,2]. Therefore, researchers keep looking for new EOR technologies. Among them, low-salinity water flooding has become a research focus. This method changes the salinity of the injected water. It affects the wettability of the reservoir rock surface. It reduces the capillary trapping of oil in the pores and increases the mobility of crude oil. At the same time, low-salinity water can reduce oil–water interfacial tension (IFT), improve the flow behavior of the oil and water phases, and enhance the relative permeability of the two phases [3,4].

In recent years, many studies have focused on the mechanisms and influencing factors of low-salinity water flooding in conventional sandstone and carbonate reservoirs [5,6,7]. The results show that low-salinity water with different salinities has different effects on the wettability and interfacial tension of reservoir rocks. The performance of low salinity water flooding (LSWF) is also closely related to factors such as mineral composition of the reservoir, crude oil properties, and temperature. In tight sandstone reservoirs, the pores are compact and small in radius. The combined effect of pore size, wettability, and interfacial tension may lead to different EOR results [8]. In the B425 low-permeability block of Shengli Oilfield [9], LSWF significantly improved oil recovery. The main mechanisms included enhanced wettability, clay particle migration, and double-layer expansion. Staged salinity reduction injection performed better than direct LSWF, and the maximum increase in oil recovery reached 29.5%. Similar conclusions have been validated in other water–rock systems. For example, Tiwari et al. [10] reported that variations in salinity and temperature significantly influence fluid–rock interactions and transport processes during seawater intrusion into sediments. This evidence further supports the necessity of considering the combined effects of temperature and salinity when evaluating the mechanisms of low-salinity water flooding.

Most previous studies have focused on the combined effect of reservoir temperature and water salinity. However, in actual oilfield development, the temperature of injected water is often lower than the reservoir temperature. This is especially true after surface treatment and long-distance pipeline transport, when the water may enter the high-temperature reservoir at room temperature or even lower. In tight sandstone reservoirs of the Ordos Basin, reservoir temperatures are usually between 60 and 90 °C [11,12,13]. Under such low-temperature water injection conditions, the physical and chemical properties of the water–oil–rock system may be very different from those under isothermal conditions. On one hand, the temperature gradient may affect the adsorption–desorption balance of polar components in crude oil, such as asphaltenes and resins, at the oil–water interface. This can change wettability and interfacial tension [14,15]. On the other hand, lower injection water temperature may change the distribution and migration rate of dissolved ions in the electrical double layer, thus affecting the electrochemical effects of LSWF [16,17]. In addition, in tight sandstone, low-temperature water injection may change the viscosity ratio of fluids and the interfacial rheological properties. This can influence the formation and migration of oil drops or microemulsions. These effects still lack systematic experimental verification [18,19].

Ayirala et al. [20] reported that low-salinity water with lower salinity usually reduces contact angle more effectively, increases the hydrophilicity of the rock surface, and improves oil mobility. Kar et al. [21] conducted core flooding tests with different salinities and found that cation exchange, wettability change, and permeability change worked together to improve oil recovery. Shaddel et al. [22] performed wettability and relative permeability tests and concluded that changing rock wettability to a more water-wet state was a key factor for EOR, while there was no strong relationship between oil relative permeability and crude oil acid number. Liu et al. [23] believed that the wettability mechanism of LSWF and its prediction of recovery were not reliable, and the best wettability did not always lead to the highest recovery. Mahmoudzadeh et al. [24] used micro-scale flooding tests and suggested that wettability alteration and IFT reduction were not effective; instead, microemulsion formation and elastic oil–water interfaces were the main mechanisms for EOR. Navarro et al. [25] found that low-salinity water injection changed pore structure and permeability, with chlorite and glauconite showing strong water sensitivity. Under low-salinity conditions, permeability increased and the pore structure shifted toward medium–large pores. Iyi et al. [26] stated that under water-wet conditions, oil is displaced from the pores; under oil-wet conditions, oil is desorbed from the rock surface; under neutral-wet conditions, initial fluid distribution had more influence than wettability on displacement efficiency. Mokhtari et al. [27] studied fluid–fluid interaction in LSWF and found that reducing salinity increased the content of dissociated polar components. While 2-times diluted seawater had the lowest IFT, 10-times diluted seawater gave the highest recovery. LSWF can also lower IFT and improve the flow of oil and water phases, enhancing relative permeability [28,29]. Liu et al. [30] concluded that in tight sandstones, LSWF can alter wettability through double-layer expansion, but this effect is weakened by divalent cations. Introducing a moderate amount of divalent cations can prevent permeability loss at very low salinity and achieve better displacement. Tang et al. [31] suggested that salinity change had little effect on oil–water interfacial interactions and recovery. Yonebayashi et al. [32] studied fluid interactions during LSWF and found that it reduced IFT and promoted water-in-oil micro-dispersion formation, especially when asphaltene content was high. Bartels and Chai et al. [33,34] reported that lower-salinity water usually achieved higher recovery in core floods. In summary, the effects of LSWF-induced wettability and IFT changes on EOR are inconsistent. In tight sandstones, poor pore connectivity and narrow throats may limit the effect of wettability and IFT changes on capillary force, preventing injected water from passing through pore throats and reducing displacement efficiency [35,36].

Therefore, the main objective of this study is to investigate the mechanism by which temperature influences the low-salinity effect during low-salinity water flooding. Elevated temperature may enhance the low-salinity effect by promoting ion release and wettability alteration. On the other hand, temperature changes may also modify mineral reactions or even deteriorate reservoir physical properties. Additionally, temperature can alter the physical characteristics of water and crude oil, potentially affecting the flow regime within the porous media. However, most existing studies have been conducted under isothermal conditions, overlooking the more common scenario in oilfield operations where low-temperature injection water enters high-temperature reservoirs. This gap limits the applicability of current findings to real reservoir conditions. To address this issue, this study systematically analyzes the influence of temperature on ion release, interfacial tension, wettability, and zeta potential under different salinity conditions. The role of temperature in modulating the effect of salinity on interfacial rheology and the desorption of polar components from crude oil is also examined. Furthermore, core flooding experiments are conducted to evaluate the integrated impact on oil recovery. The novelty of this work lies in the combination of multiple interfacial and core-scale experimental approaches to comprehensively reveal the coupled effects of temperature and salinity. These findings provide practical experimental support for optimizing LSWF injection strategies in tight sandstone reservoirs.

2. Materials and Methods

2.1. Experimental Materials

Rock Samples: As shown in Figure 1, the core samples used in this study were collected from the Chang 6 tight sandstone reservoir in a certain oilfield. The samples exhibit representative porosity and permeability values [37]. It is generally accepted that adjacent cores extracted from the same rock have similar physical properties. To minimize experimental errors, all cores used in this study were taken from the same full-diameter core [37]. Prior to the experiments, core samples with comparable porosity and permeability were selected. The screened cores had an average porosity of approximately 12.6% and an average permeability of about 0.67 mD.

In addition, the dry density of the samples is approximately 2.48 g/cm³, and the effective porosity is 11.8%. Regarding mechanical properties, the uniaxial compressive strength (UCS) of the core samples ranges from 62 to 75 MPa, with an average Young’s modulus (E) of approximately 7.24 to 8.66 GPa. These values indicate that the reservoir rocks possess relatively high strength and stiffness, which are typical characteristics of tight sandstones [37]. Porosity in the study area generally decreases with increasing burial depth. In shallow formations (<500 m), porosity is relatively high, ranging from 15% to 20%, primarily controlled by early-stage weak compaction. In the intermediate depth range (800–1500 m), porosity decreases to 8–12% due to the combined effects of mechanical compaction and cementation. The main producing interval, located within the Chang 6 formation at depths of approximately 1200–1300 m, exhibits a continued decrease in porosity with depth due to ongoing compression. In the deep section (1800–2000 m), reservoir porosity further decreases to about 5–8%. The Chang 6 formation, which serves as the primary reservoir, is characterized by tight physical properties and low fluid-flow capacity [38].

X-ray diffraction (XRD) patterns were obtained using an X-ray diffractometer (EMPYREAN, Malvern Panalytical B.V., Almelo, The Netherlands). The XRD results of clay and non-clay minerals in the reservoir rocks are shown in Figure 2. Three sets of core samples were selected for analysis. The positions of the diffraction peaks were largely consistent across the samples, indicating a high degree of similarity in mineral composition. Feldspar was the dominant mineral component (46.7%), followed by quartz (22.1%). The total clay mineral content was 22.4%, with chlorite being the most abundant (53.0%), followed by kaolinite (22.0%), illite (6.7%), and mixed-layer illite/smectite (18.3%).

Crude Oil: The crude oil used in this study was obtained from the Chang 6 reservoir. Under reservoir conditions, the oil has a viscosity of 6 mPa·s and a density of 0.83 g/cm³. To ensure uniform physical properties, the crude oil was pretreated prior to use. It was first centrifuged at 7500 rpm for 2 h, followed by filtration through an 11 μm membrane to remove any solid particles. After filtration, the oil was stirred in a thermostatic water bath for 2 h to ensure homogeneity.

Table 1. SARA fraction composition of the crude oil used in the experiments.

Fraction	Saturates	Aromatics	Resins	Asphaltenes	Total
Content (%)	71.54	22.99	2.77	2.71	100.00

summarizes the saturates, aromatics, resins, and asphaltenes (SARA) composition of the crude oil sample.

Aqueous Solutions: The ionic compositions of the produced water (PW) and formation water (FW) used in the experiments are listed in

Table 2. Ionic composition of produced water and formation water.

Ion Concentration (mg·L−1)	Na+	K+	Mg2+	Ca2+	Cl−	SO42−	Salinity
PW	1702.248	111.183	676.884	1365.363	6981.288	234.108	11,071.07
FW	20,940.84	81.415	231.285	15,262.95	40,516.3	297.745	77,330.54

. Analytical-grade salts including CaCl₂, MgCl₂, KCl, NaCl, and Na₂SO₄ (Aladdin Biotech Co., Ltd., Shanghai, China) were dissolved in distilled water to prepare various PW dilution solutions (0.8 PW, 0.6 PW, 0.4 PW, and 0.2 PW), as well as the FW solution. Prior to preparation, the distilled water was degassed under vacuum for 2 h to eliminate dissolved CO₂ and avoid interference in the experiments. Based on the required ionic compositions, the corresponding amounts of chemical reagents were weighed and dissolved in the degassed distilled water. The solutions were then stirred in sealed containers for 2 h. After preparation, the solutions were filtered using filter paper and stored in airtight containers to prevent contamination by atmospheric CO₂.

2.2. Interfacial Tension Measurement

As shown in Figure 3, the pendant drop method was employed to measure interfacial tension (IFT) in this study. First, the IFT measurement instrument was powered on, and the densities of the injected water and reservoir crude oil were entered. Brine solutions with different salinities were degassed under vacuum to eliminate the influence of dissolved gases on the measurement. The test crude oil was injected into the oil reservoir of the device, and the needle was flushed. The camera lens was then adjusted to center the needle in the image frame. The droplet volume was set to 11.5 μL. Measurements were conducted continuously for 3000 s at both 30 °C and 70 °C. Each test was repeated 3 times, and the average value was taken as the final result [34,39].

2.3. Interfacial Rheology of Crude Oil/Brine Interface

In this study, an interfacial dilational rheometer was used to measure the complex dilational modulus at the crude oil/brine interface with different salinities by applying a sinusoidal area perturbation. The dilational modulus (ε, mN/m) is defined as the ratio of the change in interfacial tension (γ, mN/m) to the corresponding change in interfacial area (A, m²), as expressed in Equation (1):

$$\epsilon ={\displaystyle \frac{d\gamma }{d\ln A}}$$

(1)

It describes the resistance of the interface to deformation. For a viscoelastic interface, the dilational modulus can be expressed as a complex number:

$$\epsilon ={\epsilon }_d+i{\epsilon }_{\eta }$$

(2)

The dilational modulus ε consists of two components: the elastic modulus ε_d, which represents the energy stored during interfacial area changes, and the viscous modulus ε_η, which reflects the energy dissipated due to molecular relaxation at the interface. The interfacial dilational rheological experiments were conducted using an interfacial dilational rheometer under controlled temperatures of 30 °C and 70 °C. A syringe was used to generate an oil droplet in a quartz glass cell, with brine solutions of varying salinities (PW and its dilutions: 0.8 PW, 0.6 PW, 0.4 PW, and 0.2 PW) serving as the continuous phase. At both 30 °C and 70 °C, once interfacial adsorption equilibrium was established, a sinusoidal perturbation with a frequency of 0.1 Hz was applied to measure the dynamic elastic and dilational moduli. These measurements were used to analyze the variation in interfacial viscoelasticity with changing salinity. Each experiment was conducted 3 times, and the average value was taken as the final result.

2.4. Zeta Potential Measurements

To analyze the effect of salinity on the electrochemical properties of rock surfaces and oil–water interfaces, core samples were ground into powder with particle sizes less than 75 μm and dispersed in brine solutions of varying salinities. The mixtures were maintained at a constant temperature of 30 °C for 24 h to reach equilibrium (with a rock-to-brine mass ratio of 1%), followed by ultrasonic treatment for 3 min. The supernatant was then collected for measurement of the zeta potential at the rock/brine interface. To determine the zeta potential at the oil/brine interface, 0.5 mL of crude oil was added to 100 mL of brine and stirred at 1000 rpm for 3 h. The mixture was then subjected to ultrasonic treatment, allowed to stand, and samples were collected for testing. Zeta potential measurements were conducted using a Zeta potential analyzer (Zetasizer Nano ZS90, Malvern Panalytical Ltd., Malvern, UK) laser particle size and zeta potential analyzer via electrophoretic light scattering. Each sample was tested three times at 30 °C and 70 °C, with 100 scans per test, and the average value was taken as the final result [38,39]. Considering potential chemical reactions occurring at the rock/brine and oil/brine interfaces, the pH of each sample was measured at 30 °C and 70 °C using a PHSJ-6L digital pH meter (Leici Instrument Co., Ltd., Shanghai, China). By comparing the variations in zeta potential and pH under different salinity conditions, the influence of temperature on surface charge characteristics and the structure of the electrical double layer was evaluated.

2.5. Contact Angle Measurements

The experimental setup is illustrated in Figure 4. Selected core slices were polished using sandpaper to minimize the influence of surface roughness on wettability. The slices were then cleaned using a Soxhlet extractor. To achieve ionic equilibrium, the samples were first saturated with FW at 70 °C for one week [34,39]. Subsequently, the slices were aged in crude oil at 70 °C for approximately four weeks to establish a stable oil-wet condition. The initial wettability (θ₀ was recorded. After aging, the core slices were cleaned and dried, then immersed in brine solutions of different salinities. The samples were treated in a vacuum oven at 70 °C for 7 days to ensure thorough interaction with the solutions. A contact angle measuring instrument (SD200, Shengding Precision Instrument Co., Ltd., Dongguan, China) was used to assess wettability alteration. A 30 μL droplet of crude oil was placed on the surface of the core slice and centered under the camera. Contact angles were recorded over a duration of 600 min at both 30 °C and 70 °C. Each test was repeated 2–3 times, and the average was taken to minimize deviations caused by local mineralogical differences. The wettability alteration index (WAI) was calculated using the following Equation (3):

$$WAI={\displaystyle \frac{{\theta }_o-{\theta }_f}{{\theta }_o-{\theta }_i}}$$

(3)

Here, θ₀ represents the original wettability, θ_f is the final contact angle, and θᵢ denotes the initial wettability. A WAI value of 0 indicates no change in wettability, while a value approaching 1 signifies a complete shift from oil-wet to water-wet conditions. In the experiments, all aged rock samples exhibited an oil-wet state, with an initial contact angle of θ₀ = 136.7° ± 4°.

2.6. Crude Oil Adsorption Experiments

To quantify the effect of water quality on the adsorption of crude oil components onto rock surfaces, the following procedure was employed. Rock powder was dried at 105 °C for 12 h, and particles smaller than 75 µm were selected. The powder was then mixed with crude oil at a mass-to-volume ratio of 5:1 (10 g powder + 2 mL crude oil), placed in pressure-resistant glass bottles, and stirred to form an oil–sand mixture. The samples were aged at 70 °C for 4 weeks. After aging, 10 mL of the test water was added to each bottle. The oil–water–rock mixtures were then oscillated at 200 rpm for 24 h under two temperature conditions (30 °C and 70 °C) to reach equilibrium. After settling, the upper crude oil layer was collected for SARA analysis. Before measuring the contents of saturates, aromatics, resins, and asphaltenes, the recovered oil samples were centrifuged at 7500 rpm for 2 h to remove residual water. The analysis was conducted following the SY/T 5119-2016 standard using an IATROSCAN MK-6s thin-layer chromatography flame ionization detector (TLC-FID, Iatron Laboratories Inc., Tokyo, Japan) and an XS205DU electronic balance (Mettler Toledo, Greifensee, Switzerland) [40]. This procedure was used to evaluate how salinity and temperature affect the adsorption behavior of crude oil components on rock surfaces.

2.7. Core Flooding Experiments

As shown in Figure 5, the unsteady-state method under constant pressure was employed to evaluate oil recovery during water flooding with different salinities. To ensure consistent initial conditions across all core samples, the cores were dried at 120 °C to a constant weight before the experiment. They were then saturated with formation water (FW) to measure porosity, and soaked in FW for one week to establish ionic equilibrium. To determine permeability, FW was injected at 70 °C at various flow rates (0.05, 0.10, 0.15, and 0.20 mL/min). The pressure drop across the core was recorded, and permeability was calculated using Darcy’s law. Degassed crude oil was then injected at 70 °C at a flow rate of 0.1 mL/min until water production ceased, allowing for the determination of initial oil saturation. The cores were aged in sealed containers filled with crude oil at 70 °C for four weeks. Water flooding experiments were conducted in a core holder. Due to the tight nature of the cores, an initial production pressure differential of 18 MPa was applied, and brine solutions of varying salinities were injected at a constant flow rate of 0.1 mL/min. Both secondary and tertiary flooding stages were performed under the same flow rate and temperature conditions (70 °C) [3,41,42]. During the flooding process, pressure drop, cumulative water injection, oil production, and total oil recovery were recorded over time. The experiments were terminated when water saturation at the outlet exceeded 98%. Experimental data were analyzed using the JBN method [3,43]. During the tests, the temperature of the core holder was maintained at 70 °C, while the injected brine was kept at 30 °C to simulate the thermal effects of low-temperature water injection into a high-temperature reservoir.

2.8. Ion Chromatography Analysis

To investigate the ion exchange behavior and mineral dissolution processes between low-salinity water and tight sandstone under different temperature conditions, ion chromatography (IC) analysis was conducted in accordance with the SY/T 5523-2016 standard [44]. Cation standard solutions were first prepared at concentrations of 20 mg/L, 40 mg/L, 80 mg/L, and 100 mg/L to establish calibration curves. The experimental rock samples were derived from tight sandstone cores in the Chang 6 formation, ground to a particle size of less than 75 μm. For each test, 10 g of rock powder was mixed with 20 mL of produced water (PW) or its dilutions (0.8 PW, 0.6 PW, 0.4 PW, and 0.2 PW), and experiments were conducted under both 30 °C and 70 °C to allow for comparative analysis. All PW-based solutions were degassed under vacuum prior to use. The rock–brine mixtures were stirred in a constant-temperature shaker for 10 h, followed by standing and cooling. The suspensions were then filtered using 0.22 μm microporous membranes. The resulting filtrates were diluted 20–40 times based on ion concentration gradients to meet the detection range of the instrument. Ion concentrations of Ca²⁺, Mg²⁺, and other common cations were analyzed using a Thermo Fisher Dionex AQUION ion chromatograph. Qualitative and quantitative analyses were performed using both peak retention time and peak area methods, and final concentrations were determined using the calibration curves.

3. Results

3.1. Temperature-Dependent Behavior of Mixed Waters

In waterflooding operations, the injection of any foreign fluid other than formation water (FW) may lead to precipitation, potentially reducing oil recovery. To address this concern, the compatibility between low-temperature produced water (PW) of varying salinities and high-temperature formation water was tested. Equal volumes of PW at 30 °C and FW at 70 °C (10 mL each, mixed to obtain 20 mL of solution) were mixed in glass tubes to simulate the chemical interaction between the injected cold water and the hot formation water. The mixtures were stored in a dark chamber at 70 °C for 14 days, and precipitation was visually monitored. The results showed that no visible precipitation occurred in any of the tested combinations. Figure 6 presents the images of the PW + FW mixtures before and after compatibility testing at different salinities. As can be seen, no precipitation was observed after mixing, indicating good compatibility between PW (and its diluted versions) and the target reservoir. Thus, the risk of permeability reduction due to fluid-induced precipitation and core blockage is considered low.

3.2. Temperature Response of Oil–Water Interfacial Tension

As shown in Figure 7, temperature exerts a significant influence on the interfacial tension (IFT) of the water/oil system. An increase in temperature clearly reduces the IFT, although the overall trend with salinity remains similar. At both 30 °C and 70 °C, the IFT initially decreases with decreasing salinity, reaching a minimum value at a certain dilution level, and then increases thereafter. At 30 °C, the IFT of undiluted PW was 14.263 mN/m. As salinity decreased, the lowest IFT value of 11.574 mN/m was observed at 0.4 PW, after which the IFT increased again. At 70 °C, the IFT of PW was 11.47 mN/m, with a minimum of 9.308 mN/m at 0.4 PW, followed by an increase to 9.795 mN/m. This indicates that direct injection of low-temperature water into the reservoir can lead to an increase in capillary forces between oil and water. Capillary force is a key resistance that traps residual oil and hinders crude oil flow. Elevated capillary forces significantly reduce displacement efficiency, resulting in more oil being retained in the pore spaces and remaining unrecovered. Meanwhile, under low-temperature conditions, the ability of low-salinity water to reduce interfacial tension (IFT) is considerably weakened. Although low-salinity water at 0.4 PW still leads to a relative reduction in IFT, the minimum IFT achieved is less favorable compared to high-temperature conditions. This suggests that the oil recovery enhancement effect of low-salinity water injection becomes less effective in cold environments, thereby limiting its potential to increase production. From the perspective of enhanced oil recovery optimization, it is therefore recommended to increase the temperature of the injected water in practical field applications. Higher temperature can reduce the adverse effects of capillary forces. Moreover, selecting an appropriate low-salinity ratio under elevated temperature conditions is more effective in reducing interfacial tension and improving displacement efficiency.

Across all salinity levels, IFT values at 70 °C were consistently lower than those at 30 °C, indicating that elevated temperatures promote interfacial tension reduction. This temperature-dependent behavior may be attributed to the enhanced thermal motion of asphaltene molecules at higher temperatures, facilitating their spontaneous adsorption at the oil–water interface. This adsorption strengthens the effect of naturally occurring surface-active components, thereby reducing IFT. Additionally, the increased interaction between asphaltene molecules and salt ions at elevated temperatures may further contribute to IFT reduction. As illustrated in Figure 8, the complex interplay between salinity, temperature, and the interactions among natural surfactants in the oil phase and salt ions can explain this phenomenon [45]. Asphaltene molecules contain both hydrophilic and hydrophobic functional groups, resembling synthetic surfactants, and can spontaneously adsorb at the oil–water interface to reduce IFT [46]. With rising temperature, the activity of asphaltenes increases, and the diffusivity of salt ions also becomes more significant. The binding affinity between divalent cations (e.g., Ca²⁺ and Mg²⁺) and asphaltenes is enhanced, further reducing IFT [46]. Therefore, higher temperatures intensify the modulation of oil–water interfacial behavior, making the effect of salinity variations on IFT more pronounced. This results in more significant IFT fluctuations across different salinity levels.

3.3. Temperature-Driven Wettability Alteration

Wettability refers to the tendency of a rock surface to be preferentially covered by either oil or water when both fluids are present. In sandstone reservoirs, water-wet conditions indicate that the rock surface is predominantly covered by a thin water film, while oil is distributed in the center of the pores. This condition is generally favorable for water flooding, as the injected water can flow along the rock surface and more effectively displace the oil within the pores. In contrast, if the reservoir exhibits oil-wet characteristics, oil tends to adhere strongly to the rock surface, leading to higher residual oil saturation and reduced water flooding efficiency. Therefore, wettability is one of the key parameters that determine oil displacement efficiency and enhanced oil recovery (EOR). It plays a critical role in the design and optimization of water injection development strategies. To evaluate the effect of temperature on wettability alteration, the wettability alteration index (WAI) was calculated under various salinity conditions. As shown in Figure 9, the WAI reached its maximum at 0.6 PW at both 30 °C and 70 °C. However, temperature induced a significant change in wettability. At 30 °C, the WAI was 0.2994, and at 70 °C, it increased to 0.4647. Both values were higher than those at other salinity levels, with the WAI at 70 °C significantly exceeding that at 30 °C. Temperature variation also caused noticeable changes in pH. At both 30 °C and 70 °C, pH increased markedly as salinity decreased. Specifically, at 30 °C, the pH rose from 0.63 (PW) to 1.25 (0.6 PW), and at 70 °C, it increased from 0.76 to 1.43. As shown in Figure 10, higher pH values promote the dissociation of polar acidic components in crude oil. This increases the negative charge at the interface, strengthens electrostatic repulsion, stabilizes the water film, and promotes a transition toward more water-wet conditions. As temperature increased, the WAI increased accordingly, especially under the 0.6 PW condition. Higher temperature enhances the thermal motion between the oil and water phases, which promotes the interaction between naturally occurring surface-active molecules in crude oil, such as asphaltenes, and salt ions [47]. This facilitates more effective adsorption of these surfactants at the oil–water interface, reduces interfacial tension, and improves water-wetness. In addition, elevated temperature accelerates chemical reactions between the solution and the rock surface, such as hydrolysis, protonation, and deprotonation, thereby increasing the pH value [48]. Under high-temperature conditions, water-wetness is further enhanced, oil droplet adhesion is reduced, and the water film becomes more stable. Although the interfacial tension reached its minimum at 0.4 PW, the WAI did not peak under this condition. The highest wettability alteration was observed at 0.6 PW. This can be explained by the combined influence of salinity on ion concentration, surfactant adsorption capability, interfacial charge, and pH [49]. At 0.4 PW, the ion concentration was relatively low. Although the concentration of divalent cations such as Ca²⁺ decreased, the reduction was not sufficient to support effective adsorption of natural surfactants such as asphaltenes at the oil–water interface, which limited wettability improvement. At the same time, the rise in pH promoted dissociation of acidic components, which increased interfacial charge and further stabilized the water film. As a result, the most significant change toward water-wetness occurred at 0.6 PW.

4. Discussion

4.1. Cation Release and Interfacial Reaction Mechanism

The interaction between injected water and reservoir rocks involves ion exchange and mineral dissolution at the mineral–water interface. This process is particularly pronounced under high-temperature conditions. By comparing the changes in ion concentrations at 30 °C and 70 °C for solutions of varying salinities (FW, 0.8 PW, 0.6 PW, 0.4 PW, and 0.2 PW), it was observed that the release of Ca²⁺ and Mg²⁺ increased with rising temperature. This indicates that elevated temperatures enhance cation mobility and promote rock–fluid chemical reactions. As shown in Figure 11, in the 0.6 PW system, the concentration of Ca²⁺ increased from an initial value of 819.2 mg/L to 946.5 mg/L at 30 °C and further to 1020.8 mg/L at 70 °C. Similarly, Mg²⁺ increased from 406.1 mg/L to 470.3 mg/L at 30 °C and to 540.8 mg/L at 70 °C, corresponding to increases of approximately 25% and 33%, respectively. This thermally enhanced cation release was also observed in other systems. In the 0.8 PW solution, Ca²⁺ increased by about 10% at 70 °C compared to 30 °C. The 0.4 PW and 0.2 PW systems also exhibited significant temperature-driven cation release. In the high-salinity FW system, the concentration of Ca²⁺ increased from 1365.4 mg/L at 30 °C to 1628.5 mg/L at 70 °C, and Mg²⁺ increased from 676.9 mg/L to 782.3 mg/L. These results confirm that temperature can significantly enhance mineral dissolution and ion exchange, even under high ionic strength conditions. The overall trend in total salinity further supports this conclusion. Taking the 0.6 PW system as an example, total salinity increased from an initial value of 6642.6 mg/L to 7275.8 mg/L at 30 °C and to 7896.2 mg/L at 70 °C, suggesting that higher temperatures enhance overall dissolution processes. The release of divalent cations is closely related to the dissolution of clay minerals, such as chlorite and kaolinite, present in the core material. Elevated temperature accelerates the breakdown of these minerals, resulting in increased concentrations of Ca²⁺ and Mg²⁺ in the aqueous phase. This alters the ionic composition and strength at the rock–brine interface, affecting surface charge distribution and adsorption equilibria. These changes have a direct impact on wettability alteration, zeta potential, and the desorption of polar oil components. Notably, in low-salinity systems such as 0.2 PW and 0.4 PW, despite initially low ion concentrations, significant cation release was still observed at 70 °C. This suggests that even dilute solutions may trigger ion activation effects at the rock–water interface under thermal conditions.

From the perspective of ion release, mineral dissolution within the core is evident, and such dissolution is often accompanied by changes in the physical properties of the rock. In sandstone reservoirs, injection water with different salinity ratios can affect not only interfacial chemical reactions but also the integrity and physical properties of the rock matrix. Previous studies have shown that changes in reservoir fluid salinity can enhance the dissolution and ion exchange of clay minerals such as chlorite and kaolinite, accompanied by fine particle migration and alterations in pore structure. These processes may lead to permeability reduction or a weakening of the overall mechanical strength of the formation [10,50]. Under high-temperature conditions, mineral dissolution and ion release are further intensified. In contrast, under low-temperature conditions, the temperature difference between injected water and the formation water or rock may destabilize the water film on rock surfaces and induce changes in pore structure. Due to thermal disequilibrium, the rock skeleton is prone to localized thermal stress differentials, triggering stress–strain responses that can result in the formation and propagation of microfractures. Such low-temperature effects may accelerate microstructural degradation of the rock, reduce mechanical strength, and lead to the detachment of mineral grains that block pore throats, further decreasing permeability [51,52]. Overall, excessively low salinity or large temperature differentials may have adverse impacts on pore connectivity and the mechanical integrity of sandstone reservoirs. Therefore, in optimizing water injection formulations and operational conditions, it is essential to balance enhanced oil recovery with the maintenance of rock stability. Extreme injection conditions should be avoided to reduce the risk of rock damage and deterioration of reservoir permeability.

4.2. Zeta Potential Shift and Wettability Alteration

The surface charge at the rock/brine and oil/brine interfaces is a critical factor affecting the wettability and interfacial tension of the oil–brine–rock system. The stability of the water film, particularly that between the oil and rock surfaces, largely depends on the charge distribution at the interface [53,54]. If the charges at both interfaces are of the same sign, electrostatic repulsion occurs, which thickens the water film and promotes a water-wet state. In contrast, if the charges are of opposite signs, electrostatic attraction occurs, allowing the oil film to overcome the water film barrier and rendering the rock surface oil-wet [17]. As shown in Figure 12, both salinity and temperature significantly influence the interfacial charge behavior at the rock/brine and oil/brine interfaces in tight sandstone reservoirs. With decreasing salinity, the zeta potentials at both interfaces become more negative. This is primarily attributed to the decrease in ion concentration, particularly the reduction in divalent cations such as Ca²⁺ and Mg²⁺. At lower salinities, the lower concentration of these cations weakens the compression of the electrical double layer, resulting in a more negative interfacial charge. This trend becomes more pronounced at elevated temperatures. At 70 °C, the interfacial charge becomes increasingly negative, thereby enhancing repulsive forces between interfaces and improving the stability of the water film. The experimental results show that the zeta potential at the rock/brine interface decreases from −3.14 mV at 30 °C to −6.26 mV at 70 °C. At the oil/brine interface, the zeta potential shifts from −5.21 mV to −7.65 mV. The rise in temperature promotes ion mobility and strengthens the interactions between water molecules and the oil phase, leading to increased electrostatic repulsion across the interface. These results indicate that temperature enhances ion reactivity and increases the negative interfacial charge, which in turn stabilizes the water film. This stabilization reduces oil droplet adhesion to the rock surface, enhances water-wetness, and improves the effectiveness of water flooding. As illustrated in Figure 13, stronger water-wet conditions facilitate the detachment of crude oil from the rock surface, thereby improving displacement efficiency. Changes in pH also play an important role in determining the charge distribution at the rock/brine and oil/brine interfaces. Under low-salinity conditions, weak acidic components tend to dissociate more readily, which increases the pH and leads to a more negative interfacial charge [55]. In experiments conducted at both 30 °C and 70 °C, pH values increased with decreasing salinity. At 30 °C, the pH at the rock/brine interface rose from 7.92 (PW) to 8.19 (0.2 PW), while the pH at the oil/brine interface increased from 7.35 to 7.62. At 70 °C, the pH at the rock/brine interface increased from 7.99 to 8.43, and at the oil/brine interface, it increased from 7.42 to 7.77. Higher pH values are generally associated with increased negative interfacial charge, which contributes to improved water film stability. Elevated pH promotes the dissociation of weak acidic components, releasing more negative charges and thereby enhancing the water-wetness of the rock surface. The increase in temperature further facilitates these effects, resulting in more pronounced water-wet behavior under high-temperature, low-salinity conditions.

4.3. Interfacial Rheological Stability Mechanism

The rheological behavior of the oil–water interface plays a crucial role in oil and water transport through porous media. During the displacement process, the formation and breakup of oil droplets largely depend on the interfacial elastic modulus. A higher interfacial elastic modulus can effectively resist droplet rupture, allowing for the formation of larger droplets, thereby improving oil recovery. Figure 14 shows the variations in the elastic modulus (G′) and viscous modulus (G″) of the oil–brine interface under different temperature conditions. At lower salinity levels, the elastic characteristics of the oil/brine interface are enhanced, resulting in more stable oil droplets [17]. In addition, significant differences in interfacial moduli were observed between 30 °C and 70 °C. At 70 °C, both G′ and G″ increased as salinity decreased. Under PW conditions, the elastic modulus reached 0.0955 Pa/m and the viscous modulus reached 0.0386 Pa/m. Under 0.4 PW conditions, the elastic modulus increased to 0.137 Pa/m and the viscous modulus to 0.0518 Pa/m. These results indicate a more elastic interface, which is favorable for the formation and stability of oil droplets. However, at very low salinity, a decrease in the elastic modulus was observed, suggesting that the interface structure becomes looser, making droplets more prone to rupture and less stable. Across all conditions, the moduli at 30 °C were generally lower than those at 70 °C, particularly the elastic modulus. As temperature increased, both G′ and G″ exhibited a significant upward trend. This behavior may be attributed to enhanced interactions between asphaltene molecules in the oil phase and salt ions at higher temperatures, which promote interfacial structure formation and molecular network reorganization. A denser and more ordered interfacial structure may form under elevated temperatures, enhancing the interface’s stability and elasticity [56]. These findings demonstrate that salinity and temperature have a pronounced effect on the elastic and viscous moduli of the oil/brine interface. Figure 15 illustrates the mechanism by which viscoelastic properties influence crude oil mobility and stability. Under high-salinity and high-temperature conditions, the interfacial moduli are greater, reducing the likelihood of droplet breakup and facilitating the formation of stable droplets, which improves oil recovery. Conversely, under lower salinity and temperature conditions, smaller interfacial moduli may lead to a looser interfacial structure, decreasing droplet stability and adversely affecting oil displacement efficiency. Optimizing both salinity and temperature can result in lower interfacial tension and higher interfacial moduli, thereby maximizing oil–water interfacial stability and oil recovery. The 0.4 PW brine exhibited the most favorable interfacial characteristics, with the lowest interfacial tension and the highest elastic modulus. Low interfacial tension allows oil droplets to pass smoothly through narrow pore spaces, while high interfacial elasticity enables oil droplets to restore their shape after rupture, promoting the formation of larger droplets and improving recovery efficiency.

4.4. Desorption Mechanism of Polar Components

The adsorption–desorption behavior of polar components in crude oil, such as resins and asphaltenes, on rock surfaces plays a critical role in interfacial wettability alteration and oil displacement efficiency. In this study, SARA analysis was conducted on the produced fluids obtained under different salinity conditions (PW, 0.8 PW, 0.6 PW, 0.4 PW, and 0.2 PW) and two temperatures (30 °C and 70 °C), in order to investigate the synergistic effects of temperature and salinity on the release behavior of crude oil components. As shown in

Table 3. Effect of produced water with different salinities on crude oil desorption from rock surfaces.

Temperature	Injection Water Type	Saturates (%)	Aromatics (%)	Resins (%)	Asphaltenes (%)
30 °C	PW	74.12	21.93	2.02	1.93
	0.8 PW	73.62	22.08	2.24	2.06
	0.6 PW	73.16	22.27	2.51	2.06
	0.4 PW	73.46	22.21	2.32	2.01
	0.2 PW	73.5	22.04	2.2	2.26
70 °C	PW	73.04	22.42	2.14	2.40
	0.8 PW	72.44	22.56	2.53	2.48
	0.6 PW	71.87	22.83	2.87	2.44
	0.4 PW	72.06	22.77	2.73	2.45
	0.2 PW	72.21	22.53	2.60	2.65

and Figure 16, the desorption of crude oil components from rock surfaces exhibited clear differences under varying salinity conditions. The composition of the produced oil changed significantly depending on the salinity of the injected water, indicating that salinity strongly influences the extent to which polar components are released from the rock surface. At 70 °C, as the salinity decreased from PW to 0.6 PW, the resin content in the produced oil increased from 2.14% to 2.87%, while the asphaltene content slightly increased to 2.44%. This indicates a clear enhancement in the desorption of polar components. Meanwhile, the proportion of saturates decreased from 73.04% to 71.87%, suggesting that under elevated temperature and moderately reduced salinity, the interfacial energy is lowered and the stability of polar molecular adsorption layers is weakened. As a result, polar components are more likely to desorb from the rock surface and migrate into the aqueous phase. In contrast, under 30 °C, the overall desorption effect was significantly weaker. At 0.6 PW, the resin and asphaltene contents only increased to 2.51% and 2.06%, respectively, which were notably lower than the maximum values observed at 70 °C. This demonstrates that elevated temperature has an amplifying effect on the desorption behavior under low-salinity conditions. The underlying mechanism is that higher temperatures intensify molecular thermal motion at the oil–water interface, disrupting the adsorption structure of polar components and enhancing their mobility and dispersion in the aqueous phase. This promotes the formation of more stable oil-in-water emulsions [57,58]. Furthermore, at very low salinity (0.2 PW), neither temperature condition resulted in effective desorption. This suggests that when ionic strength is too low, the electrostatic shielding at the interface becomes insufficient, resulting in poor stability of polar molecules in the aqueous phase and an increased tendency for them to re-aggregate into the oil phase. In contrast, 0.6 PW under high-temperature conditions exhibited the most favorable desorption performance. This highlights the synergistic effect of wettability alteration and polar component desorption, jointly regulated by optimized salinity and elevated temperature.

4.5. Oil Displacement Mechanism and Strategy Optimization of Low-Salinity Water Flooding in High-Temperature Reservoirs

Based on the core data, the flow zone indicator (FZI) for the selected cores was calculated using Equation (4). The FZI represents the flow zone index of the formation. It is a parameter that reflects pore geometry and fluid-flow characteristics. It is also used to distinguish different reservoir units [59,60].

$$RQI=0.0314\sqrt{{\displaystyle \frac{k}{{\phi }_e}}}$$

(4)

According to the experimental results presented in

Table 4. Core flooding results under low-salinity water sequence (secondary–tertiary mode).

Exp.	Brines Injected (Secondary-Tertiary Mode)	Porosity (vol %)	Kabs (mD)	FZI (µm)	Sw (%)	Oil Recovery (% of OOIP)	Optimality Condition
1	PW	12.4	0.67	0.1413	36.25	26.55	Base Case
2	0.4 PW	12.6	0.65	0.1442	36.11	29.51	Fluid/Fluid
3	0.6 PW	12.5	0.66	0.1429	36.19	32.41	Rock/Fluid
4	0.4 PW − 0.6 PW	12.4	0.64	0.1413	36.18	29.55 + 4.81 = 34.36	Fluid/Fluid + Rock/Fluid
5	0.6 PW − 0.4 PW	12.8	0.63	0.1468	36.05	32.38 + 2.51 = 34.89	Rock/Fluid + Fluid/Fluid
6	PW − 0.4 PW − 0.6 PW	12.4	0.68	0.1413	36.24	26.46 + 3.66 + 3.16 = 33.28	Fluid/Fluid + Rock/Fluid
7	PW − 0.6 PW − 0.4 PW	12.7	0.67	0.1454	36.20	26.77 + 5.44 + 2.25 = 34.46	Rock/Fluid + Fluid/Fluid

and Figure 17, all core samples exhibited FZI values ranging from 0.1413 μm to 0.1468 μm. This indicates that the cores are representative of typical tight sandstones, belonging to the same flow unit and sharing similar structural characteristics. Therefore, the oil recovery efficiency under different salinity waterflooding conditions can be directly compared. During primary waterflooding, 0.4 PW yielded a recovery factor of 29.51%, which is 2.96% higher than that of PW (26.55%). This suggests that at this salinity, favorable fluid–fluid interactions contribute to improved oil recovery. At 0.6 PW, oil recovery reached 32.41%, an increase of 5.86% compared to PW. This indicates that rock–fluid interactions play a more dominant role in enhancing oil displacement under moderate salinity conditions. These results align with the contact angle measurements, where 0.6 PW showed the highest WAI, suggesting that improved water film stability and increased water-wetness are the main contributors to enhanced recovery.

The optimal performance observed under the 0.6 PW condition can be further attributed to the synergistic effects of ion release, pH increase, and electric double-layer interactions. The ion chromatography results indicate that when the temperature increases from 30 °C to 70 °C, the release of divalent cations (Ca²⁺ and Mg²⁺) is enhanced, accompanied by an increase in solution pH. The combined effect of ion release and pH elevation promotes the dissociation of acidic polar components in the crude oil, leading to an increase in negative charge at both the oil–brine and rock–brine interfaces. This enhanced interfacial negativity strengthens electrostatic repulsion, which in turn stabilizes the water film and promotes a transition toward a more water-wet state. Therefore, the integrated effect of ion release, pH increase, and electrostatic repulsion provides a favorable interfacial environment, resulting in the most significant wettability alteration and the highest oil recovery under moderate salinity conditions.

In contrast, although 0.4 PW achieved the lowest interfacial tension (IFT), which reduced interfacial energy and improved oil mobility, its relatively weak rock–brine interactions limited further improvements in recovery. The results of sequential flooding further reveal the synergistic effects between fluid–fluid and rock–fluid mechanisms. When 0.4 PW was followed by 0.6 PW, the total oil recovery reached 34.36%, which is 4.85% higher than using 0.4 PW alone. In this case, 0.4 PW initially reduced the IFT and disrupted the oil–water interfacial structure, while 0.6 PW subsequently enhanced wettability and stabilized the water film, leading to a combined effect that improved oil recovery. Conversely, when 0.6 PW was followed by 0.4 PW, the total recovery reached 34.89%, representing a 2.48% improvement over standalone 0.6 PW injection. This relatively smaller gain suggests that once rock–fluid interactions are initiated, the additional benefit from subsequent fluid–fluid effects becomes limited. Multi-stage flooding schemes starting with PW showed more limited performance compared to optimized two-stage designs. In the sequence where 0.4 PW was injected after PW, followed by 0.6 PW, the total recovery reached 33.28%. In the sequence of PW followed by 0.6 PW and then 0.4 PW, the total recovery was 34.46%. Although both approaches improved recovery compared to PW alone (by 6.82% and 7.69%, respectively), their performance was inferior to direct 0.6 PW flooding or the two-stage scheme of 0.4 PW followed by 0.6 PW. Moreover, these multi-stage schemes required significantly longer injection times and larger water volumes, reducing their economic feasibility. During the initial PW flooding stage, high salinity resulted in higher IFT and weaker water-wet conditions. As a result, early-stage displacement relied mainly on viscous drive, and the low-salinity effect was not sufficiently activated, limiting the overall improvement in oil recovery. Therefore, in practical low-salinity waterflooding applications, it is recommended to use 0.6 PW for primary injection, followed by 0.4 PW in a secondary stage. Costly and low-yield multi-stage mixed flooding schemes starting with PW should be avoided in order to maximize recovery while maintaining economic efficiency.

This study focuses on the impact of temperature on the effectiveness of low-salinity water flooding, as illustrated in Figure 7. The experimental results demonstrate that temperature is a critical factor controlling enhanced oil recovery. Higher temperatures, such as 70 °C, significantly reduce the interfacial tension across all salinity levels by enhancing the thermal motion of asphaltene molecules and their interactions with ions. Temperature also improves water-wetness on the rock surface and strengthens the oil–water interfacial properties. However, the injection of low-temperature water introduces a significant thermal gradient. Although our laboratory core flooding experiments did not directly investigate oil recovery variations under different injection temperatures, the simulations of low-temperature low-salinity water injected into high-temperature cores still achieved enhanced oil recovery. It is worth noting that temperature differentials may induce thermal stress in the rock, potentially leading to reservoir damage. Nonetheless, in the core flooding simulations, such effects did not diminish the EOR benefits of LSWF. In contrast, increasing the injection temperature can further enhance water-wetness, reduce IFT, improve interfacial rheology, and promote the desorption of crude oil from the rock surface. Therefore, fully isothermal injection at reservoir temperature is expected to yield higher oil recovery. To maximize the effectiveness of LSWF, an optimal injection strategy should integrate both salinity and temperature optimization. Preheating the low-salinity water to reservoir temperature prior to injection can fully leverage the physicochemical advantages of high-temperature oil–water–rock interactions while avoiding the potential formation damage associated with thermal gradients. This approach may achieve the most effective development outcome.

4.6. Combined Effects of Temperature and Salinity

To further elucidate the combined effects of salinity and temperature on oil recovery, a correlation analysis was conducted based on the core flooding results. As shown in Figure 18, under the condition of 70 °C, oil recovery first increases and then decreases with decreasing salinity, reaching the optimum at 0.6 PW. This trend closely matches the variation in the wettability alteration index while showing a relatively weaker correlation with interfacial tension, indicating that wettability alteration plays a dominant role in enhancing oil recovery with changing salinity.

Meanwhile, elevated temperatures significantly amplify the low-salinity effect. Under high-temperature conditions, the surface charge at the rock–fluid interface becomes more negative, which stabilizes the water film and promotes a transition toward a water-wet state. The elastic and viscous moduli of the oil–water interface increase, resulting in a denser and more stable interfacial structure that facilitates crude oil desorption and sustained transport. Additionally, interfacial tension is reduced, weakening the adhesive forces between oil droplets and pore walls. The variation in the WAI shows strong consistency with oil recovery, further confirming that wettability improvement is the primary mechanism driving enhanced displacement efficiency. Moreover, the release of divalent cations is intensified at elevated temperatures, promoting mineral dissolution and ion exchange that further modify the interfacial environment. The increase in system pH enhances the dissociation of hydrophilic functional groups, accelerating the desorption of polar components from the rock surface. These processes are coupled under high-temperature conditions and work synergistically to improve oil–water–rock interactions. As a result, crude oil desorption and mobilization are significantly enhanced, leading to a notable increase in oil recovery.

In summary, the effects of salinity and temperature on oil recovery are not independent. An increase in temperature can significantly enhance the oil displacement efficiency of low-salinity water. Conversely, under cold injection conditions, the low-salinity effect is suppressed, and the improvement in recovery is limited. Under high-temperature conditions, the low-salinity effect can be fully realized, and moderate salinity levels (0.4–0.6 PW) result in optimal oil displacement performance. Therefore, in practical water injection operations, low-salinity water preheated to reservoir temperature should be employed to avoid the adverse effects of cold injection and to maximize the synergistic benefits of temperature and salinity.

5. Conclusions

This study systematically investigated the influence of temperature on low-salinity water flooding mechanisms in tight sandstone reservoirs through a comprehensive set of experimental methods, including ion chromatography, interfacial tension testing, wettability measurement, zeta potential analysis, interfacial rheology, and core flooding experiments. The main conclusions are as follows:

(1)

Elevated temperature significantly enhances mineral dissolution and cation exchange, particularly releasing Ca²⁺ and Mg²⁺ from the rock surface. At 70 °C, the concentration of these divalent ions increased by up to 33% compared to 30 °C, indicating intensified rock–fluid interactions and improved wettability modification.

(2)

Temperature reduces oil–water interfacial tension across all salinity conditions. The minimum IFT value of 9.308 mN/m was achieved at 70 °C with 0.4 PW salinity. High temperature facilitates the migration of asphaltenes and enhances ion binding capacity, resulting in a more stable oil–water interface.

(3)

The combination of 70 °C and 0.6 PW salinity yields optimal wettability alteration, with the highest wettability alteration index and most favorable zeta potential values. Temperature accelerates the development of negative interfacial charge, stabilizes the water film, and promotes a stronger water-wet rock surface.

(4)

The synergistic effect of temperature and optimized salinity simultaneously enhances interfacial rheological properties and promotes desorption of polar components (resins and asphaltenes). The increased elastic modulus and improved desorption behavior contribute significantly to enhanced oil displacement efficiency.

(5)

The sequential injection strategy employing 0.6 PW followed by 0.4 PW at 70 °C achieved the highest oil recovery (34.89%), substantially outperforming both high-salinity and ultra-low-salinity flooding scenarios. This demonstrates the critical importance of combining temperature optimization with salinity management for effective enhanced oil recovery in tight sandstone formations.