Synergistic emulsification of polyetheramine/nanofluid system as a novel viscosity reducer of acidic crude oil

The surfactant was AEG (effective purity of 50%), obtained from Shandong Yousuo Chemical Technology Co., Ltd. (Linyi, China). The amine organic alkali, Polyetheramine D230 and D400, and SiO₂ nanoparticles (A200, MZ32090, R974 and R805) were from McLean Biochemical Technology Co., Ltd. (Shanghai, China). The simulated formation water was provided by Shengli Oilfield from Qinghe oil production plant, with the following chemical content: CaCl₂ 222 mg/L, MgCl₂ 128 mg/L, NaHCO₃ 551 mg/L, Na₂SO₄ 3550 mg/L, NaCl 4688 mg/L.

H₂SO₄ (mass concentration of 98%), H₂O₂ (mass concentration of 30%), silane coupling agent dimethyl octadecyl silane, and toluene, were purchased from Sinopharm Chemical Reagent Co., Ltd. (Shanghai, China). All other reagents were analytically pure. The low-permeability artificial core was purchased from Hanjing Experimental Equipment and Instruments Co., Ltd. (Beijing, China; permeability 7.3 MD, porosity 15%, height 50 mm, diameter 25 mm). Crude oil samples (1^#, acidic crude oil; and 2^#, ordinary low-acidic crude oil) were obtained from Shengli Oilfield (with a reservoir temperature of 50◦C), and their properties were shown in Table 1. The 2^# ordinary crude oil was only used to verify the effectiveness of nanofluids emulsification of low-acidic crude oil, all other subsequent experiments were carried out using 1^# acidic crude oil.

Main instruments used in this study were listed: including Viscometer HAAKE viscotester E (Thermo Fisher, USA), Rotating drop interfacial tensiometer (TX500C, Corona Industries, USA), Contact angle analyzer Tracker (Teclis Scientific, France), Multifunctional incubator (IVC-II, Major Science, USA); constant temperature magnetic stirrer (Df-101S, Ketai Experimental Equipment Co., Ltd, Zhengzhou, China) high power magnetic stirrer (84-1, Guangming Instrument Co., Ltd, Juancheng, China), ultrapure water system (Puxi General Instrument Co., Ltd., Beijing, China), and a BK-POL 1901134 optical microscope (OPTEC, Chongqing, China).

To explore the viscosity reduction effects of the novel viscosity reducer, a systematic optimization approach was employed. The three key components, surfactant AEG, SiO₂ nanoparticles, and polyetheramine, were initially mixed with an aqueous phase at varying concentrations. For AEG, the concentration range was set at 0.1–1.0 wt%, SiO₂ at 0.01–0.1 wt%, and for polyetheramine at 0.1–1.0 wt%. Each mixture was stirred using a magnetic stirrer at 500 r/min for 30 min to make the mixture evenly.

For viscosity analysis, acidic crude oil (sample #1) was mixed with the viscosity reducer at a mass ratio of 7:3, and placed in a constant temperature magnetic stirrer at 50◦C standby for 30 min. Subsequently, the mixture was stirred at 300 r/min for 5 min to obtain the acidic crude oil emulsion. The viscosity of the emulsion was measured using a HAAKE viscometer at 50◦C, and a standardized shear rate at 6 r/min. After the indication was stabilized, ten continued measurements were averaged to obtain a reliable viscosity value of the acidic crude oil emulsion. The same procedure was applied to prepare and analyze the viscosity of emulsion for ordinary crude oil using sample 2^#, with the same measure method above.

To measure the stability of the emulsion, each crude oil emulsion was transferred to a measuring cylinder and placed in an incubator at 50◦C for standing. After 1, 5, 10 and 30 minutes respectively, the creaming (water separation) in the lower layer was observed and recorded every half hour over a 30-minute period. The dehydration in the lower layer at the same time among different groups indicated the stability of the crude oil emulsion. The dehydration rate was calculated as the volume of creaming water in the lower layer relative to the total water content. A higher dehydration rate indicated lower stability of the crude oil emulsion.

To create the oil phase, acidic crude oil (1^#) and toluene were mixed in a mass ratio of 2:1. Interfacial tension was measured using an interfacial tension meter at room temperature under 5000 r/min. Interfacial tension values were determined for single surfactant solution, polyetheramine aqueous solution, nanofluid, polyetheramine nanofluid solutions against the oil phase.

Considering quartz sand as the predominant component in minerals, quartz flakes were used to simulate mineral surfaces with varying properties of wettability. The quartz flakes were divided into hydrophilic, hydrophobic and original groups with different surface modification treatments.

An acidification solution was prepared by mixing 98% H₂SO₄ with 30% H₂O₂ in a volume ratio (v/v) of 3:1. Then the original quartz flakes were then immersed in the acidification solution for 2–3 days until no bubbles were generated, to ensure the complete exposure of silicon hydroxyl groups on the surface of quartz flakes. Subsequently, the quartz flakes were washed repeatedly with deionized water to remove the acidification solution until neutral, and then dried to obtain hydrophilic quartz flakes.

The obtained hydrophilic quartz flakes were immersed in a solution prepared by mixing dimethyloctadecylsilane and toluene in a mass ratio of 1:10 (w/w) for 24 h. Then the surface was washed repeatedly with chloroform and acetone and dried to obtain the alkylated hydrophobic quartz flakes. A layer of acidic crude oil 1^# was coated on the surface of these three types of quartz flakes and air dried in an incubator at 50◦C for 7 days to better simulate the surface of formation minerals.

Subsequently, the dried quartz flakes were immersed in the viscosity reducer solution to observe the stripping effect of the viscosity reducer on the adhesion of acidic crude oil on minerals with different wettability. The water contact angle on the surface of the quartz flakes under different conditions was measured to characterize the changes in different wettability.

The contact angles of deionized water droplets on the three different wettability’s quartz flakes coated with a layer of acidic crude oil 1^# were measured using the pendant-drop method with a contact angle analyzer. In brief, a small droplet of deionized water was placed on the surface-modified quartz flakes, and the contact angle between the droplet and the surface was measured. A contact angle greater than 90◦ indicated an oilwet surface, while a contact angle less than 90◦ represented a water-wet surface.

An artificial core with a permeability of 7.3 MD was selected and placed in a 100◦C incubator for 24 h to remove the water. After drying, the initial weight (M₀) was weighed. The dried core was then immersed in acidic crude oil 1^# under vacuum condition at 50◦C for 7 days to saturate it. Then, the excess crude oil on the surface was wiped off, and weighed again (M₁). Subsequently, the treated core was placed in an Amott cell, and soaked in the viscosity reducer solution that prepared using simulated formation water, and immersed in formation water for 15 days, with the temperature maintained at 50◦C. After the soaking period, the core was dried in a 110◦C incubator and weighed (M₂) to calculate the recovery rate, which is calculated by the numerical difference between M₁ and M₂, divided by the numerical difference between M₁ and M₀.

The effectiveness of the viscosity reducer in emulsifying and stabilizing acidic crude oil emulsions strongly depends on the individual concentrations of its components. We investigated the effects of varying concentrations of AEG and SiO₂ nanoparticle within the nanofluid on the emulsification of acidic crude oil.

Effect of AEG concentration was shown in Figure 1. The viscosity of acidic crude oil emulsion gradually decreased with an increase in AEG concentration, while natural dehydration rate only slightly decreased. However, when the AEG concentration reached 1.0 wt%, the crude oil emulsion exhibited noticeable creaming after standing for 5 min, with a dehydration rate exceeding 50% after standing for 30 min. Studies have shown that, excessively rapid demulsification during oil extraction can lead to pore throat plugging, given the finite certain time required for crude oil emulsion [37]. Therefore, optimizing the system for a balance between efficient emulsification and acceptable stability is critical for effective oil recovery.

Fig. 1.

To address the stability concerns with high AEG concentrations, we incorporated SiO₂ nanoparticles into the 0.5 wt% AEG solution. However, as demonstrated in Figure 2a, the increasing of SiO₂ concentration did not significantly enhance the stability of acidic crude oil emulsion. To explore whether the unexpected results was due to the high acidic content in acidic crude oil, a comparative study for emulsification and viscosity reduction was conducted using sample 2^# ordinary crude oil (acid value of 0.43 mg KOH/g), and the viscosity reducer was composed of AEG concentration of 0.5 wt%, SiO₂ concentration of 0.05 wt%. Interestingly, the prepared nanofluid successfully emulsified ordinary crude oil (samle 2^#), and exhibited no noticeable creaming within 30 min (Fig. 2b). Moreover, the resulting emulsion showed lower viscosity (100.7 mPa· s), compared to that of the acidic oil. Therefore, it can be concluded that the nanofluid formula demonstrates effective emulsification and viscosity reduction effect only for ordinary crude oil, while the acidic crude oil cannot be emulsified into stable emulsion using this formula.

Fig. 2.

Our initial observations revealed that the presence of high acidic groups in acidic crude oil reduces the activity of nanofluids, and hinders the stabling effect of emulsion, limiting the enhancement of acidic crude oil recovery. To address this issue and improve the stability of the crude oil emulsion, we introduced a low-toxicity polyetheramine (D230) into the system, to react in situ with the acid groups to form new surfactant or active soaps, thereby improving the properties of the oil-water interface, and the stability of acidic crude oil emulsion.

To optimize the formulation, we investigated the influence of D230 concentration on emulsification and stability of the acidic crude oil (sample 1^#) emulsion. As shown in Figure 3, increasing D230 concentration led to a progressive decrease in both viscosity (reaching a minimum of 129.6 mPa·s was achieved at a concentration of 0.7 wt%.) and dehydration rate. This confirms the effectiveness of D230 in promoting stability. Based on these results, we select a final formulation of viscosity reducer containing 0.5 wt% AEG, 0.05 wt% SiO₂, and 0.7 wt% polyetheramine D230, for further analysis.

Fig. 3.

Subsequently, the interfacial tension between different components and acidic crude oil was tested. As shown in Figure 4, the D230 synergetic nanofluid further reduced the interfacial tension to 10^-2 mPa·s. This reduction can be attributed to the addition of D230, which increased the pH of the aqueous phase, thus promoting the dissociation and migration of acidic groups from the oil phase to the oil-water interface. This observation aligns with the findings reported in a previous study [30]. D230 can react with these acidic groups to form active substances. Based on previous reports, these active substances along with the added hydrophilic nanofluids, effectively reduce the interfacial tension, form an orderly arrangement on the oil-water interface, and enhance the strength of the interfacial film. Consequently, the stability of the crude oil emulsion is significantly improved [38, 39]. Moreover, as the concentration of D230 increases, a greater number of active substances are formed. This leads to continuous enhancement of the strength of the interfacial film and a gradual reduction in dehydration rate, consistent with related research [36, 40].

Fig. 4.

The efficient emulsification of acidic crude oil is significantly influenced by the surface wettability and particle size of nanoparticles [23]. Therefore, the effects of SiO₂ nanoparticles with varied hydrophobic, hydrophilic characteristics and particle sizes on acidic crude oil emulsification were studied.

As shown in Table 2 and Figure 5, two hydrophobic SiO₂ nanoparticles (R974 and R805) exhibited ineffective emulsification, failed to emulsify acidic crude oil (Fig. 5A, B). Conversely, two hydrophilic SiO₂ nanoparticles (A200 and MZ32090) exhibited effective emulsification of acidic crude oil (Fig. 5C). Notably, the acidic crude oil emulsion with the smaller particle size nanoparticle (A200) displayed more stability, compared to the larger particle size nanoparticle (MZ32090) (Fig. 5D). This can be attributed to the interplay between surface properties and particle size. The strong hydrophilicity of AEG hampered its adsorption onto the hydrophobic surface of SiO₂, hindering effective emulsification at the oil-water interface. In contrast, for the hydrophilic nanoparticles, the smaller particle size indicated higher specific surface area, providing more active and adsorption sites for interaction with AEG, facilitating stronger and more stable adsorption [41]. This contribute to a more firm combination of these particles with AEG, ultimately lead to a more robust and persistent acidic crude oil emulsion.

Fig. 5.

To investigate the influence of alkali types on the stability of the system, viscosity reducers were prepared using polyetheramine D230 and D400 (with different molecular weights), and NaOH (inorganic alkali). All alkalis were used at 0.7 wt%, based on the optimal D230 concentration previously determined.

The results demonstrated that the viscosity reducer prepared with polyetheramine D230 and D400 exhibited a lower pH (10.89 and 10.82) and a lower viscosity of emulsion (129.6 and 109.6 mPa·s), compared to that prepared with NaOH (pH 12.62, viscosity of emulsion 133.7 mPa·s), as shown in Table 3. The viscosity reducer prepared with NaOH with a higher pH, result in a higher in the viscosity of the acidic crude oil emulsion, while it lead to a significant improvement in emulsion stability (Fig. 6). However, during practical application, the injection of NaOH can lead to the formation of inorganic scale caused by divalent ions such as Ca²⁺ and Mg²⁺ in formation water, potentially resulting in pore throat blockage and hindering oil flow. Moreover, as reported in previous studies, NaOH can alter the charges on the rock surface, leading to the dispersion and migration of formation clay [36, 42, 43]. In addition, excessive stability of emulsion is not conducive to the subsequent demulsification and separation that crude oil needs to undergo after being extracted from underground [44]. These effects are detrimental to the improvement of oil recovery. Therefore, new nanomaterials together with alkali has been explored for improving this [23]. In practical applications, the organic alkali polyetheramine has become a better choice due to its low toxicity and does not cause precipitation [36]. It can act as a synergistic agent [45] to achieve the objective of enhancing oil recovery.

Fig. 6.

Given the complex nature of the formation environment, and salt ions in formation water as the significant factors affecting the properties of emulsion, the influence of salinity on the effect of viscosity reducers for acidic crude oil emulsion was explored.

The findings (Fig. 7, Table 4) revealed that the presence of simulated formation water and low salinity levels of Na+ enhanced the stability of the acidic crude oil emulsion. However, even at a low concentration (5000 ppm), the presence of divalent Ca²⁺ accelerated the demulsification rate of the acidic crude oil emulsion. This can be attributed to the fact that an appropriate amount of salt ions neutralized a portion of the negative charge, maintaining an ideal range for electrostatic repulsion. Consequently, the active substances can accumulate more closely and orderly at the interface when the hydrophilicity and lipophilicity are at moderate levels.

Fig. 7.

Nevertheless, compared to monovalent Na⁺, divalent Ca²⁺ exhibited stronger interaction with the head group of the surfactant. This causes the surfactant to change from a flat state to a curly state at the oil-water interface, which failed to completely cover the oil-water interface, and ultimately leading to emulsion demulsification [46, 47].

After a 24-hour immersion in the viscosity reducer, it was observed that the degree of acidic crude oil stripping from the surface of quartz flakes varied based on their wettability (Fig. 8). The stripping effect of acidic crude oil on the surface was as follows: hydrophilic surface > untreated surface > hydrophobic surface. This observation indicated that the viscosity reducer effectively facilitated the stripping of acidic crude oil adhering to mineral surfaces with different wettability, which is conducive to improving oil recovery.

Fig. 8.

To replicate the conditions of underground oil displacement more accurately, the core imbibition experiment was carried out to select the viscosity reducer formulation. It is found that (Fig. 9; Table 5), the final recovery rate of the oil soaked with the viscosity reducer reached 49.4%, nearly double that of the pure formation water immersion system. This finding consistents with relevant studies that the addition of organic alkali D230 and the acidic components in crude oil form active substances in situ [36, 45]. These active substances, in conjunction with nanofluids further reduce the oil-water interfacial tension, leading to increased emulsification and dispersion of acidic crude oil in the aqueous phase. On the other hand, similarly with relevant studies, nanofluids can also change the mineral surface from oil wetting to water wetting [23, 24, 48], resulting in the detachment of more oil films. Overall, the screening of viscosity reducer formula has a certain potential for enhanced oil recovery.

Fig. 9.