Preparing and Characterizing Nano Relative Permeability Improver for Low-Permeability Reservoirs

Abstract

Aiming at the problems of insufficient natural productivity and large seepage resistance in low-permeability oil and gas reservoirs, a nano relative permeability improver based on nano SiO₂ was developed in this study. The nano relative permeability improver was prepared by the reversed-phase microemulsion method, and the formula was optimized (nano SiO₂ 5.1%, Span-80 33%, isobutanol 18%, NaCl 2%), so that the minimum median particle size was 4.2 nm, with good injectivity and stability. Performance studies showed that the improvement agent had low surface tension (30–35 mN/m) and interfacial tension (3–8 mN/m) as well as significantly reduced the rock wetting angle (50–84°) and enhanced wettability. In addition, it had good temperature resistance, shear resistance, and acid-alkali resistance, making it suitable for complex environments in low-permeability reservoirs.

1. Introduction

The commonly used solution for typical low-permeability oil and gas reservoirs such as the Kela Meili gas field or Zhongjia gas field, which suffer from insufficient natural production capacity, low formation porosity, poor permeability, and high permeability resistance, is to use relative permeability improvers to adjust the relative permeability of the oil, water, and gas in the reservoir, selectively block the water flow channels, and improve the flow capacity of the oil and gas phases, thereby optimizing oil and gas production efficiency [1,2]. At present, glucose, xanthan gum, cationic polymers, and polyacrylamide polymers are commonly used as relative permeability improvers. However, such improvers are generally only used in high-permeability reservoirs and do not easily enter the small pores of low-permeability oil and gas reservoirs or meet the water control requirements of low-permeability gas reservoirs. Therefore, new types of relative permeability improvers need to be developed for low-permeability oil and gas reservoirs [3,4,5,6]. Due to their small particle size, multiple surface activation centers, and excellent surface and volume effects, nanoparticles can be used as relative permeability improvers. For example, nanoparticles can adsorb on rock surfaces, greatly reducing oil–water interfacial tension, changing rock wettability, reducing formation water flow resistance, and improving the permeability of rock cores [7,8]. However, most of the nanomaterial particles are rigid and do not easily disperse stably. In low-permeability oil and gas reservoirs, they may agglomerate and cause blockage, leading to reservoir damage. Moreover, nanoparticles are easily affected by reservoir temperature, acidity, and alkalinity. Therefore, developing a novel relative permeability improver that combines nano-scale injectability, long-term stability, and high-efficiency interfacial control capability is crucial for enhancing the development efficiency of low-permeability oil and gas reservoirs. Nano SiO₂ can be adsorbed on pore surfaces through electrostatic interactions [9], hydrogen bonding [10], Brownian motion [11], and other methods, breaking through hydration layers or oil layers, changing the wettability of core walls and oil–water phase permeability. Currently, nano SiO₂ is mainly used as an oil displacement agent at home and abroad, and research on nano SiO₂ as a relative permeability improver has mainly focused on field applications. There is relatively little systematic research on nano SiO₂ relative permeability improvers. Abbas [12] studied the effect of nanofluids on spontaneous water infiltration into oil–water carbonate reservoir cores in order to improve crude oil recovery. Research has shown that nanofluids can reduce oil–water interfacial tension, change rock wettability, promote capillary infiltration, and thus improve crude oil recovery. M Al Shargabi [13] studied the mechanisms through which nanoparticles affect CO₂-EOR, including stabilizing CO₂ foam, changing rock wettability, and reducing interfacial tension, and successfully applied the synergistic effect of SiO₂ nanofoam and CO₂ to a Middle East carbonate reservoir on improving oil recovery and reducing gas channeling. Y Zhou [14] studied the effect of SiO₂ nanoparticles with different particle sizes on enhanced oil recovery (EOR) in medium-permeability reservoirs and focused on analyzing the mechanism through which nanoparticle size affected wettability changes, interfacial tension (IFT), imbibition efficiency, and oil displacement. The influence of SiO₂ nanoparticle size on EOR in medium-permeability reservoirs was systematically analyzed, but the findings do not apply to low-permeability reservoirs.

In this study, we used a reversed-phase microemulsion method to develop a nano relative permeability improver with SiO₂ nanoparticles as its core material. The synergistic effect of Span-80 and isobutanol allowed for control over nanoparticle dispersion, resulting in an ideal median particle size of 4.2 nm, successfully avoiding the pore-throat blockage risks associated with traditional nanofluids in low-permeability reservoirs. Furthermore, the improver has excellent stability under harsh reservoir conditions such as elevated temperatures (up to 90 °C), high salinity (60,000 ppm), and wide pH ranges (3–8), overcoming nanomaterial instability challenges in complex subsurface environments. Research showed that this relative permeability improver can be easily injected into low-permeability to ultra-low-permeability tight oil and gas reservoirs and exists stably. In addition, this relative permeability improver has low surface tension, interfacial tension, and good wettability, facilitating the displacement of oil and gas flow and improving the development efficiency and economic benefits of low-permeability oil and gas reservoirs.

2. Preparation of Nano Relative Permeability Improver

Hydrophobic nano-SiO₂ (average particle size: 1–16 nm, purity: 99.8%) was purchased from Wacker Chemie AG in Munich, Germany. Sorbitan monooleate (Span-80) and isobutanol were provided by Sinopharm Chemical Reagent Co., Ltd. (Shanghai, China). Diesel oil was supplied by China Petrochemical Corporation, and deionized water was self-made in the laboratory.

The nano relative permeability improver was prepared using a reversed-phase microemulsion method [15,16]. Specifically, hydrophobic nano SiO₂ and emulsifier Span-80 were sequentially added to diesel oil at room temperature (25 ± 1 °C) and mixed uniformly using a mechanical stirrer at 500 rpm. The mixture was then ultrasonically dispersed for 30 min. Subsequently, isobutanol and NaCl aqueous solution were slowly added while maintaining high-speed stirring at 500 rpm. After stirring uniformly, we continued the ultrasound for 30 min to obtain the final nano relative permeability improver. Throughout the preparation, the mass ratio of diesel oil to NaCl aqueous solution was maintained at 1:2. The preparation method is shown in Figure 1. The size of the nanoparticles and the quality of the surfactants and other additives during the preparation process had an impact on the particle size and distribution of relative permeability improver. In order to further optimize the particle size distribution of lotion, studies were carried out on each additive respectively.

2.1. Single Factor Experimental Analysis

For the preparation method of the nano relative permeability improver, the experimental factors included nano SiO₂ and Span-80. The contents of isobutanol and NaCl were analyzed in detail to determine the median particle size of the nano relative permeability improver when the content of each factor changed. All reported particle size data represent the averages of three independent measurements, with relative variations consistently below 5%.

Figure 2 shows that when the SiO₂ content is less than or equal to 9.3%, the median particle size of the nano relative permeability improver solution is less than 6.3 nm and the solution does not show obvious stratification. When the content is more than 9.3%, obvious stratification occurs. When the Span-80 content is less than or equal to 16%, the median particle size of the nano relative permeability improver solution is more than 12.5 nm, and delamination occurs. When the Span-80 content is less than 33%, the median particle size of the nano relative permeability improver solution is less than 7.7 nm, and no significant delamination occurs. For isobutanol and NaCl, their effects on the solution of nano relative permeability improver are relatively small. When the isobutanol content is between 3 and 30% and the NaCl content is between 1 and 10%, the median particle size of the nano relative permeability improver solution is less than 8 nm, and both are stratified. Among them, when the isobutanol content is 18% and the NaCl content is 2%, the median particle size of the nano relative permeability improver solution is the smallest.

Analysis shows that the contents of SiO₂ and Span-80 have a significant impact on the solution of the nano relative permeability improver. In order to further analyze the influence of SiO₂ and Span-80 contents on the solution of the nano relative permeability improver, bivariate analysis was used to investigate the effect of their content on the solution.

2.2. Two-Factor Experimental Analysis

According to the analysis in Figure 3, when the SiO₂ content is between 1% and 9.3%, and the Span-80 content is between 33% and 45%, the nano relative permeability improver solution is stratified. Therefore, further analysis of the effect of the combination of the two factors on the solution of the nano relative permeability improver was conducted in this range, and the analysis results are shown in Figure 3. All reported particle size data represent averages of three independent measurements, with relative variations consistently below 5%.

In the comprehensive analysis of both the SiO₂ and Span-80 factors, with a fixed Span-80 content, the median particle size of the nano relative permeability improver solution first decreases and then increases with the increase in SiO₂ content. When the SiO₂ content is 5.1%, the median particle size of the nano relative permeability improver solution is the smallest. When the SiO₂ content is fixed, the smaller the Span-80 content, the smaller the median particle size of the nano relative permeability improver solution. When the Span-80 content is 33%, the median particle size of the nano relative permeability improver solution is the smallest.

Based on the above, it can be concluded that the optimal formula for the solution of the nano relative permeability improver is 5.1% nano SiO₂, a surfactant Span-80 content of 33%, a co-surfactant isobutanol content of 18%, and a NaCl content of 2%. The minimum median particle size of the nano relative permeability improver solution is 4.2 nm.

In order to further test the structure, particle size, and distribution of the optimized formula for the nano relative permeability improver, infrared spectroscopy and a particle size analyzer were used to test the functional group structure and particle size distribution range of the improver, allowing the analysis of the mechanisms of nano relative permeability improver.

Figure 4 shows that the nano relative permeability improver contains hydrophilic groups such as hydroxyl (2938 cm⁻¹), C=O (2780 cm⁻¹), and C-O (1480 cm⁻¹), as well as hydrophobic groups such as Si-O-Si (1130 cm⁻¹) and C-H (1750 cm⁻¹). The hydrophilic groups enable the improving agent to be uniformly dispersed in the aqueous phase and adsorb on the surface of hydrophilic rocks, while the hydrophobic group enhances its permeability by changing the wettability of the rock surface, thereby achieving the efficient regulation of oil reservoirs. Figure 5 shows that the particle size distribution range of the nano relative permeability improver is between 1 and 30 nm, with a relatively uniform distribution, and a median particle size of 4.2 nm.

3. Research on the Performance of Nano Relative Permeability Improver

When optimizing the fluid permeability performance in porous media, the core function of nano relative permeability improver mainly includes having good rheological properties [17], so that it can easily enter low-permeability oil and gas reservoirs. It should have good surface tension and interfacial tension [18,19] to facilitate the injection and drainage of nano relative permeability improvers to displace residual oil. It should have good wettability [20,21] to facilitate the formation of one or more nanofilms on the rock surface by the nano relative permeability improver. In addition, in order for the nano relative permeability improver to exist stably in low-permeability oil and gas reservoirs, it should have good stability, including temperature resistance, acid and alkali resistance, and shear resistance. All reported viscosity data represent averages of three independent measurements, with relative variations consistently below 5%.

3.1. Study on Rheological Properties

The rheological properties of nano relative permeability improvers have a significant impact on their injection behavior as well as subsequent flow and adsorption processes in geological formations. To quantitatively analyze its rheological properties, the apparent viscosity under different conditions can be measured using a Brinell viscometer [22], and the variation in the viscosity with shear rate and concentration can be established to evaluate its injectability, flow resistance, and adsorption retention risk in the formation. Volume concentration refers to the volume-based dilution of the optimized system (5.1% nano-SiO₂, 33% Span-80, 18% isobutanol, 2% NaCl) in water.

Figure 6 shows that the viscosity of the nano relative permeability improver gradually increases with the increase in volume concentration. At the same concentration, the lower the shear rate, the higher the viscosity. Moreover, as the concentration increases, the lower the shear rate, the more obvious the effect of the increasing concentration. This is because nano SiO₂ and other particles can increase the viscosity of the improver. When the concentration of nano SiO₂ and the mass fraction of the Span-80 surfactant are higher, there are more nano SiO₂ and other particles in the water phase, thus increasing the structural viscosity of the water phase. When the shear rate increases, such as to greater than 10 s⁻¹, its viscosity is less than 30 mPa·s, which is conducive to the injection of the nano relative permeability improver into the formation and the joint action of other high-viscosity solutions.

3.2. Interface Performance Research

In oil and gas field exploitation, reducing oil–water interfacial tension can improve the crude oil recovery rate, while surface tension has a greater impact on the evaporation or spreading behavior of liquids. By regulating these two types of tension, the performance of nano relative permeability improvers can be optimized. A surface tension test was conducted using a platinum plate and a surface tension meter, and the interfacial tension was measured using an interfacial tension meter and calculated using the Vonnegut equation [23]. The test results are shown in the following figure.

Figure 7 indicates that the surface tension improves using different concentrations of nano relative permeability improver ranging from 30 mN/m to 35 mN/m, and the interfacial tension ranges from 3 mN/m to 8 mN/m. As the concentration increases, it indicates that both tension and interfacial tension decrease. When the concentration is less than 5%, the changes in surface tension and interfacial tension are more obvious. This is because nano SiO₂ and surfactant Span-80 can both reduce the surface tension and interfacial tension of the improving agent. When it is at the critical concentration (≤5%), the reduction effect is more obvious. When it is greater than the critical concentration, the reduction effect on surface tension and interfacial tension is slower.

3.3. Wetting Performance Study

The effectiveness of nano relative permeability improvers is closely related to their wetting characteristics on rock surfaces. Good wetting performance involves forming nanofilms on the surfaces of low-permeability fractured rocks, thereby regulating the flow resistance of oil–water two-phase flow [24,25,26]. Therefore, it is of great significance to systematically study the wetting behavior of nano relative permeability improvers on rock surfaces. The wetting performance is determined by testing the wetting angle of nano relative permeability improver droplets on a rock surface.

As shown in Figure 8, θ = 0° indicates that the liquid very easily wets the rock; θ ≤ 90° indicates that the liquid is more likely to wet the rock; θ > 90° indicates that the liquid does not easily wet the rock; θ = 180° indicates that the liquid cannot wet the rock.

Figure 9 shows that the contact angle of the nano relative permeability improver varies between 84° and 50° with the change in volume concentration, and gradually decreases with the increase in concentration. When the concentration is less than or equal to 10%, the rate of the contact angle change is large, and when the concentration is greater than 10%, the contact angle change is small and gradually stabilizes at around 50°. Therefore, it can be concluded that the nano relative permeability improver can enhance the wettability of a rock surface, but with the increase in concentration, the wettability gradually increases and tends to stabilize.

3.4. Stability Performance Study

For complex working conditions in geological formations, nano relative permeability improvers should have good temperature resistance, salt and acid–alkali resistance, shear resistance, and other properties in order to exist stably in low-permeability formations.

(1)

Temperature resistance performance

Figure 10 illustrates that as the temperature increases, the viscosities of the deionized water, 0 # diesel, and nano relative permeability improver all decrease. When the temperature exceeds 60 °C, the viscosity change in the nano relative permeability improver is slower because the movement of nano molecules accelerates as the temperature increases. Therefore, molecular collision acceleration causes the viscosity to decrease. For nano relative permeability improvers, increasing the temperature further may cause phenomena such as agglomeration and even delamination of nanodroplets, resulting in slower viscosity changes.

(2)

Shear resistance performance

Figure 11 shows that the shear force increases with the increase in the shear rate, and the viscosity decreases with the increase in the shear rate. This is because this nano lotion-type improver is a high-concentration dispersion system, in which the nanodroplets easily gather to form clusters. However, as the shear rate increases, these clusters are gradually destroyed and eventually disperse into individual droplets, indicating that the nano relative permeability improver is a pseudoplastic fluid rather than a Newtonian fluid.

(3)

Acid alkali resistance

Figure 12 shows that when the pH is small, the viscosity of the nano relative permeability improver is small. When the pH increases, the viscosity gradually increases, and when the pH is greater than 7, the viscosity gradually decreases. This is because a high H⁺ concentration promotes the hydrolysis of the surfactant and reduces the stability of the lotion. When H⁺ decreases, the hydrogen bonding between H⁺ and -OH reduces the droplet size, enhances Brownian motion, and increases viscosity. However, when the pH is less than 7, the effect of -OH inhibits the formation of droplets, and the viscosity decreases.

(4)

Salt resistance performance

We add different masses of KCl to the nano infiltration improver and analyzed the viscosity changes.

According to the analysis of Figure 13, as the amount of KCl added increases, the viscosity of the nano relative permeability improver shows a trend of first increasing and then stabilizing. When the added mass is more than 6 g, its viscosity does not change. The reason is that under the low-concentration conditions (KCl mass is less than 6 g), inorganic salt ions and surfactants have a synergistic effect: on the one hand, K⁺ makes the system form a denser network structure by enhancing the strength of the interfacial facial mask and promoting the formation of droplet clusters. On the other hand, the increased droplet clusters strengthen the network structure through bridging, and these two mechanisms together lead to a significant increase in viscosity. But, when the amount of KCl added exceeds 6 g, the high-concentration salt effect begins to dominate: firstly, the salt precipitation weakens the effectiveness of the surfactant, and, secondly, the counter ion compresses the double layer, causing a decrease in zeta potential and weakening the electrostatic stabilization effect between oil droplets. This dual effect reduces the dispersity of the lotion, and the phases in the system tend to separate. At this time, the viscosity growth reaches a plateau. This concentration-dependent rheological behavior transition is essentially a process of salt surfactant interaction shifting from a synergistic effect to an antagonistic effect.

4. Relative Permeability Improvement Test

After treating self-made rock cores with the above-mentioned permeability improver, oil–water two-phase flow displacement experiments were carried out to determine the relative permeability of the oil–water phases at different water saturation levels and compared with the relative permeability of the rock cores before treatment with the permeability improving agent.

The experiment first dried the rock core and measured its dry weight. Then, after saturating the formation water with a vacuum, the wet weight was measured to establish the bound water saturation and determine the oil-phase permeability in this state. Next, a water-flooding experiment was conducted at a constant displacement flow rate, recording the water breakthrough time, cumulative oil production, cumulative liquid production, displacement rate, and pressure difference at both ends of the core until the water injection volume reached 30 times the pore volume. The water-phase permeability at residual oil saturation was then measured. Then, the nano relative permeability improver was reverse-injected at a constant flow rate of 2 mL/min, the system was closed and left standing for 24 h to ensure the nanomaterial fully adsorbed on the core surface, and finally, the oil- and water-phase permeability under the conditions of bound water and residual oil were repeatedly measured to evaluate the impact of the nano treatment on the core seepage characteristics.

In order to test the effectiveness of the prepared nano permeability enhancer, four low-permeability rock cores with different permeabilities (1 × 10⁻³ μm², 5 × 10⁻³ μm², 8 × 10⁻³ μm², 12 × 10⁻³ μm²) were set up to compare the relative permeabilities of the different rock cores before and after treatment with the nano permeability enhancer.

Figure 14 shows that after treatment with nano relative permeability improver, the permeability of both the oil and water phases in the core increased, with a more significant increase in the water-phase permeability and a decrease in the bound water saturation. The experiments showed that the improver had better effects on low-permeability rock cores due to its small pore throats and high initial bound water content. The nano improver effectively released this bound water, thereby improving displacement efficiency.

To better evaluate the technological advantages of our nano relative permeability improver,

Table 1. Comparison with other academic counterparts.

Property	This Work	Nanofluid [13]	Polymer-Based Improver [6]
Particle size (nm)	4.2	64~316	Not Applicable (N.A.)
Interfacial tension (mN/m)	3–8	8–9.5	N.A.
Temperature tolerance (°C)	≤90	≤60	≤60
Salinity tolerance (mg/L)	≤60,000	≤50,000	≤300,000
viscosity (mPa·s)	7.5–23.6	0.84–1.14	3.25–26

compares its key properties with existing academic counterparts. Our improver demonstrates superior performance in nanoparticle size control, thermal stability, and interfacial tension reduction while exhibiting better salt tolerance and viscosity than conventional nanofluids. These improvements are achieved without complex synthesis procedures, highlighting the formulation’s field applicability.

As shown in Figure 15, the reason why the nano relative permeability improver can improve the permeability of a rock core is that it has low surface tension, low interfacial tension, and good wettability. In addition, the improver can adsorb onto the rock surface to form one or more layers of erosion resistant nanofilms. Although the nanofilm structure slightly reduces the porosity and permeability of the rock core, it forms a wedge-shaped nanofilm on the pore wall surface through electrostatic action, Brownian motion, and multiple hydrogen bonding effects, which can effectively destroy the hydration layer or oil film structure, significantly change the permeability characteristics of oil–water two-phase flow, facilitate the displacement of oil and gas flow, optimize reservoir permeability, and improve the development efficiency and economic benefits of low-permeability oil and gas reservoirs.

5. Conclusions

This study makes significant advances in nanofluid technology to enhance oil recovery by developing a novel nano relative permeability improver. The key innovation lies in achieving an ultra-small nanoparticle size, which enables exceptional injectability into low-permeability formations while maintaining thermal and chemical stability. Our nano relative permeability improver has outstanding advantages in terms of wettability alteration, reductions in surface tension and interfacial tension, and reducing relative permeability, which can significantly enhance the utilization potential of crude oil. The main conclusions are summarized as follows:

(1)

This article successfully developed a nano relative permeability improver suitable for low-permeability oil and gas reservoirs. The optimized formula includes a nano SiO₂ content of 5.1%, a surfactant Span-80 content of 33%, a co-surfactant isobutanol content of 18%, and an additive NaCl content of 2%. After testing, the median particle size of the nano relative permeability improver is only 4.2 nm.

(2)

The rheological properties of the nano relative permeability improver are jointly affected by concentration and shear rate. The viscosity of high-concentration systems is significantly enhanced under low-shear conditions. At the same time, when the shear rate is greater than 10 s⁻¹ in systems with different concentrations, the viscosity should be less than 30 mPs·s to ensure its injectability, making it suitable for oilfield permeability enhancement applications.

(3)

This improver has excellent wetting properties (contact angle between 50 and 84°), low surface tension (30–35 mN/m), and interfacial tension (3–8 mN/m), and gradually enhances wetting properties that tend to stabilize with increasing concentration, indicating that both tension and interfacial tension decrease, which can reduce capillary resistance and enhance fluid fluidity.

(4)

The temperature resistance, shear resistance, and acid–base resistance tests of the improver show that its stability meets the complex working conditions of low-permeability reservoirs. This research achievement provides reliable technical support for the efficient development of low-permeability oil and gas reservoirs.

(5)

Building on these laboratory successes, future work will focus on long-term stability studies under dynamic flow conditions (>6 months), detailed environmental impact assessments and cost optimization, and pilot-scale validation in representative well conditions to evaluate field performance.