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Article

A Novel Screening Method of Surfactants for Promoting the Static Imbibition of Shale

by
Zhaokai Hou
1,*,
Yuan Yuan
2,
Jingyu Qu
1,
Ye Chen
3,
Shihui Sun
1 and
Ying He
1
1
Sanya Offshore Oil & Gas Research Institute, Northeast Petroleum University, Sanya 572025, China
2
Test Team of No. 1 Oil Provide Factory, Daqing Oilfield Limited Company, Daqing 163000, China
3
Engineering Technology Research Institute, PetroChina Southwest Oil & Gasfield Company, Chengdu 610017, China
*
Author to whom correspondence should be addressed.
Water 2024, 16(16), 2298; https://doi.org/10.3390/w16162298
Submission received: 25 July 2024 / Revised: 6 August 2024 / Accepted: 14 August 2024 / Published: 15 August 2024
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Abstract

:
Following hydraulic fracturing operations within shale reservoirs, there frequently exists a considerable volume of residual oil that remains encapsulated within the matrix, thereby impeding the singular shale well’s productivity from attaining projected yields. In pursuit of augmenting the recovery efficiency of shale oil, the industry has widely adopted a post-fracture shut-in strategy within shale oil wells. This methodology is predicated on the aspiration to escalate both the production output and the recovery factor of the oil well by leveraging the imbibition and displacement mechanisms of the fracturing fluid throughout the shut-in interval. There are many kinds of surfactants, and how to select surfactants suitable for shale reservoirs from these many surfactants has become a key issue in improving shale reservoir recovery. In this study, a new surfactant screening method for improving imbibition recovery in shale reservoirs is proposed. An interfacial tension test, contact angle test, and anti-adsorption test are carried out for the collected surfactant products, and the interfacial tension, contact angle, and anti-adsorption are gradually used as indicators. The type of surfactant is initially screened. On this basis, the static imbibition experiment of shale is made to determine the type and concentration of surfactants suitable for shale oil development. The results show that the surfactants screened by this method have the characteristics of decreasing oil–water interfacial tension, varying rock wettability, and strong anti-adsorption, which can effectively improve imbibition efficiency. The study results herein can provide technical support for optimizing shale oil surfactants and provide a new idea for improving oil exploitation in low-permeability reservoirs.

1. Introduction

As oil and gas resources are constantly explored and developed, traditional oil and gas resources have been unable to satisfy the growing needs of people. Therefore, the exploration and growth of abundant shale oil resources has been a hot topic in current research [1,2]. Shale reservoirs usually have the features of poor porosity and permeability, micro-fracture development, and serious, clear mineralogical and geochemical heterogeneity. Therefore, there is generally no natural productivity [3,4]. Therefore, it is necessary to effectively transform shale reservoirs to obtain economic productivity. At present, hydraulic fracturing technology is a necessary method for increasing the generation of unconventional oil and gas. The key to the success of hydraulic fracturing is to build a complicated fracture network within the formation and then effectively place proppant in these fractures to ensure that the fractures maintain sufficient conductivity after fracturing. Hydraulic fracturing technology can effectively reduce the seepage resistance of the formation near the bottom of the well and increase the seepage area. This is the main approach to increasing shale oil production [5,6]. However, after fracturing, despite the high permeability of the fracture system, very low permeability of the matrix, and high starting pressure gradient of the matrix system, a lot of surplus oil remains in the matrix, resulting in a failure to obtain better shale oil recovery [7].
Shale oil wells usually undergo shut-in operations after fracturing to enhance oil well production and recovery through the imbibition replacement of fracturing fluid during shut-in [8,9]. Imbibition is the phenomenon whereby water enters a matrix from a fracture under the action of capillary pressure differences so that the crude oil in the matrix is replaced. Studies of the mechanism of imbibition can be traced back to 1952. Aronofsky et al. [10] first proposed that imbibition is the major oil recovery system of fractured reservoirs. Since Aronofsky’s pioneering work, more and more researchers have researched the system of imbibition in low-permeability, ultra-low-permeability, and tight reservoirs. Graham et al. [11] studied the imbibition of a triangular model and deduced the imbibition force and seepage law under different conditions. Mttax et al. [12] established the mathematical relationship between recovery degree and dimensionless time. Yang et al. [13] refined dimensionless, spontaneous absorption efficiency equations. Mason et al. [14] proposed spherical spontaneous absorption theory. Wu et al. [15] introduced the concept of layer absorption. Ashraf [16] presented a one-dimensional model similar to Washburn’s, studying the leading front in narrow pores and the lagging front in wider pores during spontaneous absorption in porous media. Liu [17] studied and analyzed the pore-scale spontaneous absorption process in a single pore with mixed wettability, identifying the main pore size distribution in the range of 1–25 μm. Patel et al. [18] and Andersen et al. [19] also established theoretical models of imbibition. More research on the law of imbibition focuses on indoor experiments. Pathak et al. [20] conducted imbibition experiments on core samples with varying heights and diameters and found that the oil recovery decreased with the increase in diameter and height. Handy et al. [21] analyzed the effect of permeability on the imbibition rate of sandstone through imbibition experiments. These results show that in cases of higher core permeability, the level of imbibition recovery will be higher and the imbibition rate will be quicker. Wang [22], using digital core technology, constructed a pore network model and simulated absorption in real core pore structures, finding that lower permeability increases capillary force and absorption dynamics. Wang [23] emphasized the critical role of permeability in recovery rates induced by spontaneous absorption. Kathel [24] conducted absorption experiments on cores with varying heights and diameters, finding that oil recovery decreases with increasing diameter and height. Jadhunandan et al. [25] found that the polar molecules in reservoir crude oil can vary the wettability of the core from neutral-hydrophilic to lipophilic, thereby increasing the resistance of imbibition. Gao et al. [26] and Hamidpour et al. [27] researched the impact of permeability, porosity, salinity, lithology, and wettability on the imbibition effect. At the same time, Meng et al. [28], Abd et al. [29], and Tian et al. [30] summarized the research status and future development direction of imbibition theory.
Ma et al. [31] demonstrated that smaller pore radii enhance imbibition rates, affirming capillary forces as the primary driver of imbibition processes. The capillary pressure in different rock pore radii can be computed using the Young–Laplace Equation (1):
Ps = 2σcosθ/r
where σ denotes the oil–water interfacial tension (mN/m), θ represents the contact angle, and r is the pore radius (m).
According to Equation (1), the magnitude of spontaneous capillary absorption primarily depends on the reservoir wettability, oil–water interfacial tension, and pore radius. Therefore, enhancing reservoir absorption efficiency can be achieved by altering the interfacial tension and wettability. At present, an effective and feasible method to enhance the performance of reservoir imbibition is to add surfactant into the imbibition medium. Fernø et al. [32], Sun et al. [33], and Chen et al. [34] have shown that the addition of surfactants can decrease the oil–water interfacial tension in the matrix, improve the deformation capacity of oil droplets, enhance the wettability of the rock matrix surface and make it easier for oil droplets to be replaced from the matrix. In the meantime, the replacement of water in the matrix system will enhance the single well production and recovery rate while supplementing the formation energy. Xiang et al. [35] found that by adding 0.1% nonionic surfactant and 0.25% clay swelling inhibitor to the injection water, the water injection and well shut-in time could be reduced by 50% and the recovery rate could be increased by 3.15%. In 2004, Wei et al. [36] discovered that under the action of the cationic surfactant CTAB (cetyltrimethylammonium bromide), the oil-wet core samples could significantly shift towards water-wet, and the effectiveness of the cationic surfactant CTAB in enhancing spontaneous imbibition capacity and recovery rate was superior to that of the anionic surfactant SDBS (sodium dodecylbenzenesulfonate). Chen et al. [37] showed that surfactant solution had a faster imbibition rate and higher recovery rate than formation water. Li et al. [38] added betaine to the slickwater to enhance the imbibition effect of the slickwater without affecting the basic performance of the slickwater. Wu et al. [39] added gemini cationic surfactants to clean fracturing fluid, which effectively improved the imbibition efficiency.
Considerable research has been conducted on the effects of surfactants on absorption laws. Han et al. [40] found that anionic surfactants generally outperform other types of surfactants in absorption efficiency. Hou et al. [41], through studying the effects of different surfactants on oil-wet sandstone cores, discovered that at the same concentration, the cationic surfactant CTAB yields higher final recovery rates from cores compared to the nonionic surfactant TX-100 and the anionic surfactant POE (1). Liu et al. [42] proposed that anionic and nonionic surfactants affect shale surface wettability differently, with anionic surfactants showing superior effects on surface wettability changes and exhibiting a time lag mechanism in wettability alteration. Based on theoretical analyses, researchers have developed various surfactants to enhance reservoir absorption efficiency. Standnes et al. [43] developed a surfactant, alkyl trimethyl ammonium chloride, using coconut palm oil. Studies have shown that alkyl trimethyl ammonium chloride can effectively improve the wettability of dolomite and improve imbibition recovery. Fan et al. [44] developed a gemini anionic–nonionic surfactant, which effectively enhanced the stripping ability of crude oil. Zhang et al. [45] used a gemini viscoelastic surfactant and organic solution to compound a composite viscoelastic surfactant. Tang et al. [46], Baruah et al. [47], Zhao et al. [48], and Pu et al. [49] also developed different surfactants. At present, the kinds of surfactants mainly include anionic, cationic, nonionic, and zwitterionic surfactants [50]. The merits and demerits of various kinds of surfactants are shown in Table 1. Selecting surfactants according to actual geological conditions has become core to enhancing the exploitation of shale oil reservoirs. At present, in the screening of surfactants, only the ultra-low interfacial tension or the strongest wetting reversal effect is used as the key index to screen surfactants, which does not take into account the dual effects of varying wettability and declining oil–water interfacial tension. In the meantime, the effect of surfactant adsorption on crude oil recovery is not considered in the screening process, resulting in the selected surfactant not reaching the expected effect.
In this study, a new surfactant screening method for improving imbibition recovery in shale reservoirs is proposed, aiming to accurately and efficiently screen out the types and concentrations of surfactants employed to enhance the imbibition performance of shale oil. In this study, the types of surfactants were preliminarily screened out by carrying out an interfacial tension test, a contact angle test, and an anti-adsorption test, with interfacial tension, contact angle, and anti-adsorption as key indicators. On this basis, the static imbibition experiment of shale was made, and the type and concentration of surfactant suitable for shale oil development were finally determined with the imbibition recovery rate as the index. This study can offer technical support for optimizing shale oil surfactants and offer a new idea for enhancing oil exploitation in low-permeability reservoirs.

2. Materials and Methods

2.1. Experimental Apparatus and Materials

The experimental apparatus included a TX-500D spinning drop tensiometer manufactured by Cono Industrial Ltd., New York, NY, USA; a DSA100 video optical contact angle measuring device from KRUSS GmbH, Hamburg, Germany; a sand-filling tube self-developed in the laboratory, measuring 30 cm long with an inner diameter of 2.5 cm and filled with 243 g of 20/40 mesh quartz sand; and static imbibition bottles, which are suitable for cores up to 5 cm in diameter and 10 cm in height.
The experimental materials were the following: formation water; total salinity of 4783.5 mg/L; eight surfactants named 1#, 2#, 3#, 4#, 5#, 6#, 7#, and 8#; Daqing crude oil with a viscosity at 50 °C of 4.74 m·Pa·s and a density of 0.734 g/cm3; and a shale outcrop core with permeabilities of 0.1 md, 0.3 md, 1 md, 3 md, and 10 md and a core specification of φ2.5 cm × 5 cm. Detailed core parameters are outlined in Table 2.

2.2. Experimental Steps and Methods

Firstly, the agents whose interfacial tension reduction effect was not up to standard were screened out by the interfacial tension test. Then, after the contact angle test, the agent whose wetting reversal effect was not up to standard was screened out again; after the anti-adsorption test, the agents with substandard anti-adsorption were screened out; finally, through the static imbibition experiment, the type and concentration of surfactants used to improve the imbibition efficiency of shale reservoirs were determined with the post-suction recovery rate as the index. The surfactant screening process is shown in Figure 1.

2.2.1. Interfacial Tension Experiment

A 0.2% mass concentration of surfactant solution was prepared with formation water; the surfactant solution was inhaled with a glass capillary, and then the oil droplets were dripped to ensure that there were no bubbles in the measuring tube and the tube was sealed. This was placed on a TX500D spinning drop tensiometer, and the speed was set to 6000 r/min. Under the action of centrifugal force, gravity and interfacial tension, the oil droplets in the solution formed a cylindrical shape. Figure 2 shows the photograph of droplets taken by an interfacial tension meter. We needed to measure the width of the oil droplets at different times. The width of the oil droplets was recorded at 1 min, 3 min, and 5 min, and then the data were recorded every 6 min until the change of the three consecutive readings was within 0.001 cm, that is, when the system was considered to have reached equilibrium. Figure 3 illustrates the experimental setup for the interfacial tension measurements.
According to Equation (2), the interfacial tension γ of oil–water phases can be calculated as follows:
γ = Δ ρ ω 2 r 3 4
where ∆ρ means the density diversity between oil and water phases, in kg/m3; ω stands for the angular velocity, in rad/s; r represents the short-axis radius of oil droplets (r = D/2), in m; D is the radial diameter of the centrifuge tube, in m; L is the axial diameter of the centrifugal tube, in m; and finally, the interfacial tension γ is obtained, in mN/m.

2.2.2. Contact Angle Experiment

The shale core was cut into thin sections of a certain thickness after washing with oil and drying. Then, the core slices were placed in different surfactant solutions with 0.2% mass concentration for soaking treatment for 24 h. The core sections were dried, then placed on the bracket of the optical contact angle measuring instrument, and adjusted to make them level. The lower platform was adjusted to move up slowly and move down quickly when it came into contact with the needle droplet. At this time, the droplet was on the core. When the contact angle of the droplet on the core no longer changed, the contact angle was recorded. The experimental results are presented in Figure 4. Figure 5 is a contact angle measurement image.

2.2.3. Anti-Adsorption Experiment

Volumes of 1000 mL of different surfactant solutions with 0.2% mass concentration were prepared, and the initial interfacial tension of the solutions was measured and recorded. Sand-filling pipes were made using surfactant solution passed through the sand-filling pipe at a displacement rate of 10 mL/min. Through 1 PV volume (50 mL) recovery, the interfacial tension of the recovered liquid was measured. The above steps were repeated, continuing to use the surfactant solution through the sand-filling tube, and the interfacial tension was measured after the liquid passed through each 1 PV volume (50 mL) of solution until the interfacial tension of the solution through the sand-filling tube no longer had a large change trend.

2.2.4. Static Imbibition Experiment

The core was washed with benzene and ethanol 3:1. After 5 days of washing, the core was taken out and dried, and the core weight was recorded. The porosity and permeability of the dried core were assessed. The core-saturated oil work was completed under the reservoir temperature condition and stood for 24 h; after the core was taken out, it was soaked in the experimental oil for use; the core was taken out from the oil, and the core weight was recorded to acquire the saturated oil volume of the core. The core was put into a static imbibition bottle containing a surfactant solution, and the amount of oil discharged from the core in varied time periods was recorded. Figure 6 illustrates the process flow of the static imbibition experiment. Figure 7 is the phenomenon picture of the static imbibition experiment.
The calculation equation of static imbibition recovery is:
R = V t V o × 100 %
where Vo means the volume of oil in the core, in mL, and Vt stands for the volume of oil discharged from the core, in mL.

3. Results and Discussion

3.1. Experimental Results of Interfacial Tension

For the research on the capacity of different surfactants to change the oil–water interface force tension, the oil–water interfacial tension in 2% 1#, 2#, 3#, 4#, 5#, 6#, 7#, and 8# surfactant solutions was compared with the oil–water interface force tension without surfactants. Figure 8 shows the experimental outcomes. The red line in the figure represents the interface force tension between oil and water without surfactant, which is 9.15 × 10−1 mN/m. After adding eight different types of surfactants, the oil–-water interfacial tension decreased. Among them, the interface force tension decreased most obviously under the action of 4# surfactant solution, and the oil–water interface force tension decreased to 3.76 × 10−3 mN/m. The oil–water interface force tensions under 2#, 5#, and 7# conditions were 9.12 × 10−1 mN/m, 6.25 × 10−1 mN/m, and 5.48 × 10−1 mN/m, respectively. The order of magnitude was greater than the 10−2 required on-site. Therefore, 1#, 3#, 4#, 6#, and 8# surfactants were selected for the next contact angle measurement.

3.2. Contact Angle Experimental Results

For further research on the wettability reversal efficiency of different surfactants, the contact angle of rock under the condition of 2% 1#, 3#, 4#, 6#, and 8# surfactant solution was compared with that without surfactant. Figure 9 shows the experimental results. The black line in the figure suggests that the contact angle of rock without surfactant is 79.4°. It can be seen from the diagram that when different types of surfactants were added, the contact angle decreased. Among them, the wetting reversal effect of 4# surfactant was the best, and the contact angle decreased to 21.5°. However, the wetting reversal effect of 3# and 8# surfactants was poor, with contact angles of 69.6° and 68.3°, respectively. Therefore, only 1#, 4#, and 6# were selected for the next screening experiment.

3.3. Anti-Adsorption Experimental Results

For the research on the anti-adsorption properties of various types of surfactants, 2% of 1#, 4#, and 6# surfactants were tested for anti-adsorption. Figure 10 shows the experimental outcomes. The diagram shows that the interfacial tension of 1#, 4#, and 6# surfactants grew first and then declined as the injection volume increased, and finally tended to the initial value. The reason for the interfacial tension increases in surfactants 1#, 4#, and 6# was that the rock surface adsorbed a certain amount of surfactant and the concentration of surfactant in the solution decreased, which could not achieve the effect of reducing the interfacial tension; so, the interfacial tension increased. The reason for the decrease in the interfacial tension was that after the surfactant adsorption on the rock was basically saturated, the amount of surfactant adsorbed in the injected solution continuously reduced, so the interfacial tension finally basically returned to its original size. Among them, the interfacial tension of 4# and 6# recovered faster, while 1# recovered slower, indicating that the anti-adsorption ability of 1# surfactant was weak and the action distance was short.

3.4. Experimental Results of Static Imbibition

In order to finally screen out the type of surfactant suitable for shale, 2% of 4# and 6# surfactants and shale cores with a permeability of 1 mD were selected for static imbibition experiments. Figure 11 shows the experimental outcomes. The figure shows that under the same concentration conditions, the imbibition recovery of 4# surfactant was greater than that of 6# surfactant. Therefore, 4# surfactant was finally selected to enhance the imbibition recovery of shale.
In order to finally determine the concentration of 4# surfactant, 0.1%, 0.2%, 0.3%, and 0.4% of 4# surfactant and shale cores with permeability of 1 md were selected for static imbibition experiments. Figure 12 shows the experimental outcomes. The diagram shows that as concentrations increased, the imbibition recovery rate increased. When the concentration was 0.3%, the recovery rate was the highest; continuing to increase, the recovery rate was not evident and the cost was too high. Therefore, the reasonable concentration was 0.3%.
For the clarification of the effect of rock permeability on imbibition recovery, static imbibition experiments were made on cores with permeabilities of 0.1 md, 0.3 md, 1 md, 3 md, and 10 md and 4# surfactant with a mass concentration of 0.3%. Figure 13 shows the experimental outcomes. The figure shows that with increases in permeability, static imbibition recovery gradually grew. This is because in cases of higher permeability, the pore throat size is bigger and the connectivity is better. At this time, the resistance decreases during the oil droplet migration process, the imbibition rate grows, and the imbibition recovery rate grows.

4. Conclusions

In this study, a new surfactant screening method for improving imbibition recovery in shale reservoirs is proposed. The surfactants screened by this method have the characteristics of reducing oil–water interface force tension, varying rock wettability, and strong anti-adsorption, which can effectively enhance imbibition performance. When the shale permeability is 1 millidarcy (mD) and the concentration is 0.3%, the imbibition recovery rate achieved by surfactant number 4 can reach 22.6%. This method is not only suitable for shale reservoirs but also for surfactant screening in other low-permeability, ultra-low-permeability, and tight reservoirs. It should be noted that this study only screened surfactants from key indicators, such as interfacial tension, contact angle, and anti-adsorption, which has certain limitations. Therefore, in future research, the screening of surfactants can be completed by increasing the screening indices such as temperature resistance and salt resistance according to the actual reservoir.

Author Contributions

Conceptualization, J.Q.; methodology, Y.Y.; validation, Y.C.; investigation, Y.H.; writing—original draft preparation, Z.H.; visualization, S.S. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by the project of the Nature Scientific Foundation of Heilongjiang Province, grant number YQ2021E006.

Data Availability Statement

The data presented in this study are available upon request from the corresponding author, as the fund project has not yet been concluded and premature public data are easy to steal.

Conflicts of Interest

Author Yuan Yuan was employed by the Daqing Oilfield Limited Company and author Ye Chen was employed by the PetroChina Southwest Oil & Gasfield Company. The remaining authors declare that this research was conducted in the absence of any commercial or financial relationships that could be construed as potential conflicts of interest.

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Water 16 02298 g001
Figure 1. Flow chart of surfactant screening method for enhancing shale imbibition recovery.
Figure 1. Flow chart of surfactant screening method for enhancing shale imbibition recovery.
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Figure 2. Photographs of droplets taken by interfacial tension meter.
Figure 2. Photographs of droplets taken by interfacial tension meter.
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Figure 3. Flow chart of interfacial tension test.
Figure 3. Flow chart of interfacial tension test.
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Figure 4. Contact angle test flow chart.
Figure 4. Contact angle test flow chart.
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Figure 5. Contact angle measurement image.
Figure 5. Contact angle measurement image.
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Figure 6. Flow chart of static imbibition experiment.
Figure 6. Flow chart of static imbibition experiment.
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Figure 7. The phenomenon picture of static imbibition experiment.
Figure 7. The phenomenon picture of static imbibition experiment.
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Figure 8. Comparison of the ability of various kinds of surfactants to decrease interfacial tension.
Figure 8. Comparison of the ability of various kinds of surfactants to decrease interfacial tension.
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Figure 9. Comparison of the capacity of various kinds of surfactants to vary contact angle.
Figure 9. Comparison of the capacity of various kinds of surfactants to vary contact angle.
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Figure 10. The variation curve of interfacial tension with the amount of solution injection under different types of surfactants.
Figure 10. The variation curve of interfacial tension with the amount of solution injection under different types of surfactants.
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Figure 11. Comparison of imbibition recovery of different types of surfactants.
Figure 11. Comparison of imbibition recovery of different types of surfactants.
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Figure 12. Change curve of imbibition recovery with surfactant concentration.
Figure 12. Change curve of imbibition recovery with surfactant concentration.
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Figure 13. Imbibition recovery rate versus permeability curve.
Figure 13. Imbibition recovery rate versus permeability curve.
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Table 1. The advantages and disadvantages of different surfactants as oil displacement agents.
Table 1. The advantages and disadvantages of different surfactants as oil displacement agents.
Surfactant TypesAdvantageDisadvantage
Anionic surfactantsThey have high interfacial activity, excellent temperature resistance, less formation adsorption, and a low price.They have poor salt tolerance and are not resistant to divalent cations, including calcium and magnesium.
Nonionic surfactantsThey have good salt resistance, good multivalent cation resistance, and many kinds of cations.They have cloud points, poor stability, poor temperature resistance, high adsorption capacity, and a high price.
Anionic–nonionic amphoteric surfactantsThey have good temperature resistance and salt tolerance, greatly reduce the chromatographic separation effect between anion and nonionic compounds, and have good compatibility.They have less variety and a high price.
Polymeric surfactantsThey have the role of decreasing interfacial tension and increasing viscosity, the adsorption capacity is small, and they have good temperature and salt resistance.They have less variety and a high price.
Table 2. Basic parameters of experimental core samples.
Table 2. Basic parameters of experimental core samples.
Core NumberLength/cmDiameter/cmPermeability/mD
15.02.51.01
25.02.51.05
35.02.51.02
45.02.51.01
55.02.50.1
65.02.50.3
75.02.53
85.02.510
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Hou, Z.; Yuan, Y.; Qu, J.; Chen, Y.; Sun, S.; He, Y. A Novel Screening Method of Surfactants for Promoting the Static Imbibition of Shale. Water 2024, 16, 2298. https://doi.org/10.3390/w16162298

AMA Style

Hou Z, Yuan Y, Qu J, Chen Y, Sun S, He Y. A Novel Screening Method of Surfactants for Promoting the Static Imbibition of Shale. Water. 2024; 16(16):2298. https://doi.org/10.3390/w16162298

Chicago/Turabian Style

Hou, Zhaokai, Yuan Yuan, Jingyu Qu, Ye Chen, Shihui Sun, and Ying He. 2024. "A Novel Screening Method of Surfactants for Promoting the Static Imbibition of Shale" Water 16, no. 16: 2298. https://doi.org/10.3390/w16162298

APA Style

Hou, Z., Yuan, Y., Qu, J., Chen, Y., Sun, S., & He, Y. (2024). A Novel Screening Method of Surfactants for Promoting the Static Imbibition of Shale. Water, 16(16), 2298. https://doi.org/10.3390/w16162298

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