Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants

Journal of Petroleum Science and Engineering 175 (2019) 624–633

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Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants

T

Junrong Liua,b, James J. Shenga,b,c,∗, Xiukun Wanga,b, Hongkui Gea,b, Erdong Yaoa a

Unconventional Petroleum Research Institute, China University of Petroleum, Beijing, China State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing, China c Bob L. Herd Department of Petroleum Engineering, Texas Tech University, Texas, USA b

A R T I C LE I N FO

A B S T R A C T

Keywords: Shale oil Spontaneous imbibition Wettability alteration Surfactant IFT

Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oilwet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, ζ-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.

1. Introduction Currently, commercial recovery of oil and gas from ultra-tight formations mainly depends on the technologies of horizonal drilling and hydraulic fracturing. During a fracturing stimulation process, surfactant additives can be injected to enhance the initial rate and maintain a long-term production (He et al., 2015). This work is focused on investigating the enhance oil recovery (EOR) mechanisms by adding different types of surfactants in the fracturing fluids in terms of wettability alteration and IFT reduction. Wettability defines the tendency of one fluid to spread onto a solid

∗

surface in the presence of the other immiscible fluid (Anderson, 1986). For petroleum engineering systems, wettability presents the tendency for water or oil to spread on the rock surface, and the wetting phase refers to the fluid with higher affinity to the rock than the nonwetting phase (Salehi et al., 2008a). Wettability is believed to be the main factor controlling spontaneous imbibition, which is considered as a EOR mechanism primarily responsible for oil and gas production in shales (Odusina et al., 2011; Dutta et al., 2014). Generally, rock wettability can be measured by several quantitative methods such as: contact-angle measurement, Amott wettability index (Amott, 1958), the United States Bureau of Mines (USBM) wettability index (Donaldson et al., 1969),

Corresponding author. Unconventional Petroleum Research Institute, China University of Petroleum, Beijing, China. E-mail address: [email protected] (J.J. Sheng).

https://doi.org/10.1016/j.petrol.2019.01.003 Received 6 August 2018; Received in revised form 21 November 2018; Accepted 1 January 2019 Available online 02 January 2019 0920-4105/ Published by Elsevier B.V.

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capillary pressure (Pc) to contact angle (θ) and IFT (σ) in a specific pore radius (r).

Nuclear Magnetic Resonance (NMR) (Brown and Fatt, 1959) and spontaneous imbibition method (Morrow, 1990). Due to the tight and complex nature of the shale formations, displacement technique can hardly be applied to determine their wettability (Lan et al., 2015). Therefore, the Amott wettability index and USBM are not applicable to shale reservoirs, and the contact-angle measurement is commonly used to characterize the wettability of shale rocks. The contact-angle measurements include several phase-system scenarios, such as: air/water/ rock, air/oil/rock and oil/water/rock (Bai et al., 2013; Elgmati et al., 2011; Habibi et al., 2016; Liang et al., 2015; Yassin et al., 2017). Among these contact angle measurement methods, the oil/water/rock phasesystem is the correct method (Sheng, 2018). In a water/oil/rock system, in which brine is the denser fluid, the rock is water-wet when the contact angle between water and solid ranges from 0 to 75°, intermediate-wet from 75° to 105°, and oil-wet from 105° to 180° (Anderson, 1986). Besides, wettability can also be characterized by the stability of surfactant-solution film between oil and the rock surface. According to the Derjaguin and Landau's and Verwey and Overbeek's (DLVO) theory, the thickness of the film and its stability depend on the charges of the rock surface, brine and oil (Hirasaki, 1991). ζ-potential Measurements of siliceous shale that are key input for surface force evaluation can be used to evaluate its wettability (Takahashi and Kovscek, 2010). ζ-potential is the electric potential in the interfacial double layer (DL) at the location of the rock surface relative to a point in the bulk fluid away from the interface. The magnitude of the ζ-potential is related to surface charges at the rock/fluid interface. In general, the greater the absolute value of the ζ-potential, the more stable the water film is, and the easier for oil film to be detached from the rock surface and change the wettability. Wettability alteration in reservoir rocks can be chemically achieved by using surfactants. Surfactants are amphiphilic compounds that have both hydrophobic and hydrophilic groups, which can effectively change the wettability of the rock surfaces and reduce the oil-water IFT. Surfactants are classified into anionic surfactants, cationic surfactants, amphoteric surfactant and nonionic surfactant by the International Standardization Organization (ISO). Due to different types of surfactants and the diversity of the rock surfaces, the mechanisms of wettability alteration are not the same. The effectiveness of surfactant on altering wettability has been extensively studied in conventional reservoirs. Three mainly mechanisms have been proposed to explain the wettability alteration by adding surfactants: ion-pairs formation, surfactant adsorption and micellar solubilization. Standnes and Austad (2000) studied the wettability alteration (oil-wet to water-wet) in chalk using water-soluble surfactants. They concluded that cationic surfactants were able to desorb negatively charged organic carboxylates from the chalk surface and formed the ion-pairs in an irreversible way, then exposed the originally water-wet rock surface. and they also found that Anionic surfactants were not able to desorb anionic organic carboxylates from the crude oil in an irreversible way, the mechanism of wettability alteration was to form a water-wet bi-layer between oil and the hydrophobic chalk surface by surfactant adsorption. Salehi et al. (2008b) compared the effects of two types of surfactants on wettability alteration of oil-wet Berea sandstone. Their experimental results demonstrated that the mechanism of wettability alteration by forming ion-pairs was more effective than by the surfactant adsorption. Feng and Xu (2015) concluded that surfactants can form micellar to solubilize the oil film which adsorbed on the oil-wet rock surface and altered the surface wetness. The significances of these three proposed mechanisms vary and depend on the types of surfactants, crude oils and rock matrices (Alvarez and Schechter, 2017a). However, there are few studies on the mechanism of wettability alteration in shale reservoirs. Whether these mechanisms are suitable for shale reservoirs and what type of surfactants can more effectively change the wettability of oilwet shales are the questions this paper attempts to answer. Conventionally, water imbibition is mainly affected by capillary pressure and gravity. The Young-Laplace equation (Eq. (1)) relates the

pc =

2σ cosθ

(1)

Therefore, in the shale micro- and nano-pores, the capillary force is particularly important and the gravity becomes a minor (Sheng, 2017). Especially, in oil-wet shales, oil is trapped inside the pores by negative capillary pressures (following the definition that Pc = Po-Pw), water cannot exchange the crude oil in the pores through spontaneous imbibition (Wang and Sheng, 2018). Adding surfactant can alter the rock wettability to shift capillary pressure values from negative to positive, then water can enter rock pores and displace oil (Alvarez et al., 2014; Austad et al., 1998; Chen et al., 2001; Hirasaki and Zhang, 2004.; Kathel and Mohanty, 2013; Neog and Schechter, 2016; Shuler et al., 2011; Wang et al., 2012). Besides, capillary pressure is also proportional to IFT, therefore, reduced IFT will decrease the rate of spontaneous imbibition. When the rock wettability changes to water-wet by surfactants, the capillary force changes from negative to positive, and the reduction of interfacial tension will lead to the decrease of capillary force, which is not conducive to the improvement of spontaneous imbibition. Therefore, what type of surfactants should be used is closely related with these two effects: IFT reduction and wettability alteration, and for different surfactants, these two effects are different and related with each other. Many researches have reported the enhanced recovery of oil reservoirs by adding surfactants to alter the rock wettability and reduce IFT. For oil-wet carbonate reservoirs, cationic surfactants are used to enhance the spontaneous imbibition and oil recovery (Xie and Weiss, 2005; Wang et al., 2012; Chen and Mohanty, 2015). Similarly, anionic surfactants and non-ionic surfactants can also be used to improve the oil recovery of these types of reservoirs (Sharma and Mohanty, 2013; Lu et al., 2014; Wang and Mohanty, 2014). However, there is no deep study on the differences in the mechanisms of enhanced oil recovery by different types of surfactants, and the suitability of different reservoirs for different surfactants, especially in shale oil reservoirs. Wang et al. (2012) investigated wettability alteration by different surfactants compared with brine alone on Middle Bakken and Upper Bakken shale reservoir cores. They concluded that the wettability of shale rock was altered from oil-wet or intermediate-wet to water-wet by different used surfactants. However, their measurement of the wettability of very small reservoir cores is using the Amott-Harvey method which is not suitable for shale reservoirs with ultra-low porosity and permeability. Neog and Schechter (2016) performed contact angle measurement, spontaneous imbibition experiment and CT-scan method to investigate the potential of several nonionic surfactants in fracturing fluids to alter wettability of ultra-tight oil-rich shale formations and improve oil recovery. They concluded that the nonionic surfactants have the potential to alter the shale wettability to water-wet state and that the IFT reduction lowers the effectiveness of wettability alteration in improving oil recovery by spontaneous imbibition. Alvarez et al. (2014) as well as Alvarez and Schechter (2017a, 2017b) performed spontaneous imbibition experiments in unconventional liquid reservoirs using different types of surfactants, including anionic surfactant and nonionic/cationic surfactant mixture. They concluded that more oil was produced by anionic surfactants followed by non-ionic/cationic surfactants. They also concluded that anionic surfactants show a superior effect on wettability alteration and IFT reduction. However, they did not dig into the differences of the mechanisms of the wettability alteration of these two types of surfactants and the effects of these two types of surfactants on the improvement of spontaneous imbibition. This paper mainly studies the surfactants-enhanced shale oil recovery by spontaneous imbibition. Previous studies have not considered the different mechanisms of different types of surfactants on shale 625

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wettability alteration and spontaneous imbibition. Moreover, whether surfactants induced IFT reduction is beneficial to the improvement of spontaneous imbibition is discussed in this work. Though various experimental studies, the objectives of this work are to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of Sichuan Basin in China, and to analyze their effects of wettability alteration and IFT reduction on the spontaneous imbibition process of the oil-wet shale samples.

Table 1 XRD experimental results of shale samples. Mineral

Content (wt%)

Quartz Clays Calcite Dolomite Feldspar Pyrite

31.8 33.0 2.0 10.8 20.6 1.8

2. Methodology experiments consist of measuring contact-angle, ζ-potential, IFT and spontaneous imbibition process. The details of the surfactants used in the experiments are presented in Table 2. To study the mechanisms of wettability alteration, different types of surfactants are tested: two anionic and two nonionic surfactants at concentrations of 0.01 wt%, 0.05 wt% and 0.1 wt%. Due to the high clay content in shale formations, a 4 wt% potassium chloride (KCl) brine is used to inhibit the clay swelling during the experiments.

This paper mainly studies the spontaneous imbibition process of fracturing fluid with surfactants added. We try to explore the mechanisms of anionic and nonionic surfactants on wettability alteration and their effect on spontaneous imbibition. These objectives are achieved by performing contact angle and ζ-potential, IFT, and spontaneous imbibition experiments with these different types of surfactants. 2.1. Rock and fluid properties

2.3. Contact-angle measurements The experimental shale cores were taken from the Sichuan Basin of China, and the cores were precisely cut into ϕ25 mm × 50 mm cylinders. The porosity obtained from helium expansion experiments ranges from 3 to 5%. The range of measured air permeability is 2–5 μD. In addition, the cores are mostly siliceous by the spectrogram of X-raydiffraction (XRD) as shown in Fig. 1, and Table 1 shows a comparison of the major minerals from the shale core sample obtained from XRD analysis. The used oil is the mineral oil with a density of 0.85 g/cm3 and a viscosity of 3.5 mPa s at room temperature of 22 °C. Before all experiments, the cores were aged for 2 months to restore the rock properties to its original reservoir state.

Contact-angle measurements are performed on the equipment named Dataphysics from Kino Corporation of the United States. Since the oil droplets will spread out on the shale rock surface, the contact angle can't be measured directly, and in principle it is not a correct method (Sheng, 2018). The captive bubble method was used as it allows accurate measurement of the contact angle of an oil droplet on a shale surface in the presence of brine, with and without surfactants. In this method, the oil droplet is dispensed bottom up through a capillary needle and attached to the shale rock surface. Then the contact-angle between the oil and rock surface can be measured in the aqueous solution by applying the enhanced video-image digitalization technique. Fig. 2 provides a schematic of this experimental process. In the experiments, the rock samples from the same depth need to be polished to minimize measurement errors caused by surface roughness. Then they

2.2. Surfactants Four different commercial surfactants are used in this work and the

Fig. 1. XRD pattern of shale core sample. 626

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Table 2 The chemical descriptions of the used surfactants. Surfactant

Type

Primary Components

PH

Purity

Manufacture

AES AOS AEO-9 IAE

Anionic Anionic Nonionic Nonionic

Sodium alcohol ether sulphate Sodium C14-16 olefin sulfonate alcohol ethoxylate Isomeric alcohol ethoxylates

7 7 7 7

> 99% > 99% > 99% > 99%

Sinopharm Sinopharm Sinopharm Sinopharm

Chemical Chemical Chemical Chemical

Reagent Reagent Reagent Reagent

Co.,Ltd Co.,Ltd Co.,Ltd Co.,Ltd

that wets this surface as shown in Fig. 3, and the film's stability is influenced by interactions between its brine/oil and brine/rock interfaces, which can be described by DLVO theory (Hirasaki, 1991).

Π(h) = ΠVDW (h) + ΠEDL (h) + ΠSTR (h)

(2)

where П(h) is disjoining pressure (Pa), which is a function of wetting film thickness h (nm), ПVDW is the London van der Waals forces (Pa), ПEDL is the electrostatic forces in the electrical double layer (Pa) and ПSTR is the structural force (Pa). Disjoining pressure (П(h)) is regard as the force that tends to separate oil and water, therefore, as the П(h) increases, the water film thickness h increases, and a thick brine film is indicative of a water-wet state. In lowered salinity solutions, the double layers expand to become more diffusive and the screening becomes weaker. As a result, the electrostatic contribution ПEDL to the disjoining pressures П(h) becomes dominant (Myint and Firoozabadi, 2015). The compression approximation model is suitable for a low to intermediate the electrostatic potential (zeψ/kBT < 2). The following approximation to ПEDL is given:

Fig. 2. Contact angle measurement using the captive bubble method where the oil droplet is dispensed on the bottom surface of the shale sample.

are cleaned using chloroform and isopropanol in a Soxhlet apparatus, and subsequently aged at reservoir temperature for more than 2 months. The contact-angle measurements were performed for fracturing fluid without or with each type of surfactants, respectively. And each type of surfactant was tested at three concentrations: 0.01 wt%, 0.05 wt % and 0.1 wt%. To investigate the different mechanisms of wettability alteration between the nonionic and anionic surfactants, we measured the contact angles with shale samples soaked for 5 min and 48 h in different surfactants solutions. We also measured the contact angles over time in the anionic surfactants solutions. To ensure the repeatability and consistency of these measurements, each sample was measured for 5 to 7 times.

ζ ζ ΠEDL (h) ≈ 64cNA kB Ttanh ⎛ 1 ⎞ tanh ⎛ 2 ⎞ exp(−hκ ) 4 ⎝ ⎠ ⎝4⎠ ⎜

⎟

⎜

⎟

(3)

Based on the properties of the function, ΠEDL is positive if both ζ1 and ζ2 are negative, and ΠEDL increases in magnitude as the potentials become more negative. The end result of increasing absolute value of ζpotential of crushed-rock powder indicates the brine film is more stable and thicker and the wettabiity of the rock is more water-wet. Herein, ζ-potential Measurements were performed on a Zetasizer Nano Z device produced by the Malvern company of UK (Binazadeh et al., 2016) as shown in Fig. 4. They were realized by using electrophoretic phase analysis light scattering (PALS) method in a light scattering analyzer. For measuring the ζ-potential, 1 mg of crushed-rock powder was added to 10 cm3 of an aqueous solution (fracturing water with or without surfactant). The diameters of shale powder used in the experiments range less than 100 μm obtained by a 300-mesh sieve and the surfactants were used in the experiments are the same as those in the contact-angle experiments. The rock/aqueous solutions were sonicated by sonifier at a frequency of 40 HZ for 1 min to keep them stable

2.4. ζ-potential measurements Using theζ-potential of crushed-rock powder to evaluate the wettability of shale is different from the contact-angle method where measured errors mainly result from the rock surface heterogeneity. The wettability of the shale surface depends on the stability of the brine film

Fig. 3. (a) The wettability of the shale surface depends on the stability of the brine film that wets this surface. (b) As the П(h) increases, the water film thickness h increases, and thick brine film is an indication of a water-wet state. 627

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spontaneous imbibition are obtained by reading the scales at the top of the Amott cells and the corresponding time intervals of imbibition are also recorded. Still, the surfactant solutions and mineral oil used in the experiments are the same as that in the contact-angle experiments in the same environment. 3. Results and discussions 3.1. Experimental results 3.1.1. Contact angle experiments The experiments are measured by captive bubble method in different surfactants solutions. The contact angle of the water phase for the water/oil/rock system is equal to 180°minus the contact angle of the oil phase which can be measured by the Dataphysics equipment directly. The results of contact-angle experiments are shown in Fig. 6 and Fig. 8. The contact angles of original shale cores are over 105°, indicating the original wettability of shale cores is oil-wetness. The contact angles are measured with the added surfactants at 5 min. During this time, the droplets can be stabilized. The efficiency of the anionic surfactants on wettability alteration is similar to that of the nonionic surfactants at 5 min (as shown in Fig. 6). After the shale cores were soaked in the surfactant solutions for 48 h, lots of small oil droplets appear on the surface of the shale in the anionic surfactants, however, there are no oil droplets appeared in the nonionic surfactants as shown in Fig. 7. In addition, the measured contact angles of the shale samples in anionic surfactant solutions are greatly reduced after soaking for 48 h (c.f. Fig. 8). However, the measured contact angles of shale cores in nonionic surfactant solutions are almost unchanged after 48 h compared with 5 min as shown in Figs. 6 and 8. To further study the time dependent effect of anionic surfactants on the wettability alteration of the shale rocks the contact angles along with time are measured by using the Dataphysics equipment. The experimental results are shown in the Fig. 9. The curves show that the measured contact angle decreases with the soaking time. As the concentration of the surfactants increases, the rate of decline increases, and the final contact angles are also smaller, which indicates the rock surfaces are more water-wet with higher concentration.

Fig. 4. Zetasizer Nano Z device.

during the measurement. All tested solutions were maintained with the similar ionic strength to keep the Debye Length constant and the PH value relatively stable, which lies between 6 and 8 throughout the experiments. 2.5. IFT measurements The IFT between each surfactant and mineral oil are performed by using Dynamic Wilhelmy method (Bahramian, 2012). In this method, aqueous solution is placed at the bottom of the vessel and the mineral oil is floating upward because of the gravity. At the beginning of the experiment, the small platinum plate is soaked in the aqueous solution, then the instrument base moves slowly downwards to make the platinum plate passing through the oil-water interface. Meanwhile, the additional tension is gradually increased. When this tension reaches the maximum, the oil-water IFT is obtained. Note that the surfactants solution and mineral oil used in these experiments are the same as the contact-angle experiments in the same environment. 2.6. Spontaneous imbibition experiments

3.1.2. ζ-potential measurements The ζ-potentials of shale particles in four different surfactant solutions are measured separately and the experimental results are shown in Fig. 10 ζ-potential values are negative because the main components of shale are quartz and calcite. The surfaces of rock particles are negatively charged. In the experimental results, the absolute value of ζ-potential of shale particles in the water is 13.1 mV, which is the smallest and it increases with added surfactants in the aqueous solution. In the same surfactant solutions, as the concentration of the surfactant increases, the absolute values of the ζ-potential increase. And the increase in anionic surfactants is much greater than in nonionic surfactants. At the same concentration, the values of the ζ-potential in the anionic surfactant solutions is higher than that in the nonionic surfactant solutions. In addition, the nonionic surfactant solutions at concentrations of 0.01 wt%, 0.05 wt% and 0.1 wt% show the absolute values of theζpotential less than 20 mV, which are similar to the fracturing water without surfactants added.

Spontaneous imbibition experiments are performed to investigate and compare the effects of different surfactants on enhancing the wateruptake by shale cores. Before the experiments, the experimental cores need to be vacuumed 24 h for preventing residual air in the cores. Then, the mineral oil is injected into the saturation cell and the saturation pressure is kept as 35 MPa for 2 weeks. After saturating the shape cores with mineral oil, we soak them in modified Amott cells which are filled with different surfactants solutions as shown in Fig. 5. The cores were placed at the bottom of the cells, the displaced oil from shale samples floats up to the top of the cells due to the buoyancy effect. The volume of the displaced oil by

3.1.3. IFT experiments These measurements are conducted using mineral oil and the same surfactants are used as in the contact-angle and ζ-potential experiments. The experimental results are shown in Fig. 11. For the fracturing fluid without surfactants, the water-oil system presents an IFT of 16.69 mN/ m. The measured IFT decreases rapidly by adding surfactants at concentrations of 0.01 wt%, 0.05 wt% and 0.1 wt%. The AES surfactant reduce the IFT to 4.89–7.45, the AOS surfactant reduce the IFT to

Fig. 5. The spontaneous imbibition experiments are performed by using modified Amott cells with different types of surfactants solutions. 628

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Fig. 6. The measured contact angles at different surfactant concentrations with cores soaked for 5 min.

3.37–5.28, the AEO-9 surfactant reduces the IFT to 4.27–6.95 and the IAE surfactant reduces the IFT to 5.12–6.87. It indicates that the efficiencies of the nonionic and anionic surfactants are similar for the reduction of the IFT.

only 5% and the recovery is significantly increased after adding surfactants. With adding nonionic surfactants, the oil recovery increases to 13.5%–20.65%. The anionic surfactants perform even better, recovering 27.48%–34.66% of the OOIP.

3.1.4. Spontaneous-imbibition experiments The shale cores used in the spontaneous-imbibition experiments are all from the same depth of the reservoir. They were aged in crude oil from the well at the reservoir temperature for more than 2 months, and the physical parameters and initial wettability are shown in Table 3. As shown in the table, initially the wettability of the experimental samples is oil-wet. The spontaneous imbibition study consists of nine groups of experiments with different concentrations of anionic and nonionic surfactant solutions: 0.01% AES, 0.1% AES, 0.01% AOS, 0.1% AOS, 0.01% AEO-9,0.1% AEO-9,0.01% IAE, 0.1% IAE and the fracturing water with no surfactant. The oil recovered by spontaneous imbibition is measured by graduated cylinders at the top of modified Amott cells. The oil recovered is presented as percentage of the original oil in place (OOIP) vs. time as shown in Fig. 12. The oil recovery in fracturing water is approximately

3.2. The mechanisms of anionic and nonionic surfactants on wettability alteration of shale samples In contact-angle experiments, these results (Figs. 6 and 8) show that the anionic surfactants perform better in wettability alteration compared with the nonionic surfactants, which is believed to be caused by the electrostatic forces (Alvarez and Schechter, 2017b; Austad et al., 1998; Sharma and Mohanty, 2013). Note that the main mineral components of the experimental shale are quartz and clay as shown in Table 1. These minerals are negatively charged (the ζ potential is negative). They can adsorb the positively charged organic matter and oil molecules (Alvarez and Schechter, 2017b). Therefore, the original wettability of shale rock is oil-wet. The experimental phenomenon of Fig. 7 shows that the organic material and oil film are detached in anionic surfactants solutions but do not appear in nonionic surfactants.

Fig. 7. Shale cores were soaked in the surfactant solutions for 48 h. There are plenty of small oil droplets on the surface of the shale in the anionic surfactants. 629

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Fig. 8. Measured contact angles for shale cores at different surfactant concentrations with cores soaked for 48 h.

nonionic surfactants solutions due to the absence of charged heads. The nonionic surfactants could alter the rock wettability by their hydrophobic tails adsorbed on hydrophobic surfaces with their hydrophilic headgroups oriented toward the bulk solutions. The wettability of oilwet surfaces can only be changed to less oil-wet or intermediate-wet (as shown in Fig. 8) and this process is reversible because of the weak hydrophobic interactions (Salehi et al., 2008a; Standnes et al., 2002). We can imply that anionic surfactants have greater capacity of wettability alteration by forming ion-pairs than nonionic surfactants by comparing the experimental results of Figs. 6 and 8. We also found that mechanisms of wettability alteration by forming ion-pairs takes a certain amount of time unlike other mechanisms of wettability by surfactants adsorption which make the contact angle decrease immediately and then does not change. And the strength and speed of wettability alteration in anionic surfactant solution increases as the concentration of surfactant increase as shown in Fig. 9. In ζ-potential measurements, the absolute values of the ζ-potential increases when the surfactant is added. As mentioned in section 2.4, the ΠEDL increases in magnitude as the potentials become more negative, which indicate a thicker and more stable brine film appears between oil and shale surface as shown in Fig. 13. Therefore, higher ζ-potential values represent better stability of the water film attached to the rock surfaces, which can prevent the oil film from adsorbing on the shale surface again and keep the system more water-wet. These experimental results show that the added surfactants can improve the water film stability of the shale rock surfaces and strengthen the hydrophilicity of its surfaces. Compare ζ-potentials in different surfactants solutions, the ζ-potentials in the anionic surfactants solutions are higher than those in the nonionic surfactants solutions. It indicates that the rock surface has a thicker and more stable water film and keep more water-wet in the anionic surfactants solutions. And the nonionic surfactants only weakly change the wettability of oil-wet shale as the ζ-potentials is similar to that in water. In addition, as the concentration of the surfactant increases, the absolute values of the ζ-potential increase. This is an indication that the wettability of the shale alters to more water-wet as the concentration increases. Combined with contact angle experiments, both the experiments fully demonstrate that the anionic surfactant changes the wettability much better than nonionic surfactants by forming ion-pairs and can keep water-wet by forming a thick and stable water film on the shale surface. Comparing the results of the IFT with contact-angle experiments, the wettability of shale surface is more water-wet as the IFT decreases in the anionic surfactant solutions, while it is merely changed for low

Fig. 9. Contact angle measurements of shale cores soaked in the anionic surfactants changes with respect to time.

This indicates that the two types of surfactants have different mechanisms for changing the wettability. In anionic surfactants solutions, the positively charged organic matter and oil molecules which adsorb to the siliceous shale surfaces will interact with the negatively charged heads of anionic surfactants and form ion-pairs. However, the formation of ion-pairs could not be applicable for the wettability alteration in 630

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Fig. 10. ζ-potential measurements for shale cores at different surfactant concentrations.

IFT conditions in nonionic surfactants. As the IFT of oil-water (σow) decreases, the oil film desorption does not significantly increase the free energy of system (W) as the adhesion work equation (Eq. (4)) indicates. The process is shown in Fig. 14. Therefore, the IFT reduction is beneficial to the desorption of oil film or organic matter on the rock surfaces and wettability alteration by forming ion-pairs. However, in nonionic surfactant solutions, the oil film or organic matter will not be stripped without electrostatic forces. They alter the wettability of shale by adsorption rather than the way shown in Fig. 14. That is why the effect of wettability alteration by IFT reduction is not as effective as in anionic surfactant. Similar experimental results can be found in the previous papers (Alvarez and Schechter, 2017b; Kumar et al., 2008), but they have not deeply studied the effect of IFT reduction on the two different mechanisms of wettability alteration. In summary, the IFT reduction favors the wettability alteration of oil-wet shales in anionic surfactant solutions, but it has no effect in nonionic surfactant solutions. Because the mechanisms of wettability alteration of oil-shale are different in the different types of surfactants.

Table 3 Basic parameters of the spontaneous imbibition experiments. Core #

Length (mm)

Diameter (mm)

Porosity (%)

Initial contact angles (°)

Surfactant added

Y-1 Y-2 Y-3 Y-4 Y-5 Y-6 Y-7 Y-8 Y-9

48.99 50.7 46.11 50.55 46.56 49.83 50.85 50.04 50.28

25.29 25.27 25.30 25.25 25.42 25.28 25.35 25.36 25.35

4.03 3.81 3.86 4.11 4.03 4.07 4.12 4.51 4.61

137.0 134.8 129.5 144.6 135.9 138.7 132.1 125.9 140.6

0.01% AES 0.1% AES 0.01% AOS 0.1% AOS 0.01% AEO-9 0.1% AEO-9 0.01% IAE 0.1% IAE Fracturing water

capillary pressures. With the nonionic surfactants (AEO-9, IAE) added, the IFT decreases and wettability of rock surface is altered to be intermediate-wet as shown in Figs. 11 and 8, the recovery factors increase and the final recoveries are around 2–4 times of that in pure water. The anionic surfactants yield even better results and the oil recoveries increase by 5–7 times of that in water. As the nonionic and anionic surfactants yield the approximate similar IFT values at the same concentration, the reason why anionic surfactants yield higher oil recoveries is their higher efficiency on wettability alteration. There are sudden increases in the rate of spontaneous imbibition for anionic

3.3. The effect of surfactants on spontaneous imbibition From the spontaneous imbibition curve as shown in Fig. 12, the water can't drive much oil in the pores though spontaneous imbibition process without surfactant addition. Because the initial wettability of the shale cores is oil-wet and oil is trapped inside the pores by negative

Fig. 11. Measured IFT values of shale cores in different surfactants with different concentrations. 631

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Fig. 12. Oil recoveries from spontaneous imbibition experiments with and without various surfactants added.

on the spontaneous imbibition process of the oil-wet shale samples. The following conclusions are drawn.

surfactants solutions between 48 h and 120 h, which probably caused by the wettability alteration inside the pores. Compared with the process of spontaneous imbibition of different concentrations of anionic surfactants solutions (AOS and AES), the rates of imbibition decrease and the equilibrium time of imbibition is prolonged in higher concentrations because of IFT reduction. IFT reduction leads to reduced positive capillary pressure and decreases the rates of spontaneous imbibition. Meanwhile, IFT reduction is beneficial to the striping of the oil film to promote the wettability alteration and enhance the final oil recovery. They are trading off with each other. In summary, for both types of surfactants, wettability alteration is the controlling factor to improvement oil recovery of shale reservoirs. For anionic surfactants, higher concentration which effects IFT and wettability promotes the wettability alteration and enhances the oil recovery by spontaneous imbibition, but it will decrease positive capillary pressure and hence decrease the rates of imbibition. For nonionic surfactants, higher concentration which mainly leading to IFT reduction increases both the imbibition rate and final recovery, but the enhancement is not significant. The experimental results may shed some light on choosing appropriate surfactant additives in fracturing fluids and optimizing the schedules of soaking and flowback in the shale reservoirs.

(1) Contact-angle experiments demonstrate that the initial wettability of the Sichuan shale reservoirs is oil-wet and surfactants have the potential to alter the wettability to water-wet or intermediate-wet state. (2) Anionic surfactants have greater capacity of wettability alteration by forming ion-pairs than nonionic surfactants on shale surface, however, the process is relatively slow. (3) Because of IFT reduction by anionic surfactants, the energy after oil stripping (oil-wetness is reduced) is reduced, from that point of view, IFT reduction may help wettability alteration. (4) The ζ-potential experiments show that the water film is more stable with the increase of surfactant concentration. Anionic surfactant changes the wettability much better than nonionic surfactants for the shale reservoirs. (5) The anionic surfactants produced oil more than the nonionic surfactants because the wettability of oil-wet shale is changed to more water-wet and the oil film desorbed from the surfaces of shale pores.

Acknowledgement 4. Conclusions The support by the Fundamental Research Funds for the Central Universities of China is appreciated.

Through various experimental studies, the objectives of this work are to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and IFT reduction

Fig. 13. The oil film is stripped off from the rock surface and a stable water film appears between the surface and the oil with added surfactants in the solution, which leads to wettability altered on the oil-wet shale surface. 632

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Fig. 14. Schematic of the oil film stripping process.

W= (σow + σws ) A − σos A

Appendix A. Supplementary data

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