Surfactant flooding is one of the successful techniques employed in enhanced oil recovery (EOR) to extract the remaining original oil in place after primary and secondary recoveries are performed. Selection of the right EOR surfactant is an important but demanding task due to a series of screening procedures that need to be executed to have a comprehensive evaluation. This article presents the experimental work done on the initial screening of ten surfactants from three different classes, namely nonionic, anionic, and amphoteric. The screening was completed with three consecutive series of testing, which are surfactant compatibility, phase behavior, and interfacial tension (IFT). Results showed that an anionic surfactant, sodium decylglucoside hydroxypropyl phosphate, passed all tests with the lowest IFT value of 8 × 10−3 mN/m at 0.1 wt% of surfactant concentration.
Oil recovery can be divided into three phases, namely primary, secondary, and tertiary. In the primary oil recovery, the natural pressure difference between the surface and the reservoir drives the crude oil into the production wellbore. During the secondary oil recovery, the crude oil is extracted from the underground reservoir by maintaining the reservoir pressure through two techniques, which are water injection and waterflooding. For the tertiary oil recovery or known as enhanced oil recovery (EOR), additive(s) is added to retrieve the remaining oil .
One of the extensively studied additives for EOR is a surfactant [1,2,3] because in many cases, the oil recovered using surfactant will be cleaner than the oil extracted by water injection at large water cuts . A surfactant, or also known as a surface-active agent, is composed of two functional groups, which are nonpolar hydrophobic (oil-soluble) tail and polar hydrophilic (water-soluble) head. The hydrophobic group is usually a long hydrocarbon chain (linear or branched), fluorocarbon, siloxane chain, or short polymer chain. The hydrophilic group may be formed by moieties in which the ionic nature of the moieties was used to classify the surfactants, namely anionic, cationic, nonionic, and amphoteric (or zwitterionic) [5,6,7]. Among these, anionic surfactants are very effective for EOR application in sandstone reservoirs due to the similarity of anionic charges and sandstone reservoir surface .
The concept of EOR surfactant was initiated in the early 1900s . There are two main mechanisms of surfactant in EOR, namely interfacial tension (IFT) reduction and wettability alteration [3,8,9,10]. Regarding the IFT, surfactant functions by reducing the IFT between the crude oil and the aqueous phase, thereby increasing the capillary number, decreasing the capillary pressure, and allowing the aqueous phase to push out and mobilize the trapped oil and thus enhancing the oil recovery [3,6,9,10,11,12,13,14,15]. In the case of wettability, the surfactant can alter the reservoir wettability toward becoming more water-wet, thus detaching the trapped oil from the reservoir rock surface and lowering residual oil saturation, and consequently improving the oil recovery [3,7,9,16]. Most EOR surfactant works in sandstone reservoirs focus on IFT reduction [1,14,15,16,17] rather than wettability, as wettability alteration plays a major role in carbonate reservoirs [2,3,7,10,16].
A thorough laboratory work must be carried out in selecting a suitable surfactant for EOR. The surfactant may perform differently, depending on the reservoir conditions, such as temperature, pressure, salinity, and type of crude oil. The criteria of a good surfactant for EOR are as follows: (1) good thermal stability at reservoir temperature, (2) capability to reduce IFT to 10−3 mN/m and below, (3) have low retention on reservoir rock (<1 mg/(g of rock)), (4) ability to withstand reservoir salinity, (5) good compatibility with additives (i.e., cosurfactant, cosolvent, and polymer), (6) availability in the market, and (7) cost-effective . Therefore, this study focuses on the initial screening work for surfactant selection, namely surfactant compatibility, phase behavior, and IFT.
2 Materials and methods
A total of ten surfactants from three different categories such as nonionic, anionic, and amphoteric surfactants were evaluated in this study, as listed in Table 1, and their general molecular structure is shown in Figure 1.
|No.||Surfactant||Category||Solid content (wt%)||Supplier|
|S1||Alkyl polyglucoside C8–16 (C8–10: 25–75 wt%, C10–16: 10–25 wt%)||Nonionic||66||BASF|
|S2||Alkyl polyglucoside C8–16 (C8–10: 25–50 wt%, C10–16: 10–20 wt%)||Nonionic||55||BASF|
|S3||Alkyl polyglucoside C8–10 (C8–10: 50–75 wt%)||Nonionic||74||BASF|
|S4||Sodium laurylglucoside hydroxypropylsulfonate||Anionic||42||Colonial chemical|
|S5||Sodium hydroxypropylsulfonate laurylglucoside crosspolymer||Anionic||42||Colonial chemical|
|S6||Sodium decylglucoside hydroxypropyl phosphate||Anionic||42||Colonial chemical|
|S7||Sodium bis-hydroxyethylglycinate coco-glucoside crosspolymer||Amphoteric||42||Colonial chemical|
|S8||Sodium bis-hydroxyethylglycinate lauryl-glucoside crosspolymer||Amphoteric||42||Colonial chemical|
|S9||Lauryl hydroxysultaine||Amphoteric||54||Colonial chemical|
|S10||Cocamidopropyl hydroxysultaine||Amphoteric||51||Colonial chemical|
The salts used to make the Field X synthetic brine were obtained from Sigma-Aldrich. The compositions of the synthetic brine utilized in this study are presented in Table 2, with a total salinity of 33,142 ppm. For the hydrocarbon oil, Field X crude oil (American Petroleum Institute gravity of 30.58, density of 0.8676 g/cm3 at room temperature, and viscosity of 2.8 cP at reservoir temperature) was used throughout this experiment.
2.2.1 Solubility and compatibility
The required salts are weighed according to Table 2. Deionized water was added to the salts up to the graduation mark in a 1 L volumetric flask. The solution was stirred using a stirring plate until the salts are completely dissolved. The prepared brine was filtered using 0.45 µm filter paper before using the brine solution.
Surfactant solution of 1 wt% was prepared by diluting the surfactant solutions with synthetic brine. Two sets (Set A and Set B) of solutions were prepared for each surfactant to evaluate the solubility at ambient and reservoir temperatures. Set A was stored at ambient temperature, while Set B was stored at reservoir temperature of Field X. The physical change of surfactant‒brine solutions was observed for up to 7 days. Surfactant solubility and compatibility were categorized as either soluble (clear) or non-soluble (cloudiness, phase separation, and/or precipitation) composition, as shown in Figure 2. From this test, only surfactant solution with soluble composition was further assessed via phase behavior [15,18].
2.2.2 Phase behavior
A thin glass tube was labeled according to the surfactant name and concentration. For each surfactant, the surfactant‒brine solution was prepared at five different concentrations, which are 0.1, 0.3, 0.5, 0.8, and 1.0 wt%, respectively. The volume ratio of oil to surfactant solution was fixed at 1 (oil/water ratio [OWR] = 1). Deionized water was used as a blank to compare the change of oil color. The glass tube was filled up with 2 mL of surfactant solution (or deionized water for blank) and then 2 mL of Field X crude oil sample. The glass tube opening was sealed with epoxy resin and checked to ensure no leakage. The tube containing oil and surfactant solution was shaken thoroughly by tilting vertically at 180° up to approximately 20 times. The tube was then stored in the oven at reservoir temperature of Field X at static conditions to attain equilibrium. The tube was tilted at the interval of 2 h for 3 days (overnight) and left for another 4 days in the oven without shaking. The observation was performed on Day 0, Day 1, Day 4, Day 7, and up to Day 14. Usually, equilibrium is reached after 1–2 days but sometimes it takes longer. Visual inspection was performed to note any changes in color, level, or volume of the oil, aqueous, and microemulsion (if any) layers [15,18,19,20].
According to Sheng [3,7,10], there are three types of microemulsions, namely Winsor type I, II, and III microemulsions, as shown in Figure 3. From this observation, the surfactant solution with Winsor type I or III was further tested for the IFT . Although the IFT value for Winsor type I is not as low as Winsor type III, which is the optimal condition for EOR, this Winsor type I still gives significantly low IFT even without the middle-phase formation . Furthermore, the oil recovery factor by cationic surfactant showed that Winsor type I or III is favored compared to Winsor type II microemulsion .
Before IFT measurement, the densities of both surfactant‒brine sample and Field X crude oil were measured using portable density meter DMA 35 (Anton Paar) at 25°C as shown in Figure 4. IFT measurement was performed using an M6500 spinning drop tensiometer (Grace Instrument) as shown in Figure 4. All the control switches (power, strobe light, rotation, and micrometer) were turned on. The Watlow temperature controller was changed to the desired temperature, which is at the reservoir temperature of Field X. The rotation control speed knob was set to zero. The Grace instrument was adjusted to ensure it is leveled and stable using the adjustment knob.
The surfactant‒brine sample (higher density) was filled into the glass capillary, with the capillary held at 45° angle from the horizontal plane, and the syringe needle is touched against the capillary wall until the sample oozed out from the mouth of the tube. The capillary was checked to ensure that no bubble is formed inside it and wiped to remove the excess sample. The capillary was inserted into the rotating chamber and gently capped with a screw cap, which is equipped with a septa and O-ring. The rotation was started at a slow speed (2,500 rpm), and the capillary was observed through a microscope eyepiece to check for any air bubble. It is important to remove all bubbles as the bubbles can affect the IFT measurement.
Once all bubbles have been removed, a minuscule volume (around 0.5 µL to less than 1.0 µL) of pre-warmed Field X crude oil (lower density) was injected into the filled glass capillary from outside of the cap using Hamilton syringe. The syringe was withdrawn quickly and the tensiometer was angled to 10–20° to allow the oil droplet to move to the middle of the capillary, away from the entry point. The rotation was started at the desired speed (3,000–6,000 rpm for approximately 0.5 µL of oil) until the length of the oil droplet is at least four times its diameter. The tensiometer was leveled until the oil droplet is stationary along the capillary.
The oil droplet diameter and speed were recorded every 5 min for at least 60 min. The IFT value was calculated using the following equation:
where γ is the IFT (mN/m), ∆ρ is the density difference between surfactant in brine and oil (g/cm3), d is the diameter (mm) taken directly from the tensiometer, and θ is the rotational speed (rpm) taken directly from the tensiometer.
Ethical approval: The conducted research is not related to either human or animal use.
3.1 Solubility and compatibility
|Testing temperature (°C)||Surfactant|
3.2 Phase behavior
|Surfactant concentration (wt%)||Surfactant|
4.1 Solubility and compatibility
The purpose of this test is to check whether the surfactant is soluble and compatible with the formation water  and thus eliminate the surfactant non-solubility problem . Furthermore, the surfactant was evaluated in brine at an elevated temperature to simulate the target reservoir conditions . For initial screening, there were ten surfactants under three categories, namely nonionic, anionic, and amphoteric, evaluated for their solubility and compatibility in synthetic brine at both ambient and reservoir temperatures.
The surfactant solubility decreases as salinity increases. Therefore, the surfactant solution has a high possibility to form precipitation in brine due to the existence of divalent or multivalent ions [7,15]. Figure 5 shows the observation on solubility and compatibility of the surfactants at both ambient and reservoir temperatures after 7 days. All the ten surfactants have very good performance of solubility and compatibility as no non-soluble composition was observed throughout the testing period even though synthetic brine was used, as summarized in Table 3. Hence, all surfactants were continued for the phase behavior test. The surfactant solution must be in soluble composition at both ambient and reservoir temperatures to ensure that it is in a single-phase solution before and after injection. This is because the injection of non-soluble composition can result in nonuniform distribution of the injected solution and nonuniform transport due to phase trapping or different motions of the coexisting phases .
Therefore, it is essential to identify surfactants with high solubility attributes so that surfactant performance can be maximized. The surfactant solubility is very much dependent on the type of hydrophilic moiety and the alkyl chain length of the hydrophobic fraction. In this work, alkyl polyglucoside-based surfactants ranging from nonionic, anionic, and amphoteric types were evaluated. The solubility of the alkyl polyglucoside-based surfactants could be anticipated from the solubility of the sugar used as its hydrophilic head . This can be explained by the higher degree of hydrogen bonding between the hydroxyl groups present in the sugar head group and water-forming stable solute–solvent interactions. The solubility of these sugar-based surfactants can be improved by making the head group more hydrophilic by reaction of the hydroxyl groups with a proper reagent to turn them into anionic or amphoteric surfactants [22,23]. Alkyl polyglucoside-based surfactants are also known for their tolerance in high electrolyte conditions, which make them suitable to be used for EOR-related applications as demonstrated by Wei et al. .
4.2 Phase behavior
The phase behavior of a microemulsion system must be determined through experimental study since there is no common equation of state even for a simple microemulsion. This is due to the complexity and dependency of phase behavior on various parameters, for example, the types and concentrations of surfactants, cosolvents, hydrocarbons, brine salinity, temperature, and pressure . Phase behavior evaluation is a helpful approach in screening various types of surfactant systems . Besides, it is commonly utilized in single surfactant systems before IFT measurement as it is a simple method  to select and optimize the concentrations of injected chemicals in a short time . The performance and interaction of surfactants, brine, and hydrocarbon in producing a microemulsion can be understood from the phase behavior [13,19,20]. A total of ten surfactants were evaluated since all of them passed the initial solubility and compatibility testing.
The phase behavior of all tested surfactants at five different surfactant concentrations and OWR = 1 is shown in Figure 6. Initially, at the lowest concentration of 0.1 wt%, only S10, which is cocamidopropyl hydroxysultaine, formed Winsor type III microemulsion. However, as the surfactant concentration increased up to 1.0 wt%, S4, S5, and S8, which are sodium laurylglucoside hydroxypropylsulfonate, sodium hydroxypropylsulfonate laurylglucoside crosspolymer, and sodium bis-hydroxyethylglycinate lauryl-glucoside crosspolymer, respectively, also formed Winsor type III microemulsion together with S10 surfactant. Other surfactants formed Winsor type I even at higher surfactant concentration. Changing the surfactant concentration can alter the phase behavior to a great extent . Through this observation, it was found that some surfactants do have the ability to form Winsor type III microemulsion without any additives as summarized in Table 4.
Several factors influence the phase behavior of the oil‒water system in the presence of surfactant. Some of the key factors reported are the molecular structure of the surfactant, the concentration of the surfactant used, ethylene oxide/propylene oxide moiety present in a surfactant, cosolvent, salinity, temperature, oil type, and water‒oil ratio [5,25]. Surfactant structure is crucial in determining the phase behavior which is demonstrated in the work presented here. S1, S2, and S3 are nonionic surfactants that are only capable of forming Winsor type I microemulsion, or in other words, they are not able to form a middle-phase microemulsion. To allow the transition from Winsor type I to Winsor type III, the surfactant hydrophobicity and the system temperature should be increased as described by Han et al. . S10 achieved Winsor type III from the first concentration evaluated and this could be explained by that the amphoteric surfactant has achieved the required optimum concentration and salinity to form the middle-phase microemulsion. The phase transition from Winsor type I to Winsor type III observed in S4, S5, and S8 potentially contributed to having the optimal concentration in the formulation [5,25].
There will be a very low possibility of the occurrence of a practical problem when a standard phase behavior evaluation is performed at a low surfactant concentration with OWR = 1 because the majority of Winsor type III system exists in three phases, which consist of oil, microemulsion, and water. However, there will be a common concern when using crude oils due to some issues, for instance, the difficulty in determining the interfaces as the microemulsions are usually formed at interfaces and will require an extended period to coalesce .
According to Tongcumpou et al. , even though the formation of microemulsion usually requires additional chemicals apart from the surfactant itself, it has been reported that single surfactant systems can form microemulsions without any cosurfactants or additives under certain conditions. Ghosh and Miller  discovered that an anionic surfactant, sodium bis(2-ethylhexyl) sulfosuccinate, which is known as Aerosol OT (AOT), produced Winsor type III using AOT–brine–n-dodecane at 2.5 wt% of AOT concentration, OWR = 1, and temperature of 30°C, with brine salinity varying from 1.0 to 2.0 wt% of NaCl. The same finding was also observed by Zulkifli et al.  using an anionic surfactant, alkyl ether carboxylate (AEC). Winsor type III was formed by AEC‒seawater brine‒crude oil composition for all surfactant concentrations between 0.2 and 1.0 wt% at an elevated temperature of 106°C.
It is still unclear whether a low surfactant concentration of below 1.0 wt% can produce Winsor type III microemulsion. Therefore, it is preferable to have Winsor type I for a very low surfactant concentration because a small volume of Winsor type III microemulsion with a highly concentrated surfactant could be easily bypassed (trapped)  or the microemulsion phase is so thin that it cannot be seen or considered as insignificant . Additionally, Winsor type I can also result in a low IFT value, even if it is not as low as Winsor type III which gives ultralow IFT of 10−3 mN/m . From this study, as all surfactants gave either Winsor type 1 or III microemulsion, all were further tested for IFT measurements.
The general principle for a successful surfactant flooding in EOR is that the IFT should be reduced to ultralow, at the range of 10−3 mN/m and below, of a typical reservoir brine‒crude oil system, to overcome the capillary forces holding the oil in a reservoir [13,14,15]. Since none of the surfactants has Winsor type II microemulsion, all proceeded with IFT measurements.
The results of IFT measurements are shown in Figure 7. The lowest IFT values for all surfactants were observed at 0.1 wt% of surfactant concentration with the IFT <30 × 10−2 mN/m, except for S9 and S10 with IFT around 45 to 55 × 10−2 mN/m. Besides, all surfactants have significantly lower IFT as the surfactant concentration decreases from 1.0 to 0.1 wt%, except for S4, S5, and S8 which have the IFT at a range from 10 to 30 × 10−2 mN/m. On the other hand, S6, which is sodium decylglucoside hydroxypropyl phosphate, gave the lowest IFT value of 8 × 10−3 mN/m at 0.1 wt% of surfactant concentration. The surfactant concentration was further decreased to 0.05 wt% to determine the optimum point. However, the IFT value was increasing instead of decreasing, which gives the optimum concentration to be at 0.1 wt% as shown in Figure 8.
Zulkifli et al.  found that AEC alone at 0.4 wt% of surfactant concentration can reduce the IFT to around 3.5 × 10−3 mN/m at 106 °C. Meanwhile, at the same temperature, a blend formulation of AEC and a modified alkyl polyglucoside with a ratio of 50:50 was able to achieve approximately 5.5 × 10−3 mN/m at a lower surfactant concentration of 0.2 wt%. In another study using an anionic surfactant, sodium dodecylbenzenesulfonate (SDBS), the IFT can only be reduced to the 10−1 mN/m region in the SDBS-diluted formation brine‒crude oil system at 80°C. As the concentration of SDBS increased from 0 to 0.5%, the IFT was decreased from 28.86 to 0.82 mN/m. The IFT value was further reduced to 0.73 mN/m when the SDBS concentration was doubled to 1.0% . From these IFT values, all studied surfactants have comparable performance with the previously tested surfactants because all surfactants reached the 10−1 mN/m region, except for S6 surfactant which has the lowest IFT of 8 × 10−3 mN/m at lower concentration of 0.1 wt%.
Looking at the phase behavior and IFT results, even though S4, S5, S8, and S10 formed Winsor type III microemulsion, the IFT values are very much higher than 10−3 mN/m. The range of surfactant concentration that results in Winsor type III phase behavior and IFT cannot be directly compared since the OWR in phase behavior evaluation is around 100 times higher than the IFT measurement .
The surfactant cost greatly contributes to the overall cost of the chemical EOR project [2,15]. In some cases, a high surfactant concentration is needed during the surfactant injection which increases the chemical cost and thus the total project expenditure . Therefore, since the S6 surfactant decreases the IFT to the acceptable IFT range at a low surfactant concentration of 0.1 wt%, this surfactant can be considered as a potential candidate to be further evaluated with thermal stability, surfactant adsorption, and core flooding .
The authors would like to thank Nur Anisah Shafie, Nik Nor Azrizam Nik Norizam, and Norzafirah Razali from PETRONAS Research Sdn. Bhd., and Nur Atiqah Mohd Haris, internship student from Universiti Teknologi PETRONAS for their support throughout this work.
Funding information: The authors would like to acknowledge PETRONAS and PETRONAS Chemical Group Bhd. (PCGB) for funding this work.
Author contributions: Najiah Nadir: investigation and writing – original draft; Sara Shahruddin: supervision and writing – original draft; Jofry Othman: supervision and writing – original draft.
Conflict of interest: The authors state no conflict of interest.
Data availability statement: The datasets generated during and/or analyzed during this study are available from the corresponding author on reasonable request.
 Santa M, Alvarez-Jürgenson G, Busch S. Sustainable surfactants in enhanced oil recovery. SPE Enhanced Oil Recovery Conference. Kuala Lumpur: Society of Petroleum Engineers; 2011.10.2118/145039-MSSearch in Google Scholar
 Pal S, Mushtaq M, Banat F, Al Sumaiti AM. Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: Challenges and future perspectives. Pet Sci. 2018;15(1):77–102.10.1007/s12182-017-0198-6Search in Google Scholar
 Farajzadeh R, Kahrobaei S, Eftekhari AA, Mjeni RA, Boersma D, Bruining J. Chemical enhanced oil recovery and the dilemma of more and cleaner energy. Sci Rep. 2021;11:1–14.10.2118/200256-MSSearch in Google Scholar
 Kamal MS, Hussein IA, Sultan AS. Review on surfactant flooding: Phase behavior, retention, IFT, and field applications. Energy Fuels. 2017;31(8):7701–20.10.1021/acs.energyfuels.7b00353Search in Google Scholar
 Olajire AA. Review of ASP EOR (alkaline surfactant polymer enhanced oil recovery) technology in the petroleum industry: Prospects and challenges. Energy. 2014;77:963–82.10.1016/j.energy.2014.09.005Search in Google Scholar
 Sheng JJ. Modern chemical enhanced oil recovery: Theory and practice. Burlington: Gulf Professional Publishing; 2011.Search in Google Scholar
 Saxena N, Kumar A, Mandal A. Adsorption analysis of natural anionic surfactant for enhanced oil recovery: The role of mineralogy, salinity, alkalinity and nanoparticles. J Pet Sci Eng. 2019;173:1264–83.10.1016/j.petrol.2018.11.002Search in Google Scholar
 Ebaga-Ololo J, Chon BH. Experimental investigation of the influence of salinity gradient on low-concentration surfactant flooding in Berea sandstone. J Ind Eng Chem. 2018;68:355–63.10.1016/j.jiec.2018.08.007Search in Google Scholar
 Flaaten A, Nguyen QP, Pope GA, Zhang J. A systematic laboratory approach to low-cost, high-performance chemical flooding. SPE Symposium on Improved Oil Recovery. Oklahoma: Society of Petroleum Engineers; 2008.10.2118/113469-MSSearch in Google Scholar
 Wu Y, Iglauer S, Shuler P, Tang Y, Goddard WA. Branched alkyl alcohol propoxylated sulfate surfactants for improved oil recovery. Tenside Surfactants Deterg. 2010;47(3):152–61.10.3139/113.110064Search in Google Scholar
 Zulkifli NN, Mahmood SM, Akbari S, Manap AAA, Kechut NI, Elrais KA. Evaluation of new surfactants for enhanced oil recovery applications in high-temperature reservoirs. J Pet Explor Prod Technol. 2020;10(2):283–96.10.1007/s13202-019-0713-ySearch in Google Scholar
 Yassin MR, Ayatollahi S, Rostami B, Hassani K, Taghikhani V. Micro-emulsion phase behavior of a cationic surfactant at intermediate interfacial tension in sandstone and carbonate rocks. J Energy Resour Technol. 2015;137(1):1–12.10.1115/1.4029267Search in Google Scholar
 Tongcumpou C, Acosta EJ, Quencer LB, Joseph AF, Scamehorn JF, Sabatini DA, et al. Microemulsion formation and detergency with oily soils: I. Phase behavior and interfacial tension. J Surfactants Deterg. 2003;6(3):191–203.10.1007/s11743-003-0262-5Search in Google Scholar
 Ghosh B, Obasi D. Eco-friendly surfactant for EOR in high temperature, high salinity carbonate reservoir. SPE Enhanced Oil Recovery Conference. Kuala Lumpur: Society of Petroleum Engineers; 2013.10.2118/165219-MSSearch in Google Scholar
 Adkins S, Arachchilage GP, Solairaj S, Lu J. Development of thermally and chemically stable large-hydrophobe alkoxy carboxylate surfactants. SPE Improved Oil Recovery Symposium. Oklahoma: Society of Petroleum Engineers; 2012.10.2118/154256-MSSearch in Google Scholar
 Levitt D, Jackson A, Heinson C. Identification and evaluation of high-performance EOR surfactants. SPE/DOE Symposium on Improved Oil Recovery. Oklahoma: Society of Petroleum Engineers; 2006.10.2118/100089-MSSearch in Google Scholar
 von Rybinski W, Hill K. Alkyl polyglycosides. In: Holmberg K, editor. Novel surfactants: Preparation applications and biodegradability. 2nd edn. New York: CRC Press; 2003. p. 35–93.10.1201/9780203911730.ch2Search in Google Scholar
 Anthony J, O’Lenick J, O’Lenick KA. Surfactants based upon alkyl polyglycosides. United States; U.S. Patent No. 6627612; 2003.Search in Google Scholar
 Anderson D, Smith DA, Anthony J, O’Lenick J. Amphoteric surfactants based upon alkyl polyglucoside. United States; U.S. Patent No. 6958315; 2005.Search in Google Scholar
 Wei P, Li J, Xie Y, Huang X, Sun L. Alkyl polyglucosides for potential application in oil recovery process: Adsorption behavior in sandstones under high temperature and salinity. J Pet Sci Eng. 2020;189:107057.10.1016/j.petrol.2020.107057Search in Google Scholar
 Esfandiarian A, Azdarpour A, Santos RM, Mohammadian E, Hamidi H, Sedaghat M, et al. Mechanistic investigation of LSW/surfactant/alkali synergism for enhanced oil recovery: Fluid–fluid interactions. ACS Omega. 2020;5(46):30059–72.10.1021/acsomega.0c04464Search in Google Scholar PubMed PubMed Central
© 2022 Najiah Nadir et al., published by De Gruyter
This work is licensed under the Creative Commons Attribution 4.0 International License.