scholarly journals Mechanism of active silica nanofluids based on interface-regulated effect during spontaneous imbibition

2021 ◽  
Author(s):  
Xu-Guang Song ◽  
Ming-Wei Zhao ◽  
Cai-Li Dai ◽  
Xin-Ke Wang ◽  
Wen-Jiao Lv
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Dynamic Contact Angle ◽  
Liquid Interface ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Low Permeability ◽  
Oil Water ◽  
Solid Liquid

AbstractThe ultra-low permeability reservoir is regarded as an important energy source for oil and gas resource development and is attracting more and more attention. In this work, the active silica nanofluids were prepared by modified active silica nanoparticles and surfactant BSSB-12. The dispersion stability tests showed that the hydraulic radius of nanofluids was 58.59 nm and the zeta potential was − 48.39 mV. The active nanofluids can simultaneously regulate liquid–liquid interface and solid–liquid interface. The nanofluids can reduce the oil/water interfacial tension (IFT) from 23.5 to 6.7 mN/m, and the oil/water/solid contact angle was altered from 42° to 145°. The spontaneous imbibition tests showed that the oil recovery of 0.1 wt% active nanofluids was 20.5% and 8.5% higher than that of 3 wt% NaCl solution and 0.1 wt% BSSB-12 solution. Finally, the effects of nanofluids on dynamic contact angle, dynamic interfacial tension and moduli were studied from the adsorption behavior of nanofluids at solid–liquid and liquid–liquid interface. The oil detaching and transporting are completed by synergistic effect of wettability alteration and interfacial tension reduction. The findings of this study can help in better understanding of active nanofluids for EOR in ultra-low permeability reservoirs.

Effects of Interfacial Tension Reduction and Wettability Alteration on Oil Recovery by Surfactant Imbibition

2013 ◽  
Vol 868 ◽  
pp. 664-668
Author(s):  
Zi Yuan Qi ◽  
Ye Fei Wang ◽  
Xiao Li Xu
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Spontaneous Imbibition ◽  
Surface Wettability ◽  
Wettability Alteration ◽  
Ionic Surfactants ◽  
Oil Sand ◽  
Sand Surface ◽  
Quartz Sands

Surfactant imbibition experiments were carried out with four surfactants and effects of interfacial tension and surface wettability on oil recovery were studied. A convenient imbibition process with quartz sands was used, and the experimental results suggest that anionic and non-ionic surfactants have higher oil recovery than cationic surfactant, and the sand surface wettability plays an important role in influencing oil recovery during spontaneous imbibition. Altering the wettability of oil sand surface from oil-wet to water-wet can enhance the oil recovery of imbibition process. The maximum ultimate imbibition recovery appeared in the area where both contact angle and interfacial tension were low.

Measurements of the Contact Angles for Various Fluids Which Are Widely Used in the Oilfields to Improve Oil Recovery

2018 ◽  
Author(s):  
M. Elsharafi ◽  
K. Vidal ◽  
R. Thomas
Keyword(s):  
Surface Tension ◽  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Dynamic Contact Angle ◽  
Dynamic Contact ◽  
Contact Angles ◽  
Rock Face ◽  
Angle Measurements ◽  
Contact Angle Measurements

Contact angle measurements are important to determine surface and interfacial tension between solids and fluids. A ‘water-wet’ condition on the rock face is necessary in order to extract oil. In this research, the objectives are to determine the wettability (water-wet or oil-wet), analyze how different brine concentrations will affect the wettability, and study the effect of the temperature on the dynamic contact angle measurements. This will be carried out by using the Cahn Dynamic Contact Angle. Analyzer DCA 315 to measure the contact angle between different fluids such as surfactant, alkaline, and mineral oil. This instrument is also used to measure the surface properties such as surface tension, contact angle, and interfacial tension of solid and liquid samples by using the Wilhelmy technique. The work used different surfactant and oil mixed with different alkaline concentrations. Varying alkaline concentrations from 20ml to 1ml were used, whilst keeping the surfactant concentration constant at 50ml.. It was observed that contact angle measurements and surface tension increase with increased alkaline concentrations. Therefore, we can deduce that they are directly proportional. We noticed that changing certain values on the software affected our results. It was found that after calculating the density and inputting it into the CAHN software, more accurate readings for the surface tension were obtained. We anticipate that the surfactant and alkaline can change the surface tension of the solid surface. In our research, surfactant is desirable as it maintains a high surface tension even when alkaline percentage is increased.

Effect of Dynamic Contact Angle on Spontaneous Capillary-Liquid-Liquid Imbibition by Molecular Kinetic Theory

SPE Journal ◽  
2021 ◽  
pp. 1-16
Author(s):  
Weibing Tian ◽  
Keliu Wu ◽  
Zhangxin Chen ◽  
Lingbin Lai ◽  
Yanling Gao ◽  
...  
Keyword(s):  
Contact Angle ◽  
Kinetic Theory ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Dynamic Contact Angle ◽  
Dynamic Contact ◽  
Viscous Effect ◽  
Molecular Kinetic Theory ◽  
Frictional Effect ◽  
Capillary Liquid

Summary Imbibition is one of the most common physical phenomena in nature, and it plays an important role in enhanced oil recovery, hydrology, and environmental engineering. The imbibition in a capillary is one of the fluid transports in porous media, and the effect of a dynamic contact angle that changes with the imbibition rate on liquid-liquid imbibition is not clear. In this paper, the molecular kinetic theory (MKT) is used to study the effect of a dynamic contact angle on spontaneous capillary-liquid-liquid imbibition at a micrometer scale. The results show that: Using a scaling time, the effects of various forces in different imbibition systems can be compared, the influence of a dynamic contact angle on imbibition can be characterized by a frictional effect of the three-phase contact line, and the proposed model considering the effect of a dynamic contact angle is better than the model neglecting the effect of a dynamic contact angle. As the displacing phase viscosity increases, the influence of a dynamic contact angle on imbibition strengthens, which is attributed to a decrease in the viscous effect and an increase in the frictional effect during the imbibition process; as the displaced phase viscosity increases, the influence of a dynamic contact angle on imbibition weakens, which is attributed to an increase in the viscous effect and a decrease in the frictional effect during the imbibition process. As the interfacial tension increases, the frictional effect increases, with the result that the effect of a dynamic contact angle on imbibition increases. As the capillary becomes more hydrophilic, the effect of a dynamic contact angle on imbibition becomes stronger because of a decreasing viscous effect and an increasing frictional effect. As the capillary length increases, the viscous effect increases, whereas the frictional effect decreases, leading to a decrease in the dynamic contact angle effect. As the capillary radius increases, the frictional force decreases, whereas its proportion in total resistance or the frictional effect increases, resulting in an increase in the effect of a dynamic contact angle. This work sheds light on the effect of a dynamic contact angle on capillary-liquid-liquid imbibition, including displacing phase viscosity, displaced phase viscosity, interfacial tension, capillary wettability, length, and radius. It will provide new insights into manipulating a capillary imbibition process and provide a fundamental theory for enhanced oil recovery by imbibition in conventional or unconventional reservoirs. Supplementary materials are available in support of this paper and have been published online under Supplementary Data at https://doi.org/10.2118/205490-PA. SPE is not responsible for the content or functionality of supplementary materials supplied by the authors.

scholarly journals Experimental study of the performances of commercial surfactants in reducing interfacial tension and wettability alteration in the process of chemical water injection into carbonate reservoirs

2019 ◽  
Vol 10 (4) ◽  
pp. 1551-1563 ◽  
Author(s):  
Siamak Najimi ◽  
Iman Nowrouzi ◽  
Abbas Khaksar Manshad ◽  
Amir H. Mohammadi
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Saline Water ◽  
Water Injection ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Core Flooding ◽  
Chemical Water

Abstract Surfactants are used in the process of chemical water injection to reduce interfacial tension of water and oil and consequently decrease the capillary pressure in the reservoir. However, other mechanisms such as altering the wettability of the reservoir rock, creating foam and forming a stable emulsion are also other mechanisms of the surfactants flooding. In this study, the effects of three commercially available surfactants, namely AN-120, NX-1510 and TR-880, in different concentrations on interfacial tension of water and oil, the wettability of the reservoir rock and, ultimately, the increase in oil recovery based on pendant drop experiments, contact angle and carbonate core flooding have been investigated. The effects of concentration, temperature, pressure and salinity on the performances of these surfactants have also been shown. The results, in addition to confirming the capability of the surfactants to reduce interfacial tension and altering the wettability to hydrophilicity, show that the TR-880 has the better ability to reduce interfacial tension than AN-120 and NX-1510, and in the alteration of wettability the smallest contact angle was obtained by dissolving 1000 ppm of surfactant NX-1510. Also, the results of interfacial tension tests confirm the better performances of these surfactants in formation salinity and high salinity. Additionally, a total of 72% recovery was achieved with a secondary saline water flooding and flooding with a 1000 ppm of TR-880 surfactant.

scholarly journals Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Polymers ◽  
2020 ◽  
Vol 12 (10) ◽  
pp. 2241
Author(s):  
Vladislav Arekhov ◽  
Rafael E. Hincapie ◽  
Torsten Clemens ◽  
Muhammad Tahir
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Acid Number ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Chemical Agent ◽  
Aging Effects ◽  
Divalent Ions ◽  
Total Acid

The injection of chemicals into sandstones can lead to alterations in wettability, where oil characteristics such as the TAN (total acid number) may determine the wetting state of the reservoir. By combining the spontaneous imbibition principle and the evaluation of interfacial tension index, we propose a workflow and comprehensive assessment to evaluate the wettability alteration and interfacial tension (IFT) when injecting chemical-enhanced oil-recovery (EOR) agents. This study examines the effects on wettability alteration due to the application of alkaline and polymer solutions (separately) and the combined alkali–polymer solution. The evaluation focused on comparing the effects of chemical agent injections on wettability and IFT due to core aging (non-aged, water-wet and aged, and neutral to oil-wet), brine composition (mono vs. divalent ions); core mineralogy (~2.5% and ~10% clay), and crude oil type (low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with a restored oil-wet state. IFT experiments were compared for a duration of 300 min. Data were gathered from 48 Amott imbibition experiments with duplicates. The IFT and baselines were defined in each case for brine, polymer, and alkali for each set of experiments. When focusing on the TAN and aging effects, it was observed that in all cases, the early time production was slower and the final oil recovery was longer when compared to the values for non-aged core plugs. These data confirm the change in rock surface wettability towards a more oil-wet state after aging and reverse the wettability alteration due to chemical injections. Furthermore, the application of alkali with high TAN oil resulted in a low equilibrium IFT. By contrast, alkali alone failed to mobilize trapped low TAN oil but caused wettability alteration and a neutral–wet state of the aged core plugs. For the brine composition, the presence of divalent ions promoted water-wetness of the non-aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between the mineral surface and polar compound of the in situ created surfactant, thereby accelerating wettability alteration. Finally, for mineralogy effects, the high clay content core plugs were shown to be more oil-wet even without aging. Following aging, a strongly oil-wet behavior was exhibited. The alkali–polymer is demonstrated to be efficient in the wettability alteration of oil-wet core plugs towards a water-wet state.

Wettability Alteration of Dolomite Rock Using Nanofluids for Enhanced Oil Recovery

2016 ◽  
Vol 864 ◽  
pp. 194-198 ◽  
Author(s):  
Mohd Shahrizan Moslan ◽  
Wan Rosli Wan Sulaiman ◽  
Abdul Razak Ismail ◽  
Mohd Zaidi Jaafar ◽  
Issham Ismail
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Ion Pairs ◽  
Adsorption Rate ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Wet Condition ◽  
The Impact

Wettability alteration of rock by surfactant has been considered as feasible method for recovery of oil reservoirs by modifying the wettability of rock surface from oil-wet to water-wet condition. The impact of surfactant can be enhanced by adding nanoparticles. Cationic surfactant performed well in carbonate rock by forming ion pairs between cationic head and acidic component of the crude. Meanwhile, nanoparticles will form continuous wedge film between the liquid and solid surface. In this paper, Al2O3 and ZrO2 nanoparticles were used as enhanced oil recovery (EOR) agents. The impact of these two nanoparticles on contact angle and interfacial tension was studied. Besides that, adsorption Cetyltrimethylammonium Bromide (CTAB) surfactant on rock surface was also investigated. The results show a significant change in water-oil contact angle after application of surfactant and nanoparticles. Initial water-oil contact angle for 6 dolomites demonstrate oil-wet condition. Then, the dolomites were submerged in prepared solution for 48 hours. The result shows that, dolomites 2, 5 and 6 changes drastically to more water-wet condition with contact angle 56°, 40° and 47° respectively. For surfactant adsorption, the adsorption is very fast at the beginning. The adsorption rate after 5 minutes was 50 mg/g and after 60 minutes the adsorption rate was 310 mg/g. The adsorption rate slowed down after 60 minutes and after 180 minutes the adsorption rate was 315 mg/g in which the rate of adsorption achieve equilibrium. Nanoparticles retention test and Zeta potential shows that Al2O3 is more stable than ZrO2. The results for interfacial tension (IFT) also show a significant reduction. The IFT value reduces from 8.46 mN/m to 1.65 mN/m and 1.85 mN/m after the application of Al2O3 and ZrO2 nanofluids respectively

scholarly journals The Potential Application of MnZn Ferrite Nanofluids for Wettability Alteration and Oil-Water Interfacial Tension Reduction

Crystals ◽  
2019 ◽  
Vol 9 (12) ◽  
pp. 626
Author(s):  
Nurul Afiqah Mohd Mokhtar ◽  
Hoe Guan Beh ◽  
Kean Chuan Lee
Keyword(s):  
Magnetic Properties ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Potential Application ◽  
Combustion Process ◽  
Wettability Alteration ◽  
Mnzn Ferrite ◽  
Auto Combustion ◽  
Oil Water

Recently, a non-invasive method of injecting magnetic/dielectric nanofluids into the oil reservoir was used for oil recovery application. The use of magnetic nanofluids in Enhanced Oil Recovery (EOR) has been reported to improve oil recovery. It is believed that the magnetic properties of nanoparticles (NPs) have a direct influence on the viscosity and wettability of nanofluid, and on oil-water interfacial tension (IFT). Thus, Mn0.5Zn0.5Fe2O4 (MnZn) ferrites may be a good candidate to be used in nanofluids for wettability alteration and oil-water IFT reduction due to their excellent magnetic properties, such as a high initial permeability and low magnetic losses. Therefore, this work investigated the potential of MnZn ferrite NPs to alter viscosity, wettability, and oil-water IFT. MnZn Ferrite NPs have been synthesized by a sol-gel auto-combustion process. The effects of calcination temperature varying from 300 °C to 700 °C on the phase formation, microstructures such as surface morphology, and magnetic characterizations were studied. MnZn ferrite nanofluids were prepared using synthesized MnZn NPs that dispersed into brine along with sodium dodecylbenzenesulfonate (SDBS) as a dispersant, and their effects on the wettability and oil-water IFT were studied. X-ray diffraction (XRD) measurements revealed that MnZn ferrite calcined at 300 °C and 400 °C were single phase. The average crystallite size calculated through Scherrer’s equation differed from 32.0 to 87.96 nm. The results showed that the nanofluid with MnZn particles calcined at 300 °C is the best nanofluid in terms of IFT reduction and base nanofluid’s wettability alteration. Moreover, the overall results proved that nanofluid with MnZn ferrite NPs can alter the wettability of base nanofluid, oil-nanofluid IFT, and nanofluid viscosity. This study provides insights towards a better understanding of the potential application of MnZn Ferrite nanofluids to Wettability Alteration and IFT Reduction in Enhanced Oil Recovery.

Synergistic Effects of Engineered Water-Nanoparticle on Oil/Brine/Rock Interactions in Carbonates

2021 ◽  
Author(s):  
Ibraheem Salaudeen ◽  
Muhammad Rehan Hashmet ◽  
Peyman Pourafshary
Keyword(s):  
Contact Angle ◽  
Zeta Potential ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Sea Water ◽  
Hybrid Methods ◽  
Carbonate Reservoir ◽  
Wettability Alteration ◽  
Combined Effects ◽  
Low Salinity

Abstract Nano particle-assisted engineered water is one of the newest hybrid methods of Enhanced Oil Recovery (EOR) that is gaining attention in the oil and gas industry. This is attributed to the low cost of the technique and environmental friendliness of the materials involved. Low salinity and ions adjustment of the injection brine has been reported to be very useful for improving oil production in carbonates, and application of nanoparticles (NPs) to improve oil recovery via different mechanisms such as wettability alteration, interfacial tension reduction, disjoining pressure and viscosity modification. This paper therefore investigates the combined effects of these two techniques on oil-brine-rock (OBR) interactions in carbonate reservoirs. Caspian Sea Water salinity of 13000 ppm was synthesized in the laboratory, potential determining ions such as Mg2+, Ca2+ and SO42- were adjusted to obtain the desired engineered waters used as dispersant for SiO2 nanoparticle. A series of experiments were performed ranging from zeta potential, interfacial tension, contact angle, electron scanning environmental imaging, pH analysis and particle size to determine the optimum formulation of engineered low salinity brine and nanoparticle. The salinities and concentration of NP considered in this experimental study ranges between (3,250 - 40,000) ppm and (0.05 - 0.5) wt.%, respectively. It was observed that optimum homogenization time for achieving stability of the chosen nanofluid without using stabilizer is 45 minutes. Four times sulphate and calcium ions in the engineered water reduced the contact angle from 163 to 109 and 151 to 118 degrees respectively. However, in the presence of NP, the contact angle further reduced to a very low values of 5 and 41 degrees. This confirms the combined effects of EW and that of nanofluid (NF) in altering wettability from the hydrophobicity state to hydrophilicity one that rapidly improves oil recovery in carbonate reservoir. IFT measurements were made between oil and formation brine as well as between oil and different EWs at room temperature. The Formation water has the least value of interfacial tension- 15mN/m. Four times diluted sea water spiked with four times sulphate is denoted as 4dsw4S. The zeta potential values showed dsw4S-NF to be the most stable, whereas EW-NF spiked with 4 times Mg2+ show detrimental effects on NF stability. The nanoparticles sizes were measured to be less than 50 nm. Rheological studies of the EW-NF at different temperatures (25, 40, 60 and 80 degrees Celsius) shows similar trend of Newtonian and non-Newtonian behavior at shear rate less than 100 and above 100 per seconds respectively. We conclude that spiking calcium ion and sulphate ion into the injected brine in combination with 0.1wt% NP yielded the wettability alteration in carbonate rock samples. The significant reduction in wettability is attributed to the combined effects of the active mechanisms present in the hybrid method and is considerably better than each standalone technique.

Injectivity and Potential Wettability Alteration of Low-Salinity Polymer in Carbonates: Role of Salinity, Polymer Molecular Weight and Concentration, and Mineral Dissolution

SPE Journal ◽  
2021 ◽  
pp. 1-24
Author(s):  
Maissa Souayeh ◽  
Rashid S. Al-Maamari ◽  
Ahmed Mansour ◽  
Mohamed Aoudia ◽  
Thomas Divers
Keyword(s):  
Contact Angle ◽  
Porous Medium ◽  
Oil Recovery ◽  
Mineral Dissolution ◽  
Mobility Control ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Low Salinity ◽  
Oil Displacement

Summary Coupling polymer with low-salinity water (LSW) to promote enhanced oil recovery (EOR) in carbonate reservoirs has attracted significant interest in the petroleum industry. However, low-salinity polymer (LSP) application to improve oil extraction from such rocks remains a challenge because of the complex synergism between these two EOR agents. Thus, this paper highlights the main factors that govern the LSP displacement process in carbonate reservoirs in terms of wettability alteration and mobility control. A series of experiments including contact angle, spontaneous imbibition, injectivity, adsorption, and oil displacement tests were performed. The impact of mineral dissolution on the polymer/brine and polymer/rock surface interactions and its possible connection to the efficiency of the LSP in carbonates was also investigated using ζ potential analysis following an elaborative procedure. All experiments were executed at elevated temperature (75°C) using two polymers (SAV10) of different molecular weights (MWs) prepared at varying concentrations and salinities. Contact angle measurements showed that increasing the polymer concentration and MW and, at the same time, decreasing the solution salinity could effectively rend homogeneous oil-wet calcite surfaces strongly water-wet. Conversely, spontaneous imbibition tests using heterogonous oil-wet Indiana limestone cores showed that the polymer viscosity and its molecular size hinder the performance of the polymer to modify the wettability of the core samples at high concentration and MW because they could limit its penetration into the porous medium. On the other hand, the results obtained from polymer injectivities showed that LSP had better propagation with lower filtration effects in comparison with high-salinity polymer (HSP). However, polymer adsorption and inaccessible pore volume (IPV) increased with the decrease of salinity. Calcite mineral dissolution triggered by LSP, which is associated with an increase in pH and [Ca2+], considerably influenced the polymer viscosity. In addition, ζ potential measurements showed that the LSP altered the rock surface charge from positive toward negative and at the same time, the Ca2+ released due to mineral dissolution could modify the polymer molecule charge toward positive. This confirms that mineral dissolution impressively results in better wettability alteration performance; however, it could lead to undesirable high polymer adsorption at low salinity. These findings provide new insight into the influence of mineral dissolution on polymer performance in carbonates. Finally, forced oil displacement tests revealed that both HSP and LSP extracted approximatively the same amount of oil. The HSP could enhance the oil recovery through mobility control. By contrast, wettability alteration could take part in the improvement of oil recovery at LSP, as proved by spontaneous imbibition tests, along with mobility control. Despite possessing high wettability alteration potential, LSP could not yield very high recovery because of its low accessibility into the porous medium. Shearing of the LSP was found effective in improving oil recovery through enhancing the polymer accessibility. This will lead us to simply say that polymer accessibility into carbonates is crucial for the success of the wettability alteration and mobility control processes, which is remarkably important not only for this specific study but also for other various polymer EOR applications.

scholarly journals Wettability Alteration in High-Temperature and High-Salinity Carbonate Reservoirs

SPE Journal ◽  
2013 ◽  
Vol 18 (04) ◽  
pp. 646-655 ◽  
Author(s):  
Gaurav Sharma ◽  
Kishore K. Mohanty
Keyword(s):  
Contact Angle ◽  
High Temperature ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
High Salinity ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Surfactant Systems ◽  
Original Oil In Place ◽  
Harsh Conditions

Summary The goal of this work was to change the wettability of a carbonate rock from mixed-wet toward water-wet at high temperature and high salinity. Three types of surfactants in dilute concentrations (<0.2 wt%) were used. Initial surfactant screening was performed on the basis of aqueous stability at these harsh conditions. Contact-angle experiments on aged calcite plates were conducted to narrow the list of surfactants, and spontaneous-imbibition experiments were conducted on field cores for promising surfactants. Secondary waterflooding was carried out in cores with and without the wettability-altering surfactants. It was observed that most but not all surfactants were aqueous-unstable by themselves at these harsh conditions. Dual-surfactant systems, mixtures of a nonionic and a cationic surfactant, increased the aqueous stability. Some of the dual-surfactant systems proved effective for wettability alteration and could recover could recover 70 to 80% OOIP (original oil in place) during spontaneous imbibition. Secondary waterflooding with the wettability-altering surfactant increased the oil recovery over the waterflooding without the surfactants (from 29 to 40% of OOIP).

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