Effect of Environment-Friendly Non-Ionic Surfactant on Interfacial Tension Reduction and Wettability Alteration; Implications for Enhanced Oil Recovery

Production from mature oil reservoirs can be optimized by using the surfactant flooding technique. This can be achieved by reducing oil and water interfacial tension (IFT) and modifying wettability to hydrophilic conditions. In this study, a novel green non-ionic surfactant (dodecanoyl-glucosamine surfactant) was synthesized and used to modify the wettability of carbonate reservoirs to hydrophilic conditions as well as to decrease the IFT of hydrophobic oil–water systems. The synthesized non-ionic surfactant was characterized by Fourier transform infrared spectroscopy (FTIR) and chemical shift nuclear magnetic resonance (HNMR) analyses. Further pH, turbidity, density, and conductivity were investigated to measure the critical micelle concentration (CMC) of surfactant solutions. The result shows that this surfactant alters wettability from 148.93° to 65.54° and IFT from 30 to 14 dynes/cm. Core-flooding results have shown that oil recovery was increased from 40% (by water flooding) to 59% (by surfactant flooding). In addition, it is identified that this novel non-ionic surfactant can be used in CO2 storage applications due to its ability to alter the hydrophobicity into hydrophilicity of the reservoir rocks.

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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

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-019-00789-0 ◽

2019 ◽

Vol 10 (4) ◽

pp. 1551-1563 ◽

Cited By ~ 5

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.

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A Systematic Study to Assess Displacement Performance of a Naturally-Derived Surfactant in Flow Porous Systems

Energies ◽

10.3390/en14248310 ◽

2021 ◽

Vol 14 (24) ◽

pp. 8310

Author(s):

Aghil Moslemizadeh ◽

Hossein Khayati ◽

Mohammad Madani ◽

Mehdi Ghasemi ◽

Khalil Shahbazi ◽

...

Keyword(s):

Oil Recovery ◽

Salt Concentration ◽

Water Flooding ◽

Wettability Alteration ◽

Ginseng Root ◽

Ionic Surfactant ◽

Root Extract ◽

Surfactant Flooding ◽

Free System ◽

Sandstone Rock

For the first time, the present work assesses the feasibility of using Korean red ginseng root extract, a non-ionic surfactant, for the purposes of enhanced oil recovery (EOR). The surfactant is characterized by Fourier-transform infrared spectroscopy (FT-IR) analysis. Pendant drop and sessile drop techniques are employed to study the oil–water interfacial tension (IFT) and wettability nature of the sandstone rock, respectively. In addition, oil recovery enhancement is investigated using micromodel and core floods. In the salt-free system, IFT measurements indicate that the surfactant carries a critical micelle concentration of 5 g/L. In a saline medium (up to 50 g/L), the addition of a surfactant with different concentrations leads to an IFT reduction of 47.28–84.21%. In a constant surfactant concentration, a contact angle reduction is observed in the range of 5.61–9.30°, depending on salinity rate, revealing a wettability alteration toward more water-wet. Surfactant flooding in the glass micromodel provides a more uniform sweeping, which leads to an oil recovery enhancement of 3.02–11.19%, depending on the extent of salinity. An optimal salt concentration equal to 30 g/L can be recognized according to the results of previous tests. Surfactant flooding (10 g/L) in optimal salt concentration achieves an additional oil recovery of 7.52% after conventional water flooding.

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Wettability alteration analysis of smart water/novel functionalized nanocomposites for enhanced oil recovery

Petroleum Science ◽

10.1007/s12182-020-00436-y ◽

2020 ◽

Vol 17 (5) ◽

pp. 1318-1328

Author(s):

Sara Habibi ◽

Arezou Jafari ◽

Zahra Fakhroueian

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Ionic Composition ◽

Water Flooding ◽

Wettability Alteration ◽

Core Flooding ◽

Sulfate Ions ◽

Smart Water ◽

Eor Processes ◽

Co Precipitation

Abstract Smart water flooding, as a popular method to change the wettability of carbonate rocks, is one of the interesting and challenging issues in reservoir engineering. In addition, the recent studies show that nanoparticles have a great potential for application in EOR processes. However, little research has been conducted on the use of smart water with nanoparticles in enhanced oil recovery. In this study, stability, contact angle and IFT measurements and multi-step core flooding tests were designed to investigate the effect of the ionic composition of smart water containing SO42− and Ca2+ ions in the presence of nanofluid on EOR processes. The amine/organosiloxane@Al2O3/SiO2 (AOAS) nanocomposite previously synthesized using co-precipitation-hydrothermal method has been used here. However, for the first time the application of this nanocomposite along with smart water has been studied in this research. Results show that by increasing the concentrations of calcium and sulfate ions in smart water, oil recovery is improved by 9% and 10%, respectively, compared to seawater. In addition, the use of smart water and nanofluids simultaneously is very effective on increasing oil recovery. Finally, the best performance was observed in smart water containing two times of sulfate ions concentration (SW2S) with nanofluids, showing increased efficiency of about 7.5%.

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Numerical modeling and experimental investigation on the effect of low-salinity water flooding for enhanced oil recovery in carbonate reservoirs

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-01071-4 ◽

2021 ◽

Vol 11 (2) ◽

pp. 925-947

Author(s):

Erfan Hosseini ◽

Mohammad Sarmadivaleh ◽

Dana Mohammadnazar

Keyword(s):

Oil Recovery ◽

Water Injection ◽

Water Flooding ◽

Wettability Alteration ◽

Experimental Investigations ◽

Core Flooding ◽

Reservoir Temperature ◽

Sulfate Ion ◽

Ionic Content ◽

Low Salinity

AbstractNumerous studies concluded that water injection with modified ionic content/salinity in sandstones would enhance the oil recovery factor due to some mechanisms. However, the effects of smart water on carbonated formations are still indeterminate due to a lack of experimental investigations and researches. This study investigates the effects of low-salinity (Low Sal) solutions and its ionic content on interfacial tension (IFT) reduction in one of the southwestern Iranian carbonated reservoirs. A set of organized tests are designed and performed to find each ion’s effects and total dissolved solids (TDS) on the candidate carbonated reservoir. A sequence of wettability and IFT (at reservoir temperature) tests are performed to observe the effects of controlling ions (sulfate, magnesium, calcium, and sodium) and different salinities on the main mechanisms (i.e., wettability alteration and IFT reduction). All IFT tests are performed at reservoir temperature (198 °F) to minimize the difference between reservoir and laboratory-observed alterations. In this paper, the effects of four different ions (SO42-, Ca2+, Mg2+, Na+) and total salinity TDS (40,000, 20,000, 5000 ppm) are investigated. From all obtained results, the best two conditions are applied in core flooding tests to obtain the relative permeability alterations using unsteady-state methods and Cydarex software. The final part is the simulation of the whole process using the Schlumberger Eclipse black oil simulator (E100, Ver. 2010) on the candidate reservoir sector. To conclude, at Low Sal (i.e., 5000 ppm), the sulfate ion increases sulfate concentration lower IFT, while in higher salinities, increasing sulfate ion increases IFT. Also, increasing calcium concentration at high TDS (i.e., 40,000 ppm) decreases the amount of wettability alteration. In comparison, in lower TDS values (20,000 and 5000 ppm), calcium shows a positive effect, and its concentration enhanced the alteration process. Using Low Sal solutions at water cut equal or below 10% lowers recovery rate during simulations while lowering the ultimate recovery of less than 5%.

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Experimental investigation of chemical solutions effects on wettability alteration and interfacial tension reduction using nano-alkaline–surfactant fluid: an EOR application in carbonate reservoirs

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-021-01155-9 ◽

2021 ◽

Vol 11 (4) ◽

pp. 1925-1941

Author(s):

M. Sadegh Rajabi ◽

Rasoul Moradi ◽

Masoud Mehrizadeh

Keyword(s):

Interfacial Tension ◽

Crude Oil ◽

Oil Recovery ◽

Carbonate Reservoirs ◽

Water Flooding ◽

Wettability Alteration ◽

Ammonium Bromide ◽

Total Production ◽

Thin Sections ◽

Chemical Solutions

AbstractThe wettability preference of carbonate reservoirs is neutral-wet or oil-wet as the prevailing of hydrocarbon reserves that affects approximately half of the total production of hydrocarbons of the world. Therefore, due to surface wettability of carbonate rocks the notable fraction of oil is held inside their pores in comparison with sandstones. Since shifting the wettability preference toward water-wet system is of great interest, numerous components were used for this purpose. In this experimental research, the wettability alteration of dolomite surface by interacting with a novel nano-surfactant–alkaline fluid has been investigated in order to diminish its adhesion to crude oil droplets. The solutions were prepared by homogenous mixing of nanosilica particles with cetyl trimethyl ammonium bromide and sodium carbonate, respectively, as a cationic surfactant and alkaline agent. The maximum wettability alteration from oil-wet to water system was obtained by employing a mixture of nanoparticles in association with surfactant–alkaline. Then, the fluids were employed in core-surface from detached and attached forms to compare their interfacial effects on saturated thin sections by crude oil and to measure the wettability. In addition, the interfacial tension (IFT) between solutions and crude oil was investigated and the maximum IFT reduction was obtained from nano-surfactant. Finally, all chemical solutions were flooded to the dolomite plugs separately after water flooding in order to evaluate the maximum oil recovery factor acquired by nano-surfactant.

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Experimental Pore-Scale Study of a Novel Functionalized Iron-Carbon Nanohybrid for Enhanced Oil Recovery (EOR)

Nanomaterials ◽

10.3390/nano12010103 ◽

2021 ◽

Vol 12 (1) ◽

pp. 103

Author(s):

Fatemeh Razavirad ◽

Abbas Shahrabadi ◽

Parham Babakhani Dehkordi ◽

Alimorad Rashidi

Keyword(s):

Interfacial Tension ◽

Oil Recovery ◽

Base Fluid ◽

Water Flooding ◽

Wettability Alteration ◽

Pore Scale ◽

Ambient Conditions ◽

Displacement Experiments ◽

A New Technique ◽

Water Base

Nanofluid flooding, as a new technique to enhance oil recovery, has recently aroused much attention. The current study considers the performance of a novel iron-carbon nanohybrid to EOR. Carbon nanoparticles was synthesized via the hydrothermal method with citric acid and hybridize with iron (Fe3O4). The investigated nanohybrid is characterized by its rheological properties (viscosity), X-ray diffraction (XRD), and Fourier transform infrared spectroscopy (FTIR) analysis. The efficiency of the synthetized nanoparticle in displacing heavy oil is initially assessed using an oil–wet glass micromodel at ambient conditions. Nanofluid samples with various concentrations (0.05 wt % and 0.5 wt %) dispersed in a water base fluid with varied salinities were first prepared. The prepared nanofluids provide high stability with no additive such as polymer or surfactant. Before displacement experiments were run, to achieve a better understanding of fluid–fluid and grain–fluid interactions in porous media, a series of sub-pore scale tests—including interfacial tension (IFT), contact angle, and zeta potential—were conducted. Nanofluid flooding results show that the nanofluid with the medium base fluid salinity and highest nanoparticle concertation provides the highest oil recovery. However, it is observed that increasing the nanofluid concentration from 0.05% to 0.5% provided only three percent more oil. In contrast, the lowest oil recovery resulted from low salinity water flooding. It was also observed that the measured IFT value between nanofluids and crude oil is a function of nanofluid concentration and base fluid salinities, i.e., the IFT values decrease with the increase of nanofluid concentration and base fluid salinity reduction. However, the base fluid salinity enhancement leads to wettability alteration towards more water-wetness. The main mechanisms responsible for oil recovery enhancement during nanofluid flooding is mainly attributed to wettability alteration toward water-wetness and micro-dispersion formation. However, the interfacial tension (IFT) reduction using the iron-carbon nanohybrid is also observed but the reduction is not significant.

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Experimental Study of Anionic Gemini Surfactant Enhancing Waterflooding Recovery Ratio

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.361-363.469 ◽

2011 ◽

Vol 361-363 ◽

pp. 469-472 ◽

Cited By ~ 1

Author(s):

Shan Fa Tang ◽

Xiao Dong Hu ◽

Xiang Nan Ouyang ◽

Shuang Xi Yan ◽

Shou Cheng Wen ◽

...

Keyword(s):

Interfacial Tension ◽

Oil Recovery ◽

Gemini Surfactant ◽

Water Flooding ◽

Ionic Surfactant ◽

Water Medium ◽

Recovery Efficiency ◽

Water Displacement ◽

Anionic Gemini Surfactant ◽

Oil Water

The oil-water interfacial tension measurement and enhancing water displacement recovery experiment were carried out, and the effects of various parameters such as category of surfactants, anionic Gemini surfactant concentration, water medium salinity, core permeability, polymer and non-ionic surfactant on anionic Gemini surfactants enhancing water displacement recovery were investigated in detail. The results show that surfactants category is different, its enhancing water flooding recovery efficiency is different, and effect of enhanced oil recovery is consistent with surfactant ability to reduce oil-water interfacial tension. The anionic Gemini surfactant AN12-4-12 is the best in enhancing water flooding recovery efficiency, because it can reduce the oil-water interfacial tension to 5×10-3 mN•m-1. Increasing the concentration of AN12-4-12 is favorable to enhance water displacement recovery. Such as when injecting 0.5PV solution containing 800mg•L-1 AN12-4-12, enhancing water displacement recovery is 11.67%. AN12-4-12 has good adaptability to different salinities (5~25×104 mg•L-1) and low permeability reservoir in improving water displacement recovery. Adding non-ionic surfactant ANT into AN12-4-12 solution can further reduce oil-water interfacial tension and enhance water flooding recovery efficiency. For example, injecting 0.5PV surfactant solution containing 400mg•L-1 AN12-4-12 and 100mg•L-1 can enhance water displacement recovery of 10.7%.

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Characterization of Surfactant Flooding for Light Oil Using Gum Arabic

International Journal of Engineering Research in Africa ◽

10.4028/www.scientific.net/jera.21.136 ◽

2015 ◽

Vol 21 ◽

pp. 136-147 ◽

Cited By ~ 1

Author(s):

Oluwaseun Taiwo ◽

Kelani Bello ◽

Ismaila Mohammed ◽

Olalekan Olafuyi

Keyword(s):

Interfacial Tension ◽

Flow Rate ◽

Oil Recovery ◽

Surfactant Concentration ◽

Sodium Dodecyl ◽

Gum Arabic ◽

Polymer Flooding ◽

Water Flooding ◽

Surfactant Flooding ◽

Acacia Senegal

Surfactant flooding, a chemical IOR technique is one of the viable EOR processes for recovering additional oil after water flooding. This is because it reduces the interfacial tension between the oil and water and allows trapped oil to be released for mobilization by a polymer.In this research, two sets of experiments were performed. First, the optimum surfactant concentration was determined through surfactant polymer flooding using a range of surfactant concentration of 0.1% to 0.6% and 15% of polymer. Secondly, another set of experiments to determine the optimum flow rate for surfactant flooding was carried out using the optimum surfactant concentration obtained. Lauryl Sulphate (Sodium Dodecyl Sulphate, SDS), an anionic surfactant, was used to alter the interfacial tension and reduce capillary pressure while Gum Arabic, an organic adhesive gotten from the hardened sap of the Acacia Senegal and Acacia Seyal trees, having a similar molecular structure and chemical characteristics with Xanthan Gum, was the polymer used to mobilize the oil.The results show that above 0.5%, oil recovery decreases with increase in concentration such that between 0.5 and 0.6%, a decrease of (20% -19%) is recorded. This suggests that it would be uneconomical to exceed surfactant concentration of 0.5%. It is shown in the result of the first set of experiments that a range of oil recovery of 59% to 76% for water flooding and a range of 11.64% to 20.02% additional oil recovery for surfactant Polymer flooding for a range of surfactant flow rate of surfactant concentration of 0.1% to 0.6%. For the second sets of experiments, a range of oil recovery of 64% to 68% for water flooding and a range of 15% to 24% additional oil recovery for surfactant flooding for a range of surfactant flow rate of surfactant flow rate of 1cc/min to 6cc/min. The Optimum surfactant flow rate resulting in the highest oil recovery for the chosen core size is 3cc/min. It's highly encouraged that the critical displacement rate is maintained to prevent the development of slug fingers.In summary, an optimum Surfactant flow rate is required for better performance of a Surfactant flooding.

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Experimental study of combined low salinity and surfactant flooding effect on oil recovery

Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles ◽

10.2516/ogst/2020085 ◽

2020 ◽

Vol 76 ◽

pp. 4

Author(s):

Abdulmecit Araz ◽

Farad Kamyabi

Keyword(s):

Interfacial Tension ◽

Oil Recovery ◽

High Salinity ◽

Wettability Alteration ◽

Moderate Increase ◽

Surfactant Flooding ◽

Improved Oil Recovery ◽

Oil Saturation ◽

Low Salinity ◽

Salinity Water

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

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Optimal Zwitterionic Surfactant Slug for an Improved Oil Recovery in Oil Wet Carbonate Rocks

Alberta Academic Review ◽

10.29173/aar45 ◽

2019 ◽

Vol 2 (2) ◽

pp. 7-8

Author(s):

Madison Barth ◽

Japan Trivedi ◽

Benedicta Nwani ◽

Yosamin Esanullah

Keyword(s):

Interfacial Tension ◽

Oil Recovery ◽

Carbonate Rocks ◽

Surfactant Concentration ◽

Wettability Alteration ◽

Ionic Surfactant ◽

Improved Oil Recovery ◽

Fluid Analysis ◽

Tertiary Recovery ◽

Brine Salinity

Of recent, there has been research and development in the technologies/techniques required to meet the ever-growing energy demand in the world. Oil is a major source of energy which is contained in over 50% of carbonate reservoirs. The oil/mixed wettability of carbonate rocks makes it technically challenging to recover the needed oil. The process of crude oil recovery has three different stages primary, secondary and tertiary recovery. Tertiary recovery is also known as enhanced oil recovery or EOR. EOR includes the use of surfactants to reduce the interfacial tension between a hydrocarbon and brine, thus suspending them both in a microemulsion. Surfactant performance can be affected by multiple variables, including brine salinity, surfactant concentration, and type of hydrocarbon. A petroleum engineer must take all variables into consideration when selecting a surfactant to make sure that its efficiency is as high as possible, especially because the use of surfactants is costly. In this work, a chembetaine zwitter ionic surfactant of two different concentrations are evaluated at various synthetic formation brine salinities for their favourable wettability alteration and interfacial tension reduction in oil-wet carbonate- Silurian Dolomite. For the evaluation, fluid-fluid and rock-fluid analysis are carried out to select the optimal surfactant concentration and brine salinity with the greatest improved oil recovery potential. Results are indicative that the surfactant at the two concentrations studied is compatible at the ranges of salinities evaluated. However, from the fluid-fluid analysis, there was no ultra-low interfacial tension that is needed for oil mobilization. More so, the rock-fluid analysis shows that the surfactant is not able to alter the wettability of oil-wet rocks favourably. The optimal surfactant slug for the greatest oil recovery, in this case, would be expected at 0.5% surfactant concentration in 10,000 ppm synthetic formation brine salinity. This study, therefore, serves as a guide for the design of optimal surfactant slug in oil-wet carbonate cores requires to reduce non-productive time, prevent reservoir damage and therefore improve recovery.

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