scholarly journals Manipulation of surface charges of oil droplets and carbonate rocks to improve oil recovery

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Jian Hou ◽  
Ming Han ◽  
Jinxun Wang
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Zwitterionic Surfactant ◽  
Surface Charges ◽  
Oil Droplets ◽  
Zeta Potentials ◽  
Potential Value ◽  
Oil Water ◽  
Incremental Oil Recovery

AbstractThis work investigates the effect of the surface charges of oil droplets and carbonate rocks in brine and in surfactant solutions on oil production. The influences of the cations in brine and the surfactant types on the zeta-potentials of both oil droplets and carbonate rock particles are studied. It is found that the addition of anionic and cationic surfactants in brine result in both negative or positive zeta-potentials of rock particles and oil droplets respectively, while the zwitterionic surfactant induces a positive charge on rock particles and a negative charge on oil droplets. Micromodels with a CaCO3 nanocrystal layer coated on the flow channels were used in the oil displacement tests. The results show that when the oil-water interfacial tension (IFT) was at 10−1 mN/m, the injection of an anionic surfactant (SDS-R1) solution achieved 21.0% incremental oil recovery, higher than the 12.6% increment by the injection of a zwitterionic surfactant (SB-A2) solution. When the IFT was lowered to 10−3 mM/m, the injection of anionic/non-ionic surfactant SMAN-l1 solution with higher absolute zeta potential value (ζoil + ζrock) of 34 mV has achieved higher incremental oil recovery (39.4%) than the application of an anionic/cationic surfactant SMAC-l1 solution with a lower absolute zeta-potential value of 22 mV (30.6%). This indicates that the same charge of rocks and oil droplets improves the transportation of charged oil/water emulsion in the porous media. This work reveals that the surface charge in surfactant flooding plays an important role in addition to the oil/water interfacial tension reduction and the rock wettability alteration.

Manganese Assisted Waterflooding Processes for Enhanced Oil Recovery in Carbonates

2021 ◽  
Author(s):  
Amani Alghamdi ◽  
Saleh Salah ◽  
Mohammed Otaibi ◽  
Subhash Ayirala ◽  
Ali Yousef
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Spontaneous Imbibition ◽  
Wetting Transition ◽  
Manganese Ions ◽  
Surface Charges ◽  
High Salinity Water ◽  
Zeta Potentials ◽  
Salinity Water ◽  
Oil Water

Abstract Modifying the wettability of carbonate formations through divalent foreign metal incorporation can become a cost-effective practical method for enhanced oil recovery (EOR) applications. The addition of manganese ions to both high salinity water (HSW) and tailored SmartWater at dilute concentrations is exploited in this study to maximize the interfacial potential and promote water-wet conditions in carbonate reservoirs. In this experimental investigation, the impact of manganese ions on zeta-potentials at calcite/brine and crude oil/brine interfaces is first determined by measuring zeta-potentials in calcite suspensions and oil emulsions. Two different water chemistries representative of HSW (~60,000 ppm TDS) and a low salinity tailored SmartWater (~6,000 ppm TDS) were used. The measurements were then extended to carbonate rocks and reservoir cores by performing contact angle and spontaneous imbibition tests at reservoir conditions. The oil-water interfacial tensions are also measured to understand the interactions of manganese ions at the oil/brine interface. The zeta potential results showed a positive consistent trend, with the addition of 100-1,000 ppm of Mn+2 ions in the form of MnSO4 to the high salinity water, to impact the wetting transition towards water-wet conditions in carbonates. The addition of Mn+2 ions at a concentration of 100-1,000 ppm to HSW enhanced the electrokinetic interactions to favorably alter surface charges at both oil/brine and calcite/brine interfaces. These findings based on eletrokinetic interactions demonstrated good agreement with contact angle data wherein manganese ions in HSW were able to drastically decrease the contact angles from 156 to 88°. Conversely, insignificant changes in oil-water interfacial tensions were observed due to manganese ions. The manganese assisted spontaneous imbibition oil recoveries were increased by about 10% in HSW. Mn+2 ions showed the ability to increase the negative potentials at both calcite/brine and oil/brine interfaces. The obvious trend of such enhanced electrical potential due to Mn+2 addition at the calcite interface supports the claim that Mn+2 selectively gets incorporated into the calcite crystal to modify its surface chemistry. This is expected to increase the surface charges of same polarity at the two opposing interfaces and promote the electrostatic repulsion to inherently change the surface preference towards water-wet conditions. This work for the first time identified the favorable impact of incorporating Mn+2 ions under optimized conditions to enhance the wetting transition in carbonate reservoirs. Such new knowledge gained from this experimental study highlights the practical significance of Mn+2 ions as cheap and sustainable wettability modifiers for EOR applications in carbonate reservoirs.

scholarly journals A Surface Complexation Model of Alkaline-SmartWater Electrokinetic Interactions in Carbonates

2020 ◽  
Vol 146 ◽  
pp. 02003
Author(s):  
Moataz Abu-Al-Saud ◽  
Amani Al-Ghamdi ◽  
Subhash Ayirala ◽  
Mohammed Al-Otaibi
Keyword(s):  
Experimental Data ◽  
Zeta Potential ◽  
Crude Oil ◽  
Oil Recovery ◽  
Surface Complexation ◽  
Surface Complexation Model ◽  
Zeta Potentials ◽  
Smart Water ◽  
Injection Water ◽  
Carbonate Formations

Understanding the effect of injection water chemistry is becoming crucial, as it has been recently shown to have a major impact on oil recovery processes in carbonate formations. Various studies have concluded that surface charge alteration is the primary mechanism behind the observed change of wettability towards water-wet due to SmartWater injection in carbonates. Therefore, understanding the surface charges at brine/calcite and brine/crude oil interfaces becomes essential to optimize the injection water compositions for enhanced oil recovery (EOR) in carbonate formations. In this work, the physicochemical interactions of different brine recipes with and without alkali in carbonates are evaluated using Surface Complexation Model (SCM). First, the zeta-potential of brine/calcite and brine/crude oil interfaces are determined for Smart Water, NaCl, and Na2SO4 brines at fixed salinity. The high salinity seawater is also included to provide the baseline for comparison. Then, two types of Alkali (NaOH and Na2CO3) are added at 0.1 wt% concentration to the different brine recipes to verify their effects on the computed zeta-potential values in the SCM framework. The SCM results are compared with experimental data of zeta-potentials obtained with calcite in brine and crude oil in brine suspensions using the same brines and the two alkali concentrations. The SCM results follow the same trends observed in experimental data to reasonably match the zeta-potential values at the calcite/brine interface. Generally, the addition of alkaline drives the zeta-potentials towards more negative values. This trend towards negative zeta-potential is confirmed for the Smart Water recipe with the impact being more pronounced for Na2CO3 due to the presence of divalent anion carbonate (CO3)-2. Some discrepancy in the zeta-potential magnitude between the SCM results and experiments is observed at the brine/crude oil interface with the addition of alkali. This discrepancy can be attributed to neglecting the reaction of carboxylic acid groups in the crude oil with strong alkali as NaOH and Na2CO3. The novelty of this work is that it clearly validates the SCM results with experimental zeta-potential data to determine the physicochemical interaction of alkaline chemicals with SmartWater in carbonates. These modeling results provide new insights on defining optimal SmartWater compositions to synergize with alkaline chemicals to further improve oil recovery in carbonate reservoirs.

Microscale Interactions of Surfactant and Polymer Chemicals at Crude Oil/Water Interface for Enhanced Oil Recovery

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1812-1826
Author(s):  
Subhash Ayirala ◽  
Zuoli Li ◽  
Rubia Mariath ◽  
Abdulkareem AlSofi ◽  
Zhenghe Xu ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
High Salinity ◽  
Interfacial Shear ◽  
Experimental Techniques ◽  
Water Interface ◽  
Oil Droplets ◽  
Interfacial Film ◽  
Chemical Eor ◽  
Oil Water

Summary The conventional experimental techniques used for performance evaluation of enhanced oil recovery (EOR) chemicals, such as polymers and surfactants, have been mostly limited to bulk viscosity, phase behavior/interfacial tension (IFT), and thermal stability measurements. Furthermore, fundamental studies exploring the different microscale interactions instigated by the EOR chemicals at the crude oil/water interface are scanty. The objective of this experimental study is to fill this existing knowledge gap and deliver an important understanding on underlying interfacial sciences and their potential implications for oil recovery in chemical EOR. Different microscale interactions of EOR chemicals, at crude oil/water interface, were studied by using a suite of experimental techniques, including an interfacial shear rheometer, Langmuir trough, and coalescence time measurement apparatus at both ambient (23°C) and elevated (70°C) temperatures. The reservoir crude oil and high-salinity injection water (57,000 ppm total dissolved solids) were used. Two chemicals, an amphoteric surfactant (at 1,000 ppm) and a sulfonated polyacrylamide polymer (at 500 and 700 ppm) were chosen because they are tolerant to high-salinity and high-temperature conditions. Interfacial viscous and elastic moduli (viscoelasticity), interface pressures, interface compression energies, and coalescence time between crude oil droplets are the major experimental data measured. Interfacial shear rheology results showed that surfactant favorably reduced the viscoelasticity of crude oil/water interface by decreasing the elastic and viscous modulus and increasing the phase angle to soften the interfacial film. Polymers in brine either alone or together with surfactant increased the viscous and elastic modulus and decreased the phase angle at the oil/water interface, thereby contributing to interfacial film rigidity. Interfacial pressures with polymers remained almost in the same order of magnitude as the high-salinity brine. In contrast, a significant reduction in interfacial pressures with surfactant was observed. The interface compression energies indicated the same trend and were reduced by approximately two orders of magnitude when surfactant was added to the brine. The surfactant was also able to retain similar interface behavior under compression even in the presence of polymers. The coalescence times between crude oil droplets were increased by polymers, while they were substantially decreased by the surfactant. These consistent findings from different experimental techniques demonstrated the adverse interactions of polymers at the crude oil/water interface to result in more rigid films, while confirming the high efficiency of the surfactant to soften the interfacial film, promote the oil droplets coalescence, and mobilize substantial amounts of residual oil in chemical EOR. This experimental study, for the first time, characterized the microscale interactions of surfactant-polymer chemicals at the crude oil/water interface. The applicability of several interfacial experimental techniques has been demonstrated to successfully understand underlying interfacial sciences and oil mobilization mechanisms in chemical EOR. These techniques and methods can provide potential means to efficiently screen and optimize EOR chemical formulations for better oil recovery in both sandstone and carbonate reservoirs.

scholarly journals Effect of Capillary Number on the Residual Saturation of Colloidal Dispersions Stabilized by a Zwitterionic Surfactant

2021 ◽  
Vol 11 (2) ◽  
pp. 524
Author(s):  
Han Am Son ◽  
Taewoong Ahn
Keyword(s):  
Oil Recovery ◽  
Capillary Number ◽  
Colloidal Dispersion ◽  
Colloidal Dispersions ◽  
Particle Aggregation ◽  
Water Interface ◽  
Residual Oil ◽  
Zwitterionic Surfactant ◽  
Anionic Polymer ◽  
Oil Water

We investigated oil recovery from porous rock using nanoscale colloidal dispersions, formed by adsorption of an anionic polymer [poly-(4styrenesulfonic acid-co-maleic acid); PSS-co-MA] and a zwitterionic surfactant [N-tetradecyl-N, N-dimethyl-3-ammonio-1-propanesulfonate, TPS] onto silica nanoparticles. In an emulsion, colloidal dispersion enhanced the stability of the oil-water interface in the absence of particle aggregation; the hydrophobic alkyl chains of TPS shifted into the oil drop, not only physiochemically, stabilizing the oil-water interface, but also promoting repulsive particle-to-particle interaction. Core flooding experiments on residual oil saturation as a function of capillary number, at various injection rates and oil viscosities, showed that the residual oil level was reduced by almost half when the zwitterionic surfactant was present in the colloidal dispersion. Consequently, the result revealed that this colloidal dispersion at the interface provides a mechanically robust layer at the oil-water interface without particle aggregation. Thus, the dispersion readily entered the pore throat and adhered to the oil-water interface, lowering the interfacial tension and improving oil recovery.

scholarly journals Stabilisation of Emulsified Agarwood Oil in an Aqueous System Using Non-Ionic Surfactant

2019 ◽  
Vol 797 ◽  
pp. 186-195
Author(s):  
Boon Yih Tien ◽  
Mohd Nazli Naim ◽  
Rabitah Zakaria ◽  
Noor Fitrah Abu Bakar ◽  
Noraini Ahmad ◽  
...  
Keyword(s):  
Zeta Potential ◽  
Droplet Size ◽  
Ostwald Ripening ◽  
Alkaline Condition ◽  
Ionic Surfactant ◽  
Water Interface ◽  
Oil Droplets ◽  
Emulsified Oil ◽  
Oil Water ◽  
Agarwood Oil

Owing to the annually increasing market value of pure agarwood oil, the extracted agarwood oil from Aquilaria malaccensis was emulsified in an aqueous solution using non-ionic surfactant (Tween 80). The surfactant concentration of 0.0167% was determined as the critical micelle concentration (CMC) with an interfacial tension value of 0.014 mNm-1. The adsorption of surfactant at the oil/water interface at the CMC value, however, reduced the zeta potential of the emulsified oil from –45 to –43 mV, and increased its size from 85 to 89 nm. Outside of the CMC value, the emulsified oil droplets tended to coalesce, owing to insufficient coverage of the surfactant at oil/water interface and Ostwald ripening. The droplet size distribution and zeta potential value of the emulsified oil droplets produced at the CMC were the most stable over a month of storage. No significant changes in the emulsified droplet size occurred when the pH conditions varied from pH 3 to 10. The emulsified droplets images obtained from transmission electron microscopy analysis showed a reduction in the layer thickness of the surfactant from 30 to 10 nm in acidic condition and 30 to 19 nm in alkaline condition. The agarwood oil emulsification at CMC value enhance the stability of chemically unstable compounds from degradation.

scholarly journals Interfacial Viscoelasticity in Crude Oil-Water Systems to Understand Incremental Oil Recovery

2020 ◽  
Author(s):  
Ahmed M. Saad ◽  
Stefano Aime ◽  
Sharath C. Mahavadi ◽  
Yi-Qiao Song ◽  
Tadeusz W. Patzek ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Water Systems ◽  
Oil Water ◽  
Incremental Oil Recovery

scholarly journals A Synergy between Controlled Salinity Brine and Biosurfactant Flooding for Improved Oil Recovery: An Experimental Investigation Based on Zeta Potential and Interfacial Tension Measurements

2019 ◽  
Vol 2019 ◽  
pp. 1-15
Author(s):  
Tinuola Udoh ◽  
Jan Vinogradov
Keyword(s):  
Zeta Potential ◽  
Interfacial Tension ◽  
Crude Oil ◽  
Oil Recovery ◽  
High Salinity ◽  
Improved Oil Recovery ◽  
Low Salinity ◽  
All Solutions ◽  
Rock Interface ◽  
Incremental Oil Recovery

In this study, we have investigated the effects of brine and biosurfactant compositions on crude-oil-rock-brine interactions, interfacial tension, zeta potential, and oil recovery. The results of this study show that reduced brine salinity does not cause significant change in IFT. However, addition of biosurfactants to both high and low salinity brines resulted in IFT reduction. Also, experimental results suggest that the zeta potential of high salinity formation brine-rock interface is positive, but oil-brine interface was found to be negatively charged for all solutions used in the study. When controlled salinity brine (CSB) with low salinity and CSB with biosurfactants were injected, both the oil-brine and rock-brine interfaces become negatively charged resulting in increased water-wetness and, hence, improved oil recovery. Addition of biosurfactants to CSB further increased electric double layer expansion which invariably resulted in increased electrostatic repulsion between rock-brine and oil-brine interfaces, but the corresponding incremental oil recovery was small compared with injection of low salinity brine alone. Moreover, we found that the effective zeta potential of crude oil-brine-rock systems is correlated with IFT. The results of this study are relevant to enhanced oil recovery in which controlled salinity waterflooding can be combined with injection of biosurfactants to improve oil recovery.

Water Ion Interactions at Crude-Oil/Water Interface and Their Implications for Smart Waterflooding in Carbonates

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1817-1832 ◽  
Author(s):  
Subhash C. Ayirala ◽  
Ali A. Al-Yousef ◽  
Zuoli Li ◽  
Zhenghe Xu
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Measurement Techniques ◽  
Fluid Interfaces ◽  
Water Interface ◽  
Oil Droplets ◽  
Coalescence Time ◽  
Ion Interactions ◽  
Phase Connectivity ◽  
Oil Water

Summary Smart waterflooding (SWF) through tailoring of injection-water salinity and ionic composition is receiving favorable attention in the industry for both improved and enhanced oil recovery (EOR) in carbonate reservoirs. Surface/intermolecular forces, thin-film dynamics, and capillary/adhesion forces at rock/fluid interfaces govern crude-oil liberation from pores. On the other hand, stability and rigidity of oil/water interfaces control the destabilization of interfacial film to promote coalescence between released oil droplets and to improve the oil-phase connectivity. As a result, the dynamics of oil recovery in smart waterflood is caused by the combined effect of favorable interactions occurring at both oil/brine and oil/brine/rock interfaces across the thin film. Most of the laboratory studies reported so far have been focused on only studying the interactions at rock/fluid interfaces. However, the other important aspect of characterizing water ion interactions at the crude oil/water interface and their impact on film stability and oil-droplet coalescence remains largely unexplored. A detailed experimental investigation was conducted to understand the effects of different water ions at the crude-oil/water interface by using several instruments such as Langmuir trough, interfacial shear rheometer, Attension tensiometer, and coalescence time-measurement apparatus. The reservoir crude oil and four different water recipes with varying salinities and individual ion concentrations were used. Interfacial tension (IFT), interface pressures, compression energy, interfacial viscous and elastic moduli, oil-droplet crumpling ratio, and coalescence time between crude-oil droplets are the major experimental data measured. The IFTs are found to be the largest for deionized (DI) water, followed by the 10-times-reduced-salinity seawater and 10-times-reduced-salinity seawater enriched with sulfates. Interfacial pressures gradually increased with compressing surface area for all the brines and DI water. The compression energy (integration of interfacial pressure over the surface-area change) is the highest for DI water, followed by the lower-salinity brine containing sulfate ions, indicating rigid interfaces. The transition times of interfacial layer to become elastic-dominant from viscous-dominant structures are found to be much shorter for brines enriched with sulfates, once again confirming the rigidity of interface. The crumpling ratios (oil drop wrinkles when contracted) are also higher with the two recipes of DI water and sulfates-only brine to indicate the same trend and to confirm elastic rigid skin at the interface. The coalescence time between oil droplets was the least in brines containing sufficient amounts of magnesium and calcium ions, while the highest in DI water and sulfate-rich brine, respectively. These results, therefore, showed a good correlation of coalescence times with the rigidity of oil/water interface, as interpreted from different measurement techniques. This study, thereby, integrates consistent results obtained from different measurement techniques at the crude-oil/water interface to demonstrate the importance of both salinity and certain ions, such as magnesium and calcium, on crude-oil-droplets coalescence, and to improve oil-phase connectivity in smart waterflood.

Novel Formulation Development and Evaluation of Nanoparticles Based in Situ Gelling System for The Ophthalmic Delivery of Ciprofloxacin Hydrochloride

2015 ◽  
Vol 5 (4) ◽  
Author(s):  
Kranti Singh ◽  
Surajpal Verma ◽  
Shyam Prasad ◽  
Indu Bala
Keyword(s):  
Particle Size ◽  
Zeta Potential ◽  
Drug Loading ◽  
In Vitro Release ◽  
Formulation Development ◽  
Ciprofloxacin Hydrochloride ◽  
Potential Value ◽  
The Mean ◽  
In Situ Gelling

Ciprofloxacin hydrochloride loaded Eudragit RS100 nanoparticles were prepared by using w/o/w emulsification (multiple emulsification) solvent evaporation followed by drying of nanoparticles at 50°C. The nanoparticles were further incorporated into the pH-triggered in situ gel forming system which was prepared using Carbopol 940 in combination with HPMC as viscosifying agent. The developed nanoparticles was evaluated for particle size, zeta potential value and loading efficiency; nanoparticle incorporated in situ gelling system was evaluated for pH, clarity, gelling strength, rheological studies, in-vitro release studies and ex-vivo precorneal permeation studies. The nanopaticle showed the mean particle size varying between 263.5nm - 325.9 nm with the mean zeta potential value of -5.91 mV to -8.13 mV and drug loading capacity varied individually between 72.50% to 98.70% w/w. The formulation was clear with no suspended particles, showed good gelling properties. The gelling was quick and remained for longer time period. The developed formulation was therapeutically efficacious, stable and non-irritant. It provided the sustained release of drug over a period of 8-10 hours.

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