Coalescence of Crude Oil Droplets in Brine Systems: Effect of

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Coalescence of Crude Oil Droplets in Brine Systems: Effect of Individual Electrolytes Subhash C. Ayirala, Ali A. Yousef, Zuoli Li, and Zhenghe Xu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00309 • Publication Date (Web): 17 Apr 2018 Downloaded from http://pubs.acs.org on April 17, 2018

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Coalescence of Crude Oil Droplets in Brine Systems: Effect of Individual Electrolytes Subhash C. Ayirala1, Ali. A. Yousef; Saudi Aramco PE&D Zuoli Li and Zhenghe Xu1; University of Alberta

Abstract To better understand mechanisms of enhanced oil production by smart water flooding, the coalescence time of crude oil droplets in different brines was measured. Sulfate ions were found to hinder the coalescence of crude oil droplets, whereas magnesium ions significantly enhanced coalescence of the crude oil droplets. To shed the lights on the observed effect of individual type of water-soluble inorganic ions in brine on coalescence time of crude oil droplets, interfacial shear rheology of crude oil-brine interfaces was measured at both ambient and elevated temperatures. Zeta potential measurements of crude oil in brine emulsions were also conducted at ambient temperature. The major objective of these measurements is to investigate interactions of individual water-soluble inorganic ions with the crude oil-water interface and study their impact on the coalescence of crude oil droplets. Interfacial shear rheology results showed significantly higher viscous/elastic modulus for brines comprising of sulfate ions, while the brines with sodium, calcium or magnesium ions showed comparable interfacial rheology. The transition time — for the interface to become elastic-dominant from a viscous-dominant regime — was found to be the lowest for sulfate brine, followed by the sodium brine and calcium brine, with the highest being with magnesium brine. The most

1

To whom correspondence should be addressed: [email protected] PO Box: 10365, Saudi Aramco, Dhahran 31311, Saudi Arabia Or [email protected], 12th Floor, DICE Building, Department of Chemical and Materials Engineering, University of Alberta, Edmonton, Canada, T6G 1H9

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negative zeta potentials, indicating strongest electrostatic repulsion between two oil droplets, were observed in the sodium brine and sulfate brine. The magnesium brine and calcium brine showed the lowest negative zeta potentials. The results on coalescence time showed a good agreement with the combined effect of film interfacial rheology and zeta potential. This study establishes the impact of individual water-soluble inorganic ions, for the first time, on coalescence between oil droplets in specific relation to water flooding and enhanced oil recovery. Keywords Enhanced Oil Recovery; Water Flooding; Interfacial Rheology; Zeta potential; Oil Ganglia; Coalescence Time. 1.

Introduction Advanced water flooding (also known as smart water flooding) processes through

the tailoring of injection water salinity and electrolyte composition are getting increasing attentions in recent years for improved oil recovery from carbonate reservoirs. Compared with other conventional enhanced oil recovery (EOR) methods such as chemical flooding and gas or steam injection, the cost of smart water flooding is relatively low. Smart water flooding can be considered simply as an improved version of water flooding since it does not require any other external EOR additives in the injection water. For this reason, extensive research has been carried out in the past decade to investigate the effect of injection water chemistry on water flooding in carbonate reservoirs. Close connection has been observed between brine composition1/ionic strength2,

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and oil recovery.

Specific type of ions such as SO42- in the presence of Ca2+ and Mg2+ was found to improve oil recovery in chalk reservoirs.4 While understanding the mechanism behind the 2 ACS Paragon Plus Environment

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effect of brine is still developing, early research is focused mostly on the rock-fluid interactions such as the alteration of wettability.1, 3, 4 Not until recently, the fluid-fluid interactions related to the mobility and continuity of oil phase2 is receiving increasingly more attentions. Interfacial tension (IFT) of an oil-brine interface influences capillary force which determines the mobilization of the trapped oil.5 IFT therefore has a significant effect on oil recovery and production strategy in EOR.6 As important components of crude oils, asphaltenes can be considered as natural surfactants. By comparing the IFT of crude oilbrine and deasphaltened oil-brine interfaces, it is believed that asphaltenes are the critical components responsible for the dynamic behaviour of IFT, although the first contact IFT (zero time) is determined by the whole oil composition7. The presence of salt may alter the distribution of surface active components, including asphaltene and resins present in the oil phase at the interface owing to so called “salting-in” or “salting-out” effects.8 The composition and concentration of brines and the chemistry of crude oils have been found to have a profound effect on brine-crude oil IFT. Vijapurapu and Rao observed a decrease in brine-crude oil IFT by diluting the brine (9,200 ppm TDS) to less than 50% with deionized water, followed by an increase in the IFT with further dilution of the brine to 50% or higher9. Other studies also reported either an increase7 or a decrease6 in the IFT with dilution of brine to different extent. Efficacy of divalent cations to reduce IFT was observed for magnesium in the presence of chloride ion.8 Higher level of IFT values was on the other hand detected for sulfate ions.10 Decreased work of adhesion resulting from lower oil-water IFT is beneficial for improving the mobility of the trapped oil.11


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Adjusting the composition of brine is therefore able to affect the IFT and consequently the oil recovery efficiency8. Surfactants that are known to reduce the IFT at the fluid-fluid interface may increase or decrease the viscoelasticity of the water-oil interfaces,12 with the interfacial elasticity hindering the snap-off of oil, leading to a more continuous interface that can be swept more easily. However, the formation of organized molecular structures related to the presence of asphaltenes and/or resins at fluid-fluid interfaces is believed to increase interfacial viscoelasticity. Recently, interfacial shear rheology (ISR) has gained momentum as a useful tool to determine the rheological properties of interfacial films at the oil-water interface.13,

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Interfacial films formed by asphaltenes (extracted from

different crude oils) in heptane and toluene (model oil) at the oil-water interface were studied using ISR, which identified threshold concentrations of asphaltenes for the formation of stable water-in-oil (W/O) emulsions. Fuller ad Vermant15 provided a good overview on the complex microstructures of oil-water interfaces when surface active molecules accumulate at the fluid-fluid interfaces. It was pointed out in their study that these complex microstructures can lead to rheological complexity to stabilize interfaces, and can also have a profound influence on the dynamics of wetting and dewetting. Furthermore, salinity was found to affect the interfacial properties of crude oil/brine systems.16 Chavez-Miyauchi et al.12 measured interfacial viscoelasticity of two crude oils-brine interfaces at ambient temperature by increasing NaCl and MgCl2 salt concentrations in the aqueous phase. The interfacial elastic and viscous moduli were found to increase as the salt concentration is decreased and a maximum viscoelasticity was observed at 0.01 wt% concentration for both the salts. Garcia-Olvera et al.17


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investigated the effect of asphaletenes and organic acids on crude oil-brine interfacial viscoelasticity and oil recovery in low salinity water flooding. It was suggested that even though snap-off suppression is correlated to viscoelasticity, it should be integrated with other important considerations of mobility control, wettability and fluid distributions to provide a more complete picture on low salinity water flooding mechanisms. While the importance of keeping the connectivity of the oil phase through increasing the oil/brine rigidity to avoid snap-off has been well recognized in water flooding, the very high rigidity of the interface is not necessary to yield a high recovery.17 Actually the two dominant processes, breakup/snap-off and coalescence are both responsible for phase connectivity. These phenomena would take place concurrently during water flooding.18, 19 The effect of individual water-soluble ions on the coalescence of oil droplets, allowing oil droplets snapped-off to reunion and oil mobilization remains largely unexplored. Despite the fact that hydrodynamic force, repulsive electrostatic force between two oil droplets of same surface charge,20 and the viscosity of continuous outer phase

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(aqueous phase in the present study) affected by temperature22 are the main

barriers for the thinning of the intervening liquid film, the final rupture of the thin film to facilitate oil droplets coalescence is closely related to the film rigidity. As a result, we carried out interfacial shear rheology, zeta potential and crude oil droplet coalescence time measurements with consideration of the temperature effect to investigate the effect of individual water-soluble ions on interactions at the crude oil-water interface. The main objective is to derive an important understanding on the effect of different individual ions on interfacial film stability, which governs the oil ganglion dynamics in water flooding and enhanced oil recovery processes.


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2.

Materials, Methods and Experimental Procedures

2.1 Brines. Different salts such as magnesium chloride, calcium chloride dihydrate, sodium sulfate anhydrous, and sodium chloride, with purity of >=99.0%, were obtained from Fisher Scientific and used as received without further treatment to prepare synthetic brine solutions. These solutions are prepared by dissolving individual salts in deionized water and then filtering with 1 µm filter paper. The composition of different synthetic brines used in experiments is summarized in Table 1. A total of four synthetic brine samples were prepared to study the effect of individual water-soluble ions by fixing the salinity at 10-times seawater dilution (5,760 ppm total dissolved solids, TDS). As can been seen in Table 1, each brine is solely composed of one of these salts: MgCl2, CaCl2, NaCl and Na2SO4.

We used fixed TDS approach in this study to decipher different individual water ion interactions at crude oil-water interface as it can be more practical for research studies relevant to oil field applications. This approach is supported by several other recent studies in the literature where salinity is used as the main controlling parameter to investigate on the stability, droplets size distributions and coalescence in emulsion systems23-25. 6 ACS Paragon Plus Environment

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2.2 Crude Oil. A stock tank crude oil was used in this study. It is a light crude oil with a viscosity of about 6.0 cP at room conditions. The total acid number and the total base number were found to be 0.0561 mg KOH/g and 0.7059 mg KOH/g, respectively. The impurities such as solids and water from the crude oil sample were removed using centrifuge methods prior to its use. 2.3 Shear Rheology Measurements. The viscoelastic properties (elastic-G’ and viscous-G”) of the crude oil-brine interface were determined using an AR-G2 stress controlled rheometer (TA Instruments, New Castle, DE, USA) equipped with a double-wall ring (DWR) geometry which is made of Pt/Ir. The radius of the DWR is 35 mm and its square-edged cross section helps to pin it at the oil-water interface. The ring was flamed before each experiment to remove all the organic contaminants. Pipetted first into the sample holder was 19.2 mL aqueous brine solutions as the bottom phase or sub-phase. After positioning the ring at the air-aqueous solution interface, 15 mL of crude oil was pipetted slowly onto the top of the aqueous phase. Finally, a Teflon cap was placed over the sample to prevent crude oil evaporation. To study the effect of interface aging on viscoelastic properties of interfacial layers, time sweep experiments were conducted at an angular frequency of 0.5 Hz using 0.8% strain amplitude for 5 hrs. The measurements were performed at 23 ± 0.1°C and 70°± 0.03oC. 2.4 Zeta Potential Measurements. A 0.01 wt% crude oil in brine emulsion was prepared by homogenization at 10,000 rpm for 3 minutes. Zeta potential of freshly prepared oil in brine emulsions was measured


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using a Zetaphoremeter III (SEPHY/CAD) at 23 ± 0.1°C by following the procedures described elsewhere.26 After filling the electrophoresis cell with the oil in brine emulsion, laser-illuminating and video-viewing system was used to trace the movement of oil droplets in the stationary layer with the direction of the movements of oil droplets being altered through switching the positive/negative electrode potentials. By analyzing the captured images using the built-in image-processing software, the distribution histogram of electrophoretic mobility was determined, which can be converted to zeta potential values. 2.5 Crude Oil Droplets Coalescence Measurements. The coalescence time between two oil droplets in aqueous solutions of different salt compositions was measured by an integrated thin film drainage apparatus (ITFDA) as shown in Figure 1,27 with the top droplet generated at the end of a capillary tube and the bottom droplet (in the shape of cap) placed on a Teflon holder. For each measurement, both of the droplets of desired sizes were aged in the aqueous solutions for 30 minutes before moving the top droplet towards the bottom droplet at a constant approach velocity of 0.3 mm/s controlled by a speaker diaphragm. After the overlap of the two oil droplets reached 0.15 mm, the top droplet was held still for 2 minutes. A charge-coupled device (CCD) camera was used to record entire process of the top drop approaching and holding in contact with the lower droplet. High temperature of the brine solution in the cell was controlled by a heating plate on which the cell was placed. Coalescence time was determined as the time required for two oil droplets to coalesce after they were just in contact. Please see reference 27 for more details on the experimental procedures.


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Figure 1. Schematic view of integrated thin film drainage apparatus (ITFDA) used for coalescence time measurements (adopted from reference 27 with the permission from publisher).

3.

Results and Discussion

3.1 Interfacial Shear Rheology. The measured elastic modulus (G’) and viscous modulus (G”) of the crude oilwater interfacial films with different brines at two temperatures of 23°C and 70°C are shown in Figure 2. The elastic and viscous moduli showed almost identical trends in response to the chemistry of brines at these two temperatures. The viscous and elastic moduli were found to be the highest for the sulfate-only brine (brine 4) at both 23°C and 70°C. The other three brines containing Na+, Ca2+ and Mg2+ ions as the chloride salts 9 ACS Paragon Plus Environment

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showed comparable values at 23°C, while Na+ and Mg2+ brines showed the similar moduli values, followed by the lowest values with Ca2+ brine at 70°C.

Figure 2. Viscous (A/C) and elastic modulus (B/D) of crude oil-brine interface vs. time at 23°C (A-B) and at 70°C (C-D).

The repeatability on the measured interfacial shear rheology is shown in Figures 3A and 3B for brine 1 at ambient and elevated temperatures, respectively. As can be seen, almost identical numbers in viscous and elastic moduli are obtained between the two runs for both 23°C and 70°C, which confirms the good repeatability of these measurements. The difference in the time where G’=G” transition occurs for the two repeating tests is


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less than 10 min at 23°C, and this difference falls below 5 min at 70°C. Therefore, it can be concluded that the interfacial shear rheology results reported in this study are very reliable.

Figure 3. Repeatability of interfacial shear rheology results measured using brine 1 at 23°C (A) and 70°C (B).

The measured viscous/elastic moduli at 23°C are summarized in Figures 4A to 4D for individual brines of Na+, Mg2+, Ca2+ and SO42-, respectively. As shown in these figures, both G’ and G’’ increased with increasing aging time but the elastic modulus evolved in a much faster rate than viscous modulus. Therefore, the original viscousdominant interfacial layers became eventually elastic-dominant for all the brines. The buildup of elastic modulus at the crude oil-brine interface may be caused by the accumulation of asphaltenes at the interface to form a rigid network of asphaltenic structures,28 which is solid-like.29 Although measurable elastic modulus would confirm the formation of a coherent interfacial barrier,30 this coherent structure must also be elastically dominant to inhibit and prevent the rupture of the intervening liquid film and 11 ACS Paragon Plus Environment

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droplet coalescence.31 Therefore, the viscous to elastic transition of the interfacial films starting from the intersection of G’ and G’’ contributes to the increased stability of crude oil-in-brine (O/W) emulsions or the hindered oil droplet coalescence in these brines.32 A good agreement between the interfacial layer transition time and the stability of water droplets in C5Pe (resembling the properties of asphaltenes) xylene solutions has been observed elsewhere31. The aging time for this transition to occur or the time for G’ = G” is actually highly affected by the chemistry of the aqueous phase.

Figure 4. Elastic and viscous moduli measured as a function of aging time for brine 1 (A), brine 2 (B), brine 3 (C) and brine 4 (D) at 23°C.


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As shown in Figure 4, the transition of the crude oil-water interface to the elastic dominant microstructure occurred within 67.4 min aging for brine 4, while this structure change took longer aging time to occur for the other three brines. The transition from the viscous-dominant (liquid-like) to the elastic-dominant (solid-like) microstructures was observed at 133.6, 153.0 and 129.5 min aging time for brines 1, 2 and 3, respectively. Since the interfacial film formed with high elastic modulus resists the compression and deformation of the droplets to hinder the coalescence of droplets,33, 34 a shorter transition time to elastic regime represents a higher stability of the interface and hence a more stable emulsions. Compared with other brines, a relatively short transition time (67.4 min) to elastic-dominant regime was observed with brine 4, indicating a stronger impact of sulfate ions on promoting the formation of rigid stable films to hinder the coalescence between the oil droplets in brine 4. This observation can be attributed to the possible decreased viscosity of crude oil in contact with brines with sulfate ions35, related to the shape change of heavy component molecules including aromatics, asphaltenes and resins, considering that asphaltenes travel faster to the interface in the lower-viscosity oils.17 In contrast, the other brines with chloride ions give rise to comparable transition time, longer than brine 4. Interestingly similar observations were also made by Chav́ezMiyauchi et al.12 who observed no appreciable differences in the ambient temperature interfacial rheology data measured between NaCl and MgCl2 brines at a low concentration. However it is important to note that the sensitivity of interfacial shear rheology data to different cations is very well reflected in the speed of interfacial film transition from viscous to elastic dominant regime (G=G” times). The crude oil-brine 2 interface remained viscous-dominant for at least 153 min, longer than brine 1 and brine 3,


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which may be caused by competitive adsorption between asphaltenes and the nonasphaltenic surface active components of crude oil, such as naphthenic acids or naphthenate salts.16, 33, 36 Higher ionic strength of cations in brines is known to lower solubility of organic acids (i.e., naphthenic acid) in aqueous phase. It is possible that the low-solubility naphthenate salts in brine adsorb preferentially at the crude oil-brine interface, slowing down the adsorption of asphaltenes and hence the formation of rigid films.36 The influence of organic acids on the rigidness and hence the emulsion stability has been observed even with a low content of inorganic cations.37 In our study, the highest and lowest cationic strength in brine 2 and brine 4 (Table 1) corresponded to the longest and shortest transition time of G’=G’’, and this difference on transition is further strengthened by the possible oil viscosity decrease by sulfate ions in brine 4, as anticipated. Figures 5A to 5D show the measured viscous and elastic moduli of crude-brine interfaces at 70°C for the individual brines of Na+, Mg2+, Ca2+ and SO42-, respectively. At room temperature, the elastic-dominant structure in the interfacial layer at the crude oilbrine 2 interface developed after an aging time of 2.5 hours, as shown in Figure 4B. However, the elastic-dominant structure formed already within less than 1 hour of aging at 70°C, as shown in Figure 5B. This decrease in the transition time of G’=G” with increasing the temperature was observed for all the brines investigated. Such decrease can be attributed to the reduced viscosity of crude oil at elevated temperature,38 resulting in faster migration of asphaltenes and other interfacial active materials to the interface.17 Similar to the case at room temperatures, the transition time of G’=G” is the longest for brine 2 and the shortest for brine 4 at 70°C, which can be attributed to the similar 14 ACS Paragon Plus Environment

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mechanisms of competitive adsorption between asphaltenes and non-asphaltenic surface active components.

Figure 5. Evolution of viscous and elastic moduli for brine 1 (A), brine 2 (B), brine 3 (C) and brine 4 (D) measured at 70°C.

3.2 Zeta Potential of Oil Droplets in Brine. The zeta potential measured for crude oil in brine emulsions was all negative as shown in Figure 6. It is well known that the dissociation of acidic functional groups and protonation of basic functional groups collectively determine the electric charge of the crude oil/brine interfaces at different pHs.39, 40 Since the pH around 6 of different brines used in the current study (Table 1) is much higher than the dissociation pH (between pH 15 ACS Paragon Plus Environment

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3 to pH 5) of typical surface active organic acids in crude oil,39, 40 it is not surprising to see negatively charged crude oil droplets when dispersed in the different brines. Increasing ionic strength of brine is known to decrease the magnitude of the zeta potential of crude oil droplets as a result of electrical double layer compression.41-43 In the current study, the lower negative zeta potential in brines 2 (magnesium-only) and 3 (calciumonly) is attributed to their high ionic strength. Similarly, the higher negative zeta potentials observed for brines 1 (sodium-only) and 4 (sulfates-only) are due to their lower ionic strength. In addition, divalent cations like Ca2+ and Mg2+ are believed to react with dissociated acidic components, forming positively charged R-COO-Ca+ complexes at the interface42, which further decrease the magnitude of the negative zeta potential for brines 2 and 3. On the other hand, the less negative zeta potential for brine 3 than brine 2 can be due the lower pH of 6.05 for the former than that of 6.32 for the latter, since the dissociation of acidic groups is promoted by increasing pH at the range higher than the isoelectric points of crude oil-water interface. The different zeta potentials of crude oil droplets in different brines are, therefore, attributed to the combined effect of pH, ionic strength, and specific adsorption. Given that the oil droplets are negatively charged in the brines, the larger magnitude of the zeta potential indicates a stronger electrostatic repulsion between two oil droplets. It is therefore anticipated to maintain a thicker water film between and be more difficult to achieve the coalescence of oil droplets in brines 1 and 4 than in brines 2 and 3.


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Figure 6. Zeta potential of crude oil in brine emulsion measured at room temperature.

3.3 Oil Droplet Coalescence Time. By accurately controlling the size and the alignment of two droplets, the coalescence time measurement in different brines was found to be highly reproducible. The snapshots captured from the recorded video of crude oil droplet coalescence process in brines 1, 2, 3 and 4 at 23oC and 50oC are shown in Figures 7A and 7B, respectively. It was observed during the preliminary experiments that the oil droplets were unstable on the glass capillary tube at 70oC, which makes it difficult to maintain the size of the droplets during the aging period. To keep the size of droplets constant and hence to obtain reproducible results, the coalescence time measurements at elevated temperature were therefore performed at 50oC to investigate the effect of temperature on oil droplet coalescence.


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Figure 7. Snapshot of crude oil droplet coalescence process in brines 1 to 4 at 23°C (A) and 50°C (B).

As shown in Figures 7A and 7B, the video frames depict different dynamics of the crude oil droplet coalescence process. The time required to initiate the coalescence of oil droplets from their initial contact is determined to be the actual coalescence time. The oil droplets coalescence time obtained with different brines, together with their error bars at both 23oC and 50oC is summarized in Figure 8. The error bars on the coalescence time are typically within ± 2 seconds and are based on at least 3 measurements for each condition. As shown in Figure 8, the coalescence time of crude oil droplets decreases with increasing temperature for all the brines, although the film is more rigid at high temperature, due to both increased reactivity and faster kinetics of interfacially active materials at the higher temperature. Considering a great difference in the viscosity of 18 ACS Paragon Plus Environment

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water between 0.9321 cP and 0.5465 cP at 23 °C and 50 °C, respectively, the faster coalescence at high temperature is probably due to the lower viscosity of the brine, which is anticipated to speed up the draining of thin liquid films, and hence cut down coalescence time, especially for the system of Re Ca+2 > Na+ > SO42-. The divalent cations such as Mg2+ and Ca2+ seem to soften the oil-water interface so that the interfacial layers can


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be easily deformed and broken to quickly facilitate the coalescence between oil droplets. The SO42- ions form rigid films at the crude oil-water interface that are hard to deform, and subsequently to retard the coalescence of oil droplets.

Figure 9. Summary of shear rheology, zeta potential and coalescence at room temperature at 23°C (A) and elevated temperature (shear rheology: 70°C; coalescence time: 50°C; zeta potential: 23°C) (B).

4.

Summary and Conclusions This experimental study demonstrated the impact of different individual inorganic

ions in brine on the viscoelastic properties of crude oil-water interfacial film and crude oil droplet coalescence time at both ambient and elevated temperatures. In contrast to the previous reports,14, 21 this study provides new understanding on the effect of different individual water-soluble inorganic ions on interfacial film stability, which governs the oil ganglion dynamics through coalescence phenomenon in water flooding processes. 22 ACS Paragon Plus Environment

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Interfacial films in the presence of Mg2+ ions showed comparable viscous/elastic modulus with the films formed in the presence of Ca2+ and Na+ ions and exhibited much higher transition time for the interfacial film to become elastic-dominant. The results indicated the favorable characteristics of Mg2+ ions to result in less rigid interfaces and promote the coalescence between oil droplets, which was confirmed by the lowest coalescence time measured between oil droplets in Mg2+ brine. The interfacial films formed in the presence of SO42- ions showed much higher viscous/elastic modulus as compared with the film formed in Mg2+, Ca2+ or Na+ brines and much lower G’ = G” transition time. Such findings revealed that SO42- ions can result in rigid films at the interface that is hard to rupture, and hence hinder the coalescence between oil droplets. The detrimental effects of sulfate ions were further corroborated with the highest coalescence time measured for oil droplets in the brine composed of only SO42- ions. The efficiency of different individual water-soluble inorganic ions to result in less rigid interfacial films and faster coalescence time is in the following order: Mg2+ > Ca+2 > Na+ > SO42-. Based on these results, it can be concluded that Mg2+ and Ca2+ ions can effectively destabilize the interfacial film to promote the coalescence between oil droplets, and enable faster oil mobilization in water flooding processes.

Acknowledgments The authors would like to acknowledge Carol Dwaik, Pradyumna Kedarisetti, Lan Liu, Zhitong Lin, and Xi Wang, at the University of Alberta, for their assistance in conducting the crude oil geochemical analysis, shear rheology, and coalescence time laboratory experiments.


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Energy & Fuels

Graphical abstract


Coalescence of Crude Oil Droplets in Brine Systems: Effect of

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