Range Of Interfacial Tensions Research Articles

Comparison of Techniques for Drying Cellulose Nanocrystal Pickering Emulsions into Oil Powders

A recent push for surfactant-free products driven by environmental awareness has propelled the use of bio-based materials in place of petroleum-derived components. However, both the formulation and processing need to be considered for scale-up feasibility and environmental sustainability. This work investigated the drying of corn oil-in-water emulsions stabilized by cellulose nanocrystals (CNCs), methyl cellulose (MC), and tannic acid via freeze drying, spray freeze drying, and spray drying. All three techniques produced oil powders with low moisture content and high encapsulated oil content (>90%). The oil powders could be redispersed in water by hand shaking to reform the original emulsion and could be stored dry for weeks without oil leakage (in the fridge). The release of oil from the powders on hydrophobic substrates (at room temperature) was controlled by changing the CNC and MC stabilizer content; the spray freeze dried samples were the most tunable. The three drying techniques imparted different surface morphologies that were linked to powder redispersibility and oil release properties. The lack of freezing (and associated ice crystal growth) in spray drying minimized oil droplet agglomeration, and it was the fastest, most scalable, and least energy-intensive drying technique of the three, but it was also the most sensitive to emulsion concentration and susceptible to instabilities associated with high temperature and shear stress. It was demonstrated that essential oils with a range of interfacial tensions and volatilities (e.g., jojoba, lavender, tea tree oil) could also be encapsulated in spray dried oil powders. This general encapsulation strategy can be tailored based on the drying technique selected, uses plant-based industrially-produced feedstocks, works with commercially relevant oils, and will hopefully contribute to the development of sustainable emulsions and oil powders for food, pharmaceutical, agricultural, and cosmetic applications.

Numerical assessment of ultrasound supported coalescence of water droplets in crude oil

In this study, a numerical assessment of the coalescence of binary water droplets in water-in-oil emulsion was conducted. The investigation addressed the effect of various parameters on the acoustic pressure and coalescence time of water droplets in oil phase. These include transducer material, initial droplet diameter (0.05–0.2 in), interfacial tension (0.012–0.082 N/m), dynamic viscosity (10.6–530 mPas), temperature (20–100 °C), US (ultra sound) frequency (26.04–43.53 kHz) and transducer power (2.5–40 W). The materials assessed are lead zirconate titanate (PZT), lithium niobate (LiNbO3), zinc oxide (ZnO), aluminum nitride (AlN), polyvinylidene fluoride (PVDF), and barium titanate (BaTiO3). The numerical simulation of the binary droplet coalescence showed good agreement with experimental data in the literature. The US implementation at a fixed frequency produced enhanced coalescence (t = 5.9–8.5 ms) as compared to gravitational settling (t = 9.8 ms). At different ultrasound (US) frequencies and transducer materials, variation in the acoustic pressure distribution was observed. Possible attenuation of the US waves, and the subsequent inhibitive coalescence effect under various US frequencies and viscosities, were discussed. Moreover, the results showed that the coalescence time reduced across the range of interfacial tensions which was considered. This reduction can be attributed to the fact that lower interfacial tension produces emulsions which are relatively more stable. Hence, at lower interface tension between the water and crude oil, there was more resistance to the coalescence of the water droplets due to their improved emulsion stability. The increment of the Weber number at higher droplet sizes leads to a delay in the recovery of the droplet to spherical forms after their starting deformation. These findings provide significant insights that could aid further developments in demulsification of crude oil emulsions under varying US and emulsion properties.

Surfactant enhanced imbibition in carbonate reservoirs: Effect of IFT reduction and surfactant partitioning

A majority of carbonate reservoirs are preferably oil-wet or intermediate wet. Spontaneous imbibition represents an important mechanism to enhance oil production. Targeting an oil-wet carbonate reservoir with high temperature and high salinity, several surfactant formulations were investigated to improve oil production by imbibition, focusing on the capacity in interfacial tension (IFT) reduction and surfactant partitioning in water and oil phases in addition to dominant wettability alteration effect. Oil production potentials using different surfactants were evaluated by spontaneous imbibition in Amott cells at 95 ​°C. A base case imbibition test was conducted using a high salinity water with IFT value of 15.2 ​mN/m and an oil-wet carbonate core, and the oil production was 6.4% of oil originally saturated in core. Reducing the oil-water IFT to 10° ​mN/m magnitude achieved 4% incremental oil production beyond base case. When the IFT was further reduced to 10 −1 ​mN/m magnitude, the incremental oil production reached 10%. For the case of water-wet core and at the same IFT range, the incremental oil production was 13%. When the IFT was reduced to 10 −2 ​mN/m, the incremental oil production was up to 17% for the tests using oil-wet cores, and up to 23% for the water-wet counterpart. When further reducing the IFT to ultra-low magnitude of 10 −3 ​mN/m, the oil production was close to that using the imbibition agents with IFT of 10 −2 ​mN/m magnitude. For surfactants with no obvious wettability alteration capacity, those surfactants with higher molecular fraction in oil phase and higher adsorption on rock surfaces could remove more oil from the pore wall, and yielded higher imbibition efficiency. This work systematically investigated the major effects of surfactant on oil mobilization during imbibition process, which can help for better understanding of chemical imbibition in carbonates. The findings will shed light on the selection of high performance imbibition agents for carbonate reservoirs.

Performance and optimization of biological and chemical composite flooding system for enhanced oil recovery

Biological and chemical compound flooding systems have excellent performance and broad application prospects in enhanced oil recovery. In this study, the most efficient and environmentally friendly type of bio-chemical compound alkaline-surfactant-polymer (ASP) flooding system, namely the ASP-PST85, is constructed with Na2CO3, petroleum sulfonate (NPS), biosurfactant surfactin, polyacrylamide, and Tween-85. The interfacial activity, dilution stability, adsorption stability, aging stability, temperature stability, and emulsification property of the ASP-PST85 system are evaluated. The results show that the range of interfacial tension of 10−4 mN/m between the ASP-PST85 system and crude oil is significantly expanded compared to that of the original ASP system, which is referred to as the ASP-PS system. Simultaneously, the emulsion and adsorption stability are also significantly improved. The microfluidic measurement results show that the ASP-PST85 system reaches the saturated adsorption of surfactant at the oil-water interface faster than the ASP-PS system, probably due to its higher emulsion stability. This study provides a reference for the construction of high-performance and bio-chemical compound flooding systems, providing a theoretical and methodological basis to obtain basic data of rapid adsorption kinetics at the oil-water interface.

How a range of metal ions influence the interfacial tension of n-decane/carboxylic acid/water systems: The impact of concentration, molecular- and electronic structure

The data from more than 700 pendant droplet interfacial tension (IFT) measurements has been scrutinized to reveal the relation between salinity/surfactant structure and IFT in a brine – decane/carboxylic acid system. The large number of measurements enabled an experimental uncertainty of around 1% in the IFT range around 30 mN/m. Thus, small changes and trends in IFT as a function of salinity and surfactant structure become apparent. Five carboxylic acids are chosen to resemble natural naphthenic acids; individually, they only differ by a CH2-group starting from cyclohexane carboxylic acid and ranging to 5-cyclohexyl pentanoic acid. The salt concentration was varied from 0.01 M to 1.0 M for a range of chlorides of monovalent and divalent metal cations: LiCl, NaCl, KCl, MgCl2, CaCl2, SrCl2, BaCl2, and ZnCl2. For Na+, NaBr, NaI, were also investigated. The variation in IFT with salinity and carboxylic acid is subtle with divalent ions, not surprisingly, inducing larger IFT changes than monovalent ones when the concentration is varied. Zn2+ gives rise to a surprisingly large IFT reduction (up to 7.5 IFT units in the range from 0.01 M to 1.0 M) and clearly stands out as a special case. For the three smallest chain acids the IFT increases as a function of salinity whereas, for the system involving the two largest ones, 4-cyclohexyl butanoic acid and 5-cyclohexyl pentanoic acid, IFT decreases as a function of salinity. The distinct behavior of Zn2+ and the sudden crossover in the variation of IFT as a function of salinity when increasing the chain length of the carboxylic acid is taken to indicate that structure of both the (solvated) electrolyte and the carboxylic acid– particularly with regard to the orientation at the interface - are important factors in determining the magnitude and variation in IFT as a function of physical parameters.

Correlations of Equilibrium Interfacial Tension Based on Mutual Solubility/Density: Extension to n-Alkane–Water and n-Alkane–CO2 Binary/Ternary Systems and Comparisons With the Parachor Model

In this study, new and pragmatic interfacial tension (IFT) correlations for n-alkane–water and n-alkane–CO2 systems are developed based on the mutual solubility of the corresponding binary systems and/or density in a pressure range of 0.1–140.0 MPa and temperature range of 283.2–473.2 K. In addition to being more accurate (i.e., the absolute average relative deviation (AARD) is 1.96% for alkane–water systems, while the AARDs for alkane–CO2 systems are 8.52% and 25.40% in the IFT range of >5.0 mN/m and 0.1–5.0 mN/m, respectively) than either the existing correlations or the parachor model (the AARDs for alkane–CO2 systems are 12.78% and 35.15% in the IFT range of >5.0 mN/m and 0.1–5.0 mN/m, respectively), such correlations can be applied to the corresponding ternary systems for an accurate IFT prediction without any mixing rule. Both a higher mutual solubility and a lower density difference between two phases involved can lead to a lower IFT, while pressure and temperature exert effects on IFT mainly through regulating the mutual solubility/density. Without taking effects of mutual solubility into account, the widely used parachor model in chemical and petroleum engineering fails to predict the IFT for CO2/methane–water pair and n-alkane–water pairs, though it yields a rough estimate for the CO2–water and methane–water pair below the CO2 and methane critical pressures of 7.38 and 4.59 MPa, respectively. However, the parachor model at least considers the effects of solubility in the alkane-rich phase to make it much accurate for n-alkane–CO2 systems. For n-alkane–CO2 pairs, the correlations developed in this work are found to be much less sensitive to the liquid density than the parachor model, being more convenient for practical use. In addition, all the IFTs for the CO2–water pair, methane–water pair, and alkane–CO2 pair can be regressed as a function of density difference of a gas–liquid system with a high accuracy at pressures lower than the critical pressures of either CO2 or methane.

Formation of the layering boundary in the water–benzene–perfluorobenzene system

The dynamics of the interface between liquid phases in the water–benzene–perfluorobenzene system was studied in a natural experiment. The interfacial tension was found to depend on the density of the organic layer. The range of interfacial tensions in which inversion of the organic and aqueous phases takes place was determined, and the working range of a separating flask as an element of the separation scheme for the mixture was revealed.

EOR Potential of Mixed Alkylbenzenesulfonate Surfactant at Low Salinity and the Effect of Calcium on “Optimal Ionic Strength”

The enhanced oil recovery (EOR) potential of different alkylbenzenesulfonate surfactants was investigated in a combined study of crude oil–water phase behavior and interfacial tension (IFT) and macroscopic oil displacement studies. In the presence of small amounts of calcium ions (calcium/sodium = 4 mol %), ultralow oil–brine IFT (<0.001 mN/m) was observed at ionic strengths 10 times lower than “optimal salinity” with sodium chloride only; this suggested an application in low salinity surfactant (LSS) EOR. “Optimal ionic strength” was determined for different calcium/sodium ratios in the brine, which further allowed prediction of phase behavior and IFT range for a given surfactant and a given crude oil at different brine compositions. In laboratory core floods, crude oil displacement by LSS with an optimal ionic strength electrolyte was around 9% higher than at “non-optimal” conditions.

Destabilization of a dual emulsion to form a Janus emulsion

A vegetable oil (VO) was added to an emulsion of silicone oil in water (SO/W) with mixing limited to once turning the test tube upside down. Initially, the VO was dispersed into virtually centimeter-sized drops and the emulsion contained effectively no Janus drops, while after 1 h of agitation at a low level to prevent creaming, drops of 50–100-μm size of the two oils were observed: in addition to an insignificant number of Janus drops. The topology of the latter showed them to emanate from flocculated individual drops of the two oils, but with no discernible effect by the interfacial tension equilibrium on the drop topology. Continued gentle mixing gave increasing fraction of Janus drops of increased size with a topology gradually approaching the one expected from the interfacial equilibrium at the contact line. The spontaneous formation of Janus drops indicated a reduction of the interfacial free energy in the process and the interfacial energy difference between separate and Janus drops was calculated for an appropriate range of interfacial tensions and for all oil fractions. The calculations enabled a distinction of the decrease due to interfacial area changes from the reduction of interfacial tensions per se, with the latter only a minor fraction.

Correlations between interfacial tension and cumulative tertiary oil recovery in a triglyceride microemulsion flooding

This paper presents measurements of interfacial tension (IFT) and tertiary oil recovery (TOR) of triglyceride microemulsion flooding over a wide range of aqueous phase compositions. Based on 160 experimental data sets, two empirical correlations were established. Both the power-law and logarithmic models were validated statistically. Power-law and logarithmic models are predicted to perform best at ultralow IFT range (<0.001mN/m) and high IFT range (>2mN/m), respectively. The valid models indicate that IFT is the sole parameter affecting the cumulative TOR in a triglyceride microemulsion flooding. This phenomenon, however, does not apply in hydrocarbon-based microemulsions.

An Experimental Study of the Influence of Interfacial Tension on Water–Oil Two-Phase Relative Permeability

Adding surfactant into the displacing aqueous phase during surfactant-enhanced aquifer remediation of NAPL contamination and in chemical flooding oil recovery signifi- cantly changes interfacial tension (IFT) ( σ) on water-oil interfaces within porous media. The change in IFT may have a large impact on relative permeability for the two-phase flow system. In most subsurface flow investigations, however, the influence of IFT on relative permeability has been ignored. In this article, we present an experimental study of two-phase relative- permeability behavior in the low and more realistic ranges of IFT for water-oil systems. The experimental work overcomes the limitations of the existing laboratory measurements of rel- ative permeability (which are applicable only for high ranges of IFT (e.g., σ> 10 −2 mN/m). In particular, we have (1) developed an improved steady-state method of measuring com- plete water-oil relative permeability curves; (2) proven that a certain critical range of IFT exists such that IFT has little impact on relative permeability for σ greater than this range, while within the range, relative permeabilities to both water and oil phases will increase with decreasing IFT; and (3) shown that a functional correlation exists between water-oil two- phase relative permeability and IFT. In addition, this work presents such correlation formula between water-oil two-phase relative permeability and IFT. The experimental results and proposed conceptual models will be useful for quantitative studies of surfactant-enhanced aquifer remediation and chemical flooding operations in reservoirs.

A generalized correlation for predicting gas–condensate relative permeability at near wellbore conditions

It is a well established finding, both experimentally and theoretically that relative permeability ( k r) of gas–condensate systems at low interfacial tension (IFT) depends on velocity and IFT. There are a number of correlations available both in the literature and commercial reservoir simulators that account for the coupling (i.e., the increase of k r as velocity increases and/or IFT decreases) and inertial (i.e., the reduction of k r as velocity increases) effects at near wellbore conditions. These functional forms, which with the exception of Whitson et al. (Whitson, C.H., Fevang, O., Saevareid, A., Oct. 1999. Gas condensate relative permeability for well calculations, SPE 56476. Proc. of SPE Annual Technical Conference and Exhibition Texas) are based on saturation, estimate the two effects separately and include a number of parameters, which should be determined by cumbersome and expensive k r measurements at low IFT and high velocity conditions. We have previously reported the development of a fractional flow based correlation (Jamiolahmady, M., Danesh, A., Henderson, G.D. and Tehrani, D.H., Dec. 2006. Variations of gas–condensate relative permeability with production rate at near wellbore conditions: a general correlation, SPE Reserv. Eng. Evalu. J., 9 (6), pp. 688–697), which expressed the combined effect of coupling and inertia simultaneously, but its dependency on fluid viscosity limited its use to the range of IFT values studied. In this paper we present a generalized correlation based on relative-permeability-ratio, which is closely related to a fractional flow of gas and condensate. The parameters of the new correlation are either universal, applicable to all types of rocks, or can be determined from commonly measured petrophysical data. The performance of the correlation has been evaluated over a relatively wide range of IFT and velocity variations. This has been conducted by comparing its prediction with the gas–condensate relative permeability values measured on porous media with very different characteristics. These data had not been used in developing the correlation. The results are quite satisfactory confirming the generality of the correlation in providing reliable information on gas–condensate relative permeability values for near wellbore conditions.

Development and application of dilute surfactant–polymer flooding system for Shengli oilfield

A dilute surfactant–polymer (S–P) flooding system has been designed and developed for Gudong oilfield with Shengli petroleum sulfonate (SLPS) as the primary ingredient. The dynamic behavior of the system and the interactions of the system components have been investigated through various methods, including DPD molecular modeling technology and dynamic interfacial-tension analysis. The results have shown a significant synergistic effect between sulfonate and nonionic surfactant. The interfacial tension (IFT) and its time to reach equilibrium could be dramatically decreased, suggesting a fast diffusion–adsorption characteristic of ionic surfactants as well as the high surface activity of nonionic surfactants. The S–P flooding formulation was finalized as 0.3% (w/w) SLPS + 0.1% (w/w) 1# + 0.15% polyacrylamide (PAM), in which 1#, the secondary surfactant, is able to enhance the interfacial activity of SLPS and the flooding efficiency of the system. The S–P flooding system manifests a wide range of IFT with the lowest value of 2.95 × 10 − 3 mN/m. The pilot field trial of the system has exhibited outstanding performance to improve oil production and reduce water cut since the first injection of the main slug of the S–P flooding system started in June 2004. Until July 2008, the accumulated oil-production had risen by 17.8 × 10 4 tons, with the oil-recovery increase by 6.4%. The field trial provides useful information for the further large-scale application of the SP system in Shengli oilfield.

Initial Interfacial Tension and Oil Uptake by Deep‐fat Fried Foods

ABSTRACTFundamental theory of surface chemistry was utilized to develop an equation for calculating initial interfacial tension between a product and liquid. The relationship provides a practical approach to overcome the complexity of quantitatively determining interfacial tension of foods. The range of interfacial tension between a restructured potato product and the frying medium was 0.01 to 5.23–10−3 N/m. This range was determined using various frying media or additives. A power relationship was found between the initial interfacial tension and uptake of oil or other frying media. A model of capillary rise in porous media was implemented to explain the linear relationship between uptake and contact angle.

An improved and semi-automated version of the drop volume technique for interfacial tension measurement

Although it requires only small volumes of liquids, the drop volume technique is capable of measuring interfacial tensions with high precision. The volume of the drop which just detaches from a cylindrical support of known radius is determined, and this value is used in conjunction with known liquid densities and empirically derived tables (Harkins and Brown 1919) to calculate the interfacial tension. A syringe micrometer head (Mitutoyo Digimatic Series 164) allows the traditional technique to be improved in two ways. First, the new head has an increased capacity, which in certain systems means that the accessible range of interfacial tensions is widened and in others that more data are obtained from a single setting-up of the system. Second, the head is capable of outputting in BCD form. This allows the technique to be made on-line and eliminates a tedious calculation routine.

Lipase kinetics at the triacylglycerol-water interface using surface tension measurements

Two methods, the so-called “oil drop” and “Teflon plunger” methods, were designed to monitor lipase hydrolysis of natural long-chain triacylglycerols through the variation with time of the oil-water interfacial tension. The first part of this work is devoted to the development of these two techniques using pure, well-characterized porcine pancreatic lipase. They gave linear responses with enzyme concentrations ranging from 1 × 10 −3 to 30 units × ml −1. We then applied them to a study of the optimal pH conditions for human gastric lipase which were found to range around 5, as previously observed. In the presence of variable concentrations of sodium taurodeoxycholate, these two methods also showed that human gastric lipase is active in the 8–13 dyn cm −1 range of interfacial tension. It is concluded that these two methods, based upon variations with time of the oil-water interfacial tension, constitute reliable, sensitive and convenient means of investigating lipase kinetics.

Effect of Interfacial Tension on Displacement Efficiency

Abstract Immiscible displacement tests were performed in a consolidated sandstone core over the interfacial tension range from less than 0.01 to 5 dynes/cm to better define how interfacial tension (IFT) reduction can lead to increased oil recovery. Data obtained were displacement efficiency at breakthrough vs IFT for both drainage and imbibition conditions. These tests simulate water flooding under oil-wet and water-wet conditions, respectively. Results of the study have shown that displacement efficiency under both oil-wet and water-wet conditions can be markedly improved by a sufficient reduction in IFT. In the particular porous media used and for the low pressure gradients employed, the IFT must be reduced to a value less than about 0.07 dynes/cm to achieve increased recovery at the time of breakthrough of the injected phase. Below 0.07 dynes/cm, further small reductions in IFT result in large increases in displacement efficiency. Observed increases in recovery were obtained at pressure gradients which are well below those which can exist in the interwell area of a reservoir under water flood. The effect of pressure gradient on recovery is discussed. INTRODUCTION A residual oil saturation remains in rock which has been water flooded because, under usual reservoir conditions, the driving force which can be generated is inadequate to expel oil trapped by capillary forces. Since these capillary forces can be reduced by reducing the IFT a frequently studied method 1-5 of increasing oil recovery has been the use of surfactants to reduce the water-oil interfacial tension. Mungan1 observed improved recovery in both water-wet and oil-wet systems at 1.1 dyne/cm IFT, finding that the amount of improvement was greater in oil-wet systems. Moore and Blum,2 working with visual flow cell micro-models, concluded that recovery cannot be improved in water-wet systems by injecting surfactant solutions. They calculated that, for a pressure gradient of 1 psi/ft in their model, the IFT must be reduced to 0.03 dynes/cm to release oil trapped under water-wet conditions. Berkeley et al.3 indicated that, at representative field flooding rates, the IFT must be reduced to 0.001 dyne/cm to improve recovery. Thus, there is a wide variation of opinion about the IFT levels needed to improve recovery under field conditions. These previous investigators all have used as their experimental method the addition of surfactants to the injected water. The use of surfactant solutions to reduce IFT creates two experimental problems:the loss of surfactant through adsorption on reservoir rock can obscure the true IFT value which exists at the displacement front, andat very low values of IFT emulsification of oil and water commonly occurs. It is difficult, therefore, to determine whether the increased recovery is caused by IFT reduction as such, or is instead caused by emulsification. Also the properties of the available surfactants limit the IFT range which can be studied. In the present study the purpose is to better define how interfacial tension reduction can lead to increased oil recovery. A matter of great interest is the amount of recovery improvement potentially achievable in this way. The study was made using very low pressure gradients which was well within the range achievable by water flooding in the interwell region of petroleum reservoirs. A unique experimental approach was chosen to avoid adsorption and emulsification problems, and to allow convenient control of IFT. The fluid phases used were the equilibrium vapor and liquid phases of the methane-n-pentane system. The interfacial tension level was varied by changing the equilibrium pressure of the methane-pentane system over the range from 1,200 psia to near the critical pressure (2,420 psia). All tests were performed at a controlled temperature of 100F. The IFT-vs-pressure relationship for the methane-pentane system was based on the data of Stegemeier and Hough,6 and on new data obtained in this study. With this experimental approach it has been possible to study displacement at lower values of IFT than have been previously investigated.