Effects of temperature, pH, and ionic strength on the adsorption of nanoparticles at liquid–liquid interfaces

Ferdous, Sultana; Ioannidis, Marios A.; Henneke, Dale

doi:10.1007/s11051-012-0850-4

Cited by 42 publications

(26 citation statements)

References 43 publications

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“…19,46 Solution pH can alter both the surface properties of the nanoparticles (e.g., their 'hydrophobicity'), 47 as well as NP-NP interactions 48 .…”

Section: Resultsmentioning

confidence: 99%

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Nanoparticle effects on the water-oil interfacial tension

2012

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Although it is well known that solid particles adsorb at interfaces, no consensus has been reached on whether or not the adsorbed nanoparticles affect interfacial tension. In this work the Wilhelmy plate method is implemented in mesoscale dissipative particle dynamics (DPD) simulations to study the influence of nanoparticles on the water-oil interfacial tension. The results are compared with predictions that neglect nanoparticlenanoparticle interactions at the interface. We find that the two estimates can differ significantly. In the regime where nanoparticle-nanoparticle repulsion is large, the Wilhelmy plate method suggests interfacial tension reduction, which appears to be a strong function of nanoparticle surface coverage. Some experimental data from the literature, in apparent disagreement, are re-interpreted based on this insight.

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“…19,46 Solution pH can alter both the surface properties of the nanoparticles (e.g., their 'hydrophobicity'), 47 as well as NP-NP interactions 48 .…”

Section: Resultsmentioning

confidence: 99%

“…46 If repulsive NP-NP interactions lead to reductions in interfacial tension, attractive interactions could be responsible for increases in interfacial tension. This interpretation is in agreement with…”

Section: Resultsmentioning

confidence: 99%

Nanoparticle effects on the water-oil interfacial tension

2012

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Section: Surfactant-polymermentioning

confidence: 99%

A review on applications of nanotechnology in the enhanced oil recovery part A: effects of nanoparticles on interfacial tension

2016

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Chemical enhanced oil recovery is another strong growing technology with the potential of a step change innovation, which will help to secure future oil supply by turning resources into reserves. While Substantial amount of crude oil remains in the reservoir after primary and secondary production, conventional production methods give access to on average only one-third of original oil in place, the use of surfactants and polymers allows for recovery of up to another third of this oil. Chemical flooding is of increasing interest and importance due to high oil prices and the need to increase oil production. Research in nanotechnology in the petroleum industry is advancing rapidly and an enormous progress in the application of nanotechnology in this area is to be expected. Nanotechnology has the potential to profoundly change enhanced oil recovery and to improve mechanism of recovery. This paper, therefore, focuses on the reviews of the application of nano technology in chemical flooding process in oil recovery and reviews the application nano in the polymer and surfactant flooding on the interfacial tension process.

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“…However, studies on SP flooding only focused on the screening and evaluation of the polymer and surfactant and their interaction. Reduction in mobility ratio and IFT is influenced by reservoir brine salinity, reservoir temperature, concentration of chemical ingredients and oil components, and others (Gaonkar 1992;Ferdous et al 2012;Liu et al 2008;Gong et al 2009;Cao et al 2012;Zhang et al 2012). Displacement performance is affected by the interaction of the physical properties of the reservoir and those of the fluid.…”

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confidence: 99%

Effect of viscosity and interfacial tension of surfactant–polymer flooding on oil recovery in high-temperature and high-salinity reservoirs

Yue

Cheng³

et al. 2013

J Petrol Explor Prod Technol

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This study aims to analyze the influence of viscosity and interfacial tension (IFT) on oil displacement efficiency in heterogeneous reservoirs. Measurement of changes in polymer viscosity and IFT indicates that viscosity is influenced by brine salinity and shearing of pore media and that IFT is influenced by salinity and the interaction between the polymer and surfactant. High concentrations (2,500 and 3,000 mg/L) of polymer GLP-85 are utilized to reduce the effect of salinity and maintain high viscosity (24 mPa s) in formation water. After shearing of pore media, polymer viscosity is still high (17 mPaÁs). The same polymer viscosity (17 mPaÁs) is utilized to displace oil, whose viscosity is 68 mPaÁs, at high temperature and high pressure. The IFTs between surfactant DWS of 0.2 % in the reservoir water of different salinities and crude oil droplet are all below 10 -2 mN/m, with only a slight difference. Surfactant DWS exhibits good salt tolerance. In the surfactant-polymer (SP) system, the polymer solution prolongs the time to reach ultra-low IFT. However, the surfactant only has a slight effect on the viscosity of the SP system. SP slugs are injected after water flooding in the heterogeneous core flooding experiments. Recovery is improved by 4.93-21.02 % of the original oil in place. Furthermore, the core flooding experiments show that the pole of lowering the mobility ratio is more significant than decreasing the IFT of the displacing agent; both of them must be optimized by considering the injectivity of the polymer molecular, emulsification of oil, and the economic cost. This study provides technical support in selecting and optimizing SP systems for chemical flooding.

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Effects of temperature, pH, and ionic strength on the adsorption of nanoparticles at liquid–liquid interfaces

Cited by 42 publications

References 43 publications

Nanoparticle effects on the water-oil interfacial tension

Nanoparticle effects on the water-oil interfacial tension

A review on applications of nanotechnology in the enhanced oil recovery part A: effects of nanoparticles on interfacial tension

Effect of viscosity and interfacial tension of surfactant–polymer flooding on oil recovery in high-temperature and high-salinity reservoirs

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