The Effect of Interfacial Tension on Two-phase Relative Permeability: A Review

Jamaloei, Benyamin Yadali

doi:10.1080/15567036.2011.557708

Cited by 15 publications

(3 citation statements)

References 42 publications

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“…Like other gases, salinity increases the H 2 ‐brine IFT which increases the required capillary pressures for drainage and slightly reduces the relative permeability of the non‐wetting phase (i.e., H 2 ). Similar behavior has been observed for CO 2 gas in other studies (Bachu & Bennion, 2008; Jamaloei, 2015; Middleton et al., 2012). Furthermore, the increase in NaCl concentration is expected to reduce the hydrogen solubility (salting‐out effect) in a manner proportional to the salt concentration until full saturation of the solution is reached.…”

Section: Resultssupporting

confidence: 88%

Relative Permeability of Hydrogen and Aqueous Brines in Sandstones and Carbonates at Reservoir Conditions

Rezaei

Hassanpouryouzband

Molnar

et al. 2022

Geophysical Research Letters

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Section: Resultssupporting

confidence: 88%

Relative Permeability of Hydrogen and Aqueous Brines in Sandstones and Carbonates at Reservoir Conditions

Rezaei

Hassanpouryouzband

Molnar

et al. 2022

Geophysical Research Letters

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“…Fluid viscosity (µ) referred to flow mobility in the system (the mobility is the water viscosity to the oil viscosity ratio). These three factors are typically discussed in the EOR studies because they are known to associate in the EOR mechanisms (Anderson 1987;Hu et al 2017;Jamaloei 2015;Jeirani et al 2013;Jiang et al 2016;Mason et al 2010). Table 1 shows the values of the affecting factors with its %OOIP from the coreflooding tests.…”

Section: Almansour Et Al (2017)mentioning

confidence: 99%

Evaluation of effecting factors on oil recovery using the desirability function

Tangparitkul

2018

J Petrol Explor Prod Technol

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The new method to evaluate the contribution of the related factors to the oil recovery is proposed by using the desirability model. The related factors are re-scaled and combined to be a single parameter in order to correlate with an indicator of oil recovery. The correlated result could be able to predict a trend of the factors and oil recovery as an empirical approach if a good correlation is achieved. Three published works of the coreflooding experiments are examined the effectivenesses and limitations of the proposed model. The analysed plots of desirability and the oil recovery imply an insight into the oil recovery mechanisms by indicating the dominant factors. The results meet a good agreement with the published works. Although the dominant factors are indicated and the correlation trend is able to be determined, the accuracy of the proposed method needs a high number of data sets to increase the statistical reliability.

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“…Two-phase flow characteristics in complex porous media have been extensively studied using the percolation dynamic network simulation method due to its capability to deal with irregular flow paths and simulate fluid–fluid interaction behavior. ,− Jamaloei et al and Ming and Boming investigated the impacts of capillary number, wettability, fractal dimensions of pore size, and viscosity ratio on the front morphology of immiscible displacement. Their simulation results verified the appearance of viscous fingering, capillary fingering, and stable displacement of the front morphology of immiscible displacement based on variations in the capillary number.…”

Section: Introductionmentioning

confidence: 99%

Control of Generalized Capillary Number on Immiscible Displacement Path: NMR Online and Network Simulation of Fluid Displacement Mechanism

Zhao

et al. 2021

Energy Fuels

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Tight sandstone has a complex pore-throat structure and usually has multiple immiscible displacement paths. Capillary number may control and affect this process, but its control mechanism is still unclear. Therefore, this work aims to study the control process of generalized capillary number on the immiscible displacement process of tight sandstone. Through nuclear magnetic resonance (NMR) online experiments, real-time monitoring of changes in remaining oil in different-radius pores was performed under the control of different generalized capillary numbers. Combined with the microscopic experimental results of a scanning electron microscope and thin-section and constant-speed mercury intrusion, the pore-throat distribution law was obtained, and a pore network model based on a real core was established. The results show that under the control of low capillary numbers, the immiscible displacement path shifts to large and medium pores, while under the control of medium and high capillary numbers, the displacement path shifts to medium and small pores. Moreover, the simulation results also showed interesting phenomena that were not realized in the experiment. When the number of capillaries increases to a certain value (Ca ≈ 6.734 × 10–2 in this study area), unfavorable viscous displacement will occur in tight sandstones, that is, the displacement efficiency will decrease rapidly.

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The Effect of Interfacial Tension on Two-phase Relative Permeability: A Review

Cited by 15 publications

References 42 publications

Relative Permeability of Hydrogen and Aqueous Brines in Sandstones and Carbonates at Reservoir Conditions

Relative Permeability of Hydrogen and Aqueous Brines in Sandstones and Carbonates at Reservoir Conditions

Evaluation of effecting factors on oil recovery using the desirability function

Control of Generalized Capillary Number on Immiscible Displacement Path: NMR Online and Network Simulation of Fluid Displacement Mechanism

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