Specificity and Synergy at the Oil–Brine Interface: New Insights from Experiments and Molecular Dynamics Simulations

Abdel‐Azeim, Safwat; Sakthivel, Sivabalan; Kandiel, Tarek A.; Kanj, Mazen Y.

doi:10.1021/acs.energyfuels.1c02133

Cited by 19 publications

(13 citation statements)

References 79 publications

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“…Oil-A is a mixture of saturates, aromatics, resin, and asphaltene based on previous reports (it is a mixture of 10 types of hydrocarbons: hexane, heptane, octane, nonane, cyclohexane, cycloheptane, toluene, benzene, asphaltene, and resin, with 128, 140, 138, 116, 86, 52, 300, 974, 2, and 6 molecules, respectively, in a 10.6 × 10.6 × 4.7 nm 3 simulation box). 17,67 In model Oil-B, we have added organic acids to model Oil-A representing the Arabian crude oil's total acid number (6.5 mg KOH/g oil), 71 taking into account the high aromaticity of the crude oil. We have added ethylbenzoic, nonanoic, and 3-cyclohexyl propanoic acids (264, 88, and 176 molecules, respectively, divided over the two oil− water interfaces).…”

Section: Resultsmentioning

confidence: 94%

“…Light oil was modeled from Kunieda et al We also considered a mixture of polar and nonpolar oil components from Sedghi et al Asphaltene and resin structure models were adopted from Jian et al and Mikami et al (Table S1 and Figure S1). The polar oil components have been considered based on the Arabian oil’s high total acid number (TAN), which is 6.5 mg KOH/g oil, besides resin and asphaltene . We considered a large interfacial area (112.4 nm 2 ), and the average system size is 185,000 atoms.…”

Section: Computational Detailsmentioning

confidence: 99%

“…The polar oil components have been considered based on the Arabian oil's high total acid number (TAN), which is 6.5 mg KOH/g oil, besides resin and asphaltene. 71 We considered a large interfacial area (112.4 nm 2 ), and the average system size is 185,000 atoms. IFT tension γ is calcceq 1…”

Section: Computational Detailsmentioning

confidence: 99%

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Phase Behavior and Interfacial Properties of Salt-Tolerant Polymers: Insights from Molecular Dynamics Simulations

Abdel‐Azeim

2021

ACS Appl. Polym. Mater.

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Mobilization of the capillary trapped oil beyond the conventional recovery methods is essential to enhance the oil extraction process and meet the global energy demands. Partially hydrolyzed polyacrylamide (HPAM) is a water-soluble polymer widely used to control the mobility ratio between the injected and displaced fluids to improve the sweep efficiency. However, its viscosifying capacity is substantially affected by the harsh reservoir conditions (high temperature and high salinity conditions). Using equilibrium molecular dynamics simulations and well-tempered metadynamics, we have investigated the effect of sidechain sulfonation on the polyacrylamide (PAM) phase behavior and interfacial properties. The sulfonated polymer exhibits weak interactions with the brine's cations; it interacts almost equally with Na + and Ca 2+ , while it displays an even weaker interaction with Mg 2+ ions. Contrarily, the pristine HPAM shows stronger and specific interactions with Ca 2+ and Mg 2+ ions. Furthermore, HPAM encapsulates the metal cations, which induce a significant conformational contraction, leading to viscosity reduction. Combining our results and the reported works of the literature, the salt tolerance and the thermal stability of this kind of polymer originate from the sulfonated sidechain−ion weak interactions and its slower hydrolysis compared to the acrylamide group. Finally, the interfacial properties of the sulfonated polymer at the oil−brine interface are examined. These findings can help to enrich our understanding of the polymer salt tolerance and thermal stability in order to design polymers with better performance.

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Section: Resultsmentioning

confidence: 94%

Section: Computational Detailsmentioning

confidence: 99%

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Phase Behavior and Interfacial Properties of Salt-Tolerant Polymers: Insights from Molecular Dynamics Simulations

Abdel‐Azeim

2021

ACS Appl. Polym. Mater.

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“…1(g)-1(k). These components have been widely used to study shale oil in MD simulations (Mikami et al, 2013;Sedghi et al, 2016;Tian et al, 2018;Xiong et al, 2019;Abdel-Azeim et al, 2021;Zhang and Guo., 2021).…”

Section: Modelmentioning

confidence: 99%

Molecular modeling on Gulong shale oil and wettability of reservoir matrix

et al. 2022

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Understanding molecular interactions between oil and reservoir matrix is crucial to develop a productive strategy for enhanced oil recovery. Molecular dynamics simulation has become an important method for analyzing microscopic mechanisms of some static properties and dynamic processes. However, molecular modeling of shale oil and reservoir matrix is still challenging, due to their complex features. Wettability, which is the measurement of oilmatrix interactions, requires in-depth understanding from the microscopic perspective. In this study, the density, interfacial tension and viscosity of eleven common components in shale oil are calculated using molecular dynamics simulations. Then a molecular model of Gulong shale oil is built, based on the reported experimental results and simulations. Compared with the variation in hydrocarbon content, the change in polar component content leads to more significant variations in the physical properties of shale oil. This molecular model is also employed to investigate the wettability of shale-oil nanodroplets on minerals and organic matter, with or without the surrounding aqueous phase. This work suggests fresh ideas for studying the oil-matrix interactions on the nanoscale and provides theoretical guidance for shale oil exploitation.

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“…Ionic Composition of Arabian Gulf FW and SSW 83. Also, the increase in pH from 7.64 to 8.50 shows that the dominant interaction is due to the H water and O calcite interactions, resulting in more OH water in the system and thus the shift in pH.…”

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confidence: 94%

Effect of Sulfate-Based Scales on Calcite Mineral Surface Chemistry: Insights from Zeta-Potential Experiments and Their Implications on Wettability

et al. 2022

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Scale formation and deposition in the subsurface and surface facilities have been recognized as a major cause of flow assurance issues in the oil and gas industry. Sulfate-based scales such as sulfates of calcium (anhydrite and gypsum) and barium (barite) are some of the commonly encountered scales during hydrocarbon production operations. Oilfield scales are a well-known flow assurance problem, which occurs mainly due to the mixing of incompatible brines. Researchers have largely focused on the rocks’ petrophysical property modifications (permeability and porosity damage) caused by scale precipitation and deposition. Little or no attention has been paid to their influence on the surface charge and wettability of calcite minerals. Thus, this study investigates the effect of anhydrite and barite scales’ presence on the calcite mineral surface charge and their propensity to alter the wetting state of calcite minerals. This was achieved vis-à-vis zeta-potential (ζ-potential) measurement. Furthermore, two modes of the scale control (slug and continuous injections) using ethylenediaminetetraacetic acid (EDTA) were examined to determine the optimal control strategy as well as the optimal inhibitor dosage. Results showed that the presence of anhydrite and barite scales in a calcite reservoir affects the colloidal stability of the system, thus posing a threat of precipitation, which would result in permeability and porosity damage. Also, the calcite mineral surface charge is affected by the presence of calcium and barium sulfate scales; however, the magnitude of change in the surface charge via ζ-potential measurement is insignificant to cause wettability alteration by the mineral scales. Slug and continuous injections of EDTA were implemented, with the optimal scale control strategy being the continuous injection of EDTA solutions. The optimal dosage of EDTA for anhydrite scale control is 5 and 1 wt % for the formation water and seawater environments, respectively. In the case of barite, in both environments, an EDTA dosage of 1 wt % suffices. Findings from this study not only further the understanding of the scale effects on calcite mineral systems but also provide critical insights into the potential of scale formation and their mechanisms of interactions for better injection planning and the development of a scale control strategy.

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Specificity and Synergy at the Oil–Brine Interface: New Insights from Experiments and Molecular Dynamics Simulations

Cited by 19 publications

References 79 publications

Phase Behavior and Interfacial Properties of Salt-Tolerant Polymers: Insights from Molecular Dynamics Simulations

Phase Behavior and Interfacial Properties of Salt-Tolerant Polymers: Insights from Molecular Dynamics Simulations

Molecular modeling on Gulong shale oil and wettability of reservoir matrix

Effect of Sulfate-Based Scales on Calcite Mineral Surface Chemistry: Insights from Zeta-Potential Experiments and Their Implications on Wettability

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