Impact of Individual Ions on Oil/Brine/Rock Interface: A Macroscopic Insight on Wettability Alteration

AlGeer, M. A.; Gmira, A.; Al-Enezi, S. M.; Yousef, Ali

doi:10.2118/183202-ms

Cited by 6 publications

(3 citation statements)

References 13 publications

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“…AlGeer et al 17 showed the existence of a threshold temperature (70−75 °C) at which potential-determining ions modified the wettability of carbonate rocks toward a more water-wet state. Considering this threshold temperature and the fact that pore fluids are generally in equilibrium with rock minerals at temperatures higher than 70 °C, 18 all the ITC experiments were performed at 75 °C.…”

Section: ■ Materials and Methodsmentioning

confidence: 99%

Isothermal Titration Calorimetry Study of Brine–Oil–Rock Interactions

2018

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Isothermal titration calorimetry (ITC) is a technique that allows us to accurately determine the thermodynamic parameters that characterize a binding interaction between two molecular systems. However, this technique has not had a wide application in petroleum science. This study is an attempt to determine the adhesion of different fluids onto a rock surface through ITC experiments. Two artificial brines with different ionic composition were titrated into chalk powder, and then crude oil was added to those systems in order to mimic the processes that take place in an oil reservoir. In addition, the wettability alteration process associated with smart water flooding was investigated from a thermodynamic point of view. The results from the ITC experiments suggest that the interaction between smart water and chalk + brine + oil systems is both exothermic and endothermic. The exothermic heat response indicates chemisorption of sulfate (SO4 2–) onto the mineral lattice, whereas the endothermic response proved the substitution of carboxylate complexes from the chalk surface by magnesium (Mg2+). The ITC results also show that the performance of diluted seawater seems to be higher than smart water with increased sulfate concentration. This is due to dynamic processes like brine dilution resulting in an increased osmotic pressure.

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Section: ■ Materials and Methodsmentioning

confidence: 99%

Isothermal Titration Calorimetry Study of Brine–Oil–Rock Interactions

2018

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“…In general, formation water and seawater contain mostly the same ions which may be in different percentages. The common ions appearing in the seawater and formation water are Na + , Mg 2+ , Ca 2+ , Cl – , CO 3 – – , SO 4 – – , etc. , However, the salinity of the reservoir may vary in both areal and vertical direction, while in matured crude oil reservoir, this may be due to the reason for long-term water flooding. In chemical EOR “salinity gradient” concept is designed due to variation in salinity of the reservoir fluid to prevent the loss of surfactant …”

Section: Introductionmentioning

confidence: 99%

Synergistic Effect of Brine System Containing Mixed Monovalent (NaCl, KCl) and Divalent (MgCl₂, MgSO₄) Salts on the Interfacial Tension of Pure Hydrocarbon–Brine System Relevant for Low Salinity Water Flooding

Behera

Sangwai

2020

Energy Fuels

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Interfacial tension (IFT) plays a vital role in the petroleum industry for enhanced oil recovery. In recent years, a new technology called “low salinity water flooding” has captured the attention of researchers because of its ability to alter IFT. However, the role of salt types and their impact on the IFT of pure hydrocarbon–water systems are not well understood which could help to develop robust models and processes. In the present investigation, we have considered both aliphatic (heptane) and aromatic (toluene) hydrocarbons along with set of nine mixed brine systems containing monovalent (NaCl, KCl) and divalent (MgCl2, MgSO4) salts with a wide range of compositions and concentrations for IFT studies which are otherwise not reported in the literature. Various combinations of monovalent salts (NaCl:KCl::25:75, NaCl:KCl::50:50, NaCl:KCl::75:25) divalent salts (MgSO4:MgCl2::25:75, MgSO4:MgCl2::50:50, MgSO4:MgCl2::75:25), and monovalent and divalent salts (NaCl:MgCl2::25:75, NaCl:MgCl2::50:50, NaCl:MgCl2::75:25) along with varying concentrations (0, 500, 750, 1 000, 2 000, 5 000, 10 000, 20 000 ppm) have been used. The experimental result reveals that combination of monovalent (NaCl) and divalent (MgCl2) salt in brine has significant impact on the reduction of the IFT of the n-heptane–brine system, and combination of divalent salts (MgSO4 and MgCl2) shows better impact on IFT reduction for the toluene–brine system. The mechanism of IFT variation at different salt concentrations and compositions has also been explained based on the Gibbs adsorption isotherm and specific ion effect based on the Hofmeister series. The study will be useful to understand the synergetic effect of these salts on the hydrocarbon–brine systems and also will help to develop robust models of IFT suitable for low salinity water flooding and other industrial operations.

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“…Através de estudos já realizados, a molhabilidade da rocha é considerada um dos maiores fatores na influência da baixa taxa de recuperação de óleo (GUIMARÃES, 2019;ANDRADE, 2017;LIMA, 2016;ALGEER et al, 2016;KLINGER, 2018;LI et al, 2018;CONTRERAS, 2020;CAMARGO & PINTO, 2020). O comportamento dos fluidos no meio poroso e características petrofísicas dos reservatórios, como pressão capilar, permeabilidade relativa, saturação de óleo residual e de água irredutível são parâmetros que são diretamente afetados devido a molhabilidade (SOARES, 2016;ANDERSON, 1986).…”

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Avaliação da recuperação de óleo em carbonatos utilizando água calibrada com redução de cloreto de sódio

Cristina Clemente

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The injection of water with alteration of salinity is an advanced recovery method that has been promising over the years, as it stands out due to its economy and simple application, which significantly increase the recovery factor of reservoirs when compared with the other techniques used. For carbonate reservoirs, defined by having complex characteristics and preferential wettability to oil, this technique is even more attractive, resulting in alteration of wettability, an important factor in increasing oil recovery. The literature highlights the influence of the composition of the injection water; however, the physicochemical mechanisms involved have not been fully understood and so far generated discussions. This research aims to evaluate the recovery of oil in carbonate reservoirs by reducing the concentration of sodium chloride in the injection water. Coreflooding tests were conducted, with experimental conditions of 8230 psi and 69° C, representing the Brazilian Pre-Salt carbonate reservoir. Four rock samples were used. The tests were divided into three series; each series is composed of three tests. Three different brines concentrations are used in each tests. The injection waters analyzed were: formation water (FW), seawater (SW), desulfated seawater (SWDs), seawater depleted in NaCl (SW0NaCl), desulfated seawater depleted in NaCl (SWDs0NaCl), seawater depleted in NaCl with the addition of sulfate ion (SW0NaCl+SO 2− ) and desulfated seawater with a 50% reduction of NaCl (SWDs0.5NaCl). In addition to the brines used, a mixture of oil with a simplified gas composition was used to represent the fluid condition in the reservoir. The results obtained demonstrated that the most promising injection waters were: SWDs0NaCl (tertiary recovery), which resulted in total increases of 13.5% in production and SW0NaCl (final recovery), which resulted in total increments of 14.8% in more than four porous volume injected. The influence of the sulfate ion could also be observed. SW0NaCl+SO 2− was not effective, which may indicate that the proposal to increase the amount of sulfate in the last injection water is not valid for this type of lithology and operational conditions. Regarding the analysis of water used as the first injected water (FW, SW and SW with change in salinity), all proved to be efficient, the FW and SW resulted in tertiary recovery. However, it was possible to observe that the amount of oil produced with few porous injected volumes of FW is much greater than with SW, which indicates that oil production is faster with the injection of formation water, which fluid is not considered reactive. Concerning to SW with change in salinity, it recovered larger volumes of oil compared to other waters in this mode. In conclusion, the low salinity water injection is efficiently increases oil recovery in carbonate reservoirs.

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Impact of Individual Ions on Oil/Brine/Rock Interface: A Macroscopic Insight on Wettability Alteration

Cited by 6 publications

References 13 publications

Isothermal Titration Calorimetry Study of Brine–Oil–Rock Interactions

Isothermal Titration Calorimetry Study of Brine–Oil–Rock Interactions

Synergistic Effect of Brine System Containing Mixed Monovalent (NaCl, KCl) and Divalent (MgCl₂, MgSO₄) Salts on the Interfacial Tension of Pure Hydrocarbon–Brine System Relevant for Low Salinity Water Flooding

Avaliação da recuperação de óleo em carbonatos utilizando água calibrada com redução de cloreto de sódio

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Impact of Individual Ions on Oil/Brine/Rock Interface: A Macroscopic Insight on Wettability Alteration

Cited by 6 publications

References 13 publications

Isothermal Titration Calorimetry Study of Brine–Oil–Rock Interactions

Isothermal Titration Calorimetry Study of Brine–Oil–Rock Interactions

Synergistic Effect of Brine System Containing Mixed Monovalent (NaCl, KCl) and Divalent (MgCl2, MgSO4) Salts on the Interfacial Tension of Pure Hydrocarbon–Brine System Relevant for Low Salinity Water Flooding

Avaliação da recuperação de óleo em carbonatos utilizando água calibrada com redução de cloreto de sódio

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Synergistic Effect of Brine System Containing Mixed Monovalent (NaCl, KCl) and Divalent (MgCl₂, MgSO₄) Salts on the Interfacial Tension of Pure Hydrocarbon–Brine System Relevant for Low Salinity Water Flooding