Wettability alteration and oil recovery by spontaneous imbibition of low salinity brine into carbonates: Impact of Mg2+, SO42− and cationic surfactant

Karimi, Mahvash; Al-Maamari, Rashid S.; Ayatollahi, Shahab; Mehranbod, Nasir

doi:10.1016/j.petrol.2016.09.015

Cited by 104 publications

(47 citation statements)

References 47 publications

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“…The results showed that increasing the sulfate concentration in seawater alters the wettability of the CBR system toward a less oil-wet state. The same behavior was observed by Karimi et al [17,18] and Rashid et al [15]. The concentrations of Ca 2+ and Mg 2+ ions also affect alterations in wettability by smart water; the presence of these cations together with sulfate ions improves recovery [19].…”

Section: Introductionsupporting

confidence: 76%

Effect of Initial Wettability on Performance of Smart Water Flooding in Carbonate Reservoirs—An Experimental Investigation with IOR Implications

Al-Nofli¹,

Pourafshary

Mosavat

et al. 2018

Energies

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In this paper, the effects of salinity and active ions on wettability alteration in carbonate reservoirs with different initial wettability conditions with implications in smart water flood design, optimization, and performance analysis are experimentally investigated. Contact angle measurement was used as the main tool to study the alteration in wettability. Other analytical techniques such as pH measurements along with energy-dispersive X-ray spectroscopy (EDS) were used to support the analysis. Initial wettability of the tested carbonate samples ranges from strongly water wet to preferentially water wet, neutral wet, oil wet, and strongly oil wet (5 cases or groups) condition. Four different synthetic brines, namely high salinity (Hsal), low salinity (Lsal), and smart waters 1 and 2 (SW1 = a Mg brine, and SW2 = a Mg and sulfate brine) were prepared and used by adjusting the salinity and ion concentration to study their effects on wettability alteration. Low-salinity brine (Lsal) proved to be more effective than high-salinity brine (Hsal) for the wettability alteration of calcite surfaces at intermediate (neutral) or oil-wet conditions. The smart brine containing only the Mg 2+ ion (SW1) was able to alter the wettability of calcite surfaces in intermediate or oil-wet states. The sulfate ion played a catalytic role in wettability alteration by the magnesium ion, and the process was faster, as indicated by higher wettability alteration index values. High-salinity brine (Hsal) is a good choice for design of water floods in reservoir rocks with initial wettability in the range of strongly water wet to neutral wet conditions. In the wettability alteration process of oil-wet samples, brine with a high magnesium ion concentration was slower than brine containing high concentrations of both magnesium and sulfate ions. This can be attributed to the catalytic role of the sulfate ion compared to that of the magnesium ion. Finally, the results showed that the initial wettability of the reservoir rock plays a major role in design of a proper water flood to maximize oil recovery from carbonate reservoirs. The results obtained from this research work suggests that some effective smart water flooding scenarios can be developed and executed incorporating different smart brines to manage the reservoir rock wettability and maximize the oil recovery from carbonate oil reservoirs.

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Section: Introductionsupporting

confidence: 76%

Effect of Initial Wettability on Performance of Smart Water Flooding in Carbonate Reservoirs—An Experimental Investigation with IOR Implications

Al-Nofli¹,

Pourafshary

Mosavat

et al. 2018

Energies

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“…Therefore, water flooding is technically and economically preferred compared to other enhanced oil recovery techniques (Austad 2013;Kazemi Nia Korrani 2014;Mohanty and Chandrasekhar 2013;Yousef et al 2010). Recently, much research has shown that controlling the composition and salinity of the injected water (known as low salinity water) disturbs the equilibrium condition and, hence, results in higher oil recovery efficiency through favorable influence on oil/brine/rock interactions compared to common seawater flooding (Al-Attar et al 2013;Al-Shalabi and Sepehrnoori 2016;Austad 2013;Austad et al 2011;Emadi and Sohrabi 2013;Gupta and Mohanty 2011;Karimi et al 2016;Li 2011;Morrow and Buckley 2011;Nasralla et al 2011;RezaeiDoust et al 2009;Seccombe et al 2008;Strand et al 2006;Morrow 1997, 1999;Yildiz and Morrow 1996;Zaeri et al 2018). Among various mechanisms suggested for low salinity water, the complex crude oil/aqueous solution interactions are not yet well understood.…”

Section: Introductionmentioning

confidence: 99%

Dissociation of polar oil components in low salinity water and its impact on crude oil–brine interfacial interactions and physical properties

Mokhtari

Ayatollahi

2018

Pet. Sci.

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Despite many efforts into the study of fluids interaction in low salinity water flooding, they are not probing the basics of transport phenomena between the involved phases. This work is aimed to bring new understanding of fluid-fluid interaction during low salinity water flooding through a series of organized experiments in which a crude oil sample with known properties was kept in contact with different brine solutions of various ionic strengths. Measuring brine pH, conductivity and crude oil viscosity and density for a period of 45 days illustrates the strong effect of the contact time and ionic strength on the dissociation of polar components and physical properties of the crude oil and brine. Besides, the interfacial tension (IFT) measurements show that the interfacial interactions are affected by several competitive interfacial processes. By decreasing the ionic strength of the brine, the solubility of naphthenic acids in the aqueous solution increases, and hence, the conductivity and the pH of the aqueous phase decrease. To verify this important finding, UV-Vis spectroscopy and 1 H NMR analysis were also performed on aged brine samples. Notably, there is an ionic strength of brine in which the lowest IFT is observed, while the other physical properties are remained relatively unchanged.

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“…Their proposed mechanism for the alteration of the wettability with the cationic surfactant, C 12 TAB, was ionic interaction between the surfactant and fatty acid adsorbed on the rock surface. Karimi et al (2016) investigated the effect of a cationic surfactant along with Mg 2+ and SO 4 2− ions on oil recovery, using spontaneous imbibition tests. Their findings indicated that a combination of a cationic surfactant along with the potential determining ions can induce a greater increase in oil recovery in spontaneous imbibition tests.…”

Section: Introductionmentioning

confidence: 99%

Wettability alteration and oil recovery by spontaneous imbibition of smart water and surfactants into carbonates

et al. 2020

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Naturally fractured carbonate reservoirs have very low oil recovery efficiency owing to their wettability and tightness of matrix. However, smart water can enhance oil recovery by changing the wettability of the carbonate rock surface from oilwet to water-wet, and the addition of surfactants can also change surface wettability. In the present study, the effects of a solution of modified seawater with some surfactants, namely C 12 TAB, SDS, and TritonX-100 (TX-100), on the wettability of carbonate rock were investigated through contact angle measurements. Oil recovery was studied using spontaneous imbibition tests at 25, 70, and 90 °C, followed by thermal gravity analysis to measure the amount of adsorbed material on the carbonate surface. The results indicated that Ca 2+ , Mg 2+ , and SO 4 2− ions may alter the carbonate rock wettability from oil-wet to water-wet, with further water wettability obtained at higher concentrations of the ions in modified seawater. Removal of NaCl from the imbibing fluid resulted in a reduced contact angle and significantly enhanced oil recovery. Low oil recoveries were obtained with modified seawater at 25 and 70 °C, but once the temperature was increased to 90 °C, the oil recovery in the spontaneous imbibition experiment increased dramatically. Application of smart water with C 12 TAB surfactant at 0.1 wt% changed the contact angle from 161° to 52° and enhanced oil recovery to 72%, while the presence of the anionic surfactant SDS at 0.1 wt% in the smart water increased oil recovery to 64.5%. The TGA analysis results indicated that the adsorbed materials on the carbonate surface were minimal for the solution containing seawater with C 12 TAB at 0.1 wt% (SW + CTAB (0.1 wt%)). Based on the experimental results, a mechanism was proposed for wettability alteration of carbonate rocks using smart water with SDS and C 12 TAB surfactants.

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Wettability alteration and oil recovery by spontaneous imbibition of low salinity brine into carbonates: Impact of Mg2+, SO42− and cationic surfactant

Cited by 104 publications

References 47 publications

Effect of Initial Wettability on Performance of Smart Water Flooding in Carbonate Reservoirs—An Experimental Investigation with IOR Implications

Effect of Initial Wettability on Performance of Smart Water Flooding in Carbonate Reservoirs—An Experimental Investigation with IOR Implications

Dissociation of polar oil components in low salinity water and its impact on crude oil–brine interfacial interactions and physical properties

Wettability alteration and oil recovery by spontaneous imbibition of smart water and surfactants into carbonates

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