Role of Acid Components and Asphaltenes in Wyoming Water-in-Crude Oil Emulsions

Alvarado, Vladimir; Wang, X.; Moradi, Mehrnoosh

doi:10.1021/ef2010805

Cited by 44 publications

(25 citation statements)

References 23 publications

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“…However, increasing the amount of sulfates in SSW by four times results in a water-in-crude oil microemulsion at the fluid-fluid interface. According to previous studies [ 26 , 50 ], the controlling mechanism is associated with two coalescence-suppressing interfacial barriers between fluids. Summarising the IFT response, higher values of IFT at the interface enhance the ionic interfacial properties (indirectly, elasticity), which, in turn, is expected to produce larger oil drops.…”

Section: Resultsmentioning

confidence: 99%

Coupling Microfluidics Data with Core Flooding Experiments to Understand Sulfonated/Polymer Water Injection

et al. 2020

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The injection of sulfonated-modified water could be an attractive application as it results in the formation of a mechanically rigid oil-water interface, and hence, possible higher oil recovery in combination with polymer. Therefore, detailed experimental investigation and fluid-flow analysis into porous media are required to understand the possible recovery mechanisms taking place. This paper evaluates the potential influence of low-salt/sulfate-modified water injection in oil recovery using a cross-analyzed approach of coupled microfluidics data and core flooding experiments. Fluid characterization was achieved by detailed rheological characterization focusing on steady shear and in-situ viscosity. Moreover, single and two-phase micromodels and core floods experiments helped to define the behavior of different fluids. Overall, coupling microfluidics, with core flooding experiments, confirmed that fluid-fluid interfacial interaction and wettability alteration are both the key recovery mechanisms for modified-water/low-salt. Finally, a combination of sulfate-modified/low-salinity water, with polymer flood can lead to ~6% extra oil, compared to the combination of polymer flood with synthetic seawater (SSW). The results present an excellent way to make use of micromodels and core experiments as a supporting tool for EOR processes evaluations, assessing fluid-fluid and rock-fluid interactions.

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Section: Resultsmentioning

confidence: 99%

Coupling Microfluidics Data with Core Flooding Experiments to Understand Sulfonated/Polymer Water Injection

et al. 2020

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“…Naphthenic acids have similar ring structures as asphaltenes. They interact with asphaltenes and solubilize them in the bulk crude (Auflem et al 2002;Ostlund et al 2003). Without these compounds, the solubility of asphaltenes decreases in the crude, promoting more-stable asphaltene aggregates at the W/O interface.…”

Section: Resultsmentioning

confidence: 99%

Demulsifier in Injected Water for Improved Recovery of Crudes That Form Water/Oil Emulsions

Sun

Mogensen²,

Bennetzen

et al. 2016

SPE Reservoir Evaluation &Amp; Engineering

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Waterflooding for oil displacement becomes a challenge when water-in-oil (W/O) emulsion forms upon contact of injected water with oil in the porous media. We have recently reported very-high pressure drops and high pressure fluctuations for a number of crudes in waterflooding. In this work, we address the challenge by adding a small amount of a demulsifier in the injected water. The stability of W/O emulsion is affected by many factors, including oil chemistry, brine chemistry, and temperature. We find that the W/O emulsion formation may correlate closely to the low total acid number (TAN). In this work, we report the effectiveness of a demulsifier in significant reduction of pressure drop and elimination of pressure-drop fluctuations. The demulsifier can be dispersed in brine or water, and can be carried by injection fluid as an additive for improved oil recovery. Both micromodel observations and coreflooding results show that W/O-emulsion formation is avoided when 100 ppm demulsifier is injected in the carrier brine. Results also show that there is an increase in oil recovery.

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“…Interestingly, the fastest spreading, as seen in the film pressure measurements, occurred on the CaCl2 subphase. Calcium ions are known to interact with crude oil components, in particular carboxylic (i.e., naphthenic) acids [37,38], and the observation of higher spreading rates may signify their presence in the interfacial film. Given the experimental differences mentioned above, the induction times preceding the increase in film pressure are similar to those seen in Fig.…”

Section: Surface Tension (And Film Pressure) Measurementsmentioning

confidence: 99%

Physical and chemical aspects of “precursor films” spreading on water from natural bitumen

Gonzalez

Taylor

2018

Journal of Petroleum Science and Engineering

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Role of Acid Components and Asphaltenes in Wyoming Water-in-Crude Oil Emulsions

Cited by 44 publications

References 23 publications

Coupling Microfluidics Data with Core Flooding Experiments to Understand Sulfonated/Polymer Water Injection

Coupling Microfluidics Data with Core Flooding Experiments to Understand Sulfonated/Polymer Water Injection

Demulsifier in Injected Water for Improved Recovery of Crudes That Form Water/Oil Emulsions

Physical and chemical aspects of “precursor films” spreading on water from natural bitumen

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