Oil mobilization and solubilization in porous media by in situ emulsification

Alzahid, Yara; Mostaghimi, Peyman; Alqahtani, Naif; Sun, Chenhao; Xiao, Lu; Armstrong, Ryan T.

doi:10.1016/j.jcis.2019.07.009

Cited by 29 publications

(10 citation statements)

References 47 publications

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“…This wettability alteration could be explained by the formation of strong chemical bonds between carbonate and carboxylate groups of NAPL molecules, leading to the formation of adsorbed NAPL layers on the mineral surfaces. 2,9 The dynamics of wettability reversal by MENP was investigated next. After injecting 0.5 and 1 PV of nanofluid, the average contact angle sharply reduced to 104 o and 88 o , respectively.…”

Section: In-situ Contact Anglementioning

confidence: 99%

“…Furthermore, these techniques can provide necessary links to fundamental pore-scale displacement processes, which cannot be observed by traditional core-scale measurements. [8][9][10] For example, a fast synchrotron x-ray CT scanner coupled with a miniature core-flooding system was used to examine the dynamics of NAPL mobilization by water flooding in a water-wet Berea sandstone. The brine phase could mobilize the trapped non-wetting phase by establishing dynamic fluid connectivity during steady-state flow, where the isolated non-wetting phase could be periodically reconnected and form temporary flow channels.…”

Section: Introductionmentioning

confidence: 99%

“…The remaining NAPL clusters after AS flooding were immobile due to capillary trapping and would only be removed after further solubilization. 9 To better understand the pore-scale dynamic mobilization and solubilization, direct pore-scale reactive transport modeling was performed with a carbonate rock and a surfactant. The simulations revealed that the dynamic wettability alteration of pore surfaces could cause a decrease in the amount of residual NAPL left in the invaded pore space and an increase in the number of pores that were invaded.…”

Section: Introductionmentioning

confidence: 99%

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Pore-scale dynamics of nanofluid-enhanced NAPL displacement in carbonate rock

Qin

Goual

Piri

et al. 2020

Journal of Contaminant Hydrology

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This study consists of a pore-scale investigation of two-phase flow dynamics during nanofluid flooding in subsurface formations containing non-aqueous phase liquids (NAPLs) such as crude oils. The goal was to gain fundamental understanding of the dominant displacement mechanisms of NAPL at different stages of nanofluid injection in a carbonate rock using x-ray microtomography integrated with a miniature coreflooding system. The nanofluid consisted of surfactant-based microemulsions with in-situ synthesized silica nanoparticles. After establishing its initial wettability state, the carbonate core sample was subjected to various pore volumes (PV) of nanofluid flooding (from 0.5 to 10) to examine the impact on NAPL flow dynamics. We found that most NAPL mobilization occurred within the first PV of injection, removing nearly 50% of NAPL from the rock. The nanofluid invaded into larger pores first with piston-like displacement due to a sharp decrease in NAPL/brine interfacial tension (from 14 to 0.5 mN/m) and contact angle (from 140 to 88). With higher amount of nanofluid delivered into the pores through advection and diffusion, over 90% of NAPL droplets were emulsified and their size decreased from 9 to 3 µm. Subsequent nanofluid injection could further remove NAPL from the smaller pores by altering the thickness of NAPL layers adsorbed on the rock. This dynamic solubilization process reached equilibrium after 5 PV of injection, leading to a reduced layer thickness (from 12 to 0.2 µm), a narrower in-situ contact angle distribution around 81, and an additional 16% of NAPL removal.

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Section: In-situ Contact Anglementioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Pore-scale dynamics of nanofluid-enhanced NAPL displacement in carbonate rock

Qin

Goual

Piri

et al. 2020

Journal of Contaminant Hydrology

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“…Osmosis and water-in-oil emulsions have been proposed as the main underlying mechanisms for the LSE. − LSW experiments in both carbonates , and sandstones showed a correlation between increased oil recovery and the ability of the crude oil to form microdispersions when exposed to low salinity water. Moreover, further tests of LSW using micromodels observed the mobilization of oil by spontaneous emulsification when in contact with diluted brine. ,, …”

Section: Introductionmentioning

confidence: 99%

Pore-Scale Imaging of Emulsification of Oil during Tertiary and Secondary Low Salinity Waterflooding in a Reservoir Carbonate

Selem,

Agenet,

Foroughi

et al. 2023

Energy Fuels

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While it is known that changing the salinity of the brine used to displace oil in porous rock can lead to additional recovery, the mechanism by which this occurs at the pore scale is still not fully understood. We investigate whether the emulsification of oil is the process by which recovery is improved, removing oil from the solid surface and rendering the rock more water-wet. High-resolution three-dimensional X-ray imaging was used to visualize the emulsification kinetics during secondary and tertiary low salinity waterflooding in a carbonate reservoir rock. The rock samples were imaged during water flooding, where the salinity of the injected brine was much lower than that of the formation water. An intermediate phase that appeared to be a mixture of oil and brine, and which we hypothesize is an emulsion, was imaged in both tertiary and secondary low salinity waterflooding experiments. The formation of this intermediate phase is observed to be the preliminary step prior to oil mobilization. Gray-level histograms and pore occupancy maps showed a faster displacement of oil in the secondary mode compared to tertiary flooding where the emulsified oil remained in the sample for longer before displacement.

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“…In addition, the surfactant generated is more effective than that yielded by direct surfactant flooding. The mechanisms involved in the chemically produced surfactant method, such as IFT reduction, wettability alteration, and emulsification, have been identified as the same as that in the ready-made surfactant flooding. − Nonetheless, in situ surfactants can be achieved more quickly via chemical reaction and accumulate more fast and precisely at the water–oil interface, whereas direct surfactant injection tends to be slow because it requires temporal surfactant transport to the interface . Sumino et al discovered that surfactant aggregates accumulated near the water–oil interface when a cationic surfactant was in contact with an anionic surfactant .…”

Section: Introductionmentioning

confidence: 99%

Effect of In-situ Dual Surfactant Formulation on Spontaneous Oil Deformation: A Comprehensive Study from Mechanism Discovery to Oil Recovery Application

She

Aoki

et al. 2022

Ind. Eng. Chem. Res.

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An in-situ dual-surfactant formulation is developed by using a novel cationic surfactant adsorbing the in-situ acid components in crude oil. As a result, various oil deformation patterns are first revealed and applied to control the viscous instabilities for oil recovery application. To this end, four dynamic oil displacement tests are conducted via camera snapshotting or X-ray microtomography in two and three dimensions, without and with porous media, in single to multipore-throat structures as well as through pore-scale and macroscale visualizations. As suggested in the results, displacing the oil phase using a 20 mmol/L cationic surfactant is the most effective method to suppress interfacial instability. The preferential flow path is frequently diverted by the repeated change of oil shape at a low flow rate. By contrast, emulsification plays a key role when the flow rate is high. It depends on which is dominant between the oil deformation and shearing velocity. From a deep insight into the pore spaces, oil deformation patterns are classified into oil spreading, shrinking, splitting, film detachment, and bridge breakup. The most significant oil deformation in the tortuous pore spaces occurs after 10 min of aging. Based on this time, we propose a new injection−alternate− stop scenario to suppress the viscous fingering and maximize the oil recovery efficiency to 80% in a large-scale reservoir.

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Oil mobilization and solubilization in porous media by in situ emulsification

Cited by 29 publications

References 47 publications

Pore-scale dynamics of nanofluid-enhanced NAPL displacement in carbonate rock

Pore-scale dynamics of nanofluid-enhanced NAPL displacement in carbonate rock

Pore-Scale Imaging of Emulsification of Oil during Tertiary and Secondary Low Salinity Waterflooding in a Reservoir Carbonate

Effect of In-situ Dual Surfactant Formulation on Spontaneous Oil Deformation: A Comprehensive Study from Mechanism Discovery to Oil Recovery Application

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