Microemulsion-enhanced displacement of oil in porous media containing carbonate cements

Qin, Tianzhu; Javanbakht, Gina; Goual, Lamia; Piri, Mohammad; Towler, Brian F.

doi:10.1016/j.colsurfa.2017.07.017

Cited by 51 publications

(33 citation statements)

References 37 publications

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“…The detailed preparation procedures are provided in previous studies. 8,9,51 In order to synthesize the SiO2 NP in-situ at the d-limonene/water interfaces in ME, we selected tetraethyl orthosilicate (>99%, Sigma Aldrich) as the oil-soluble precursor. It was first dissolved in dlimonene and then the mixture was used as the hydrocarbon phase to prepare surfactant-stabilized ME following the procedure described previously.…”

Section: Microemulsions Stabilized By Surfactants (Me) and In-situ Synthesized Nps (Menp)mentioning

confidence: 99%

“…6,7 The performance of surfactants can be further enhanced by putting them into microemulsified state. 8,9 Microemulsions (MEs) are composed of water, hydrocarbon, and amphiphiles, which are optically isotropic and thermodynamically stable liquid solutions. 10 They differ from ordinary emulsions in that they can be prepared with little or no input of mechanical energy.…”

Section: Introductionmentioning

confidence: 99%

“…17 With their unique ability to swell these layers, MEs usually provide more effective NAPL solubilization than surfactants, especially in rocks containing carbonate cements. 8,9 Recent studies showed that nanoparticles (NPs) could be used as stabilizers for MEs under harsh subsurface conditions, such as high temperature and salinity. 18 Nanoparticles are particles between 1 and 100 nanometers in size, 19 that tend to adsorb at oil/water interfaces to form pickering emulsions.…”

Section: Introductionmentioning

confidence: 99%

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Nanoparticle-stabilized microemulsions for enhanced oil recovery from heterogeneous rocks

Qin

Goual

Piri

et al. 2020

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Surfactant-stabilized microemulsions (MEs) are often used to reduce the capillary forces responsible for trapping residual non-aqueous phase liquids (NAPLs) such as crude oils inside subsurface geological formations. Recent studies showed that the presence of nanoparticles (NPs) in the ME phase could enhance NAPL recovery, however their interfacial interactions and the impact of rock characteristics (e.g., mineralogy, topology, etc.) is still unclear, especially at the microscale. The objective of this study was to understand the effect of microemulsions stabilized by nanoparticles (MENP) on pore-scale fluid displacement mechanisms in a heterogeneous aquifer rock such as Arkose sandstone. A novel method was developed to synthesize silicon oxide (SiO2) in-situ in a ME. These nanoparticles had less tendency to agglomerate compared to nanopowders and promoted the formation of pickering emulsions. The impact of ME and MENP on NAPL displacement in Arkose was examined using a micro-CT scanner integrated with a miniature core flooding system. NAPL-aged cores were subjected to flooding tests with different aqueous solutions (brine, ME, and MENP) to investigate the effectiveness of these additives in enhancing NAPL removal. We found that ME promoted NAPL mobilization by reducing IFT and enhancing emulsification.The ability of ME to solubilize adsorbed NAPL layers contributed to a wettability alteration from NAPL-wet to weakly water-wet. Therefore, ME could remove 20% of additional NAPL after waterflooding. The incremental NAPL removal with MENP (34.3%) was higher than that of ME due to the emulsification of NAPL into even smaller droplets where NPs and surfactants synergistically interacted at the interface. The small NAPL droplets could penetrate small capillary elements of the rock that were inaccessible to ME, leading to stronger wettability alteration especially in microporous carbonate cements.

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Section: Microemulsions Stabilized By Surfactants (Me) and In-situ Synthesized Nps (Menp)mentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Nanoparticle-stabilized microemulsions for enhanced oil recovery from heterogeneous rocks

Qin

Goual

Piri

et al. 2020

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“…Compared to the high-pressure of water injection, low water displacement efficiency, and low ultimate recovery efficiency of water flooding [1][2][3][4], the surfactant flooding can reduce the threshold pressure gradient and injection pressure, increase the water injection rate which expands the swept volume, reduce the interfacial tension, and improve the displacement efficiency [5][6][7][8]. According to the surfactant concentration in the injection system, the surfactant flooding is divided into active water system (C s < 1%) and microemulsion system (C s � 3%∼5%) [9][10][11][12][13]. Because of the peculiarities of ultra-low interfacial tension and better mobility control, the latter one has become the hotspot in enhanced oil recovery of low-permeability reservoir.…”

Section: Introductionmentioning

confidence: 99%

Numerical Simulation of Microemulsion Flooding in Low-Permeability Reservoir

Dongqi

Yin

Gong

2019

Journal of Chemistry

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Based on the features of microemulsion flooding in low-permeability reservoir, a three-dimension three-phase five-component mathematical model for microemulsion flooding is established in which the diffusion and adsorption characteristics of surfactant molecules are considered. The non-Darcy flow equation is used to describe the microemulsion flooding seepage law in which the changes of threshold pressure gradient can be taken into account, and the correlation coefficients in the non-Darcy flow equation are determined through the laboratory experiments. A new treatment for the changes of threshold pressure and the quantitative description of adsorption quantity of surfactant and relative permeability curves are presented, which enhance the coincidence between mathematical model and experiment results. The relative errors of main development indexes are within 4%. A software is programmed based on the model to execute a core-level small-scale numerical simulation in Chaoyanggou Oilfield. The fitting relative errors of the pressure, flow rate, and moisture content are 3.25%, 2.71%, and 2.54%, respectively. The results of laboratory experiments and numerical simulation showed that microemulsion system could reduce the threshold pressure gradient by 0.010 MPa/m and injection pressure by 0.6 MPa. The biggest decline in moisture content reaches 33%, and the oil recovery is enhanced by 10.8%.

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“…Their effectiveness in modifying wettability and altering interfacial tension (IFT) is directly proportional to the oil recovery factor during the spontaneous imbibition process (Alvarez et al, ). Moreover, the surfactant structural make‐up can affect the displacement of oil recovery (Qin et al, ). This work extends those studies to include designing immiscible solvent‐based microemulsion solutions that can impart surface modifications to enhance oil recovery.…”

Section: Introductionmentioning

confidence: 99%

Experimental Investigation into the Screening of New Surfactant Flowback Aids and Statistical Interpretation of Their Imbibing Capacity for Selected Core Substrates

Khamatnurova

Henkel

et al. 2019

J Surfact & Detergents

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Spontaneous imbibition is a pervasive part of many natural and industrial processes. As an inherent feature of fluid transport in porous media, it is a driver for oil recovery. Understanding spontaneous imbibition and leveraging surface science is fundamental for fluid recovery; specifically, the role of the surfactant in the imbibition processes and the potential to alter capillarity and wettability of reservoir rock. Surfactant success relies on the understanding of the factors governing the interfacial phenomena among crude oil, and formation properties under reservoir conditions. Developing a methodology coupling chemical performance with analytical techniques, and statistical interpretation of core/surfactant/oil interactions, can help establish workflows to advance new chemistries and enhance oil recovery. This article discusses a study of flowback aids formulated as microemulsions corresponding to the thermodynamically stable Winsor Type IV solutions. Neat formulated microemulsions, when dosed at field treatment concentrations, provide either oil‐in‐water droplet microemulsions or nanoemulsions. The solvency potential was measured, and the Kauri‐butanol (Kb) value was determined. Parameters such as critical micelle concentration (CMC) and interfacial tension (IFT) were determined to characterize microemulsion solutions. These systems were tested using either in the column flow test with formation material sieved to match mineral grain size, or sandstone cores of various permeabilities. The results indicate that surfactant‐based flow‐enhancing aids are desirable for improved oil recovery when compared to the control fluid. The statistical analysis of core‐fluid interaction includes an ANOVA followed by assumption evaluations and model interpretation, which demonstrates that the core permeability term, followed by the surfactant term, has the highest contribution whereas oil has no statistical significance to the model.

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Microemulsion-enhanced displacement of oil in porous media containing carbonate cements

Cited by 51 publications

References 37 publications

Nanoparticle-stabilized microemulsions for enhanced oil recovery from heterogeneous rocks

Nanoparticle-stabilized microemulsions for enhanced oil recovery from heterogeneous rocks

Numerical Simulation of Microemulsion Flooding in Low-Permeability Reservoir

Experimental Investigation into the Screening of New Surfactant Flowback Aids and Statistical Interpretation of Their Imbibing Capacity for Selected Core Substrates

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