Insights into Nanoscale Wettability Effects of Low Salinity and Nanofluid Enhanced Oil Recovery Techniques

In this study, enhanced oil recovery (EOR) techniques—namely low salinity and nanofluid EOR—are probed at the nanometer-scale using an atomic force microscope (AFM). Mica substrates were used as model clay-rich rocks while AFM tips were coated to present alkyl (-CH3), aromatic (-C6H5) and carboxylic acid (-COOH) functional groups, to simulate oil media. We prepared brine formulations to test brine dilution and cation bridging effects while selected concentrations (0 to 1 wt%) of hydrophilic SiO2 nanoparticles dispersed in 1 wt% NaCl were used as nanofluids. Samples were immersed in fluid cells and chemical force mapping was used to measure the adhesion force between polar/non-polar moieties to substrates. Adhesion work was evaluated based on force-displacement curves and compared with theories. Results from AFM studies indicate that low salinity waters and nanoparticle dispersions promote nanoscale wettability alteration by significantly reducing three-phase adhesion force and the reversible thermodynamic work of adhesion, also known as adhesion energy. The maximum reduction in adhesion energy obtained in experiments was in excellent agreement with existing theories. Electrostatic repulsion and reduced non-electrostatic adhesion are prominent surface forces common to both low salinity and nanofluid EOR. Structural forces are complex in nature and may not always decrease total adhesion force and energy at high nanoparticle concentration. Wettability effects also depend on surface chemical groups and the presence of divalent Mg2+ and Ca2+ cations. This study provides fresh insights and fundamental information about low salinity and nanofluid EOR while demonstrating the application of force-distance spectroscopy in investigating EOR techniques.

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A mechanistic investigation of low salinity water flooding coupled with ion tuning for enhanced oil recovery

RSC Advances ◽

10.1039/d0ra08301a ◽

2020 ◽

Vol 10 (69) ◽

pp. 42570-42583

Author(s):

Rohit Kumar Saw ◽

Ajay Mandal

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Water Flooding ◽

Wettability Alteration ◽

Rock Surface ◽

Calcite Dissolution ◽

Low Salinity ◽

Low Salinity Water ◽

Mechanistic Investigation ◽

Salinity Water

The combined effects of dilution and ion tuning of seawater for enhanced oil recovery from carbonate reservoirs. Dominating mechanisms are calcite dissolution and the interplay of potential determining ions that lead to wettability alteration of rock surface.

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Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding

SPE Journal ◽

10.2118/169127-pa ◽

2018 ◽

Vol 23 (03) ◽

pp. 803-818 ◽

Cited By ~ 24

Author(s):

Mehrnoosh Moradi Bidhendi ◽

Griselda Garcia-Olvera ◽

Brendon Morin ◽

John S. Oakey ◽

Vladimir Alvarado

Keyword(s):

Crude Oil ◽

Water Chemistry ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Interaction Mechanism ◽

Field Trials ◽

Wettability Alteration ◽

Low Salinity ◽

Injection Water

Summary Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25°C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.

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Effect of Total Acid Number and Recovery Mode on Low-Salinity Enhanced Oil Recovery in Carbonates

SPE Reservoir Evaluation & Engineering ◽

10.2118/203281-pa ◽

2021 ◽

pp. 1-18

Author(s):

Takaaki Uetani ◽

Hiromi Kaido ◽

Hideharu Yonebayashi

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Carbonate Rock ◽

Acid Number ◽

Spontaneous Imbibition ◽

Wettability Alteration ◽

Oil Composition ◽

Total Acid ◽

Low Salinity ◽

Total Acid Number

Summary Low-salinity water (LSW) flooding is an attractive enhanced oil recovery (EOR) option, but its mechanism leading to EOR is poorly understood, especially in carbonate rock. In this paper, we investigate the main reason behind two tertiary LSW coreflood tests that failed to demonstrate promising EOR response in reservoir carbonate rock; additional oil recovery factors by the LSW injection were only +2% and +4% oil initially in place. We suspected either the oil composition (lack of acid content) or the recovery mode (tertiary mode) was inappropriate. Therefore, we repeated the experiments using an acid-enriched oil sample and injected LSW in the secondary mode. The result showed that the low-salinity effect was substantially enhanced; the additional oil recovery factor by the tertiary LSW injection jumped to +23%. Moreover, it was also found that the secondary LSW injection was more efficient than the tertiary LSW injection, especially in the acid-enriched oil reservoir. In summary, it was concluded that the total acid number (TAN) and the recovery mode appear to be the key successful factors for LSW in our carbonate system. To support the conclusion, we also performed contact angle measurement and spontaneous imbibition tests to investigate the influence of acid enrichment on wettability, and moreover, LSW injection on wettability alteration.

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Wettability Alteration and Enhanced Oil Recovery Using Low Salinity Waterflooding in Limestone Rocks: A Mechanistic Study

10.2118/192425-ms ◽

2018 ◽

Cited By ~ 1

Author(s):

Joel Tetteh ◽

Nazirah Mohd Janjang ◽

Reza Barati

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Wettability Alteration ◽

Mechanistic Study ◽

Low Salinity ◽

Low Salinity Waterflooding

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Osmosis as Mechanism for Low-Salinity Enhanced Oil Recovery

SPE Journal ◽

10.2118/179741-pa ◽

2016 ◽

Vol 21 (04) ◽

pp. 1227-1235 ◽

Cited By ~ 34

Author(s):

K.. Sandengen ◽

A.. Kristoffersen ◽

K.. Melhuus ◽

L. O. Jøsang

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Salinity Gradient ◽

Spontaneous Imbibition ◽

Model Systems ◽

Wettability Alteration ◽

Connate Water ◽

Low Salinity ◽

Low Salinity Water ◽

Salinity Water

Summary We believe that osmosis has been overlooked as a possible mechanism for observed low-salinity enhanced-oil-recovery (EOR) effects. Osmosis can occur in an oil/water/rock system when injecting low-salinity water, because the system is full of an excellent semipermeable membrane—the oil itself. In the present work, water transport through oil films was visualized both in 2D micromodels and in sandstone cores imaged in a microcomputed tomography (CT). After treating these model systems with hexamethyldisilazane (HMDS) to render them more oil-wet, water became discontinuous, and it was possible to establish osmotic gradients. Either expansion or contraction of the connate water was observed, depending on the direction of the imposed salinity gradient. Because osmosis could be the underlying mechanism for low-salinity EOR, two changes in research strategy are proposed: Most importantly, the use of spontaneous-imbibition tests as evidence for wettability alteration in low-salinity water should be critically reinvestigated. This is because observed production could have stemmed from “osmotic expansion” of the connate water rather than wettability change. Second, much research focus should be shifted from sandstone reservoirs to fractured oil-wet carbonates. Osmosis potentially yields larger responses for the latter reservoir type, whereas from a mechanistic perspective the reason behind low-salinity EOR functioning in both sandstones and carbonates deserves further attention.

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