Microscale Interactions of Surfactant and Polymer Chemicals at Crude Oil/Water Interface for Enhanced Oil Recovery

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1812-1826
Author(s):  
Subhash Ayirala ◽  
Zuoli Li ◽  
Rubia Mariath ◽  
Abdulkareem AlSofi ◽  
Zhenghe Xu ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
High Salinity ◽  
Interfacial Shear ◽  
Experimental Techniques ◽  
Water Interface ◽  
Oil Droplets ◽  
Interfacial Film ◽  
Chemical Eor ◽  
Oil Water

Summary The conventional experimental techniques used for performance evaluation of enhanced oil recovery (EOR) chemicals, such as polymers and surfactants, have been mostly limited to bulk viscosity, phase behavior/interfacial tension (IFT), and thermal stability measurements. Furthermore, fundamental studies exploring the different microscale interactions instigated by the EOR chemicals at the crude oil/water interface are scanty. The objective of this experimental study is to fill this existing knowledge gap and deliver an important understanding on underlying interfacial sciences and their potential implications for oil recovery in chemical EOR. Different microscale interactions of EOR chemicals, at crude oil/water interface, were studied by using a suite of experimental techniques, including an interfacial shear rheometer, Langmuir trough, and coalescence time measurement apparatus at both ambient (23°C) and elevated (70°C) temperatures. The reservoir crude oil and high-salinity injection water (57,000 ppm total dissolved solids) were used. Two chemicals, an amphoteric surfactant (at 1,000 ppm) and a sulfonated polyacrylamide polymer (at 500 and 700 ppm) were chosen because they are tolerant to high-salinity and high-temperature conditions. Interfacial viscous and elastic moduli (viscoelasticity), interface pressures, interface compression energies, and coalescence time between crude oil droplets are the major experimental data measured. Interfacial shear rheology results showed that surfactant favorably reduced the viscoelasticity of crude oil/water interface by decreasing the elastic and viscous modulus and increasing the phase angle to soften the interfacial film. Polymers in brine either alone or together with surfactant increased the viscous and elastic modulus and decreased the phase angle at the oil/water interface, thereby contributing to interfacial film rigidity. Interfacial pressures with polymers remained almost in the same order of magnitude as the high-salinity brine. In contrast, a significant reduction in interfacial pressures with surfactant was observed. The interface compression energies indicated the same trend and were reduced by approximately two orders of magnitude when surfactant was added to the brine. The surfactant was also able to retain similar interface behavior under compression even in the presence of polymers. The coalescence times between crude oil droplets were increased by polymers, while they were substantially decreased by the surfactant. These consistent findings from different experimental techniques demonstrated the adverse interactions of polymers at the crude oil/water interface to result in more rigid films, while confirming the high efficiency of the surfactant to soften the interfacial film, promote the oil droplets coalescence, and mobilize substantial amounts of residual oil in chemical EOR. This experimental study, for the first time, characterized the microscale interactions of surfactant-polymer chemicals at the crude oil/water interface. The applicability of several interfacial experimental techniques has been demonstrated to successfully understand underlying interfacial sciences and oil mobilization mechanisms in chemical EOR. These techniques and methods can provide potential means to efficiently screen and optimize EOR chemical formulations for better oil recovery in both sandstone and carbonate reservoirs.

Water Ion Interactions at Crude-Oil/Water Interface and Their Implications for Smart Waterflooding in Carbonates

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1817-1832 ◽  
Author(s):  
Subhash C. Ayirala ◽  
Ali A. Al-Yousef ◽  
Zuoli Li ◽  
Zhenghe Xu
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Measurement Techniques ◽  
Fluid Interfaces ◽  
Water Interface ◽  
Oil Droplets ◽  
Coalescence Time ◽  
Ion Interactions ◽  
Phase Connectivity ◽  
Oil Water

Summary Smart waterflooding (SWF) through tailoring of injection-water salinity and ionic composition is receiving favorable attention in the industry for both improved and enhanced oil recovery (EOR) in carbonate reservoirs. Surface/intermolecular forces, thin-film dynamics, and capillary/adhesion forces at rock/fluid interfaces govern crude-oil liberation from pores. On the other hand, stability and rigidity of oil/water interfaces control the destabilization of interfacial film to promote coalescence between released oil droplets and to improve the oil-phase connectivity. As a result, the dynamics of oil recovery in smart waterflood is caused by the combined effect of favorable interactions occurring at both oil/brine and oil/brine/rock interfaces across the thin film. Most of the laboratory studies reported so far have been focused on only studying the interactions at rock/fluid interfaces. However, the other important aspect of characterizing water ion interactions at the crude oil/water interface and their impact on film stability and oil-droplet coalescence remains largely unexplored. A detailed experimental investigation was conducted to understand the effects of different water ions at the crude-oil/water interface by using several instruments such as Langmuir trough, interfacial shear rheometer, Attension tensiometer, and coalescence time-measurement apparatus. The reservoir crude oil and four different water recipes with varying salinities and individual ion concentrations were used. Interfacial tension (IFT), interface pressures, compression energy, interfacial viscous and elastic moduli, oil-droplet crumpling ratio, and coalescence time between crude-oil droplets are the major experimental data measured. The IFTs are found to be the largest for deionized (DI) water, followed by the 10-times-reduced-salinity seawater and 10-times-reduced-salinity seawater enriched with sulfates. Interfacial pressures gradually increased with compressing surface area for all the brines and DI water. The compression energy (integration of interfacial pressure over the surface-area change) is the highest for DI water, followed by the lower-salinity brine containing sulfate ions, indicating rigid interfaces. The transition times of interfacial layer to become elastic-dominant from viscous-dominant structures are found to be much shorter for brines enriched with sulfates, once again confirming the rigidity of interface. The crumpling ratios (oil drop wrinkles when contracted) are also higher with the two recipes of DI water and sulfates-only brine to indicate the same trend and to confirm elastic rigid skin at the interface. The coalescence time between oil droplets was the least in brines containing sufficient amounts of magnesium and calcium ions, while the highest in DI water and sulfate-rich brine, respectively. These results, therefore, showed a good correlation of coalescence times with the rigidity of oil/water interface, as interpreted from different measurement techniques. This study, thereby, integrates consistent results obtained from different measurement techniques at the crude-oil/water interface to demonstrate the importance of both salinity and certain ions, such as magnesium and calcium, on crude-oil-droplets coalescence, and to improve oil-phase connectivity in smart waterflood.

Experimental Analysis of Alkali-Brine-Alcohol Phase Behavior with High Acid Number Crude Oil

2021 ◽  
pp. 1-19
Author(s):  
D. Magzymov ◽  
T. Clemens ◽  
B. Schumi ◽  
R. T. Johns
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Complex Mixture ◽  
Acid Number ◽  
Field Application ◽  
Water Interface ◽  
Total Acid ◽  
Oil Water

Summary A potential enhanced oil recovery technique is to inject alkali into a reservoir with a high-total acid number (TAN) crude to generate soap in situ and reduce interfacial tension (IFT) without the need to inject surfactant. The method may be cost-effective if the IFT can be lowered enough to cause significant mobilization of trapped oil while also avoiding formation of gels and viscous phases. This paper investigates the potential field application of injecting alkali to generate in-situ soap and favorable phase behavior for a high-TAN oil. Oil analyses show that the acids in the crude are a complex mixture of various polar acids and not mainly carboxylic acids. The results from phase behavior experiments do not undergo typical Winsor microemulsion behavior transition and subsequent ultralow IFTs below 1×10−3 mN/m that are conventionally observed. Instead, mixing of alkali and crude/brine generate water-in-oil macroemulsions that can be highly viscous. For a specific range of alkali concentrations, however, phases are not too viscous, and IFTs are reduced by several orders of magnitude. Incremental coreflood recoveries in this alkali range are excellent, even though not all trapped oil is mobilized. The viscous phase behavior at high alkali concentrations is explained by the formation of salt-crude complexes, created by acids from the crude oil under the alkali environment. These hydrophobic molecules tend to agglomerate at the oil-water interface. Together with polar components from the crude oil, they can organize into a highly viscous network and stabilize water droplets in the oleic phase. Oil-soluble alcohol was added to counter those two phenomena at large concentrations, but typical Winsor phase behavior was still not observed. A physicochemical model is proposed to explain the salt-crude complex formation at the oil-water interface that inhibits classical Winsor behavior.

scholarly journals Dilational Viscoelasticity of Interfacial Film Formed by Active Components of Crude Oil at Oil/Water Interface

2002 ◽  
Vol 18 (02) ◽  
pp. 161-165 ◽  
Author(s):  
Sun Tao-Lei ◽  
◽  
Peng Bo ◽  
Xu Zhi-Ming ◽  
Zhang Lu ◽  
...  
Keyword(s):  
Crude Oil ◽  
Water Interface ◽  
Active Components ◽  
Interfacial Film ◽  
Dilational Viscoelasticity ◽  
Oil Water

scholarly journals Effect of Polar Molecule Aggregation on the Stability of Crude Oil/Water Interface: A Molecular Simulation Study

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 4) ◽  
Author(s):  
Xinming Zhao ◽  
Minmin Xia ◽  
Peng Li ◽  
Jianwei Wang ◽  
Yunfei Xu ◽  
...  
Keyword(s):  
Crude Oil ◽  
Dynamics Simulation ◽  
Molar Ratio ◽  
Water Interface ◽  
Aggregation Process ◽  
Interfacial Film ◽  
Polar Components ◽  
Π Stacking ◽  
Forming Characteristics ◽  
Oil Water

Abstract To ensure the efficient operation of crude oil dehydration and sewage treatment technology in oilfield surface production system, the effect mechanism of polar components represented by asphaltene and resin on the formation and stability of oil-water emulsion needs to be revealed at nanoscale. In this paper, the molecular dynamics simulation method was used to construct the crude oil/polar component/water system models with different molar ratios of asphaltene to resin by adjusting the number of asphaltene and resin molecules, so as to reveal the molecular arrangement and aggregation process and film forming characteristics of asphaltene, resin, and their mixture at the oil-water interface. The simulated results showed that the aggregation process of asphaltene molecules under the influence of hydrogen bonds can be divided into three stages. The addition of resin molecules enhanced the connection between molecules of all polar components at the interface. The π−π stacking and T-shaped stacking structures were found in all aggregations, and the higher the molar ratio of asphaltene molecules, the higher the proportion of π−π stacking structure. With the increase of the molar ratio of asphaltene to resin increases from 0 : 1 to 1 : 0, the interfacial film thickness and interface formation energy increase from 2.366 nm and -143.89 kJ/mol to 3.796 nm and -304.09 kJ/mol, respectively, which indicated that asphaltene molecules play a more significant role in promoting the formation of interfacial film and maintaining its structural stability than resin molecules. The investigations in this study provide theoretical support for demulsification of the crude oil emulsion.

Microscale Interactions of Surfactant and Polymer Chemicals at Crude Oil-Water Interface for Enhanced Oil Recovery

2019 ◽  
Author(s):  
Subhash Ayirala ◽  
Zuoli Li ◽  
Rubia Mariath Mariath ◽  
Abdulkareem AlSofi ◽  
Zhenghe Xu ◽  
...  
Keyword(s):  
Crude Oil ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Interface ◽  
Oil Water

scholarly journals Microemulsion Rheological Analysis of Alkaline, Surfactant, and Polymer in Oil-Water Interface

Processes ◽  
2020 ◽  
Vol 8 (7) ◽  
pp. 762 ◽  
Author(s):  
Mohd Sofi Numin ◽  
Khairulazhar Jumbri ◽  
Anita Ramli ◽  
Noorazlenawati Borhan
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Shear Thinning ◽  
Angular Frequency ◽  
Water Interface ◽  
Sweep Efficiency ◽  
Rheological Analysis ◽  
Fluid Behavior ◽  
Significant Difference ◽  
Oil Water

Injection of alkaline (A), polymer (P), and surfactant (S) chemicals in enhanced oil recovery (cEOR) processes increases output by changing the properties of the injected fluid. In this work, micellar fluid interactions were studied via microemulsion rheological analysis. Crude oil and stimulated brine with ASP or SP was used for bottle testing. The results revealed that no microemulsion was produced when ASP (Alkaline, Surfactant, and Polymer) or SP (Surfactant and Polymer) was left out during the bottle testing phase. The addition of ASP and SP led to the formation of microemulsions—up to 29% for 50% water cut (WC) ASP, and 36% for 40% WC SP. This shows that the addition of ASP and SP can be applied to flooding applications. The results of the rheological analysis show that the microemulsions behaved as a shear-thinning micellar fluid by decreasing viscosity with increase in shear rate. As per the power-law equation, the ASP micellar fluid viscoelastic behavior shows better shear-thinning compared to SP, suggesting more efficiency in fluid mobility and sweep efficiency. Most of the microemulsions exhibited viscoelastic fluid behavior (G’ = G”) at angular frequency of 10 to 60 rad s−1, and stable elastic fluid behavior (G’ > G’’) below 10 rad s−1 angular frequency. The viscosity of microemulsion fluids decreases as temperature increases; this indicates that the crude oil (i.e., alkanes) was solubilized in core micelles, leading to radial growth in the cylindrical part of the wormlike micelles, and resulting in a drop in end-cap energy and micelle length. No significant difference was found in the analysis of viscoelasticity evaluation and viscosity analysis for both ASP and SP microemulsions. The microemulsion tendency test and rheology test show that the addition of ASP and SP in the oil-water interface yields excellent viscoelastic properties.

scholarly journals Manipulation of surface charges of oil droplets and carbonate rocks to improve oil recovery

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Jian Hou ◽  
Ming Han ◽  
Jinxun Wang
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Zwitterionic Surfactant ◽  
Surface Charges ◽  
Oil Droplets ◽  
Zeta Potentials ◽  
Potential Value ◽  
Oil Water ◽  
Incremental Oil Recovery

AbstractThis work investigates the effect of the surface charges of oil droplets and carbonate rocks in brine and in surfactant solutions on oil production. The influences of the cations in brine and the surfactant types on the zeta-potentials of both oil droplets and carbonate rock particles are studied. It is found that the addition of anionic and cationic surfactants in brine result in both negative or positive zeta-potentials of rock particles and oil droplets respectively, while the zwitterionic surfactant induces a positive charge on rock particles and a negative charge on oil droplets. Micromodels with a CaCO3 nanocrystal layer coated on the flow channels were used in the oil displacement tests. The results show that when the oil-water interfacial tension (IFT) was at 10−1 mN/m, the injection of an anionic surfactant (SDS-R1) solution achieved 21.0% incremental oil recovery, higher than the 12.6% increment by the injection of a zwitterionic surfactant (SB-A2) solution. When the IFT was lowered to 10−3 mM/m, the injection of anionic/non-ionic surfactant SMAN-l1 solution with higher absolute zeta potential value (ζoil + ζrock) of 34 mV has achieved higher incremental oil recovery (39.4%) than the application of an anionic/cationic surfactant SMAC-l1 solution with a lower absolute zeta-potential value of 22 mV (30.6%). This indicates that the same charge of rocks and oil droplets improves the transportation of charged oil/water emulsion in the porous media. This work reveals that the surface charge in surfactant flooding plays an important role in addition to the oil/water interfacial tension reduction and the rock wettability alteration.

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