Hybrid surfactant-nanoparticles assisted CO2 foam flooding for improved foam stability: A review of principles and applications

Issakhov, Miras; Shakeel, Mariam; Pourafshary, Peyman; Aidarova, Saule; Sharipova, А.

doi:10.1016/j.ptlrs.2021.10.004

Cited by 20 publications

(19 citation statements)

References 94 publications

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“…A limitation of foam generation with only nanoparticles is that more energy is required to generate the foam. A combination of surfactant and nanoparticles may achieve the favorable attributes of both (Eftekhari et al, 2015;Issakhov, et al, 2021;Nazari, et al, 2020;Singh and Mohanty, 2014;Singh and Mohanty, 2017;Worthen, et al, 2015;Xue, et al, 2016).…”

Section: Nanoparticlesmentioning

confidence: 99%

Potential and Challenges of Foam-Assisted CO2 Sequestration

Rossen

Farajzadeh

Hirasaki

et al. 2022

SPE Improved Oil Recovery Conference

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Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome. CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping, dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geological traps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden. Maximizing storage while minimizing overburden stress in the near term depends on residual trapping in the swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiency and capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foam applications. Foam increases both sweep efficiency and residual gas saturation in the region swept. Both properties reduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foam generation, better injectivity, and better prospects for long-distance foam propagation at low pressure gradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil, as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency while reducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helps equalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reduces gravity segregation of CO2. Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, either through pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-design strategy. We review foam field trials for EOR and the state of the art from laboratory and modeling research on CO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.

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Section: Nanoparticlesmentioning

confidence: 99%

Potential and Challenges of Foam-Assisted CO2 Sequestration

Rossen

Farajzadeh

Hirasaki

et al. 2022

SPE Improved Oil Recovery Conference

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“…Surfactants can effectively enhance foam viscosity, resulting in more consistent and piston-like oil front displacement. 23 …”

Section: Introductionmentioning

confidence: 99%

“…Surfactants can effectively enhance foam viscosity, resulting in more consistent and piston-like oil front displacement. 23 Anionic and nonionic surfactants are the commonly used foaming agents in foam generation. Some common anionic surfactants are sodium dodecyl benzene sulfonate (ABS), sodium lauryl sulfate (SDS), sodium dodecyl sulfate (AS), and so forth.…”

Section: Introductionmentioning

confidence: 99%

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Experimental Investigation of Foam Flooding Using Anionic and Nonionic Surfactants: A Screening Scenario to Assess the Effects of Salinity and pH on Foam Stability and Foam Height

et al. 2022

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Gravity override and viscous fingering are inevitable in gas flooding for improving hydrocarbon production from petroleum reservoirs. Foam is used to regulate gas mobility and consequently improve sweep efficiency. In the enhanced oil recovery process, when the foam is introduced into the reservoir and exposed to the initial saline water saturation and pH condition, selection of the stable foam is crucial. Salinity and pH tolerance of generated foams are a unique concern in high salinity and pH variable reservoirs. NaOH and HCl are used for adjusting the pH, and NaCl and CaCl 2 are utilized to change salinity. Through analyzing these two factors along with surfactant concentration, we have instituted a screening scenario to optimize the effects of salinity, pH, surfactant type, and concentration to generate the most stable state of the generated foams. An anionic (sodium dodecyl sulfate) and a nonionic (lauric alcohol ethoxylate-7) surfactants were utilized to investigate the effects of the surfactant type. The results were applied in a 40 cm synthetic porous media fully saturated with distilled water to illustrate their effects on water recovery at ambient conditions. This most stable foam along with eight different stabilities and foamabilities and air alone was injected into the sand pack. The results show that in optimum surfactant concentration, the stability of LA-7 was not highly changed with salinity alteration. Also, we probed that serious effects on foam stability are due to divalent salt and CaCl 2 . Finally, we found the most water recovery that was obtained by the three most stable foams by the formula of 1 cmc SDS + 0.5 M NaCl, 1 cmc SDS + 0.01 M CaCl 2 , and LA-7@ pH ∼ 6 from porous media flooding. Total water recovery for the most stable foam increased by an amount of 65% compared to the state of air alone. A good correlation between foam stability and foamability at higher foam stabilities was observed.

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“…Understanding how the wettability of the reservoir shifts from oil-wet to water-wet conditions during the oil recovery process depends on the oil disjoining pressure. Recently, researchers have investigated the application of nanoparticles in wettability modification for enhanced oil recovery [ 21 , 22 , 23 , 24 , 25 , 26 ]. The potential of nanoparticles to alter the wettability of the rock to a water-wet state and increase the recovery factor greatly improves when they work in conjunction with other additives such as polymers and surfactants.…”

Section: Introductionmentioning

confidence: 99%

Laboratory Investigation of Nanofluid-Assisted Polymer Flooding in Carbonate Reservoirs

et al. 2022

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In the petroleum industry, the remaining oil is often extracted using conventional chemical enhanced oil recovery (EOR) techniques, such as polymer flooding. Nanoparticles have also greatly aided EOR, with benefits like wettability alteration and improvements in fluid properties that lead to better oil mobility. However, silica nanoparticles combined with polymers like hydrolyzed polyacrylamide (HPAM) improve polymer flooding performance with better mobility control. The oil displacement and the interaction between the rock and polymer solution are both influenced by this hybrid approach. In this study, we investigated the effectiveness of the injection of nanofluid-polymer as an EOR approach. It has been observed that nanoparticles can change rock wettability, increase polymer viscosity, and decrease polymer retention in carbonate rock. The optimum concentrations for hydrolyzed polyacrylamide (2000 ppm) and 0.1 wt% (1000 ppm) silica nanoparticles were determined through rheology experiments and contact angle measurements. The results of the contact angle measurements revealed that 0.1 wt% silica nanofluid alters the contact angle by 45.6°. The nano-silica/polymer solution resulted in a higher viscosity than the pure polymer solution as measured by rheology experiments. A series of flooding experiments were conducted on oil-wet carbonate core samples in tertiary recovery mode. The maximum incremental oil recovery of 26.88% was obtained by injecting silica nanofluid followed by a nanofluid-assisted polymer solution as an EOR technique. The application of this research will provide new opportunities for hybrid EOR techniques in maximizing oil production from depleted high-temperature and high-salinity carbonate reservoirs.

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Hybrid surfactant-nanoparticles assisted CO2 foam flooding for improved foam stability: A review of principles and applications

Cited by 20 publications

References 94 publications

Potential and Challenges of Foam-Assisted CO2 Sequestration

Potential and Challenges of Foam-Assisted CO2 Sequestration

Experimental Investigation of Foam Flooding Using Anionic and Nonionic Surfactants: A Screening Scenario to Assess the Effects of Salinity and pH on Foam Stability and Foam Height

Laboratory Investigation of Nanofluid-Assisted Polymer Flooding in Carbonate Reservoirs

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