Experimental investigation of enhancement of carbon dioxide foam stability, pore plugging, and oil recovery in the presence of silica nanoparticles

Risal, Abdul Rahim; Manan, Muhammad A.; Yekeen, Nurudeen; Azli, Nur Bashirah; Samin, Ali Mohamed; Tan, Xin

doi:10.1007/s12182-018-0280-8

Cited by 57 publications

(12 citation statements)

References 53 publications

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“…In pump injectors from injectants to equipment, ISCO pump was used. At 0.5 mL/min, crude oil was introduced into the core to represent a laminar flow (Shiran and Skauge 2013 ; Kumar and Mandal 2018 ; Risal et al 2019 ; Agi et al 2019b ; Bila et al 2020 ). The system was heated for 24 h to reach equilibrium.…”

Section: Methodsmentioning

confidence: 99%

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Extraction, characterization and evaluation of saponin-based natural surfactant for enhanced oil recovery

et al. 2022

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To minimize environmental impact and costs, natural surfactants are suggested as an ecologically sustainable replacement for synthetic surfactants. The aim of this work is to evaluate the efficiency of low-cost saponin-based natural surfactant (SBNS) from Vernonia amygdalina ( VA ) leaves for enhanced oil recovery (EOR). Furthermore, the study investigated the IFT behaviour of SBNS at oil-water interface and the emulsion behaviour and oil displacement efficiency of SBNS. The SBNS was obtained via ultrasonic extraction of dried VA leaves in a water bath, centrifuging the obtained liquid mixture and freeze drying to evaporate to dryness. Thereafter, Fourier-transform infrared spectroscopy (FTIR) and high-performance liquid chromatography were used to characterize the extracted SBNS. Moreover, tensiometer (Easy-Dyne KRUSS) was used to study the interfacial tension (IFT) behaviour of the SBNS at oil-water interface. Also, the SBNS ability to form stable emulsion in the presence of crude oil was determined. Finally, oil displacement by SBNS solution was investigated under simulated reservoir conditions (3000 psi and 100 °C) with high-pressure high-temperature (Fars EOR) core flooding equipment. The performance of SBNS was compared to commercial non-ionic surfactant 4-octylphenol polyethoxylated (TX-100). Experimental result indicated that the SBNS reduced the IFT at oil-water interface. The natural surfactant lowered the IFT of the oil-water interface from 18.0 to 0.97 mN/m. Moreover, emulsions formed with SBNS showed good stability characterized by a decrease in the median drop diameter with an increase in SBNS concentration. Finally, oil displacement test shows that oil recovery of TX-100 and SBNS increased by 9% and 15% original-oil-in-place (OOIP), respectively. Hence, SBNS is recommended as an appropriate substitute for conventional surfactant due to its inexpensive raw material, lower toxicity, and higher efficiency.

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Section: Methodsmentioning

confidence: 99%

“…a laminar flow (Shiran and Skauge 2013;Kumar and Mandal 2018;Risal et al 2019;Agi et al 2019b;Bila et al 2020).…”

Section: Core Flooding Testmentioning

confidence: 99%

Extraction, characterization and evaluation of saponin-based natural surfactant for enhanced oil recovery

et al. 2022

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“…Foam generation is responsible for the formation of liquid films (lamellas), that segregates gas bubbles (Risal et al 2019). In situ lamella generation is as the result of different mechanisms, such as snap-off, leave-behind and lamella division.…”

Section: Case 1: Absence Of Capillary Pressurementioning

confidence: 99%

Impact of pertinent parameters on foam behavior in the entrance region of porous media: mathematical modeling

2020

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Foam injection is a promising solution for control of mobility in oil and gas field exploration and development, including enhanced oil recovery, matrix-acidization treatments, contaminated-aquifer remediation and gas leakage prevention. This study presents a numerical investigation of foam behavior in a porous medium. Fractional flow method is applied to describe steady-state foam displacement in the entrance region. In this model, foam flow for the cases of excluding and including capillary pressure and for two types of gas, nitrogen (N 2) and carbon dioxide (CO 2) are investigated. Effects of pertinent parameters are also verified. Results indicate that the foam texture strongly governs foam flow in porous media. Required entrance region may be quite different for foam texture to accede local equilibrium, depending on the case and physical properties that are used. According to the fact that the aim of foaming of injected gas is to reduce gas mobility, results show that CO 2 is a more proper injecting gas than N 2. There are also some ideas presented here on improvement in foam displacement process. This study will provide an insight into future laboratory research and development of full-field foam flow in a porous medium.

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“…Commonly used chemical additives include organic compounds, electrolysis quality, nanoparticles, polymers, and liquid crystals (Farzaneh and Sohrabi, 2015;Lv et al, 2014;Rezvani et al, 2020;Yan et al, 2011). For example, Risal et al (2019) investigated the enhancement of carbon dioxide foam stability, pore plugging, and oil recovery in the presence of silica nanoparticles. Wang proposed enhancing the foam system by adding polymer additives into the foam (Wang and Wang, 2004).…”

Section: Introductionmentioning

confidence: 99%

Study on the regional characteristics during foam flooding by population balance model

Wei

et al. 2020

Energy Exploration & Exploitation

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Foam flooding is an effective method for enhancing oil recovery in high water-cut reservoirs and unconventional reservoirs. It is a dynamic process that includes foam generation and coalescence when foam flows through porous media. In this study, a foam flooding simulation model was established based on the population balance model. The stabilizing effect of the polymer and the coalescence characteristics when foam encounters oil were considered. The numerical simulation model was fitted and verified through a one-dimensional displacement experiment. The pressure difference across the sand pack in single foam flooding and polymer-enhanced foam flooding both agree well with the simulation results. Based on the numerical simulation, the foam distribution characteristics in different cases were studied. The results show that there are three zones during foam flooding: the foam growth zone, stable zone, and decay zone. These characteristics are mainly influenced by the adsorption of surfactant, the gas–liquid ratio, the injection rate, and the injection scheme. The oil recovery of polymer-enhanced foam flooding is estimated to be 5.85% more than that of single foam flooding. Moreover, the growth zone and decay zone in three dimensions are considerably wider than in the one-dimensional model. In addition, the slug volume influences the oil recovery the most in the foam enhanced foam flooding, followed by the oil viscosity and gas-liquid ratio. The established model can describe the dynamic change process of foam, and can thus track the foam distribution underground and aid in optimization of the injection strategies during foam flooding.

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Experimental investigation of enhancement of carbon dioxide foam stability, pore plugging, and oil recovery in the presence of silica nanoparticles

Cited by 57 publications

References 53 publications

Extraction, characterization and evaluation of saponin-based natural surfactant for enhanced oil recovery

Extraction, characterization and evaluation of saponin-based natural surfactant for enhanced oil recovery

Impact of pertinent parameters on foam behavior in the entrance region of porous media: mathematical modeling

Study on the regional characteristics during foam flooding by population balance model

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