The Effect of Zinc Oxide and Aluminum Oxide Nanoparticles on Interfacial Tension and Viscosity of Nanofluids for Enhanced Oil Recovery

2014 ◽  
Vol 1024 ◽  
pp. 56-59 ◽  
Author(s):  
Hasnah Mohd Zaid ◽  
Noor Rasyada Ahmad Latiff ◽  
Noorhana Yahya
Keyword(s):  
Zinc Oxide ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Substantial Reduction ◽  
Aluminium Oxide ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Aluminum Oxide Nanoparticles

Application of nanotechnology in enhanced oil recovery (EOR) has been increasing in the recent years. After secondary flooding, more than 60% of the original oil in place (OOIP) remains in the reservoir due to trapping of oil in the reservoir rock pores. One of the promising EOR methods is surfactant flooding, where substantial reduction in interfacial tension between oil and water could sufficiently displace oil from reservoir. The emulsion that is created between the two interfaces has a higher viscosity than its original components, providing more force to push the trapped oil. In this paper, the recovery mechanism of the enhanced oil recovery was determined by measuring oil-nanofluid interfacial tension and the viscosity of the nanofluid. Series of core flooding experiments were conducted using packed silica beads whichreplicate core rocks to evaluate the oil recovery efficiency of the nanofluid in comparison to that using an aqueous commercial surfactant, 0.3wt% sodium dodecyl sulfate (SDS). 117 % increase in the recovery of the residual oil in place (ROIP) was observed by the 2 pore volume (PV) injection of aluminium oxide nanofluid in comparison with 0.3wt% SDS. In comparison to the type of material, 5.12% more oil has been recovered by aluminium oxide compared to zinc oxide nanofluid in the presence of EM wave. The effect of the EM wave on the recoverywas also studied by and it was proven that electric field component of the EM waves has been stimulating the nanofluid to be more viscous by the increment of 54.2% in the oil recovery when aluminium oxide nanofluid was subjected to 50MHz EM waves irradiation.

The Effect of Nanoparticles Crystallite Size on the Recovery Efficiency in Dielectric Nanofluid Flooding

2012 ◽  
Vol 21 ◽  
pp. 103-108 ◽  
Author(s):  
Hasnah Mohd Zaid ◽  
Noorhana Yahya ◽  
Noor Rasyada Ahmad Latiff
Keyword(s):  
Interfacial Tension ◽  
Crystallite Size ◽  
Oil Recovery ◽  
Zno Nanoparticles ◽  
Sodium Dodecyl ◽  
Substantial Reduction ◽  
Reservoir Rock ◽  
Recovery Efficiency ◽  
Spontaneous Emulsification ◽  
Emulsification Process

Application of nanotechnology in enhanced oil recovery (EOR) has been increasing in recent years. After secondary flooding, more than 60% of the original oil in place (OOIP) remains in the reservoir due to trapping of oil in the reservoir rock pores. One of the promising EOR methods is surfactant flooding, where substantial reduction in interfacial tension between oil and water could sufficiently displace oil from the reservoir. In this research, instability at the interfaces is created by dispersing 0.05 wt% ZnO nanoparticles in aqueous sodium dodecyl sulfate (SDS) solution during the core flooding experiment. The difference in the amount of particles adsorbed at the interface creates variation in the localized interfacial tension, thus induces fluid motion to reduce the stress. Four samples of different average crystallite size were used to study the effect of particle size on the spontaneous emulsification process which would in turn determine the recovery efficiency. From the study, ZnO nanofluid which consists of larger particles size gives 145% increase in the oil recovery as compared with the smaller ZnO nanoparticles. In contrast, 63% more oil was recovered by injecting Al2O3 nanofluid of smaller particles size as compared to the larger one. Formation of a cloudy solution was observed during the test which indicates the occurrence of an emulsification process. It can be concluded that ultralow Interfacial tension (IFT) value is not necessary to create spontaneous emulsification in dielectric nanofluid flooding.

Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

2021 ◽  
Author(s):  
Tinuola Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Core Samples ◽  
Recovery Potential ◽  
Secondary Formation ◽  
Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

scholarly journals Insights into the Effects of Pore Size Distribution on the Flowing Behavior of Carbonate Rocks: Linking a Nano-Based Enhanced Oil Recovery Method to Rock Typing

Nanomaterials ◽  
2020 ◽  
Vol 10 (5) ◽  
pp. 972 ◽  
Author(s):  
Amin Rezaei ◽  
Hadi Abdollahi ◽  
Zeinab Derikvand ◽  
Abdolhossein Hemmati-Sarapardeh ◽  
Amir Mosavi ◽  
...  
Keyword(s):  
Size Distribution ◽  
Enhanced Oil Recovery ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Alpha Olefin Sulfonate ◽  
Core Flooding ◽  
Recovery Method ◽  
Fluid Saturation

As a fixed reservoir rock property, pore throat size distribution (PSD) is known to affect the distribution of reservoir fluid saturation strongly. This study aims to investigate the relations between the PSD and the oil–water relative permeabilities of reservoir rock with a focus on the efficiency of surfactant–nanofluid flooding as an enhanced oil recovery (EOR) technique. For this purpose, mercury injection capillary pressure (MICP) tests were conducted on two core plugs with similar rock types (in respect to their flow zone index (FZI) values), which were selected among more than 20 core plugs, to examine the effectiveness of a surfactant–nanoparticle EOR method for reducing the amount of oil left behind after secondary core flooding experiments. Thus, interfacial tension (IFT) and contact angle measurements were carried out to determine the optimum concentrations of an anionic surfactant and silica nanoparticles (NPs) for core flooding experiments. Results of relative permeability tests showed that the PSDs could significantly affect the endpoints of the relative permeability curves, and a large amount of unswept oil could be recovered by flooding a mixture of the alpha olefin sulfonate (AOS) surfactant + silica NPs as an EOR solution. Results of core flooding tests indicated that the injection of AOS + NPs solution in tertiary mode could increase the post-water flooding oil recovery by up to 2.5% and 8.6% for the carbonate core plugs with homogeneous and heterogeneous PSDs, respectively.

scholarly journals Characterization and oil recovery enhancement by a polymeric nanogel combined with surfactant for sandstone reservoirs

2020 ◽  
Author(s):  
Mustafa Almahfood ◽  
Baojun Bai
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Suspension Polymerization ◽  
Sodium Dodecyl ◽  
Polymerization Process ◽  
Core Flooding ◽  
A Value ◽  
Fixed Concentration ◽  
Oil In Water ◽  
Recovery Mechanisms

Abstract The characterization and enhanced oil recovery mechanisms of a nanosized polymeric cross-linked gel are presented herein. A negatively charged nanogel was synthesized using a typical free radical suspension polymerization process by employing 2-acrylamido 2-methyl propane sulfonic acid monomer. The synthesized nanogel showed a narrow size distribution with one peak pointing to a predominant homogeneous droplet size. The charged nanogels were also able to adsorb at the oil–water interfaces to reduce interfacial tension and stabilize oil-in-water emulsions, which ultimately improved the recovered oil from hydrocarbon reservoirs. In addition, a fixed concentration of negatively charged surfactant (sodium dodecyl sulfate or SDS) was combined with different concentrations of the nanogel. The effect of the nanogels combined with surfactant on sandstone core plugs was examined by running a series of core flooding experiments using multiple flow patterns. The results show that combining nanogel and SDS was able to reduce the interfacial tension to a value of 6 Nm/m. The core flooding experiments suggest the ability of the nanogel, both alone and combined with SDS, to improve the oil recovery by a factor of 15% after initial seawater flooding.

scholarly journals Experimental study of the performances of commercial surfactants in reducing interfacial tension and wettability alteration in the process of chemical water injection into carbonate reservoirs

2019 ◽  
Vol 10 (4) ◽  
pp. 1551-1563 ◽  
Author(s):  
Siamak Najimi ◽  
Iman Nowrouzi ◽  
Abbas Khaksar Manshad ◽  
Amir H. Mohammadi
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Saline Water ◽  
Water Injection ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Core Flooding ◽  
Chemical Water

Abstract Surfactants are used in the process of chemical water injection to reduce interfacial tension of water and oil and consequently decrease the capillary pressure in the reservoir. However, other mechanisms such as altering the wettability of the reservoir rock, creating foam and forming a stable emulsion are also other mechanisms of the surfactants flooding. In this study, the effects of three commercially available surfactants, namely AN-120, NX-1510 and TR-880, in different concentrations on interfacial tension of water and oil, the wettability of the reservoir rock and, ultimately, the increase in oil recovery based on pendant drop experiments, contact angle and carbonate core flooding have been investigated. The effects of concentration, temperature, pressure and salinity on the performances of these surfactants have also been shown. The results, in addition to confirming the capability of the surfactants to reduce interfacial tension and altering the wettability to hydrophilicity, show that the TR-880 has the better ability to reduce interfacial tension than AN-120 and NX-1510, and in the alteration of wettability the smallest contact angle was obtained by dissolving 1000 ppm of surfactant NX-1510. Also, the results of interfacial tension tests confirm the better performances of these surfactants in formation salinity and high salinity. Additionally, a total of 72% recovery was achieved with a secondary saline water flooding and flooding with a 1000 ppm of TR-880 surfactant.

Computational Modeling of the Influence of Geminal Zwitterionic Liquids on Changes in the Parameters of Wetting of Oil-Rock System

2012 ◽  
Vol 1473 ◽  
Author(s):  
Ernesto Lopez-Chavez ◽  
Luis Silvestre Zamudio-Rivera ◽  
Jose Manuel Martinez-Magadan ◽  
Eduardo Buenrostro-Gonzalez ◽  
Raúl Hernández-Altamirano
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Theoretical Study ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Rock System ◽  
Reservoir Conditions ◽  
Low Interfacial Tension ◽  
Limestone Rock

ABSTRACTZwitterionic liquid (ZL) molecules are considered among the surfactant molecular species used in enhanced oil recovery (EOR). The surface activity of asphaltenes (ASP) is crucial for establishing reservoir rock wettability, which impacts enhanced oil recovery (EOR) process. The key to a successful EOR formulation is to carefully select the components that provide ultra-low interfacial tension (IFT) under reservoir conditions. Achieving ultra-low IFT greatly reduces capillary forces that trap oil. The objective of this work is the theoretical study of the influence of a class of germinal zwitterionic liquid on interfacial tension or changes on wettability of the oil-rock system under reservoir conditions. The ZL molecule used in this study was designed by Zamudio et al; while the asphaltene model was originally proposed by Buenrostro-González. Methods of molecular mechanics and dynamics were used in order to calculate interaction energies of all systems. The results indicate that the ZL molecule adheres more strongly to the limestone-rock than the asphaltene molecule does. In addition, our results suggest that the ion-pair formation is the dominant wettability alteration mechanism.

scholarly journals Design and Tuning of Nanofluids Applied to Chemical Enhanced Oil Recovery Based on the Surfactant–Nanoparticle–Brine Interaction: From Laboratory Experiments to Oil Field Application

Nanomaterials ◽  
2020 ◽  
Vol 10 (8) ◽  
pp. 1579 ◽  
Author(s):  
Carlos A. Franco ◽  
Lady J. Giraldo ◽  
Carlos H. Candela ◽  
Karla M. Bernal ◽  
Fabio Villamil ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Field Trial ◽  
Primary Objective ◽  
Field Application ◽  
Ftir Spectra ◽  
Oil Field ◽  
Surfactant Adsorption ◽  
Core Flooding

The primary objective of this study is to develop a novel experimental nanofluid based on surfactant–nanoparticle–brine tuning, subsequently evaluate its performance in the laboratory under reservoir conditions, then upscale the design for a field trial of the nanotechnology-enhanced surfactant injection process. Two different mixtures of commercial anionic surfactants (SA and SB) were characterized by their critical micelle concentration (CMC), density, and Fourier transform infrared (FTIR) spectra. Two types of commercial nanoparticles (CNA and CNB) were utilized, and they were characterized by SBET, FTIR spectra, hydrodynamic mean sizes (dp50), isoelectric points (pHIEP), and functional groups. The evaluation of both surfactant–nanoparticle systems demonstrated that the best performance was obtained with a total dissolved solid (TDS) of 0.75% with the SA surfactant and the CNA nanoparticles. A nanofluid formulation with 100 mg·L−1 of CNA provided suitable interfacial tension (IFT) values between 0.18 and 0.15 mN·m−1 for a surfactant dosage range of 750–1000 mg·L−1. Results obtained from adsorption tests indicated that the surfactant adsorption on the rock would be reduced by at least 40% under static and dynamic conditions due to nanoparticle addition. Moreover, during core flooding tests, it was observed that the recovery factor was increased by 22% for the nanofluid usage in contrast with a 17% increase with only the use of the surfactant. These results are related to the estimated capillary number of 3 × 10−5, 3 × 10−4, and 5 × 10−4 for the brine, the surfactant, and the nanofluid, respectively, as well as to the reduction in the surfactant adsorption on the rock which enhances the efficiency of the process. The field trial application was performed with the same nanofluid formulation in the two different injection patterns of a Colombian oil field and represented the first application worldwide of nanoparticles/nanofluids in enhanced oil recovery (EOR) processes. The cumulative incremental oil production was nearly 30,035 Bbls for both injection patterns by May 19, 2020. The decline rate was estimated through an exponential model to be −0.104 month−1 before the intervention, to −0.016 month−1 after the nanofluid injection. The pilot was designed based on a production increment of 3.5%, which was successfully surpassed with this field test with an increment of 27.3%. This application is the first, worldwide, to demonstrate surfactant flooding assisted by nanotechnology in a chemical enhanced oil recovery (CEOR) process in a low interfacial tension region.

scholarly journals The Role of Microbial Products in Green Enhanced Oil Recovery: Acetone and Butanone

Polymers ◽  
2021 ◽  
Vol 13 (12) ◽  
pp. 1946
Author(s):  
Bashirul Haq
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Process ◽  
Residual Oil ◽  
Core Flooding ◽  
Recovery Potential ◽  
Wide Range ◽  
Green Surfactant ◽  
Core Flood

Green enhanced oil recovery is an oil recovery process involving the injection of specific environmentally friendly fluids (liquid chemicals and gases) that effectively displace oil due to their ability to alter the properties of enhanced oil recovery. In the microbial enhanced oil recovery (MEOR) process, microbes produce products such as surfactants, polymers, ketones, alcohols, and gases. These products reduce interfacial tension and capillary force, increase viscosity and mobility, alter wettability, and boost oil production. The influence of ketones in green surfactant-polymer (SP) formulations is not yet well understood and requires further analysis. The work aims to examine acetone and butanone’s effectiveness in green SP formulations used in a sandstone reservoir. The manuscript consists of both laboratory experiments and simulations. The two microbial ketones examined in this work are acetone and butanone. A spinning drop tensiometer was utilized to determine the interfacial tension (IFT) values for the selected formulations. Viscosity and shear rate across a wide range of temperatures were measured via a Discovery hybrid rheometer. Two core flood experiments were then conducted using sandstone cores at reservoir temperature and pressure. The two formulations selected were an acetone and SP blend and a butanone and SP mixture. These were chosen based on their IFT reduction and viscosity enhancement capabilities for core flooding, both important in assessing a sandstone core’s oil recovery potential. In the first formulation, acetone was mixed with alkyl polyglucoside (APG), a non-ionic green surfactant, and the biopolymer Xanthan gum (XG). This formulation produced 32% tertiary oil in the sandstone core. In addition, the acetone and SP formulation was effective at recovering residual oil from the core. In the second formulation, butanone was blended with APG and XG; the formulation recovered about 25% residual oil from the sandstone core. A modified Eclipse simulator was utilized to simulate the acetone and SP core-flood experiment and examine the effects of surfactant adsorption on oil recovery. The simulated oil recovery curve matched well with the laboratory values. In the sensitivity analysis, it was found that oil recovery decreased as the adsorption values increased.

Ultra-Low Interfacial Tension of a Surfactant under a Wide Range of Temperature and Salinity Conditions for Chemical Enhanced Oil Recovery

2018 ◽  
Vol 55 (3) ◽  
pp. 252-257 ◽  
Author(s):  
Derong Xu ◽  
Wanli Kang ◽  
Liming Zhang ◽  
Jiatong Jiang ◽  
Zhe Li ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Wide Range ◽  
Low Interfacial Tension
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