Silica Nanoparticle Enhancement in the Efficiency of Surfactant Flooding of Heavy Oil in a Glass Micromodel

Effect of Titanium Dioxide Nanoparticles on Surfactants and Their Impact on the Interfacial Properties of the Oil-Water-Rock System

The application of nanoparticles (NPs) in the oil and gas industry has received wide attention in recent years because it is increasingly being considered a promising approach to recovering trapped oil in conventional hydrocarbon reservoirs. Numerous studies have demonstrated that combining nanoparticles with a surfactant can enhance surfactant performance by changing the interfacial properties of the solution when it comes in contact with crude oil and rock surfaces. However, more information and additional experimental data are required concerning the application of titanium dioxide nanoparticles in alkyl ethoxy carboxylic surfactants. In this study, we measure the changes in interfacial tension and wettability due to the addition of titanium dioxide nanoparticles (0, 100, 250, and 500 ppm) in alkyl ethoxy carboxylic surfactant using a spinning drop tensiometer and contact angle measurements. The interfacial tension of the crude oil-water (surfactant) system decreases by approximately two orders of magnitude with an increasing titanium dioxide concentration, exhibiting a minimum value of 5.85 × 10-5 mN/m. Similarly, the contact angle decreases on the surface of the Berea sandstone by combining the surfactant with titanium dioxide, reaching a minimum contact angle of 8.8°. These results demonstrate the potential of this new approach to maximize the recovery of trapped oil and significantly improve oil production.

Study on the relationships between the oil HLB value and emulsion stabilization

In order to study the relationship between the HLB value of oil and emulsion stabilization, the optimal formation of emulsification system was determined, and then, the properties of emulsion, such as particle size, stability, interfacial tension and zeta potential, were tested by laser particle analyzer, stability analyzer, and interfacial tensiometer. Experimental results showed that the optimal ratio of emulsification was Tween 80 : Span 80 = 5 : 5. Meanwhile, when the HLB value of the emulsification system was close to that of oil, the emulsion exhibited the best stability. This phenomenon is due to the fact that when the HLB values are close, the surfactant molecules are arranged more closely on the oil-water interface, leading to smaller sized emulsion droplet, which is conducive to emulsion stability. This study provides new insights into the effective adjustment of emulsion stability.

Enhancing ASP Flooding by Using Special Combinations of Surfactants and Starch Nanoparticles

This study aimed to address the challenges faced by mature oilfields in extracting substantial oil quantities. It focused on improving the efficiency of alkaline-surfactant-polymer (ASP) flooding technique, which is a proven tertiary recovery technology, to overcome scaling issues and other hindrances in its large-scale implementation. Appropriate materials and their suitable concentrations were selected to enhance the ASP flooding technique. Special surfactants from Indonesia were introduced to improve the interfacial tension reduction and wettability alteration. Reservoir rock model that resembling Langgak oilfield in Sumatra was utilized, and low-salinity water was employed to mimic the oilfield conditions. Starches derived from cassava nanoparticles (CSNPs) and purple yam nanoparticles (PYNPs) were combined separately with conventional hydrolyzed polyacrylamide (HPAM) polymer to enhance its performance. Sodium hydroxide and sodium carbonate were used as alkaline in final ASP formula. It was demonstrated from this research that only two combinations of ASP formulations have led to improved oil recovery. One combination utilizing PYNPs resulted in 39.17% progressive recovery, while the other combination incorporating CSNPs achieved 35% incremental oil recovery. The ASP combination that resulted in recovery rate of 39.17% was composed of sodium hydroxide (NaOH) at a concentration of 1.28 wt.%, PSC EOR 2.2 (0.98 wt.%), and a combined polymer consisting of HPAM (0.2 wt.%) and PYNPs nano-starch (0.6 wt.%). The second combination led to 35% recovery rate and involved NaOH also at concentration 1.28 wt.%, PSC HOMF (0.63 wt.%), and a combined polymer comprising from HPAM (0.2 wt.%) and CSNPs nano-starch (0.8 wt.%). These findings of this study highlighted the potential of this modified ASP flooding to enhance oil recovery in mature oilfields, thereby offering valuable insights for oil industry.

Multiphase displacement manipulated by micro/nanoparticle suspensions in porous media via microfluidic experiments: From interface science to multiphase flow patterns

Multiphase displacement in porous media can be adjusted by micro/nanoparticle suspensions, which is widespread in many scientific and industrial contexts. Direct visualization of suspension flow dynamics and corresponding multiphase patterns is crucial to understanding displacement mechanisms and eventually optimizing these processes in geological, biological, chemical, and other engineering systems. However, suspension flow inside the opaque realistic porous media makes direct observation challenging. The advances in microfluidic experiments have provided us with alternative methods to observe suspension influence on the interface and multiphase flow behaviors at high temporal and spatial resolutions. Macroscale processes are controlled by microscale interfacial behaviors, which are affected by multiple physical factors, such as particle adsorption, capillarity, and hydrodynamics. These properties exerted on the suspension flow in porous media may lead to interesting interfacial phenomena and new displacement consequences. As an underpinning science, understanding and controlling the suspension transport process from interface to flow patterns in porous media is critical for a lower operating cost to improve resource production while reducing harmful emissions and other environmental impacts. This review summarizes the basic properties of different micro/nanoparticle suspensions and the state-of-the-art microfluidic techniques for displacement research activities in porous media. Various suspension transport behaviors and displacement mechanisms explored by microfluidic experiments are comprehensively reviewed. This review is expected to boost both experimental and theoretical understanding of suspension transport and interfacial interaction processes in porous media. It also brings forward the challenges and opportunities for future research in controlling complex fluid flow in porous media for diverse applications.

A Critical Overview of ASP and Future Perspectives of NASP in EOR of Hydrocarbon Reservoirs: Potential Application, Prospects, Challenges and Governing Mechanisms

Oil production from depleted reservoirs in EOR (Enhanced Oil Recovery) techniques has significantly increased due to its huge demands in industrial energy sectors. Chemical EOR is one of the best approaches to extract the trapped oil. However, there are gaps to be addressed and studied well for quality and cost consideration in EOR techniques. Therefore, this paper addresses for the first time a systematic overview from alkaline surfactant polymer ((ASP)) and future perspectives of nano-alkaline surfactant polymer ((NASP)), its synergy effects on oil recovery improvement, and the main screening criteria for these chemicals. The previous findings have demonstrated that the optimum salinity, choosing the best concentration, using effective nano-surfactant, polymer and alkaline type, is guaranteed an ultra-low IFT (Interfacial Tension). Core flood results proved that the maximum oil is recovered by conjugating nanoparticles with conventional chemical EOR methods (surfactant, alkaline and polymer). This work adds a new insight and suggests new recommendation into the EOR application since, for the first time, it explores the role and effect of nanotechnology in a hybrid with ASP. The study illustrates detailed experimental design of using NASP and presents an optimum micro-model setup for future design of NASP flow distribution in the porous media. The presence of nano along with other chemicals increases the capillary number as well as the stability of chemicals in the solution and strengthens the effective mechanisms on the EOR.

Synergistic Efficiency of Zinc Oxide/Montmorillonite Nanocomposites and a New Derived Saponin in Liquid/Liquid/Solid Interface-Included Systems: Application in Nanotechnology-Assisted Enhanced Oil Recovery

Oil production faces challenges such as limited oil production from carbonate reservoirs, high oil production costs, and environmental issues. Chemical flooding as an enhanced oil recovery (EOR) method (CEOR) can increase oil production by the use of chemical additives such as surfactants into the reservoirs. Surfactants can increase oil recovery by interfacial tension (IFT) reduction and alteration of the rock wettability from oil-wet to water-wet. The synthesis of chemicals such as synthetic surfactants is usually costly and harmful to the environment. To solve these problems, many researchers have oriented on the use of natural surfactants instead of synthetic ones within the CEOR process. A new approach to increase the efficiency of CEOR is the synergizing of the chemical additives with nanoparticles as a hybrid fluid, which is known as the nanotechnology-assisted EOR method. In this research, a natural surfactant derived from Cyclamen persicum (CP) plant was extracted, and its performance was optimized with the zinc oxide/montmorillonite (ZnO/MMT) nanocomposite in a synergistic usage. At the optimum concentration of the surfactant, the measurements of the IFT and the contact angle show 57.78 and 61.58% optimizations, respectively. Also, in the presence of NaCl, the performance of CP is improved. IFT and contact angle measurements were also conducted for ZnO/MMT nanofluids and CP-ZnO/MMT as hybrid nanofluids. Results indicate that ZnO/MMT nanocomposites can alter the wettability of the carbonate rock to the water-wet state. Also, the CP-ZnO/MMT hybrid nanofluid shows a good potential in both IFT reduction and altering wettability from oil-wet to water-wet. Finally, to investigate the effects of solutions on increasing oil recovery factor (RF), the optimum concentrations of the surfactant, nanocomposite, and hybrid solutions were selected for dynamic core flooding experiments, and improvements showed oil RF increases of 8.2, 6, and 13%, respectively.

Interaction of Surface-Modified Alumina Nanoparticles and Surfactants at an Oil/Water Interface: A Neutron Reflectometry, Scattering, and Enhanced Oil Recovery Study

The evaluation of the mechanism of nanoparticle (NP)/surfactant complex adsorption at the critical oil/water interface was studied. A sophisticated technique (neutron reflectometry) was used to give a unique insight on NP/oil interactions in oil recovery systems. Herein, the adsorption of two modified alumina NPs with different degrees of hydrophobicity [hydrophilic = 2-[2-(2-methoxyethoxy)ethoxy]acetic acid and hydrophobic = octanoic acid (OCT)] stabilized with two different surfactants were studied at the oil/water interface. A thin layer of deuterated (D) and hydrogenated (H) hexadecane (contrast matching silicon substrate) oil was formed on a silicon block by a spin coating freeze process. The distribution of the NPs across the oil/water interface with the CTAB surfactant is similar between the two systems. NPs coated with CTAB have more affinity toward the oil/water interface, which explains the oil recovery increase by around 5% when flooding the core with the OCT-NP/CTAB system compared to the surfactant flooding alone. These results suggest that the NP/surfactant complexes can have potential usage in EOR recovery applications.

Direct Pore-Level Visualization and Verification of In Situ Oil-in-Water Pickering Emulsification during Polymeric Nanogel Flooding for EOR in a Transparent Three-Dimensional Micromodel

Different from inorganic nanoparticles, nanosized cross-linked polymeric nanoparticles (nanogels) have been demonstrated to generate more stable Pickering emulsions under harsh conditions for a long term owing to their inherent high hydrophilicity and surface energy. In both core and pore scales, the emulsions are found to be able to form in situ during the nanofluid flooding process for an enhanced oil recovery (EOR) process. Due to the limitation of direct visualization in core scale or deficient pore geometries built by two-dimensional micromodels, the in situ emulsification by nanofluids and emulsion transport are still not being well understood. In this work, we use a three-dimensional transparent porous medium to directly visualize the in situ emulsification during the nanogel flooding process for EOR after water flooding. By synthesizing the nanogel with a fluorescent dye, we find the nanogels adsorbed on the oil-water interface to lower the total interfacial energy and emulsify the large oil droplets into small Pickering oil-in-water emulsions. A potential mechanism for in situ emulsification by nanogels is proposed and discussed. After nanogel flooding, the emulsions trapped in pore throats and those in the effluents are all found encapsulated by the nanogels. After nanogel flooding under different flow rates, the sphericity and diameter changes of remaining oil droplets are quantitatively compared and analyzed using grouped boxplots. It is concluded that in situ emulsification happens during nanogel injection due to the reduction of interfacial tension, which helps to increase the oil recovery rate under different flow rates and pore geometries.

Rheological, physicochemical, and microstructural properties of asphalt binder modified by fumed silica nanoparticles

Warm mix asphalt (WMA) is gaining increased attention in the asphalt paving industry as an eco-friendly and sustainable technology. WMA technologies are favorable in producing asphalt mixtures at temperatures 20-60 °C lower in comparison to conventional hot mix asphalt. This saves non-renewable fossil fuels, reduces energy consumption, and minimizes vapors and greenhouse gas emissions in the production, placement and conservation processes of asphalt mixtures. At the same time, this temperature reduction must not reduce the performance of asphalt pavements in-field. Low aging resistance, high moisture susceptibility, and low durability are generally seen as substantial drawbacks of WMA, which can lead to inferior pavement performance, and increased maintenance costs. This is partly due to the fact that low production temperature may increase the amount of water molecules trapped in the asphalt mixture. As a potential remedy, here we use fumed silica nanoparticles (FSN) have shown excellent potential in enhancing moisture and aging susceptibility of asphalt binders. In this study, asphalt binder modification by means of FSN was investigated, considering the effects of short-term and long-term aging on the rheological, thermal, and microstructural binder properties. This research paves the way for optimizing WMA by nanoparticles to present enhanced green asphalt technology.

Nanotechnology in Enhanced Oil Recovery

Nanoparticles (NPs) are known as important nanomaterials for a broad range of commercial and research applications owing to their physical characteristics and properties. Currently, the demand for NPs for use in enhanced oil recovery (EOR) is very high. The use of NPs can drastically benefit EOR by changing the wettability of the rock, improving the mobility of the oil drop and decreasing the interfacial tension (IFT) between oil/water. This paper focuses on a review of the application of NPs in the flooding process, the effect of NPs on wettability and the IFT. The study also presents a review of several investigations about the most common NPs, their physical and mechanical properties and benefits in EOR.

New insights into the interactions between asphaltene and a low surface energy anionic surfactant under low and high brine salinity

HYPOTHESIS

The hyperbranched chains on the tail of low surface energy surfactants (LSES) causes lowering of surface free energy and rock wettability alteration, offering significant improvement in oil recovery in asphaltene oil reservoirs.

EXPERIMENTS

Oil sweep efficiency was determined by fluid displacement in pure brine and LSES-brine solutions in a microfluidic pattern that was representative of a sandstone cross-section. Interfacial tension (IFT), wettability alteration, Raman and X-ray photoelectron spectroscopy (XPS) were used to measure the changes of asphaltene interactions with oil-aged substrate after surface treating with brine and surfactant-brine solutions.

FINDINGS

The hyperbranched LSES yielded a significant increase in the original-oil-in-place (OOIP) recovery (58%) relative to brine flooding (25%), even in the presence of asphaltene. Raman spectra showed the LSES-brine solutions to be capable of causing change to the asphaltene aggregate size after centrifugation treatment.

Challenges and future of chemical assisted heavy oil recovery processes

The primary method for heavy oil and bitumen production across the world is still in-situ steam-based technology. There are some drawbacks associated with steam-driven heavy oil recovery methods such as cyclic steam stimulation (CSS), steam flooding, and steam-assisted gravity drainage (SAGD). These cons include the high greenhouse gas footprint, low heavy oil/bitumen recovery, and difficulty in stop operation in emergency conditions. There exists a need for an improved method for recovering residual oils after applying steam injection. One of the potential technologies for doing this is chemical assisted heavy oil recovery, especially alkaline and surfactant additives. But the challenging question is how to develop a chemical-based oil recovery method considering long-term steam-rock interactions. Several associated issues of chemical additives, including adsorption behavior of surfactant at reservoir conditions and thermal stability of surfactant at steam chamber temperature, make this question more complex. This paper addresses all these concerns and provides solid knowledge regarding this technology. We delve into newly formulated chemicals for coupling with thermal oil recovery techniques that are still limited to lab-scale research, with the need for further studies. This critical review also provides the opportunities and challenges associated with chemical assisted heavy oil/bitumen production in a post-steam injection scenario. Finally, different aspects of such a method are covered in this review, along with practical information on field trials and best practices across the world.

Surfactant-Augmented Functional Silica Nanoparticle Based Nanofluid for Enhanced Oil Recovery at High Temperature and Salinity

Nanofluids in recent years have shown great potential as a chemical enhanced oil recovery (EOR) technology, thanks to their excellent performance in altering interfacial properties. However, because of the great challenge in preparing stable systems suitable for an elevated temperature and a high salinity environment, expanding the application of nanofluids has been greatly restrained. In this work, a novel nanofluid was prepared by integrating positively charged amino-terminated silica nanoparticles (SiNP-NH₂) with negatively charged anionic surfactant (Soloterra 964) via electrostatic force. The resulted nanofluid could be stored at relatively high salinity (15 wt % NaCl solution) and high temperature (65 °C) for more than 30 days without aggregation. Successful coating of the surfactant on target SiNPs was verified by Fourier transform infrared spectrometry and the surface charge and size distribution. In addition, the potential of the nanofluid in recovering oil was investigated by analyzing the nanofluid/Bakken oil interfacial tension and the variation trend of the oil contact angle when brine was replaced by nanofluids. Experimental results showed that the water-oil interfacial tension of the Bakken crude oil decreased by 99.85% and the contact angle increased by 237.8% compared to the original value of 13.78 mN/m and 43.4°, respectively, indicating strong oil displacement efficiency and obvious wetting transition from oil-wet toward water-wet. Spontaneous imbibition tests conducted on Berea rocks showed that the nanofluid yielded a high oil recovery rate of 46.61%, compared to that of 11.30, 16.58, and 22.89% for brine, pure SiNP-NH₂, and pure surfactant (Soloterra 964), respectively. In addition, when core flooding was applied, a total of 60.88% of the original oil in place could be recovered and an additional oil recovery of 17.23% was achieved in the chemical flooding stage. Moreover, a possible mechanism of the EOR using the nanofluid was proposed. Overall, the developed nanofluid is a promising new material for EOR.

Numerical Simulation of Microemulsion Flooding in Low-Permeability Reservoir

Based on the features of microemulsion flooding in low-permeability reservoir, a three-dimension three-phase five-component mathematical model for microemulsion flooding is established in which the diffusion and adsorption characteristics of surfactant molecules are considered. The non-Darcy flow equation is used to describe the microemulsion flooding seepage law in which the changes of threshold pressure gradient can be taken into account, and the correlation coefficients in the non-Darcy flow equation are determined through the laboratory experiments. A new treatment for the changes of threshold pressure and the quantitative description of adsorption quantity of surfactant and relative permeability curves are presented, which enhance the coincidence between mathematical model and experiment results. The relative errors of main development indexes are within 4%. A software is programmed based on the model to execute a core-level small-scale numerical simulation in Chaoyanggou Oilfield. The fitting relative errors of the pressure, flow rate, and moisture content are 3.25%, 2.71%, and 2.54%, respectively. The results of laboratory experiments and numerical simulation showed that microemulsion system could reduce the threshold pressure gradient by 0.010 MPa/m and injection pressure by 0.6 MPa. The biggest decline in moisture content reaches 33%, and the oil recovery is enhanced by 10.8%.

Development and Evaluation of Surfactant Nanocapsules for Chemical Enhanced Oil Recovery (EOR) Applications

The primary objective of this study is the synthesis of nanocapsules (NC) that allow the reduction of the adsorption process of surfactant over the porous media in enhanced oil recovery processes. Nanocapsules were synthesized through the nanoprecipitation method by encapsulating commercial surfactants Span 20 and Petro 50, and using type II resins isolated from vacuum residue as a shell. The NC were characterized using dynamic light scattering, transmission electron microscopy, Fourier transform infrared, solvency tests, softening point measurements and entrapment efficiency. The obtained NC showed spherical geometry with sizes of 71 and 120 nm for encapsulated Span 20 (NCS20), and Petro 50 surfactant (NCP50), respectively. Also, the NCS20 is composed of 90% of surfactant and 10% of type II resins, while the NCP50 material is 94% of surfactant and 6% of the shell. Nanofluids of nanocapsules dispersed in deionized water were prepared for evaluating the nanofluid—sandstone interaction from adsorption phenomena using a batch-mode method, contact angle measurements, and FTIR analysis. The results showed that NC adsorption was null at the different conditions of temperatures evaluated of 25, 50, and 70 °C, and stirring velocities up to 10,000 rpm. IFT measurements showed a reduction from 18 to 1.62 and 0.15 mN/m for the nanofluids with 10 mg/L of NCS20, and NCP50 materials, respectively. Displacements tests were conducted using a 20 °API crude oil in a quarter five-spot pattern micromodel and showed an additional oil recovery of 23% in comparison with that of waterflooding, with fewer pore volumes injected than when using a dissolved surfactant.