Recent advances and prospects in polymeric nanofluids application for enhanced oil recovery

Experimental insights into the stability of graphene oxide nanosheet and polymer hybrid coupled by ANOVA statistical analysis

The synergistic potential of using graphene oxide (GO) nanosheets and hydrolyzed polyacrylamide (HPAM) as GO enhanced polymer hybrid (GOeP) for enhancing oil recovery (EOR) purposes has drawn attention. However, the hybridization method and stability of GOeP have not been comprehensively studied. To cover this gap, the current study evaluates the stability of GOeP under different conditions, including temperatures such as 60 and 80 °C, high and low salinities, and the presence of Mg2+ ions (6430 and 643 ppm). Hence, GO nanosheets were synthesized and characterized through XRD, Raman, FTIR, and DLS techniques. The performance of five preparation methods was assessed to determine their ability to produce stable hybrids. Zeta potential and sedimentation methods, coupled with the ANOVA statistical technique, were used for measuring and interpreting stability for 21 days. Results revealed that the stability of GOeP in the presence of brine is influenced by hydrolyzation duration, the composition of the water used in polymer hydrolyzation, the form of additives (being powdery or in aqueous solution), and the dispersion quality, including whether the GO solution was prediluted. The results revealed that the positive impact of higher temperatures on the long-term stability of GOeP is approximately seven times less significant than the reduction in stability caused by salinity. Under elevated salinity conditions, a higher Mg2+ concentration led to an 80% decrease in long-term stability, whereas the temperature impact was negligible. These findings highlight the potential of GOeP for EOR applications, offering insights into optimizing stability under challenging reservoir conditions.

On the role of disjoining pressure in nanofluid-assisted enhanced oil recovery: a mini-review

Nanofluid application in enhanced oil recovery (EOR) recently emerged and garnered significant attention within the field. Nanofluids possess unique properties of reducing oil-water interfacial tension, stabilizing emulsions, altering rock surface wettability, and enhancing disjoining pressure between crude oil and rock surfaces, therefore have potential for the oil recovery process. This review provides an in-depth exploration of various aspects related to nanofluids in EOR. Different types of nanofluids are presented with their preparation methods and representative properties. More importantly, the disjoining pressure, a key physical concept in nanofluid-assisted EOR, is introduced and discussed in terms of the mechanism of oil displacement and measurement methods. Further understanding the role of disjoining pressure in nanofluid-assisted oil displacement is necessary for the development and application of effective nanofluids for EOR.

Preparation and Performance Evaluation of Self-Cementing Nanoscale Polymeric Microspheres with Salt and Temperature Tolerance

Polymer microspheres with temperature and salt resistance were synthesized using the anti-suspension polymerization method, incorporating the functional monomers AMPS, AM, and AA. To enhance their self-gelling properties, the microspheres were designed with a core-shell structure. The shell is composed of a polymeric surfactant, fatty alcohol polyoxyethylene ether methacrylate (AEOMA), which serves as a thermosensitive crosslinking agent, enabling self-crosslinking upon shell decomposition, addressing compatibility with reservoir pore throat dimensions. Comprehensive characterizations including infrared spectroscopy, scanning electron microscopy, optical microscopy, and laser particle size analysis were conducted. The microspheres exhibited successful synthesis, a nanoscale size, and regular spherical morphology. They demonstrated excellent temperature and salt resistance, making them suitable for high-temperature, high-salinity reservoir profile control. With a stable three-dimensional network structure, the microspheres displayed good expansion behavior due to hydrophilic groups along the polymer chains, resulting in favorable water affinity. Even after aging, the microspheres maintained their gelling state with a distinct and stable microscopic network skeleton. They exhibited superior plugging performance in low-permeability reservoirs, while effectively improving water absorption profiles in reservoirs with permeability contrasts of 10 to 80, thereby enhancing oil recovery.

BSEO-Semiautomatic Method for Determination of Oil Recovery with Nanofluids in Microfluidic Devices

Microfluidic models have become essential instruments for studying enhanced oil recovery techniques through fluid and chemical injection into micromodels to observe interactions with pore structures and resident fluids. The widespread use of cost-effective lab-on-a-chip devices, known for efficient data extraction and minimal reagent usage, has driven demand for efficient data management methods crucial for high-performance data and image analyses. This article introduces a semiautomatic method for calculating oil recovery in polymeric nanofluid flooding experiments based on the background subtraction (BSEO). It employs the background subtraction technique, generating a foreground binary mask to detect injected fluids represented as pixel areas. The pixel difference is then compared to a threshold value to determine whether the given pixel is foreground or background. Moreover, the proposed method compares its performance with two other representative methods: the ground truth (manual segmentation) and Fiji-ImageJ software. The experiments yielded promising results. Low values of mean-squared error (MSE), mean absolute error (MAE), and root-mean-squared error (RMSE) indicate minimal prediction errors, while a substantial coefficient of determination (R2) of 98% highlights the strong correlation between the method's predictions and the observed outcomes. In conclusion, the presented method emphasizes the viability of BSEO as a robust alternative, offering the advantages of reduced computational resource usage and faster processing times.

Advances of polymer microspheres and its applications for enhanced oil recovery

After long-term water injection, mature reservoirs are encountered with the adverse consequences of the treatment, including erosion, rock formation destruction and drastic decline in oil recovery rate for the past years. Today, the inexpensive and highly efficient polymer microspheres can be considered as a solution to the current issue with excess water production. Studies on practical utilization of polymer microspheres to plug high-permeability zones in heterogeneous reservoirs gained immense popularity in oil production lately. This review aims to give classification to polymer microspheres, including fluorescent polymer microspheres, low elastic polymer microspheres, viscoelastic polymer microspheres and nano-composite polymer microspheres and discuss the specific structural and behavioral traits of each polymer microsphere. Differences in preparation methods, comparisons of performance evaluation and oil recovery rate assessment were also studied. The current complications with functional application of polymer microspheres and its further improvements were considered. This review will provide assistance to the researchers with further advancements of the polymer microspheres, by effectively increasing the oil recovery levels in heterogeneous reservoirs, which will also meet the economical and ecological requirements of the oilfields.

Nanotechnology Impact on Chemical-Enhanced Oil Recovery: A Review and Bibliometric Analysis of Recent Developments

Oil and gas are only two industries that could change because of nanotechnology, a rapidly growing field. The chemical-enhanced oil recovery (CEOR) method uses chemicals to accelerate oil flow from reservoirs. New and enhanced CEOR compounds that are more efficient and eco-friendly can be created using nanotechnology. One of the main research areas is creating novel nanomaterials that can transfer EOR chemicals to the reservoir more effectively. It was creating nanoparticles that can be used to change the viscosity and surface tension of reservoir fluids and constructing nanoparticles that can be utilized to improve the efficiency of the EOR compounds that are already in use. The assessment also identifies some difficulties that must be overcome before nanotechnology-based EOR can become widely used in industry. These difficulties include the requirement for creating mass-producible, cost-effective nanomaterials. There is a need to create strategies for supplying nanomaterials to the reservoir without endangering the formation of the reservoir. The requirement is to evaluate the environmental effects of CEOR compounds based on nanotechnology. The advantages of nanotechnology-based EOR are substantial despite the difficulties. Nanotechnology could make oil production more effective, profitable, and less environmentally harmful. An extensive overview of the most current advancements in nanotechnology-based EOR is provided in this paper. It is a useful resource for researchers and business people interested in this area. This review's analysis of current advancements in nanotechnology-based EOR shows that this area is attracting more and more attention. There have been a lot more publications on this subject in recent years, and a lot of research is being done on many facets of nanotechnology-based EOR. The scientometric investigation discovered serious inadequacies in earlier studies on adopting EOR and its potential benefits for a sustainable future. Research partnerships, joint ventures, and cutting-edge technology that consider assessing current changes and advances in oil output can all benefit from the results of our scientometric analysis.

A numerical investigation of mathematical modelling in 3D hexagonal porous prism on oil recovery using nanoflooding

The use of nanomaterials as a means of recovering heavy and light oil from petroleum reservoirs has increased over the preceding twenty years. Most researchers have found that injecting a nanoparticle dispersion (nanofluids) has led to good results and increased the amount of oil that can be recovered. In this research, we aim to imitate the three-dimensional hexagonal prism in the existence of SiO2 and Al2O3 nanoparticles for better oil recovery. Porosity (0.1 ≤ φ ≤ 0.4 ), mass flow rate (0.05 m L / min ≤ Q ≤ 0.05 m l / min ), nanoparticle concentration (0.01 ≤ ψ ≤ 0.04 ), and the effect of relative permeability (kr) on oil and water saturation in the presence of gravity under different time durations are all investigated. The result obtained for the model is verified with existing experimental data. The results indicated that the infulence of nanoparticle volume fraction (VF) is significant in enhancing the oil recovery rate. It is also observed that at low porosity values the oil recovery is maximum. The maximum oil recovery is attained at low values of mass flow rate in the 3D hexagonal prism in the presence of silicon and aluminium nanoparticles It is also observed that the use of SiO2 gives a better oil recovery rate than Al2O3. It is also observed that maximum oil recovery is obtained at 99% at a flow rate of 0.05 mL/min in the presence of silicon injection.

Synthesis and Performance Evaluation of Alginate-Coated Temperature-Sensitive Polymer Gel Microspheres

With the long-term water-flooding development of the reservoir, the non-homogeneity of the formation is increasing and the reservoir environment is deteriorating; the microspheres used for deep plugging have shown disadvantages, such as poor temperature and salt resistance and faster expansion. In this study, a polymeric microsphere was synthesized that is resistant to high temperature and high salt and can achieve slow expansion and slow release for deep migration. P(AA-AM-SA)@TiO₂ polymer gel/inorganic nanoparticle microspheres were prepared by reversed-phase microemulsion polymerization using acrylamide (AM) and acrylic acid (AA) as monomers, 3-methacryloxypropyltrimethoxysilane (KH-570)-modified TiO₂ as the inorganic core, and sodium alginate (SA) as a temperature-sensitive coating material. Through single-factor analysis of the polymerization process, the optimal synthesis conditions were determined as follows: the oil(Cyclohexane)-water volume ratio was 8:5, the emulsifier mass ratio (Span-80:Tween-80) was 3:1 (10 wt% of the total system amount), the stirring speed was 400 r/min, the reaction temperature was 60 °C, and the initiator (ammonium persulfate and sodium bisulfite) dosage was 0.6 wt%. The size of the dried polymer gel/inorganic nanoparticle microspheres prepared by the optimized synthesis conditions was 10~40 μm with uniform particle size. The observation of P(AA-AM-SA)@TiO₂ microspheres reveals that the Ca elements are uniformly distributed on the microspheres, and FT-IR indicates that the synthesized product is the target product. TGA shows that the polymer gel/inorganic nanoparticle microspheres have better thermal stability after the addition of TiO₂, with a larger mass loss at 390 °C, which can adapt to the medium-high permeability reservoir environment. The thermal and aqueous salinity resistance of the P(AA-AM-SA)@TiO₂ microspheres was tested, and the cracking temperature of P(AA-AM-SA)@TiO₂ microsphere temperature-sensitive material was 90 °C. It still has favorable water absorption and swelling performance under the sodium salt concentration of 2.5 × 10⁴ mg/L and can tolerate calcium salt up to 2.0 × 10⁴ mg/L. Plugging Performance Test results show that the microspheres have good injectability between the permeability of 1.23 and 2.35 μm² and good plugging effect near the permeability of 2.20 μm². At high temperature and high salinity, P(AA-AM-SA)@TiO₂ microspheres have a remarkable effect on profile control and water shutoff, the plugging rate reaches 95.3%, and the oil recovery rate is increased by 12.89% compared with water flooding, achieving the effect of slow swelling and slow release.

A comparative study on the design and application of new nano benzimidazolium gemini ionic liquids for curing interfacial properties of the crude oil-water system

Gemini surface active ionic liquids (GSAILs) are considered a new prosperous class of ionic liquids and recognized as high performance materials. The present study explores the capabilities of the newly synthesized GSAILs, constructed from two benzimidazole rings attached via a four or a six carbon spacer, namely [C₄benzim-C_n-benzimC₄][Br₂], n = 4 and 6. The products were characterized with FT-IR, NMR, XRD, TGA, DTG and SEM methods and were used in curing interfacial properties of the crude oil-water system. The interfacial tension (IFT) was reduced to about 64 and 71% under critical micelle concentrations (CMCs) of 0.028 and 0.025 mol dm^-3 at 298.2 K for n = 4 and 6 GSAILs, respectively. Temperature significantly assisted this effect. Both the GSAILs could transfer the wettability of the solid surface from oil-wet to water-wet. Further, stable oil/water emulsions were produced, having emulsion indices of 74.2 and 77.3% for n = 4 and 6 GSAILs, respectively. Compared to homologous imidazolium GSAILs, the benzimidazolium products revealed better performance in the sense of exhibiting desired effects on the investigated interfacial properties. These can be attributed to the stronger hydrophobicity of the benzimidazolium rings as well as better spreading of the molecular charges. The Frumkin isotherm could exactly reproduce the IFT data, leading to precise determination of the important adsorption and thermodynamic parameters.

A review on application of nanoparticles for EOR purposes: history and current challenges

Applications of nanotechnology in several fields of petroleum industry, e.g., refinery, drilling and enhanced oil recovery (EOR), have attracted a lot of attention, recently. This research investigates the applications of nanoparticles in EOR process. The potential of various nanoparticles, in hybrid and bare forms for altering the state of wettability, reducing the interfacial tension (IFT), changing the viscosity and activation of other EOR mechanisms are studied based on recent findings. Focusing on EOR, hybrid applications of nanoparticles with surfactants, polymers, low-salinity phases and foams are discussed and their synergistic effects are evaluated. Also, activated EOR mechanisms are defined and specified. Since the stabilization of nanofluids in harsh conditions of reservoir is vital for EOR applications, different methods for stabilizing nanofluids through EOR procedures are reviewed. Besides, a discussion on different functional groups of NPs is represented. Later, an economic model for evaluation of EOR process is examined and "Hotelling" method as an appropriate model for investigation of economic aspects of EOR process is introduced in detail. The findings of this study can lead to better understanding of fundamental basis about efficiency of nanoparticles in EOR process, activated EOR mechanisms during application of nanoparticles, selection of appropriate nanoparticles, the methods of stabilizing and economic evaluation for EOR process with respect to costs and outcomes.

Laboratory Investigation of Nanofluid-Assisted Polymer Flooding in Carbonate Reservoirs

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.

Upgrading the Properties of the Crude Oil-Water System for EOR with Simultaneous Effects of a Homologous Series of NanoGemini Surface-Active Ionic Liquids, Electrolytes, and pH

This study investigated the simultaneous effects of electrolytes, NaCl and MgCl₂ electrolytes, individually and as a mixture, and pH on a homologous series of imidazolium nano-Gemini surface-active ionic liquids (GSAILs), [C₄im-C _m -imC₄][Br₂], where m = 2, 4, and 6. These can improve the properties of the crude oil-water system and consequently enhance the oil recovery. The results precisely revealed that interfacial tension (IFT) and critical micelle concentration were initially decreased with electrolyte concentration up to 55.7 and 58.6%, respectively, in comparison to the salt-free condition, followed by a slight increase. Moreover, adjusting the pH can provide a further improvement so that 79.2% IFT reduction is attained at pH 9.5 compared to that at the natural pH and that GSAILs show high stability in the pH range of 2.5-9.5. Meanwhile, aqueous solutions of crude oil and electrolyte presented 1 day emulsification indices within 43-53%, followed by minor changes after 1 week. Interestingly, the emulsification index of 77.1% was attained at pH 9.5. Surface wettability was also favorably altered from oil-wet to water-wet with the nanoGSAILs. The findings of this study help gain a better understanding of the effects of nanosurface active materials to improve oil extraction under reservoir conditions.

Experimental Study on the Application of Cellulosic Biopolymer for Enhanced Oil Recovery in Carbonate Cores under Harsh Conditions

Polymer flooding is used to improve the viscosity of an injectant, thereby decreasing the mobility ratio and improving oil displacement efficiency in the reservoir. Thanks to their environmentally benign nature, natural polymers are receiving prodigious attention for enhanced oil recovery. Herein, the rheology and oil displacement properties of okra mucilage were investigated for its enhanced oil recovery potential at a high temperature and high pressure (HTHP) in carbonate cores. The cellulosic polysaccharide used in the study is composed of okra mucilage extracted from okra (Abelmoschus esculentus) via a hot water extraction process. The morphological property of okra mucilage was characterized with Fourier transform infrared (FTIR), while the thermal stability was investigated using a thermogravimetric analyzer (TGA). The rheological property of the okra mucilage was investigated for seawater salinity and high-temperature conditions using a TA rheometer. Finally, an oil displacement experiment of the okra mucilage was conducted in a high-temperature, high-pressure core flooding equipment. The TGA analysis of the biopolymer reveals that the polymeric solution was stable over a wide range of temperatures. The FTIR results depict that the mucilage is composed of galactose and rhamnose constituents, which are essentially found in polysaccharides. The polymer exhibited pseudoplastic behavior at varying shear rates. The viscosity of okra mucilage was slightly reduced when aged in seawater salinity and at a high temperature. Nonetheless, the cellulosic polysaccharide exemplified sufficiently good viscosity under high-temperature and high-salinity (HTHS) conditions. Finally, the oil recovery results from the carbonate core plug reveal that the okra mucilage recorded a 12.7% incremental oil recovery over waterflooding. The mechanism of its better displacement efficiency is elucidated

Scientific investigation of a fractional model based on hybrid nanofluids with heat generation and porous medium: applications in the drilling process

This article investigates graphite-aluminum oxide hybrid nanoparticles in water-base fluid with the addition of heat generation in the presence of a porous medium. The problem is formulated in terms of momentum and energy equations with sufficient initial and boundary conditions. The solution is investigated by using the Laplace transform method. It is observed that the velocity of the drilling fluid is controlled by adding hybrid nanoparticles as compared to simple nanofluids. In a similar way, the temperature of the fluid is reduced. Also, the heat transfer rate is boosted up to 37.40741% by using hybrid nanofluid compared to regular nanofluid. Moreover, the heat transfer rate was increased up to 11.149% by using different shapes of nanoparticles in the base fluid water. It is also observed that by using hybrid nanofluid skin fraction is boosted up at y = 0 and boosted down at y = 1.

Application of Polymers for Chemical Enhanced Oil Recovery: A Review

Polymers play a significant role in enhanced oil recovery (EOR) due to their viscoelastic properties and macromolecular structure. Herein, the mechanisms of the application of polymeric materials for enhanced oil recovery are elucidated. Subsequently, the polymer types used for EOR, namely synthetic polymers and natural polymers (biopolymers), and their properties are discussed. Moreover, the numerous applications for EOR such as polymer flooding, polymer foam flooding, alkali–polymer flooding, surfactant–polymer flooding, alkali–surfactant–polymer flooding, and polymeric nanofluid flooding are appraised and evaluated. Most of the polymers exhibit pseudoplastic behavior in the presence of shear forces. The biopolymers exhibit better salt tolerance and thermal stability but are susceptible to plugging and biodegradation. As for associative synthetic polyacrylamide, several complexities are involved in unlocking its full potential. Hence, hydrolyzed polyacrylamide remains the most coveted polymer for field application of polymer floods. Finally, alkali–surfactant–polymer flooding shows good efficiency at pilot and field scales, while a recently devised polymeric nanofluid shows good potential for field application of polymer flooding for EOR.

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.

Polymer Flooding in Heterogeneous Heavy Oil Reservoirs: Experimental and Simulation Studies

Polymer flooding (PF) in heterogeneous heavy oil reservoirs is not only closely related to polymer degradation, but also to non-Newtonian flow. In this paper, both experimental and simulation methods are combined to investigate this type of flooding. Through experiments, the degradation of polymer, rheological properties of fluids, and flow of fluids in porous media were determined. Based on the experimental results, a novel mathematical model was established, and a new PF simulator was designed, validated, and further applied to study the effects of polymer degradation, polymer solution shear thinning, and non-Newtonian flow on PF in heterogeneous heavy oil reservoirs. These experimental results demonstrated that the polymer first-order static degradation rate constant was lower than the polymer first-order dynamic degradation rate constant; the polymer solution and heavy oil were non-Newtonian fluids, with shear thinning and Bingham fluid properties, respectively; and the heavy oil threshold pressure gradient (TPG) in low-permeability porous media was higher than that in high-permeability porous media. All comparison results showed that the designed simulator was highly accurate and reliable, and could well describe both polymer degradation and non-Newtonian flow, with special emphasis on the distinction between polymer static and dynamic degradation and heavy oil TPG. Furthermore, the simulation results verified that polymer degradation, polymer solution shear thinning, and heavy oil TPG all had negative effects on the efficiency of PF in heterogeneous heavy oil reservoirs.

Thermosensitive Core-Shell Fe3O4@poly(N-isopropylacrylamide) Nanogels for Enhanced Oil Recovery

An investigation on the application of thermosensitive core-shell Fe₃O₄@PNIPAM nanogels in enhanced oil recovery was successfully performed. Here, the unique core-shell architecture was fabricated by conducting the polymerization at the surface of 3-butenoic acid-functionalized Fe₃O₄ nanoparticles and characterized using X-ray diffraction (XRD), ¹H NMR, vibration sample magnetometer (VSM), and high-resolution transmission electron microscopy (HR-TEM). According to the results, this core-shell structure was beneficial for achieving the desired high viscosity and low nanofluid mobility ratio at high temperatures, which is essential for enhanced oil recovery (EOR) application. The results demonstrated that the nanogels exhibited a unique temperature-dependent flow behavior due to the PNIPAM shell's ability to transform from a hydrated to a dehydrated state above its low critical solution temperature (LCST). At such conditions, the nanogels exhibited a significantly low mobility ratio (M = 0.86), resulting in an even displacement front during EOR and leads to higher oil production. Based on the result obtained from sand pack flooding, about 25.75% of an additional secondary oil recovery could be produced when the nanofluid was injected at a temperature of 45 °C. However, a further increase in the flooding temperature could result in a slight reduction in oil recovery due to the precipitation of some of the severely aggregated nanogels at high temperatures.

Application of Novel Colloidal Silica Nanoparticles in the Reduction of Adsorption of Surfactant and Improvement of Oil Recovery Using Surfactant Polymer Flooding

Surfactant polymer flooding is one of the most common chemical enhanced oil recovery techniques, which improves not only the microscopic displacement of the fluid through the formation of the emulsion but also the volumetric sweep efficiency of the fluid by altering the viscosity of the displacing fluid. However, one constraint of surfactant flooding is the loss of the surfactant by adsorption onto the reservoir rock surface. Hence, in this study, an attempt has been made to reduce the adsorption of the surfactant on the rock surface using novel colloidal silica nanoparticles (CSNs). CSNs were used as an additive to improve the performance of the conventional surfactant polymer flooding. The reduction in adsorption was observed in both the presence and absence of a polymer. The presence of a polymer also reduced the adsorption of the surfactant. Addition of 25 vol % CSNs effectively reduced the adsorption of up to 61% in the absence of a polymer, which increased to 64% upon the introduction of 1000 ppm polymer in the solution at 2500 ppm of the surfactant concentration at 25 °C. The adsorption of surfactant was also monitored with time, and it was found to be increasing with respect to time. The adsorption of surfactant increased from 1.292 mg/g after 0.5 days to 4.179 mg/g after 4 days at 2500 ppm of surfactant concentration at 25 °C. The viscosity, surface tension, and wettability studies were also conducted on the chemical slug used for flooding. The addition of CSNs effectively reduced the surface tension as well as shifted the wettability toward water-wet at 25 °C. Sand pack flooding experiments were performed at 60 °C to access the potential of CSNs in oil recovery, and it was found that the addition of 25 vol % CSNs in the conventional surfactant polymer chemical slug aided in the additional oil recovery up to 5% as compared to that of the conventional surfactant polymer slug.

Hybrid Application of Nanoparticles and Polymer in Enhanced Oil Recovery Processes

Nowadays, the addition of nanoparticles to polymer solutions would be of interest; however, the feasible property of nanoparticles and their impact on oil recovery has not been investigated in more detail. This study investigates the rheology and capillary forces (interfacial tension and contact angle) of nanoparticles in the polymer performances during oil recovery processes. Thereby, a sequential injection of water, polymer, and nanoparticles; Nanosilica (SiO2) and nano-aluminium oxide (Al2O3) was performed to measure the oil recovery factor. Retention decrease, capillary forces reduction, and polymer viscoelastic behavior increase have caused improved oil recovery due to the feasible mobility ratio of polymer-nanoparticle in fluid loss. The oil recovery factor for polymer flooding, polymer-Al2O3, and polymer-SiO2 is 58%, 63%, and 67%, respectively. Thereby, polymer-SiO2 flooding would provide better oil recovery than other scenarios that reduce the capillary force due to the structural disjoining pressure. According to the relative permeability curves, residual oil saturation (Sor) and water relative permeability (Krw) are 29% and 0.3%, respectively, for polymer solution; however, for the polymer-nanoparticle solution, Sor and Krw are 12% and 0.005%, respectively. Polymer treatment caused a dramatic decrease, rather than the water treatment effect on the contact angle. The minimum contact angle for water and polymer treatment are about 21 and 29, respectively. The contact angle decrease for polymer treatment in the presence of nanoparticles related to the surface hydrophilicity increase. Therefore, after 2000 mg L-1 of SiO2 concentration, there are no significant changes in contact angle.

Experimental Investigation of Polymer-Coated Silica Nanoparticles for EOR under Harsh Reservoir Conditions of High Temperature and Salinity

Laboratory experiments have shown higher oil recovery with nanoparticle (NPs) flooding. Accordingly, many studies have investigated the nanoparticle-aided sweep efficiency of the injection fluid. The change in wettability and the reduction of the interfacial tension (IFT) are the two most proposed enhanced oil recovery (EOR) mechanisms of nanoparticles. Nevertheless, gaps still exist in terms of understanding the interactions induced by NPs that pave way for the mobilization of oil. This work investigated four types of polymer-coated silica NPs for oil recovery under harsh reservoir conditions of high temperature (60 ∘C) and salinity (38,380 ppm). Flooding experiments were conducted on neutral-wet core plugs in tertiary recovery mode. Nanoparticles were diluted to 0.1 wt.% concentration with seawater. The nano-aided sweep efficiency was studied via IFT and imbibition tests, and by examining the displacement pressure behavior. Flooding tests indicated incremental oil recovery between 1.51 and 6.13% of the original oil in place (OOIP). The oil sweep efficiency was affected by the reduction in core's permeability induced by the aggregation/agglomeration of NPs in the pores. Different types of mechanisms, such as reduction in IFT, generation of in-situ emulsion, microscopic flow diversion and alteration of wettability, together, can explain the nano-EOR effect. However, it was found that the change in the rock wettability to more water-wet condition seemed to govern the sweeping efficiency. These experimental results are valuable addition to the data bank on the application of novel NPs injection in porous media and aid to understand the EOR mechanisms associated with the application of polymer-coated silica nanoparticles.

Synthesis, Characterization, and Assessment of a CeO2@Nanoclay Nanocomposite for Enhanced Oil Recovery

In this paper, synthesis and characterization of a novel CeO₂/nanoclay nanocomposite (NC) and its effects on IFT reduction and wettability alteration is reported in the literature for the first time. The NC was characterized using scanning electron microscopy (SEM), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), energy-dispersive X-ray spectroscopy (EDS), and EDS MAP. The surface morphology, crystalline phases, and functional groups of the novel NC were investigated. Nanofluids with different concentrations of 100, 250, 500, 1000, 1500, and 2000 ppm were prepared and used as dispersants in porous media. The stability, pH, conductivity, IFT, and wettability alternation characteristics of the prepared nanofluids were examined to find out the optimum concentration for the selected carbonate and sandstone reservoir rocks. Conductivity and zeta potential measurements showed that a nanofluid with concentration of 500 ppm can reduce the IFT from 35 mN/m to 17 mN/m (48.5% reduction) and alter the contact angle of the tested carbonate and sandstone reservoir rock samples from 139° to 53° (38% improvement in wettability alteration) and 123° to 90° (27% improvement in wettability alteration), respectively. A cubic fluorite structure was identified for CeO₂ using the standard XRD data. FESEM revealed that the surface morphology of the NC has a layer sheet morphology of CeO₂/SiO₂ nanocomposite and the particle sizes are approximately 20 to 26 nm. TGA analysis results shows that the novel NC has a high stability at 90 °C which is a typical upper bound temperature in petroleum reservoirs. Zeta potential peaks at concentration of 500 ppm which is a sign of stabilty of the nanofluid. The results of this study can be used in design of optimum yet effective EOR schemes for both carbobate and sandstone petroleum reservoirs.

Field Application of Nanoscale Polymer Microspheres for In-Depth Profile Control in the Ultralow Permeability Oil Reservoir

Much research has been carried out on nanoscale polymer microspheres (PMs) in laboratories in recent years. However, there are limited reports on the practical application of nanoscale PMs in ultralow permeability reservoirs. This paper reports a field application case of nanoscale PMs for in-depth profile control in the ultralow permeability oil reservoir. In the paper, the characteristics of the reservoir and the problems faced during development are analyzed in detail. Then, the PMs with calibration diameters of 300 nm and 800 nm are researched by evaluation experiments, and are selected for in-depth profile control in the ultralow permeability oil reservoir. Finally, according to the effect of the pilot application, the performance of PMs is evaluated, and a more suitable size for the pilot test reservoir is determined. The experiment's results show that the PMs have a good capacity for swelling and plugging. For the PMs with a calibration diameter of 300 nm, the final equilibrium swelling ratio is 56.2 nm·nm^-1, and the maximum resistance coefficient and the blocking rate after swelling are 3.7 and 70.31%, respectively. For the PMs with a calibration diameter of 800 nm, the final equilibrium swelling ratio is 49.4 nm·nm^-1, and the maximum resistance coefficient the blocking rate after swelling are 3.5 and 71.42%, respectively. The performance evaluation results show that nanoscale PMs can be used for in-depth profile control in the ultralow permeability oil reservoir. After the application of PMs in the pilot test area, the average water cut decreased by 10.4%, the average liquid production of single well-increased by 0.9 t/d, and the average thickness of the water-absorbing layer increased by 1.77 m. Comparing the dynamic data variation of well-groups using the PMs with the calibration diameter as 800 nm and the calibration diameter as 300 nm, it indicates that, for the pilot test area, PMs with a calibration diameter of 300 nm are more suitable than PMs with a calibration diameter of 800 nm.

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

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 S_BET, FTIR spectra, hydrodynamic mean sizes (dp₅₀), isoelectric points (pH_IEP), 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.

Experimental evaluation of oil recovery mechanism using a variety of surface-modified silica nanoparticles: Role of in-situ surface-modification in oil-wet system

Recent developments propose renewed use of surface-modified nanoparticles (NPs) for enhanced oil recovery (EOR) due to improved stability and reduced porous media retention. The enhanced surface properties render the nanoparticles more suitable compared to bare nanoparticles, for increasing the displacement efficiency of waterflooding. However, the EOR mechanisms using NPs are still not well established. This work investigates the effect of in-situ surface-modified silica nanoparticles (SiO₂ NPs) on interfacial tension (IFT) and wettability behavior as a prevailing oil recovery mechanism. For this purpose, the nanoparticles have been synthesized via a one-step sol-gel method using surface-modification agents, including Triton X-100 (non-ionic surfactant) and polyethylene glycol (polymer), and characterized using various techniques. These results exhibit the well-defined spherical particles, particularly in the presence of Triton X-100 (TX-100), with particle diameter between 13 to 27 nm. To this end, SiO₂ nanofluids were formed by dispersing nanoparticles (0.05 wt.%, 0.075 wt.%, 0.1 wt.%, and 0.2 wt.%) in 3 wt.% NaCl to study the impact of surface functionalization on the stability of the nanoparticle suspension. The optimal stability conditions were obtained at 0.1 wt.% SiO₂ NPs at a basic pH of 10 and 9.5 for TX-100/ SiO₂ and PEG/SiO nanofluids, respectively. Finally, the surface-treated SiO₂ nanoparticles were found to change the wettability of treated (oil-wet) surface into water-wet by altering the contact angle from 130° to 78° (in case of TX-100/SiO₂) measured against glass surface representing carbonate reservoir rock. IFT results also reveal that the surfactant treatment greatly reduced the oil-water IFT by 30%, compared to other applied NPs. These experimental results suggest that the use of surface-modified SiO₂ nanoparticles could facilitate the displacement efficiency by reducing IFT and altering the wettability of carbonate reservoir towards water-wet, which is attributed to more homogeneity and better dispersion of surface-treated silica NPs compared to bare-silica NPs.

Unique Oil-in-Brine Pickering Emulsion Using Responsive Antipolyelectrolyte Functionalized Latex: A Versatile Emulsion Stabilizer

A simple and straightforward approach to synthesize oil-in-water (O/W) emulsions under high salinity and temperature using zwitterion-functionalized latexes are presented in this work. First, well-defined functionalized latexes were synthesized by emulsifier-free emulsion copolymerization in the presence of precursor sulfobetaine comonomer using brine as a continuous phase. The surface-functionalized latex particles were then characterized by DLS, SEM, TEM, XPS, and TGA. The functionalized latex exhibited antipolyelectrolyte behavior in high salinity brine and at high temperatures. The effects of salinity, temperature, and pH on the long-term stability of the particles were investigated. Further, to evaluate the potential in high salinity brine and high temperature, the saltphilic functionalized latexes were utilized to stabilize the oil/brine (O/W) interface without any other additives. The latex enabled the formation of a stable Pickering emulsion system with low solid content (<0.02% w/w) in the presence of 50% v/v n-decane. The functionalized latexes were self-assembled at the O/W interface as a spherical colloidosome in high salinity brine through hydrophobic interactions and irreversible adsorption. The supraparticles were imaged with SEM, providing an insight that the exterior of the emulsion droplets is stabilized by the saltphilic latex particles, forming a protective layer at the oil-water interface through electrostatic repulsion. The antipolyelectrolyte latex can be utilized as a novel emulsion stabilizer, which can provide a versatile alternative for applications in a complex environment such as high salinity, temperature, and low or high pH.

Impact of Spacer Nature and Counter Ions on Rheological Behavior of Novel Polymer-Cationic Gemini Surfactant Systems at High Temperature

Compatible surfactant-polymer (SP) hybrid systems at high temperature are in great demand due to the necessity of chemical flooding in high-temperature oil reservoirs. The rheological properties of novel SP systems were studied. The SP system used in this study consists of a commercial polymer and four in-house synthesized polyoxyethylene cationic gemini surfactants with various spacers (mono phenyl and biphenyl ring) and different counterions (bromide and chloride). The impact of surfactant concentration, spacer nature, counterions, and temperature on the rheological features of SP solutions was examined using oscillation and shear measurements. The results were compared with a pure commercial polymer. All surfactants exhibited good thermal stability in seawater with no precipitation. Shear viscosity and storage modulus were measured as a function of shear rate and angular frequency, respectively. The experimental results revealed that the novel SP solution with a mono phenyl and chloride counterions produces a better performance in comparison with the SP solution, which contains mono phenyl and bromide counterions. Moreover, the effect is enhanced when the mono phenyl ring is replaced with a biphenyl ring. Shear viscosity and storage modulus decrease by increasing surfactant concentration at the same temperature, due to the charge screening effect. Storage modulus and complex viscosity reduce by increasing the temperature at a constant angular frequency of 10 rad/s. Among all studied SP systems, a surfactant containing a biphenyl ring in the spacer with chloride as a counterion has the least effect on the shear viscosity of the polymer. This study improves the understanding of tuning the surfactant composition in making SP solutions with better rheological properties.

Advances of spontaneous emulsification and its important applications in enhanced oil recovery process

Emulsions, including oil-in-water (O/W) and water-in-oil (W/O) emulsions, can play important roles in both controlling reservoir conformance and displacing residual oil for enhanced oil recovery (EOR) projects. However, current methods, like high-shear mixing, high-pressure homogenizing, sonicators and others, often use lots of extra energy to prepare the emulsions with high costs but very low energy efficiency. In recent decades, spontaneous emulsification methods, which allow one to create micro- and nano-droplets with very low or even no mechanical energy input, have been launched as an overall less expensive and more efficient alternatives to current high extra energy methods. Herein, we primarily review the basic concepts on spontaneous emulsification, including mechanisms, methods and influenced parameters, which are relevant for fundamental applications for industrials. The spontaneity of the emulsification process is influenced by the following variables: surfactant structure, concentration and initial location, oil phase composition, addition of co-surfactant and non-aqueous solvent, as well as salinity and temperature. Then, we focus on the description of importance for emulsions in EOR processes from advances and categories to improving oil recovery mechanisms, including both sweep efficiency and displacement efficiency aspects. Finally, we systematically address the applications and outlooks based on the use of spontaneous emulsification in the practical oil reservoirs for EOR processes, in which conventional, heavy, high-temperature, high-salinity and low-permeability oil reservoirs, as well as wastewater treatments after EOR processes are involved.

Surface-Functionalized Superparamagnetic Nanoparticles (SPNs) for Enhanced Oil Recovery: Effects of Surface Modifiers and Their Architectures

Superparamagnetic nanoparticles (SPNs) have been considered as one of the most studied nanomaterials for subsurface applications, including in enhanced oil recovery (EOR), due to their unique physicochemical properties. However, a comprehensive understanding of the effect of surface functionalization on the ability of the nanoparticles to improve secondary and tertiary oil recoveries remains unclear. Therefore, investigations on the application of bare and surface-functionalized SPNs in EOR using a sand pack were carried out in this study. Here, the as-prepared SPNs were functionalized using oleic acid (OA) and polyacrylamide (PAM) to obtain several types of nanostructure architectures such as OA-SPN, core-shell SPN@PAM, and SPN-PAM. Based on the result, it is found that both the viscosity and mobility of the nanofluids were significantly affected by not only the concentration of the nanoparticles but also the type and architecture of the surface modifier, which dictated particle hydrophilicity. According to the sand pack tests, the nanofluid containing SPN-PAM was able to recover as much as 19.28% of additional oil in a relatively low concentration (0.9% w/v). The high oil recovery enhancement was presumably due to the ability of suspended SPN-PAM to act as a mobility control and wettability alteration agent and facilitate the formation of a Pickering emulsion and disjoining pressure.