Nanotechnology in Enhanced Oil Recovery

Unveiling the revolutionary role of nanoparticles in the oil and gas field: Unleashing new avenues for enhanced efficiency and productivity

Prominent oil corporations are currently engaged in a thorough examination of the potential implementation of nanoparticles within the oil and gas sector. This is evidenced by the substantial financial investments made towards research and development, which serves as a testament to the significant consideration given to nanoparticles. Indeed, nanoparticles has garnered increasing attention and innovative applications across various industries, including but not limited to food, biomedicine, electronics, and materials. In recent years, the oil and gas industry has conducted extensive research on the utilization of nanoparticles for diverse purposes, such as well stimulation, cementing, wettability, drilling fluids, and enhanced oil recovery. To explore the manifold uses of nanoparticles in the oil and gas sector, a comprehensive literature review was conducted. Reviewing several published study data leads to the conclusion that nanoparticles can effectively increase oil recovery by 10 %-15 % of the initial oil in place while tertiary oil recovery gives 20-30 % extra initial oil in place. Besides, it has been noted that the properties of the reservoir rock influence the choice of the right nanoparticle for oil recovery. The present work examines the utilization of nanoparticles in the oil and gas sector, providing a comprehensive analysis of their applications, advantages, and challenges. The article explores various applications of nanoparticles in the industry, including enhanced oil recovery, drilling fluids, wellbore strengthening, and reservoir characterization. By delving into these applications, the article offers a thorough understanding of how nanoparticles are employed in different processes within the sector. This analysis may prove highly advantageous for future studies and applications in the oil and gas sector.

Synthesis of Raspberry-like Nanoparticles via Surface Grafting of Positively Charged Polyelectrolyte Brushes: Colloidal Stability and Surface Properties

A method to synthesize stable, raspberry-like nanoparticles (NPs), using surface grafting of poly(glycidyl methacrylate) (PGMA) brushes on a polystyrene (PS) core with varying grafting densities, is reported. A two-step functionalization reaction of PGMA epoxide groups comprising an amination step first using ethylene diamine and then followed by a quaternization using glycidyltrimethylammonium chloride generates permanently and positively charged polyelectrolyte brushes, which result in both steric and electrostatic stabilization. The dispersion stability of the brush-bearing NPs is dramatically improved compared to that of the pristine PS core in salt solutions at ambient (25 °C) and elevated temperatures (60 °C). Additionally, the grafted polyelectrolyte chains undergo a reversible swelling in the presence of different ionic strength (IS) salts, which modulate the surface properties, including roughness, stiffness, and adhesion. An atomic force microscope under both dry and wet conditions was used to image conformational changes of the polyelectrolyte chains during the swelling and deswelling transitions as well as to probe the nanomechanical properties by analyzing the corresponding force-sample separation curves. The quaternized polyelectrolyte brushes undergo a conformational transition from a collapsed state to a swelled state in the osmotic brush (OB) regime triggered by the osmotic gradient of mobile ions to the interior of the polymer chain. At IS ∼ 1 M, the brushes contract and the globules reform (salted brush state) as evidenced by an increase in the surface roughness and a reduction in the adhesion of the brushes. Beyond IS ∼ 1 M, quartz crystal microbalance with dissipation monitoring measurements show that salt uptake continues to take place predominantly on the exterior surface of the brush since salt adsorption is not accompanied by a size increase as measured by dynamic light scattering. The study adds new insights into our understanding of the behavior of NPs bearing salt-responsive polyelectrolyte brushes with adaptive swelling thresholds that can ultimately modulate surface properties.

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.

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.

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.

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.

Influence of Sodium Metal Nanoparticles on the Efficiency of Heavy Oil Aquathermolysis

In this study, for the first time we investigated the in situ upgrading performance of Na metal nanoparticles, which were obtained by dispersing small pieces of sodium in liquid paraffin up to certain dispersity. In situ aquathermolytic reactions were modeled in a high pressure–high temperature reactor coupled with a Gas Chromatography (GC) system at a temperature of 250 °C for 24 h using a heavy oil sample, produced from the Ashal’cha reservoir, Republic of Tatarstan (Russia). The mean particle size of Na nanoparticles was 6.5 nm determined by the Dynamic Light Scattering (DLS) method. The nanoparticles were introduced to the reaction medium with a concentration of 2 wt.% The upgrading performance of Na nanoparticles was evaluated by several analytical methods such as Gas Chromatography (GC), elemental analysis (CHNS), SARA, Gas Chromatography–Mass Spectroscopy (GC-MS), FT-IR spectroscopy and viscosity measurements. It was revealed that Na nanoparticles interact with water to yield hydrogen gas, the concentration of which increases from 0.015 to 0.805 wt.% Moreover, the viscosity of upgraded heavy oil was reduced by more than 50% and the content of low-molecular-weight hydrocarbons in saturated and aromatics fractions was increased. The Na nanoparticles contributed to the utilization of hydrogen sulfide and carbon dioxide by 99 and 94 wt.%, respectively.

Study on Gas Invasion Behavior of Gas–Liquid Displacement in Fractured Reservoirs

When drilling or exploiting fractured formations, gas fluid displacement and invasion often occur, and gas invasion is very subtle and difficult to find. The gas in the fracture enters the wellbore and arrives near the wellhead with the drilling fluid. Improper treatment may lead to serious accidents such as lost circulation and blowout. In this study, using computational fluid dynamics (CFD) simulation software for modeling and grid generation, based on the volume of fluid (VOF) method, the gas invasion behavior under different conditions was simulated to explore the flow process and characteristics of gas invasion, and the effects of different drilling fluid properties and fracture morphology on gas invasion were analyzed. The experimental results show that the drilling fluid enters the fracture to compress the gas, making the pressure in the fracture greater than that in the wellbore, thus leading to the occurrence of gas invasion. The viscosity and density of the drilling fluid have different effects on the gas invasion process. The higher the viscosity, the smaller the possibility of gas invasion. However, when the viscosity of the drilling fluid gradually increases from 10–50 MPa·s, the change of gas invasion rate is small, all within 1.0–1.2 m/s. The higher the density, the more conducive to the occurrence of gas invasion. The inlet pressure has no obvious effect on the occurrence of gas invasion, and the occurrence time of the gas invasion fluctuates in 0.35 s at 0.5–2.5 MPa. With the increase in the fracture width and length, the possibility of gas invasion decreases, but there is an extreme value for the fracture height. The time of gas invasion does not change beyond this extreme value. When the fracture height is 100–700 mm, the time of gas invasion increases with the increase in the height; when the height is 700–900 mm, the gas invasion time does not change. These results provide a practical and effective method for enhancing oil recovery, preventing and treating gas invasion in gas–liquid flooding.

Nanoparticles in Chemical EOR: A Review on Flooding Tests

The use of nanofluids is showing promise as an enhanced oil recovery (EOR) method. Several reviews have been published focusing on the main mechanisms involved in the process. This new study, unlike previous works, aims to collect information about the most promising nano-EOR methods according to their performance in core-flooding tests. As its main contribution, it presents useful information for researchers interested in experimental application of nano-EOR methods. Additional recoveries (after brine flooding) up to 15% of the original oil in place, or higher when combined with smart water or magnetic fields, have been found with formulations consisting of simple nanoparticles in water or brine. The functionalization of nanoparticles and their combination with surfactants and/or polymers take advantage of the synergy of different EOR methods and can lead to higher additional recoveries. The cost, difficulty of preparation, and stability of the formulations have to be considered in practical applications. Additional oil recoveries shown in the reviewed papers encourage the application of the method at larger scales, but experimental limitations could be offering misleading results. More rigorous and systematic works are required to draw reliable conclusions regarding the best type and size of nanoparticles according to the application (type of rock, permeability, formation brine, reservoir conditions, other chemicals in the formulation, etc.).

Insight into Nano-chemical Enhanced Oil Recovery from Carbonate Reservoirs Using Environmentally Friendly Nanomaterials

The use of nanoparticles (NPs) in enhanced oil recovery (EOR) processes is very effective in reducing the interfacial tension (IFT) and surface tension (ST) and altering the wettability of reservoir rocks. The main purpose of this study was to use the newly synthesized nanocomposites (KCl/SiO₂/Xanthan NCs) in EOR applications. Several analytical techniques including X-ray diffraction (XRD), Fourier transform infrared spectroscopy (FTIR), and scanning electron microscope (SEM) were applied to confirm the validity of the synthesized NCs. From the synthesized NCs, nanofluids were prepared at different concentrations of 100-2000 ppm and characterized using electrical conductivity, IFT, and ST measurements. From the obtained results, it can be observed that 1000 ppm is the optimal concentration of the synthesized NCs that had the best performance in EOR applications. The nanofluid with 1000 ppm KCl/SiO₂/Xanthan NCs enabled reducing the IFT and ST from 33 and 70 to 29 and 40 mN/m, respectively. However, the contact angle was highly decreased under the influence of the same nanofluid to 41° and the oil recovery improved by an extra 17.05% OOIP. To sum up, KCl/SiO₂/Xanthan NCs proved highly effective in altering the wettability of rocks from oil-wet to water-wet and increasing the cumulative oil production.

Influence of the Injection Scheme on the Enhanced Oil Recovery Ability of Heterogeneous Phase Combination Flooding in Mature Waterflooded Reservoirs

With the maturity of waterflooded reservoirs, owing to serious heterogeneity, the fluid will channel through the thief zone, leading to considerable remaining oil unrecovered in the upswept area. To further enhance oil recovery (EOR) after waterflooding, the heterogeneous phase combination flooding (HPCF) was composed of a polymer, branched-preformed particle gel (B-PPG), and surfactant. For the sake of improving the economic efficiency, the influence of the injection scheme on the EOR of HPCF with an equal chemical agent cost was investigated by sand-pack flooding experiments. Then, visual plate sand-pack model flooding experiments were performed to study the swept area of HPCF under different injection schemes. Results demonstrated that the total EOR of HPCF under different injection schemes ranged from 33.5 to 39.3%. Moreover, the EOR of HPCF under the alternation injection (AI) scheme was the highest, followed by the concentration step change injection (CI) scheme, and that of the simultaneous injection (SI) scheme was the least. The visual flooding experimental results showed that the swept area of HPCF after waterflooding under the AI scheme was higher than that of the SI. Moreover, in view of qualitative analysis of remaining oil distribution, the EOR of AI of HPCF was higher than that of SI, which was consistent with the parallel sand-pack flooding results.

Effects of MgO, γ-Al2O3, and TiO2 Nanoparticles at Low Concentrations on Interfacial Tension (IFT), Rock Wettability, and Oil Recovery by Spontaneous Imbibition in the Process of Smart Nanofluid Injection into Carbonate Reservoirs

Recently, some nanoparticles have been used to upgrade injected water into oil reservoirs to enhance oil recovery. These nanoadditives can be used in a variety of injectable waters, including smart/engineered water with special salinities. In this study, the performance of smart water containing different concentrations of magnesium sulfate (MgSO₄) and calcium chloride (CaCl₂) and 500 ppm of titanium dioxide (TiO₂), γ-alumina (γ-Al₂O₃), and magnesium oxide (MgO) nanoparticles in interfacial tension (IFT) and contact angle reduction and oil production under imbibition of the chemical fluids was investigated. Based on the results, the IFT decreased more when ions and nanoparticles were present in the system. An optimum IFT of 4.684 mN/m was recorded for the nanofluid containing 2000 ppm of MgSO₄ + 500 ppm of MgO. The results of contact angle tests demonstrated improved saline water capabilities in the presence of nanoparticles and showed that a very effective reduction was accessible and highly hydrophilic wettability was obtained when using smart water with stable nanoparticles as a minimum contact angle of 18.33° was obtained by the optimal fluid containing nano-γ-Al₂O₃. Finally, an ultimate oil production of 64.1-68.7% was obtained in six experiments with smart water and stable nanoparticles.

Nanofluid Structural Forces Alter Solid Wetting, Enhancing Oil Recovery

Nanofluids have attracted significant research interest for their promising application in enhanced oil recovery. One striking feature leading to the outstanding efficiency of nanofluids in enhanced oil recovery is the structure of nanoparticles, which induces oscillatory structural forces in the confined space between fluid–fluid interfaces or air–liquid and liquid–solid interfaces. To promote the understanding of the oscillatory structural forces and their application in enhanced oil recovery, we reviewed the origin and theory of the oscillatory structural forces, factors affecting their magnitude, and the experimental techniques demonstrating their impacts on enhanced oil recovery. We also reviewed the methods, where the benefits of nanofluids in enhanced oil recovery provided by the oscillatory structural forces are directly manifested. The oscillatory structural forces promote the wetting and spreading of nanofluids on solid surfaces, which ultimately enhances the separation of oil from the reservoir. Some imbibition tests demonstrated as much as 50% increased oil recovery, compared to the cases where the oscillatory structural forces were absent.

Carbon Dioxide Applications for Enhanced Oil Recovery Assisted by Nanoparticles: Recent Developments

Carbon dioxide (CO₂) in enhanced oil recovery (EOR) has received significant attention due to its potential to increase ultimate recovery from mature conventional oil reserves. CO₂-enhanced oil recovery (CO₂-EOR) helps to reduce global greenhouse gas emissions by sequestering CO₂ in subterranean geological formations. CO₂-EOR has been exploited commercially over recent decades to improve recovery from light and medium gravity oil reservoirs in their later stages of development. CO₂ tends to be used in either continuous flooding or alternated flooding with water injection. Problems can arise in CO₂-flooded heterogeneous reservoirs, due to differential mobility of the fluid phases, causing viscous fingering and early CO₂ penetration to develop. This study reviews the advantages and disadvantages of the techniques used for injecting CO₂ into subsurface reservoirs and the methods adopted in attempts to control CO₂ mobility. Recently developed methods are leading to improvements in CO₂-EOR results. In particular, the involvement of nanoparticles combined with surfactants can act to stabilize CO₂ foam, making it more effective in the reservoir from an EOR perspective. The potential to improve CO₂ flooding techniques and the challenges and uncertainties associated with achieving that objective are addressed.

Thermophysical Properties of Nanofluid in Two-Phase Fluid Flow through a Porous Rectangular Medium for Enhanced Oil Recovery

It is necessary to sustain energy from an external reservoir or employ advanced technologies to enhance oil recovery. A greater volume of oil may be recovered by employing nanofluid flooding. In this study, we investigated oil extraction in a two-phase incompressible fluid in a two-dimensional rectangular porous homogenous area filled with oil and having no capillary pressure. The governing equations that were derived from Darcy’s law and the mass conservation law were solved using the finite element method. Compared to earlier research, a more efficient numerical model is proposed here. The proposed model allows for the cost-effective study of heating-based inlet fluid in enhanced oil recovery (EOR) and uses the empirical correlations of the nanofluid thermophysical properties on the relative permeability equations of the nanofluid and oil, so it is more accurate than other models to determine the higher recovery factor of one nanoparticle compared to other nanoparticles. Next, the effect of nanoparticle volume fraction on flooding was evaluated. EOR via nanofluid flooding processes and the effect of the intake temperatures (300 and 350 K) were also simulated by comparing three nanoparticles: SiO2, Al2O3, and CuO. The results show that adding nanoparticles (<5 v%) to a base fluid enhanced the oil recovery by more than 20%. Increasing the inlet temperature enhanced the oil recovery due to changes in viscosity and density of oil. Increasing the relative permeability of nanofluid while simultaneously reducing the relative permeability of oil due to the presence of nanoparticles was the primary reason for EOR.

Recovery Observations from Alkali, Nanoparticles and Polymer Flooding as Combined Processes

We have studied wettability alterations through imbibition/flooding and their synergy with interfacial tension (IFT) for alkalis, nanoparticles and polymers. Thus, the total acid number (TAN) of oil may determine the wetting-state of the reservoir and influence recovery and IFT. Data obtained demonstrate how the oil TAN number (low and high), chemical agent and reservoir mineralogy influence fluid–fluid and rock–fluid interactions. We used a laboratory evaluation workflow that combines complementary assessments such as spontaneous imbibition tests, IFT, contact angle measurements and selected core floods. The workflow evaluates wettability alteration, IFT changes and recovery when injecting alkalis, nanoparticles and polymers, or a combination of them. Dynamics and mechanisms of imbibition were tracked by analyzing the recovery change with the inverse bond number. Three sandstone types (outcrops) were used, which mainly differed in clay content and permeability. Oils with low and high TANs were used, the latter from the potential field pilot 16 TH reservoir in the Matzen field (Austria). We have investigated and identified some of the conditions leading to increases in recovery rates as well as ultimate recovery by the imbibition of alkali, nanoparticle and polymer aqueous phases. This study presents novel data on the synergy of IFT, contact angle Amott imbibition, and core floods for the chemical processes studied.

Sorption of Nanomaterials to Sandstone Rock

We investigated the interaction of silica nanostructured particles and sandstone rock using various experimental approaches, such as fluid compatibility, batch sorption and single-phase core-floods. Diol and polyethylenglycol (PEG) surface-modified nanostructured silica materials were tested using two brines differing in ionic strength and with the addition of sodium carbonate (Na₂CO₃). Berea and Keuper outcrop materials (core plug and crushed samples) were used. Core-flood effluents were analysed to define changes in concentration and a rock's retention compared to a tracer. Field Flow Fractionation (FFF) and Dynamic Light Scattering (DLS) were performed to investigate changes in the effluent's size distribution. Adsorption was evaluated using UV-visible spectroscopy and scanning electron microscopy (SEM). The highest adsorption was observed in brine with high ionic strength, whereas the use of alkali reduced the adsorption. The crushed material from Berea rock showed slightly higher adsorption compared to Keuper rock, whereas temperature had a minor effect on adsorption behaviour. In core-flood experiments, no effects on permeability have been observed. The used particles showed a delayed breakthrough compared to the tracer, and bigger particles passed the rock core faster. Nanoparticle recovery was significantly lower for PEG-modified nanomaterials in Berea compared to diol-modified nanomaterials, suggesting high adsorption. SEM images indicate that adsorption spots are defined via surface roughness rather than mineral type. Despite an excess of nanomaterials in the porous medium, monolayer adsorption was the prevailing type observed.

Wettability Changes Due to Nanomaterials and Alkali-A Proposed Formulation for EOR

We investigated the usage of two silica nanomaterials (surface-modified) and alkali in enhanced oil recovery through Amott spontaneous imbibition tests, interfacial tension (IFT) measurements, and phase behavior. We evaluated the wettability alteration induced by the synergy between nanomaterials and alkali. Moreover, numerical analysis of the results was carried out using inverse Bond number and capillary diffusion coefficient. Evaluations included the use of Berea and Keuper outcrop material, crude oil with different total acid numbers (TAN), and Na2CO3 as alkaline agent. Data showed that nanomaterials can reduce the IFT, with surface charge playing an important role in this process. In synergy with alkali, the use of nanomaterials led to low-stable IFT values. This effect was also seen in the phase behavior tests, where brine/oil systems with lower IFT exhibited better emulsification. Nanomaterials' contribution to the phase behavior was mainly the stabilization of the emulsion middle phase. The influence of TAN number on the IFT and phase behavior was prominent especially when combined with alkali. Amott spontaneous imbibition resulted in additional oil recovery ranging from 4% to 50% above the baseline, which was confirmed by inverse Bond number analysis. High recoveries were achieved using alkali and nanomaterials; these values were attributed to wettability alteration that accelerated the imbibition kinetics as seen in capillary diffusion coefficient analysis.

Synergistic Effect of Nanofluids and Surfactants on Heavy Oil Recovery and Oil-Wet Calcite Wettability

In recent years, unconventional oils have shown a huge potential for exploitation. Abundant reserves of carbonate asphalt rocks with a high oil content have been found; however, heavy oil and carbonate minerals have a high interaction force, which makes oil-solid separation difficult when using traditional methods. Although previous studies have used nanofluids or surfactant alone to enhance oil recovery, the minerals were sandstones. For carbonate asphalt rocks, there is little research on the synergistic effect of nanofluids and surfactants on heavy oil recovery by hot-water-based extraction. In this study, we used nanofluids and surfactants to enhance oil recovery from carbonate asphalt rocks synergistically based on the HWBE process. In order to explore the synergistic mechanism, the alterations of wettability due to the use of nanofluids and surfactants were studied. Nanofluids alone could render the oil-wet calcite surface hydrophilic, and the resulting increase in hydrophilicity of calcite surfaces treated with different nanofluids followed the order of SiO2 > MgO > TiO2 > ZrO2 > γ-Al2O3. The concentration, salinity, and temperature of nanofluids influenced the oil-wet calcite wettability, and for SiO2 nanofluids, the optimal nanofluid concentration was 0.2 wt%; the optimal salinity was 3 wt%; and the contact angle decreased as the temperature increased. Furthermore, the use of surfactants alone made the oil-wet calcite surface more hydrophilic, according to the following order: sophorolipid (45.9°) > CTAB (49°) > rhamnolipid (53.4°) > TX-100 (58.4°) > SDS (67.5°). The elemental analysis along with AFM and SEM characterization showed that nanoparticles were adsorbed onto the mineral surface, resulting in greater hydrophilicity of the oil-wet calcite surface, and the roughness was related to the wettability. Surfactant molecules could aid in the release of heavy oil from the calcite surface, which exposes the uncovered calcite surface to its surroundings; additionally, some surfactants adsorbed onto the oil-wet calcite surface, and the combined role made the oil-wet calcite surface hydrophilic. In conclusion, the study showed that hybrid nanofluids showed a better effect on wettability alteration, and the use of nanofluids and surfactants together resulted in synergistic alteration of oil-wet calcite surface wettability.

Surfactants Enhanced Heavy Oil-Solid Separation from Carbonate Asphalt Rocks-Experiment and Molecular Dynamic Simulation

In this study, surfactants were used to enhance heavy oil-solid separation, and a detailed mechanism was explored by SARA (saturates, aromatics, resins, asphaltenes) analysis, element analysis, AFM measurement, and molecular dynamic simulation. Surfactants could effectively decrease oil/solid interaction force and then oil-solid separation would be enhanced. The oil-solid interactive force was in relation to surfactants concentration, pH value, asphaltene content, and salinity. The molecular dynamics simulation results show that the dissociation of saturated hydrocarbon, aromatic hydrocarbon, resin, and asphaltene (SARA) on carbonate minerals is gradually weakened for all surfactants. In the process of molecular dynamics simulation of surfactant stripping SARA, firstly, the surfactant molecules adsorb on the surface of SARA molecules. After that, the surfactant peels SARA molecules off the surface of calcite under the influence of molecular thermal motion. In this process, surfactant molecules will not be directly adsorbed on the surface of trace minerals. The results of energy/temperature balance indicated that saturates, aromatics and resins could remain stable when the molecular dynamics simulation time reached 2000 ps with the phenomenon that saturates, aromatics could liberate from minerals totally within 2000 ps. The molecular dynamics simulation of asphaltenes will not liberate from calcite surface within 6000 ps, meanwhile, they could not reach the energy balance/energy balance within 6000 ps. The functional groups of surfactant molecules would have interactions with the SARA functional group, resulting in different dissociation effects of SARA. The results of molecular dynamics simulation are consistent with the experiment results. The separation effect of saturated hydrocarbon, aromatic hydrocarbon, resin, and asphaltene in five kinds of surfactants were different. The molecular dynamic simulation results were in accordance with the SARA analysis.

Catalytic Effects of Temperature and Silicon Dioxide Nanoparticles on the Acceleration of Production from Carbonate Rocks

The use of engineered water (EW) nanofluid flooding in carbonates is a new enhanced oil recovery (EOR) hybrid technique that has yet to be extensively investigated. In this research, we investigated the combined effects of EW and nanofluid flooding on oil-brine-rock interactions and recovery from carbonate reservoirs at different temperatures. EW was used as dispersant for SiO2 nanoparticles (NPs), and a series of characterisation experiments were performed to determine the optimum formulations of EW and NP for injection into the porous media. The EW reduced the contact angle and changed the rock wettability from the oil-wet condition to an intermediate state at ambient temperature. However, in the presence of NPs, the contact angle was reduced further, to very low values. When the effects of temperature were considered, the wettability changed more rapidly from a hydrophobic state to a hydrophilic one. Oil displacement was studied by injection of the optimised EW, followed by an EW-nanofluid mixture. An additional recovery of 20% of the original oil in place was achieved. The temperature effects mean that these mechanisms are catalytic, and the process involves the initiation and activation of multiple mechanisms that are not activated at lower temperatures and in each standalone technique.

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.

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.

Effect of Fumed Silica Nanoparticles on Ultraviolet Aging Resistance of Bitumen

In this study, bitumen modified by fumed silica nanoparticles was characterized through dynamic shear rheometer tests, scanning electron microscopy, and Fourier transform infrared spectroscopy. The fumed silica nanoparticles were used in three different ratios, i.e., 0.1, 0.2 and 0.3 wt.-% of bitumen. Specifically, the modified bitumen characteristics were studied after laboratory aging by analyzing the chemical composition and rheological properties. From the determination of oxidation degree and carbonyl index it was found that the resistance of the modified bitumen to ultraviolet aging was improved with the increasing nanoparticle content. In bitumen modified by fumed silica nanoparticles, the nanoparticles were well dispersed. Moreover, the results illustrated that the bitumen properties were improved, and the improvement effect of 0.1 wt.-% fumed silica nanoparticles was more distinct than the higher concentrations.

Extra-Heavy Oil Aquathermolysis Using Nickel-Based Catalyst: Some Aspects of In-Situ Transformation of Catalyst Precursor

In the present work, we studied the catalytic performance of an oil-soluble nickel-based catalyst during aquathermolysis of oil-saturated crushed cores from Boca de Jaruco extra-heavy oil field. The decomposition of nickel tallate and some aspects of in-situ transformation of the given catalyst precursor under the steam injection conditions were investigated in a high-pressure batch reactor using XRD and SEM analysis methods. The changes in physical and chemical properties of core extracts after the catalytic aquathermolysis process with various duration were studied using gas chromatography for analyzing gas products, SARA analysis, GC-MS of saturated and aromatic fractions, FT-IR spectrometer, elemental analysis, and matrix-activated laser desorption/ionization (MALDI). The results showed that nickel tallate in the presence of oil-saturated crushed core under the injection of steam at 300 °C transforms mainly into nonstoichiometric forms of nickel sulfide. According to the SEM images, the size of nickel sulfide particles was in the range of 80–100 nm. The behavior of main catalytic aquathermolysis gas products such as CH4, CO2, H2S, and H2 depending on the duration of the process was analyzed. The catalytic upgrading at 300 °C provided decrease in the content of resins and asphaltenes, and increase in saturated hydrocarbon content. Moreover, the content of low-molecular alkanes, which were not detected before the catalytic aquathermolysis process, dramatically increased in saturates fraction after catalytic aquathermolysis reactions. In addition, the aromatics hydrocarbons saturated with high molecular weight polycyclic aromatic compounds—isomers of benzo(a)fluorine, which were initially concentrated in resins and asphaltenes. Nickel sulfide showed a good performance in desulfurization of high-molecular components of extra-heavy oil. The cracking of the weak C–S bonds, which mainly concentrated in resins and asphaltenes, ring-opening reactions, detachment of alkyl substitutes from asphaltenes and inhibition of polymerization reactions in the presence of catalytic complex reduced the average molecular mass of resins (from 871.7 to 523.3 a.m.u.) and asphaltenes (from 1572.7 to 1072.3 a.m.u.). Thus, nickel tallate is a promising catalyst to promote the in-situ upgrading of extra-heavy oil during steam injection techniques.

In-Situ Heavy Oil Aquathermolysis in the Presence of Nanodispersed Catalysts Based on Transition Metals

The aquathermolysis process is widely considered to be one of the most promising approaches of in-situ upgrading of heavy oil. It is well known that introduction of metal ions speeds up the aquathermolysis reactions. There are several types of catalysts such as dispersed (heterogeneous), water-soluble and oil soluble catalysts, among which oil-soluble catalysts are attracting considerable interest in terms of efficiency and industrial scale implementation. However, the rock minerals of reservoir rocks behave like catalysts; their influence is small in contrast to the introduced metal ions. It is believed that catalytic aquathermolysis process initiates with the destruction of C-S bonds, which are very heat-sensitive and behave like a trigger for the following reactions such as ring opening, hydrogenation, reforming, water–gas shift and desulfurization reactions. Hence, the asphaltenes are hydrocracked and the viscosity of heavy oil is reduced significantly. Application of different hydrogen donors in combination with catalysts (catalytic complexes) provides a synergetic effect on viscosity reduction. The use of catalytic complexes in pilot and field tests showed the heavy oil viscosity reduction, increase in the content of light hydrocarbons and decrease in heavy fractions, as well as sulfur content. Hence, the catalytic aquathermolysis process as a distinct process can be applied as a successful method to enhance oil recovery. The objective of this study is to review all previously published lab scale and pilot experimental data, various reaction schemes and field observations on the in-situ catalytic aquathermolysis process.