Oil Interfacial Tension Research Articles

Study on the properties of oil-water interface after the interaction between ionized water and naphthenic acid

The properties of the oil-water interface have a great influence on improving oil recovery. However, there are few studies on the impact of the interaction between ionized water and polar components of crude oil on the properties of the oil-water interface. In this paper, the influence of ionized water and naphthenic acid on the properties of the oil-water interface was investigated by measuring the oil-water interfacial tension, dilational rheological parameters, and interfacial film thickness, and the displacement mechanism of the ionized water flooding system was discussed. The results show that after the action, the interfacial tension of oil and water continues to decrease, and 1/3 ionized water (salinity diluted to 1/3 of the prepared ionized water, 1253 ppm) decreases to a maximum of 50.89%, while 1/5 ionized water (752 ppm) only decreases 14.40%; the thickness of the oil-water interface film decreases with the salinity of ionized water, but the decrease increases after 1/3 ionized water. In addition, the interfacial shear viscosity, interfacial expansion modulus, and interfacial phase angle tangent values all reach the maximum value within 10–15 days and then decrease. The research results of this article will provide a theoretical basis for the application of ionized water in oilfields.

A CO2-Modified Surfactant for Chemical Flooding

Summary Carbon dioxide (CO2) modification of a nonionic surfactant alkyl polyglycoside (C-APG) was conducted based on a commercial APG product under mild synthesis conditions, including a low temperature (50°C) and a low pressure (2.5 bar). Using this method, CO2 was incorporated into APG molecules through the formation of carbonyl structures. The effectiveness and performance of C-APG as a novel surfactant for enhanced oil recovery (EOR) application in carbonate reservoirs were investigated and compared with its precursor—the unmodified APG. The key factors in the chemical structure of C-APG were characterized by Fourier transform infrared spectroscopy (FTIR) to confirm successful CO2 modification. The properties, including compatibility, surface tension, wettability alteration, interfacial tension (IFT), phase behavior, and static and dynamic adsorption of both APG and C-APG, were evaluated by various techniques and methods. Crude oil displacement efficiency of the surfactants was investigated via spontaneous imbibition, visualized micromodel, and coreflooding tests, respectively. Both surfactants were compatible with a high-salinity water (HSW), they exhibited a similar critical micelle concentration (CMC) of 8.5 mg/L and 13.5 mg/L for APG and C-APG, respectively, and had the same contact angle of around 135°. Interestingly, C-APG was found more effective in reducing IFT between oil and water phases. The IFT of oil in the C-APG solution was 0.058 ±0.001 mN/m, one order of magnitude lower than the value of 0.47 ±0.02 mN/m obtained from the solution of original APG, suggesting a better performance of C-APG in chemical flooding for oil displacement. A Winsor Type I microemulsion was formed by APG within the salinity range, while a transition of Type I to Type II microemulsion was observed for C-APG. The static adsorption of APG and C-APG at 2 g/L in carbonate were 0.93 mg/g rock and 1.08 mg/g rock, and the adsorption decreased to 0.11 mg/g rock and 0.13 mg/g rock under dynamic conditions for APG and C-APG, respectively. The spontaneous imbibition test demonstrated a higher oil imbibition recovery of 18.0% from C-APG solution compared to the result of 10.2% obtained from APG solution. A micromodel test showed that more crude oil was displaced by injection of APG or C-APG solution after waterflooding, while C-APG injection exhibited a stronger emulsification. The oil displacement by coreflood test showed that C-APG injection led to a lower differential pressure and a higher cumulative oil production (48%) compared to APG chemical flooding with a cumulative oil production of 41%. The produced fluids containing displaced crude oil from C-APG flooding, and subsequent waterflooding demonstrated very strong emulsification compared to the fluids produced after APG injection. This study demonstrates the significant potential of C-APG in two aspects—CO2 reduction and chemical EOR for the upstream petroleum industry.

A novel hybrid enhanced oil recovery technique to enhance oil production from oil-wet carbonate reservoirs by combining electrical heating with nanofluid flooding

Enhanced Oil Recovery provides a promising technique to maximise fossil fuel recovery from existing resources, and when used in conjunction with Carbon Capture and Storage/Utilisation provides a way to support a transition to alternative cleaner fuels. A hybrid Enhanced Oil Recovery method by a combination of electrical heating and nanofluid flooding was applied to oil-wet carbonate reservoirs and assessed in terms of the oil production, zeta potential, contact angle, pellet compaction, interfacial tension, and pH values. The hybrid technique consisted of a combination of direct current (up to 30 V) and iron oxide (Fe2O3) or magnesium oxide (MgO) nanofluids. Both nanofluids were injected into oil-wet Austin chalk – our laboratory model of an oil-wet carbonate reservoir – and then electrical heating was started, or vice versa. Introducing electrical heating first increased oil recovery by up to 27% in seawater compared to 16% in deionised water. When Fe2O3 nanofluid was injected, oil recovery further increased to 32% in seawater and 24% in deionised water. The contact angle and zeta potential decreased from 124° to 36° and from −24.4 to −23.7 mV, respectively, when nanofluid was injected in seawater, leading to better nanofluid stability and penetration into the carbonate rock as shown by increased pellet porosity from 6.6% to 14.8%. Moreover, it was found that the interfacial tension was reduced from 72 to 32.7 mN/m in the pre-magnetised samples with Fe2O3 NPs injection compared to 33.2 mN/m in the samples with MgO injection. It was found from our experiments that the effect of the generated electricity on the surface charge was of a temporary nature as the zeta potential of the rock returned to its original value as soon as the power was disconnected. The mechanism underlying the hybrid Enhanced Oil Recovery EOR technique from the laboratory findings was found to be based on electrowetting and nanofluid adsorption. Results indicate that the technique is promising for further improving oil recovery and securing energy supply during the transition to net zero.

Visualization and Analysis of Mapping Knowledge Domain of Fluid Flow Related to Microfluidic Chip.

Microfluidic chips are important tools to study the microscopic flow of fluid. To better understand the research clues and development trends related to microfluidic chips, a bibliometric analysis of microfluidic chips was conducted based on 1115 paper records retrieved from the Web of Science Core Collection database. CiteSpace and VOSviewer software were used to analyze the distribution of annual paper quantity, country/region distribution, subject distribution, institution distribution, major source journals distribution, highly cited papers, coauthor cooperation relationship, research knowledge domain, research focuses, and research frontiers, and a knowledge domain map was drawn. The results show that the number of papers published on microfluidic chips increased from 2010 to 2023, among which China, the United States, Iran, Canada, and Japan were the most active countries in this field. The United States was the most influential country. Nanoscience, energy, and chemical industry and multidisciplinary materials science were the main fields of microfluidic chip research. Lab on a Chip, Microfluidics and Nanofluidics, and Journal of Petroleum Science and Engineering were the main sources of papers published. The fabrication of chips, as well as their applications in porous media flow and multiphase flow, is the main knowledge domain of microfluidic chips. Micromodeling, fluid displacement, wettability, and multiphase flow are the research focuses in this field currently. The research frontiers in this field are enhanced oil recovery, interfacial tension, and stability.

The Effect of Crude Oil Stripped by Surfactant Action and Fluid Free Motion Characteristics in Porous Medium.

The surfactant solution is crucial in facilitating the spontaneous imbibition process for the recovery of oil in tight reservoirs. Further investigation is required to examine the fluid flow in porous mediums and the process of crude oil stripping by a surfactant solution during spontaneous imbibition. Hence, this study aims to determine the free motion properties of oil and water in porous mediums using the finite-element approach to solve the multiphase flow differential equation, taking into account the capillary pressure. An investigation was conducted to examine the impact of oil viscosity and interfacial tension on the mean liquid flow rate and oil volume fraction. An experimental study was conducted to investigate the impact of surface tension, interfacial tension, and wetting angle on crude-oil-stripping efficiency. The findings indicate that the stripped crude oil migrated through porous mediums as individual oil droplets, exhibiting a degree of stochasticity in its motion. When the interfacial tension is reduced, the average velocity of the fluid in the system decreases. The crude oil exhibited a low viscosity, high flow capacity, and a high average flow rate within the system. Once the concentration of the surfactant solution surpasses a specific threshold, it binds with the oil to create colloidal aggregates, resulting in the formation of micelles and influencing the efficiency of the stripping process. As the temperature rises, the oil-stripping efficiency also increases. Simultaneously, an optimal range of wetting angle, surface tension, and interfacial tension could enhance the effectiveness of removing oil using surfactant solutions. The research results of this paper enrich the enhanced oil recovery mechanism of surfactant and are of great significance to the development of tight reservoirs.

The Impact of Electromagnetic Waves Propagation to the Dielectric Nanoparticles on Crude Oil Interfacial Tension Reduction for Oil Recovery: A Review

The presence of interfacial tension (IFT) force between crude oil and other fluids in reservoirs is one of the critical parameters that restrict the effective mobility of the oil and is continuously entrapped in reservoir pores. Reducing binding forces between oil and such fluids is one of the methods employed to improve oil productivity known as enhanced oil recovery (EOR). Various nanoparticles (NPs) have been utilized to reduce IFT. However, NPs encountered a challenge in terms of successful operation under a high temperature. Consequently, the NPs tend to segregate at the oil/ water interface which diminishes the IFT influences and more oil continuously entrapped. Recently, an innovative approach to enhance oil mobility was proposed by activating the charges of the NPs via electromagnetic (EM) wave propagation. Few analyses were reported using dielectric NPs with reasonable reductions to IFT. The dielectric properties of NPs are essential attributes corresponding to EM waves. During the EM wave exposure, the extra disruptions were generated at the fluid/oil interface that function as activating agents for the NPs resulting in the additional reduction for IFT. The present study provides a comprehensive review of the few results available, challenges that confronted the success of this novel approach, and admirable recommendations to improve the process in the future.

Potential of nonionic polyether surfactant-assisted CO2 huff-n-puff for enhanced oil recovery and CO2 storage in ultra-low permeability unconventional reservoirs

Sequestering CO2 in oil reservoirs using CO2 huff-n-puff technology while maximizing oil recovery is critical for the efficient development of shale/tight reservoirs. In this work, intrinsic reasons for the limited EOR efficiency of CO2 huff-n-puff technology and the potential of a nonionic polyether surfactant C4(PO)3-assisted CO2 huff-n-puff process in further enhancing oil recovery and increasing CO2 storage capability in shale/tight reservoirs were investigated by physical modeling experiments combined with nuclear magnetic resonance techniques. The EOR performance, the mobilization of oil from different pore size ranges, and CO2 storage capability were analyzed in the CO2 huff-n-puff and CO2–C4(PO)3 mixed fluid huff-n-puff experiments. The results showed that the EOR efficiency of CO2 huff-n-puff was limited by the rapidly declining cyclic recovery and the meager recoveries from micropores and deep matrix regions. Applying CO2–C4(PO)3 mixed fluid with a surfactant concentration of 0.5 wt% resulted in a 9.7%–13.2% increase in the cumulative matrix oil recovery relative to CO2 under the same huff-n-puff cycles. Moreover, relative increases in oil recoveries from micropores, mesopores, and macropores reached 113.4%–142.2%, 14.2%–41.1%, and 0.8%–17.6%, respectively. When CO2 no longer enhanced production after the 4–5 huff-n-puff cycles, approximately 14%–19% of the residual oil was effectively recovered by applying the C4(PO)3-assisted CO2 huff-n-puff stimulation. Simultaneously, the ultimate CO2 storage capability in the examined cores increased by 22.3%–32.2% after the CO2–C4(PO)3 mixed fluid huff-n-puff process. The enhancement of CO2 injection and diffusion capabilities induced by the CO2–C4(PO)3 mixed fluid improved CO2 sweep and oil displacement efficiencies in shale/tight reservoirs, leading to a significant increase in the oil mobilization within micropores and an extended effective stimulation cycle, as well as achieving a higher CO2 storage capability. The increase of CO2 injection and diffusion amounts induced by nonionic polyether surfactants during the huff-n-puff process was attributed to the reduction in capillary resistance caused by the lowered CO2–oil interfacial tension and the increase of dissolved CO2 in oil resulting from the improved CO2–oil miscibility. This paper presents new strategies for advancing the sustainable and efficient development of shale/tight reservoirs with highly developed nanopores.

The impacts of CO2 flooding on crude oil stability and recovery performance

Numerous studies have investigated the fundamental mechanisms by which CO2 flooding can increase oil production by altering the properties of the hydrocarbon fluid, including oil swelling, viscosity and interfacial tension reductions, and the extraction of light-to-intermediate components. However, the interactions between CO2 and hydrocarbon fluid may also cause several problems, such as asphaltene precipitation due to crude oil's instability during the CO2 flooding process. This study investigates the complex factors that affect the instability of crude oil, including CO2 injection pressures, temperatures, and crude oil compositions. The light-dead oil samples taken from two Indonesian oil fields were used. The impacts of the instability of crude oil on CO2 displacement performance were also observed to evaluate oil recovery and minimum miscibility pressure (MMP). The observation was performed using a slim tube under varying CO2 high-pressure injections at 90 °C and 70 °C. The produced oils were analyzed based on their polarity component, saturates, aromatics, resins, and asphaltenes fractions, to observe the changes in oil composition and colloidal index instability. The results showed that increasing temperatures at given pressures resulted in higher oil recovery. Moreover, the asphaltene and resin fractions in the oil produced at a lower temperature significantly decrease compared to those at a higher temperature. It was also shown that asphaltene tends to precipitate more easily at a lower temperature. The other phenomenon revealed that the lighter oil resulted in a lower recovery than the heavier oil at a given pressure and temperature and correspondingly higher MMP. It was also suggested that CO2 flooding is more likely to cause asphaltene precipitation in light oils.

Inhibition of asphaltene deposition by Al2O3 nanoparticles during CO2 injection

Carbon dioxide flooding is of interest due to its high oil-sweep efficiency for enhanced oil recovery and contribution to the reduction of greenhouse gas emissions. However, when CO2 is injected into deep geological strata, asphaltene may precipitate. In this work, the effect of Al2O3 nanoparticles on the deposition of asphaltene was examined by assessing the variations of bond number and interfacial tension at different pressures and a temperature of 60 °C. The asphaltene onset point and intensity were characterized using the bond number, which proved a better indicator of changes in oil droplet shape and interfacial tension with gravity. Synthesized mixtures of toluene and n-heptane that contained two different kinds of asphaltenes were used as M and D oil samples. A 0.06 mass% addition of Al2O3 nanoparticles, which worked best for reduction of interfacial tension, was also applied at various pressures. Addition of nanoparticles to the oils prevented asphaltene precipitation in both synthetic samples by altering the slope of the plot of interfacial tension with pressure by 49.7% for the M sample and 9.0% for the D sample. The Al2O3 nanoparticles were found to be more effective at inhibiting asphaltene precipitation for the M oil sample due to its lower H/C ratio and higher nitrogen content.

Effects of Entrained Slag Droplets on Slag-Metal Interface in A Gas-Stirred Ladle

This study explores the underlying mechanism between secondary refining efficiency, gas flow rate, and slag properties. The secondary refining efficiency is directly affected by the slag-metal interface area. Traditionally, the slag-metal interface has been limited to the liquid-liquid interface of the ladle cross-section and does not include the interface area between the entrained slag droplets and metal. To investigate the interface area with different slags and metals under various bottom blow rates, a physical model of a single-nozzle gas-stirred ladle was established using oil to simulate slag and water to simulate metal. The roles of relevant variables that affect the volume of entrained oil, the diameter of entrained droplets, and interface area were studied, as well as oil viscosity, interfacial tension, and oil thickness. Experimental data were collected using colorants and image processing techniques. Based on these findings, the increase in gas flow rate and oil layer thickness increased the volume of entrained oil and interface area, while the increase in oil viscosity and interfacial tension decreased these parameters. When the gas flow rate increased, the mean diameter of droplets first increased and then decreased. However, the specific surface area of droplets revealed the opposite trend. Furthermore, the mean diameter and specific surface area increased and decreased with increasing oil-layer thickness.

Calculation of IFT in porous media in the presence of different gas and normal alkanes using the modified EoS

Gas injection can increase oil recovery because the gas–oil interfacial tension is less than the water–oil interfacial tension (IFT) and tends to zero in the miscibility state. However, little information has been provided on the gas–oil movement and penetration mechanisms in the fracture system at the porosity scale. The IFT of oil and gas in the porous medium changes and can control oil recovery. In this study, the IFT and the minimum miscibility pressure (MMP) are calculated using the cubic Peng-Robinson equation of state that has been modified using the mean pore radius and capillary pressure. The calculated IFT and MMP change with the pore radius and capillary pressure. To investigate the effect of a porous medium on the IFT during the injection of CH4, CO2, and N2 in the presence of n-alkanes and for validation, measured experimental values in references have been used. According to the results of this paper, changes in IFT vary in terms of pressure in the presence of different gases and, the proposed model has good accuracy for measuring the IFT and the MMP during the injection of hydrocarbon gases and CO2. In addition, as the average radius of the pores gets smaller, the interfacial tension tends to lower values. This effect is different with increasing the mean size of interstice in two different intervals. In the first interval, i.e. the Rp from 10 to 5000 nm, the IFT changes from 3 to 10.78 mN/m and in the second interval, i.e. the Rp from 5000 nm to infinity, the IFT changes from 10.78 to 10.85 mN/m. In other words, increasing the diameter of the porous medium to a certain threshold (i.e. 5000 nm) increases the IFT. As a rule, changes in IFT affected by exposure to a porous medium affect the values of the MMP. In general, IFT decreases in very fine porous media, causing miscibility at lower pressures.

Assessing the effects of CO2/methane mixtures on gas−oil interfacial tension and fluid flow using compositional simulation

Assessing the effects of CO2/methane mixtures on gas−oil interfacial tension and fluid flow using compositional simulation

Techno-economic comparative assessment of the ultrasound, electrostatic and microwave supported coalescence of binary water droplets in crude oil

In this study, comparative assessment of the technical performance, energy usage and economic impact of ultrasound, electrostatics and microwave on the coalescence of binary water droplets in crude oil was conducted. The effect of different oil properties such as crude oil viscosity (10.6–106 mPa s) and interfacial tension (IFT) (20–250 mN/m) on the coalescence time and energy consumption was examined. In addition, operation conditions such as inlet emulsion flow velocity (10–100 mm/s), electric field type, ultrasound frequency and applied voltage amplitude (0–30 kV) were evaluated. The numerical models showed good agreement with experimental findings in the literature. Moreover, the process time of the dewatering process increased with rising inlet flow velocities. The elevation of the coalescence time with velocity can be attributed to the increasing effect of flow disturbance, and the reduction of the emulsion residence time. As regards the IFT, the coalescence time reduced as the IFT was increased. This can be associated with the improved stability of emulsions formed at lowered IFT. As the maximum droplet size is directly proportional to the IFT, lowering the IFT reduces the peak diameter of the droplets that are present in the emulsion. Moreover, the coalescence time followed the order: ultrasound < microwave < electrostatics approaches under varying IFT. The coalescence energy increased from ∼15 J, ∼90 J and ∼25 mJ to ∼61 J, ∼235 J and ∼26 mJ for microwave, electrostatics and ultrasound techniques, respectively, as the viscosity was raised from 10.6 to 106 mPa s. Ultrasound coalescence showed significant energy and economic savings in comparison to microwave and electro-coalescence. Hence, ultrasound coalescence would be a potential method for standalone or integrated demulsification over the two other techniques. However, there are indications that beyond a viscosity of 300 mPa s, the effect of ultrasound becomes weak with significant hindrance to droplet movement and accumulation. This analysis provides fundamental insights on the comparative behavior of the three emulsion separation techniques.

Functionalized silica nanoparticles within a multicomponent oil emulsion by molecular dynamic study

Molecular dynamics simulations were employed to study hydroxylated and functionalized SiO2 nanoparticles (NPs) within a light crude oil under different temperatures. The model oil comprised a combination of aromatics, alkanes, and cycloalkanes, while the hydroxylation, PEGlyation, and sulfonation of the NPs were evaluated. The effects of functional size were considered for PEGlyated NPs. Interestingly, benzene clusters dispersed in the oil phase were formed for all systems studied; clusters of 9 and 11 molecules were the most common. The benzene clusters adsorbed onto the NPs, forming a surrounding shell approximately 10 Å in width. The agglomeration of aromatic molecules was more evident for hydroxylation covering: the density of benzene molecules in the first shell of aromatic molecules surrounding the NPs decreased in the order NP-H, NP-SA, NP-EG, and NP-PEG2 and reached a maximum for hydroxylated NPs, where the hydrocarbons form a first shell of molecules ∼25 Å in width. The density of benzenes is 24% greater than in pristine oil. Compared to other coverings, this effect reduces the NP–oil interfacial tension for the hydroxylated NPs by about 15%. Our results indicated that the adsorption of benzene on NPs and the NPs–oil interfacial tension could be tuned by the NP covering. This degree of control is highly desirable for applications of NPs in enhanced oil recovery processes.

Formation Damage Caused by Wax Deposition Results in Shale Production Decline

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210414, “First Evidence for Shale Production Decline as a Result of Formation Damage Caused by C60+ Paraffin Wax Deposition: A Permian Case Study,” by Amir Mahmoudkhani, SPE, Locus Fermentation Solutions, and Jonathan Rogers and Martin Shumway, SPE, Locus Bio-Energy Solutions, et al. The paper has not been peer reviewed. _ Analysis of production decline curves revealed that three candidate wells in West Texas depleted faster than indicated by a type decline curve, indicating a potentially abnormal permeability-reduction mechanism. A biosurfactant-based squeeze program was recommended and applied in three horizontal wells. The biosurfactant treatment offers an alternative and economical method for remediation of formation damage caused by high‑molecular‑weight paraffin wax deposition in porous media that does not require costly intervention techniques to apply. Introduction The Bone Springs horizontal oil play in the Delaware Basin spans from southeast New Mexico into West Texas. Stacked, multipay reservoirs, each with diverse rock properties, possess upside but also complexity. The initial targets in the play were conventional sandstones. Wells then tapped into carbonate lenses and, ultimately, low-permeability sandstones. As a result of horizontal drilling technology combined with hydraulic fracturing, very thin sands and other facies are now being produced. Generally, reservoir quality of this unconventional hydrocarbon system is controlled by carbonate content, where increased carbonate content typically is associated with lower productivity. Experimental Methods All crude oils exhibited precipitation of organics at ambient laboratory temperatures. Even after storing crudes at the bottomhole temperature of 140°F, a small amount of wax remained insoluble in bulk liquid. Samples of formation drill cuttings were received for various depth intervals between 8,500 and 12,000 ft. X‑ray diffraction analyses of solids revealed quartz as the major mineral phase, with clays and carbonates account for remaining phases. Combined fractions with 160-micron size were used for microcolumn oil-recovery screening tests. Carbon distributions of oils and waxes were performed by high-temperature gas chromatography (HTGC). The Du Noüy ring method was used to measure static surface tensions of biosurfactant solutions at different concentrations and was applied to calculate critical micelle concentrations at ambient temperature. Interfacial tension (IFT) measurements were performed using a drop-shaped tensiometer using the pendant-drop method. Finally, the IFTs of oil in synthetic formation water and in biosurfactant solutions prepared in city tap water were determined. Contact-angle measurements also were performed. The wax-appearance temperature (WAT) of crude and wax samples was determined by the differential scanning calorimetry method. Spontaneous imbibition experiments were performed using the Amott-cell method at reservoir temperature. Berea sandstone core plugs (25×50 mm) with a permeability of 385 md and porosity of 18.4% were used. Core plugs were saturated with homogenized crude oil samples at 140°F for 7 days.

Porous media flooding mechanism of nanoparticle-enhanced emulsification system

This study carried out interfacial tension (IFT) testing, sand surface element analysis and scanning electron microscope imaging, rock–oil–emulsification system interaction testing, and microstructure, droplet size distribution, and stability of oil in water (O/W) emulsion to clarify the porous media flooding mechanism of a hydrophilic nano-SiO2 enhanced emulsification system. The results show that by adding a small amount of nano-SiO2 (0.01 wt. %) into an anionic surfactant fatty alcohol polyoxyethylene ether sodium hydroxypropyl sulfonate (AEOSHS) solution (0.5 wt. %), the IFT of oil–water was effectively reduced, the adsorption loss of AEOSHS on the formation sand surface was reduced by more than 70%, and the droplet size of the formed O/W emulsion was reduced by 50%. This greatly improves the effective concentration of AEOSHS and emulsifies the heavy oil ability in the formation away from the injection well. Moreover, the spreading ability of oil on the core surface is greatly reduced, and the width of the diffusion zone is narrowed. Meanwhile, a very clear dividing line of oil can be seen, which shows that the wettability of the core has changed to water wet. The stability of the formed O/W emulsion was further enhanced, and the coalescence and migration process of the droplet is extremely slow. The oil recovery of the AEOSHS + nano-SiO2 system can effectively increase 21.95% of the original oil in place. Both the sand-packed tube experiment and the microscopic visual oil flooding experiment show that the system can not only expand the swept volume but also improve the oil displacement efficiency, which means that the combined system can significantly improve the oil displacement effect.

Investigation of feasibility of alkali–cosolvent flooding in heavy oil reservoirs

Cold production is a challenge in the case of heavy oil because of its high viscosity and poor fluidity in reservoir conditions. Alkali–cosolvent–polymer flooding is a type of microemulsion flooding with low costs and possible potential for heavy oil reservoirs. However, the addition of polymer may cause problems with injection in the case of highly viscous oil. Hence, in this study the feasibility of alkali–cosolvent (AC) flooding in heavy oil reservoirs was investigated via several groups of experiments. The interfacial tension between various AC formulations and heavy crude oil was measured to select appropriate formulations. Phase behavior tests were performed to determine the most appropriate formulation and conditions for the generation of a microemulsion. Sandpack flooding experiments were carried out to investigate the displacement efficiency of the selected AC formulation. The results showed that the interfacial tension between an AC formulation and heavy oil could be reduced to below 10−3 mN/m but differed greatly between different types of cosolvent. A butanol random polyether series displayed good performance in reducing the water–oil interfacial tension, which made it possible to form a Type III microemulsion in reservoir conditions. According to the results of the phase behavior tests, the optimal salinity for different formulations with four cosolvent concentrations (0.5 wt%, 1 wt%, 2 wt%, and 3 wt%) was 4000, 8000, 14000, and 20000 ppm, respectively. The results of rheological measurements showed that Type III microemulsion had a viscosity that was ten times that of water. The results of sandpack flooding experiments showed that, in comparison with waterflooding, the injection of a certain AC formulation slug could reduce the injection pressure. The pressure gradient during waterflooding and AC flooding was around 870 and 30–57 kPa/m, respectively. With the addition of an AC slug, the displacement efficiency was 30%–50% higher than in the case of waterflooding.

Experimental study of the low salinity water injection process in the presence of scale inhibitor and various nanoparticles

In this work, the process of low salinity water injection (LSWI) into reservoirs at various salt concentrations was simulated in order to study the change in the oil recovery factor during oil production. The simulation results of the recovery factor were compared with the experimental data. The results demonstrated that the simulation data were in good agreement with the experimental results. In addition, the formation damage (rock permeability reduction) in carbonate core samples was evaluated through coreflood experiments during LSWI in the range of salt concentration and temperature of 1500–4000 ppm and 25–100 °C, respectively. In the worst scenario of LSWI, the rock permeability has reached about 83% of the initial value. Our previous correlation was used to predict the formation damage in LSWI. In this case, the R-squared value between predicted and experimental data of rock permeability ratios was more than 0.97. Furthermore, the recovery factor during LSWI was analyzed with and without the use of DTPMP scale inhibitor (diethylenetriamine penta (methylene phosphonic acid)), and various nanoparticles (TiO2, SiO2, Al2O3). The results of the coreflood experiments showed that the use of scale inhibitor provides an increase in the recovery factor by more than 8%. In addition, the highest recovery factor was observed in the presence of SiO2 nanoparticles at 0.05 wt.%. The oil displacement during LSWI in the porous media with SiO2 particles was better than TiO2 and Al2O3. The recovery factor in the presence of SiO2, TiO2, and Al2O3 with DTPMP was 72.2, 62.4, and 59.8%, respectively. Among the studied nanoparticles, the lowest values of the oil viscosity and interfacial tension (IFT) between oil and water were observed when using SiO2. Moreover, the contact angle was increased by increasing the brine concentration. The contact angle with the use of SiO2, TiO2, and Al2O3 at 0.05 wt.% was reduced by 11.2, 10.6, and 9.9%, respectively.

Fluorescent-tagged water with carbon dots derived from phenylenediamine as an equipment-free nanotracer for enhanced oil recovery

Chemical enhanced oil recovery (EOR) through waterflooding is the most commonly used method to improve crude oil displacement and extraction however; the impact of environmental side effects may remain ambiguous. Regarding, flooding tagged water with tracers provides a better understanding of the fate of injected water and the reservoir conditions more than oil recovery. This study's main focus is the proposed carbon dots (CDs) to develop fluorescent-tagged with dual functions as a sensing and an enhancing agent for EOR operations. Different physicochemical and optical properties were obtained for CDs by tuning the surface chemistry of phenylenediamine (PD) isomers and tartaric acid (TA) via the solvothermal method which leads to green, and yellow fluorescent emissions. Size distribution and colloidal and thermal stability of the prepared nanofluids carrying CDs were controlled by atomic force microscope (AFM), transmission electron microscopy (TEM), dynamic light scattering (DLS), zeta potential, and thermogravimetric analysis (TGA). Long-time emission stability in high temperature and salinity such as conditions found in the oil reservoirs was precisely detected by fluorescence spectroscopy and a portable UV cabinet as the on-site detection method to confirm the sensing ability of CDs. While, rheological parameters of nanofluids such as viscosity, wettability alteration, and fluid/crude oil interfacial tension were evaluated to support the potential of CDs as an enhancing agent to sweep crude oil on the carbonate rock reservoirs. The oil displacement mechanism was monitored on the micromodel pattern by recording 27.8 % and 20.5 % displacement factors for the prepared nanofluids carrying 200 ppm CDs.

Enhanced oil recovery with nanofluids based on aluminum oxide and 1-dodecyl-3-methylimidazolium chloride ionic liquid

Surface-active ionic liquids (SAILs) have multiplied the possibilities of surfactant enhanced oil recovery (EOR) methods. Among their multiple promising features, the possibility of functionalization and their stability at harsh conditions should be highlighted for the application. They have been successfully applied to increase oil recovery by improving crucial parameters such as: formulation stability, reduction of water–oil interfacial tension, and wettability. Recently, nanoparticles have attracted attention for EOR applications due to their capacity to modify the properties of rock surfaces. However, to date no research has been conducted on the combination of SAILs with nanoparticles for EOR. In this work, the combination of the SAIL 1-dodecyl-3-methylimidazolium chloride, [C12mim]Cl, with Al2O3 nanoparticles is proposed for EOR. Stable dispersions in brine were achieved, using the polymer polyvinylpyrrolidone (PVP) as a stabilizing agent, and characterized through density and dynamic viscosity measurements. According to stability and interfacial tension studies, a nanofluid consisting of 0.05 wt% [C12mim]Cl, 0.05 wt% Al2O3 and 1.0 wt% PVP, in brine (5.0 wt% NaCl) was proposed for EOR in carbonate reservoirs. The presence of nanoparticles reduced the adsorption of the surfactant-polymer formulation on carbonate rocks and changed the aged rock wettability from oil-wet to water-wet. An additional oil recovery of 10.4 %OOIP was achieved with the surfactant-polymer formulation, in comparison with 14.8 %OOIP obtained with the nanofluid.