Reduction Of Oil-water Interfacial Tension Research Articles

Comparative Assessment of Conventionally and Locally Sourced Surfactants for Enhancing Steam Flooding Techniques for Heavy Oil Recovery in Niger Delta

The recovery of heavy oil reserves presents a significant challenge in the petroleum industry due to its high viscosity and poor mobility characteristics. Steam flooding, as a thermal Enhanced Oil Recovery (EOR) technique, has shown promise in mobilizing heavy oil deposits. However, the limited success of conventional steam flooding in heavy oil reservoirs necessitates innovative approaches. This study explores the utilization of conventional and locally sourced surfactants in surfactant-enhanced steam flooding (SESF) for heavy oil recovery in the Niger Delta region. The study examines the selection, formulation, and injection of surfactants specifically tailored for heavy oil reservoir conditions. Laboratory experiments, core flooding tests, and numerical simulations are conducted to evaluate the impact of surfactants on interfacial tension reduction, wettability alteration, and improved oil mobility in heavy oil reservoirs subjected to steam flooding. The project’s findings demonstrate the significant potential of (SESF) for heavy oil recovery. The synergistic effects of surfactants and steam, including the reduction of oil-water interfacial tension, lead to increased oil production rates, reduced steam consumption, and enhanced sweep efficiency. Furthermore, economic assessments are conducted to evaluate the feasibility of implementing this approach on a field scale, considering both technical and economic aspects. This study not only contributes valuable insights to the field of heavy oil recovery but also underscores the practicality of surfactant-enhanced steam flooding as an environmentally responsible solution for unlocking the vast heavy oil reserves worldwide. The research bridges the gap between laboratory findings and real-world applications, offering a promising path forward for the sustainable development of heavy oil resources.

Sulfonamide Derivatives as Novel Surfactant/Alkaline Flooding Processes for Improving Oil Recovery.

Over time, oil consumption has increased along with a continuous demand for petroleum products that require finding ways to increase hydrocarbon production more economically and effectively. So, enhanced oil recovery technologies are believed to be very promising and will serve as a key to meeting the future energy demand. This paper aims to introduce an innovative method to boost the EOR by using two novel types of surfactants synthesized from sulfonamide derivatives. Types I and II surfactants were analyzed using Fourier transform infrared spectroscopy, and their characterization was further performed using 1H NMR and 13C NMR spectroscopy. Additionally, the evaluation of these surfactants included interfacial tension measurements at concentrations up to 0.9 wt %. The combination of types I and II surfactants with alkaline (NaOH) was also investigated by the measurements of interfacial tension. A series of coreflood and sandpack tests under high-salinity conditions were carried out to assess the effects of a surfactant alone and alkaline-surfactant as a combination on improving oil recovery. The rock wettability was evaluated using relative permeability saturation curves, and the oil displacement efficiency was determined using fractional flow curves. The coreflood results demonstrated that alkaline-surfactant flooding with the chemical formula 0.2 wt % surfactant type II plus 0.5 wt % NaOH achieved a higher oil recovery of 74% OOIP compared to surfactant flooding with the chemical formula 0.5 wt % surfactant type II (64% OOIP) and waterflooding (saline solution with a 35,000 ppm salinity: 48% OOIP). Moreover, the experimental results showed that under both core and sandpack flood conditions, there was a noticeable reduction in oil-water interfacial tension, a change in rock wettability to more water-wet, and higher efficiency of oil displacement when alkaline was added to the surfactant. Based on current research, the alkaline-surfactant formulation is strongly recommended for chemical flooding because of its high efficacy and relatively low cost.

Influence of Henna Extracts on Static and Dynamic Adsorption of Sodium Dodecyl Sulfate and Residual Oil Recovery from Quartz Sand.

The application of surfactant flooding for enhanced oil recovery (EOR) promotes hydrocarbon recovery through reduction of oil-water interfacial tension and alteration of oil-wet rock wettability into the water-wet state. Unfortunately, surfactant depletion in porous media, due to surfactant molecule adsorption and retention, adversely affects oil recovery, thus increasing the cost of the surfactant flooding process. Chemical-based materials are normally used as inhibitors or sacrificial agents to minimize surfactant adsorption, but they are quite expensive and not environmentally friendly. Plant-based materials (henna extracts) are far more sustainable because they are obtained from natural sources. However, there is limited research on the application of henna extracts as inhibitors to reduce dynamic adsorption of the surfactant in porous media and improve oil recovery from such media. Thus, henna extracts were introduced as an eco-friendly and low-cost sacrificial agent for minimizing the static and dynamic adsorption of sodium dodecyl sulfate (SDS) onto quartz sand in this study. Results showed that the extent of surfactant adsorption was inversely proportional to the henna extract concentration, and the adsorption of the henna extract onto the quartz surface was a multilayer adsorption that followed the Freundlich isotherm model. Precisely, the henna extract adsorption on quartz sand is in the range of 3.12-4.48 mg/g (for static adsorption) and 5.49-6.73 mg/g (for dynamic adsorption), whereas the SDS adsorption on quartz sand was obtained as 2.11 and 4.79 mg/g at static and dynamic conditions, respectively. In the presence of 8000 mg/L henna extract, SDS static and dynamic adsorption was significantly reduced by 64 and 82%, respectively. At the same conditions, the residual oil recovery increased by 9.2% over normal surfactant flooding. The study suggests that the use of henna extracts as a sacrificial agent during SDS flooding could result in the reduction of static and dynamic adsorption of surfactant molecules on quartz sand, thus promoting hydrocarbon recovery from sandstone formations.

Temperature/salt tolerance and oil recovery of xanthan gum solution enhanced by surface-modified nanosilicas

Amide- and alkyl-modified nanosilicas (AANPs) were synthesized and introduced into Xanthan gum (XG) solution, aiming to improve the temperature/salt tolerance and oil recovery. The rheological behaviors of XG/AANP hybrid dispersions were systematically studied at different concentrations, temperatures and inorganic salts. At high temperature (75 °C) and high salinity (10,000 mg⋅L−1 NaCl), AANPs increase the apparent viscosity and dynamic modulus of the XG solution, and XG/AANP hybrid dispersion exhibits elastic-dominant properties. The most effective concentrations of XG and AANP interacting with each other are 1750 mg⋅L−1 and 0.74 wt%, respectively. The temperature tolerance of XG solution is not satisfactory, and high temperature further weakens the salt tolerance of XG. However, the AANPs significantly enhance the viscoelasticity the XG solution through hydrogen bonds and hydrophobic effect. Under reservoir conditions, XG/AANP hybrid recovers approximately 18.5% more OOIP (original oil in place) than AANP and 11.3% more OOIP than XG. The enhanced oil recovery mechanism of the XG/AANP hybrid is mainly increasing the sweep coefficient, the contribution from the reduction of oil-water interfacial tension is less.

Synthesis and pore-scale visualization studies of enhanced oil recovery mechanisms of rice straw silica nanoparticles

There is increasing interest in synthesis of silicon dioxide (SiO2) nanoparticles from agricultural biomass waste because the process is cost-efficient and eco-friendly. However, the application of rice straw SiO2 nanoparticles as enhanced oil recovery (EOR) agents have not been examined in detail. Moreover, the pore-scale mechanisms governing the mobilization and displacement of resident oil during rice straw silica nanofluids (RS SNF) flooding is rarely reported in literature. In this study, SiO2 nanoparticles (nanosilica) were synthesized from rice straw and characterized. Oil-water interfacial tension (IFT) and contact angles were measured to assess the performance of RS SNF as EOR agents. Pore-scale visualization experiments were conducted using 2-dimensional micromodel to identify the prevailing EOR mechanisms of RS SNF flooding. Significant reduction in oil-water IFT and contact angles were obtained in presence of RS SNF. These results were comparable to the performance of commercial silica nanofluids, suggesting that RS SNF could be utilized as favourable substitute to commercial SNF. The ideal rice straw nanosilica concentration for achieving optimum residual oil mobilization and microscopic sweep was identified as 0.1 wt% from pore-scale visualization experiments. At similar conditions, the oil retained (oil saturation) within the micromodel was determined by Image J software as 28.51% after 0.05 wt% RS SNF flooding and 23.73% after 0.1 wt% RS SNF flooding. The oil trapped in the micromodel after rice straw nanosilica–SDS and commercial nanosilica–SDS solutions injections were comparable at 19.35% and 18.33% respectively. The displacement efficiency and microscopic sweep was much higher when the synergy of nanoparticles and 0.2 wt% sodium dodecyl sulfate (SDS) solutions were injected into the micromodel due to the lowest oil-water IFT and contact angles achieved by SiO2/SDS solutions. The SiO2/SDS fluid front propagated uniformly and in piston-like movement pattern, suggesting that the impact of viscous force over capillary oil retention forces was significantly higher. During nanofluids flooding, uniform invasion of the displacing fluid was observed at the onset of fluid injection, the nanofluid become thicker whereas the oil become thinner with the advancement of the displacing front. However, fingering of the displacing fluid front was noticed with time, resulting in progression of displacement fronts with dendritic and dispersive patterns.

Spontaneous Imbibition Oil Recovery by Natural Surfactant/Nanofluid: An Experimental and Theoretical Study.

Organic surfactants have been utilized with different nanoparticles in enhanced oil recovery (EOR) operations due to the synergic mechanisms of nanofluid stabilization, wettability alteration, and oil-water interfacial tension reduction. However, investment and environmental issues are the main concerns to make the operation more practical. The present study introduces a natural and cost-effective surfactant named Azarboo for modifying the surface traits of silica nanoparticles for more efficient EOR. Surface-modified nanoparticles were synthesized by conjugating negatively charged Azarboo surfactant on positively charged amino-treated silica nanoparticles. The effect of the hybrid application of the natural surfactant and amine-modified silica nanoparticles was investigated by analysis of wettability alteration. Amine-surfactant-functionalized silica nanoparticles were found to be more effective than typical nanoparticles. Amott cell experiments showed maximum imbibition oil recovery after nine days of treatment with amine-surfactant-modified nanoparticles and fifteen days of treatment with amine-modified nanoparticles. This finding confirmed the superior potential of amine-surfactant-modified silica nanoparticles compared to amine-modified silica nanoparticles. Modeling showed that amine surfactant-treated SiO2 could change wettability from strongly oil-wet to almost strongly water-wet. In the case of amine-treated silica nanoparticles, a strongly water-wet condition was not achieved. Oil displacement experiments confirmed the better performance of amine-surfactant-treated SiO2 nanoparticles compared to amine-treated SiO2 by improving oil recovery by 15%. Overall, a synergistic effect between Azarboo surfactant and amine-modified silica nanoparticles led to wettability alteration and higher oil recovery.

Crude oil-water interface partitioning of polyvinylpyrrolidone-coated silica nanoparticles in low-salinity brine

Nanoparticles are of interest in recent oil production process due to their potential to wettability alteration, but not interfacially active at the crude oil-water interface. Stability loss in brine environment, where nanoparticles tend to aggregate, is another issue for field implementation. Hence, recent challenge is to functionalize nanoparticles that are interfacially active and still stabilized in brine. The current study fabricated and characterized the polyvinylpyrrolidone-coated silica composite nanoparticles for their interfacial activity at the crude oil-water interface. Reduction in oil-water interfacial tension was observed and more dramatic with increasing particle concentration, confirming particle adsorption performance. In low-salinity brine (2000 ppm NaCl), the composite particles remained stabilized with weakened electrostatic force between particle and crude oil surfaces, while their size was smaller due to polymer shell dehydration. These led to faster diffusion rate than in Milli-Q water, which affected the rate of change in oil-water/brine interfacial tension, with the early-stage adsorption being a diffusion-controlled in both fluids. At equivalent particle concentration, the oil-water interfacial tensions in brine were lower than those of Milli-Q water (by ∼2 mN/m), with interfacial coverage of the particles at the interface was found to be higher in the brine. Such difference is attributed to a weaker repulsive force between particle and the interface, induced by surface charge screening that is only present in brine. The study has demonstrated the potential use of polymer-coated nanoparticles as suitable additives for use in oil recovery, which can be used concurrently with low-salinity brine as a combined fluid. While both chemicals are known to construct disjoining pressure for wettability alteration, advantage of using interfacially active nanoparticles is additional mechanism to enhance oil recovery, i.e. reducing the oil-water interfacial tension, which unfunctionalized particles could not contribute.

Shale core wettability alteration, foam and emulsion stabilization by surfactant: Impact of surfactant concentration, rock surface roughness and nanoparticles

Hexadecyltrimethyl ammonium bromide (HCTAB) and sodium dodecyl sulfate (SDS) are popular conventional surfactants with versatile industrial and oilfield applications. Knowledge of the optimum conditions for their applications for shale rock wettability modification, as well as foam and emulsion stabilization is relevant for hydrocarbon recovery process optimization. Influence of surfactant concentration, rock surface roughness and presence of nanoparticles in surfactant solutions on contact angles, oil-water interfacial tension (IFT), as well as foam and emulsion stabilization by HCTAB and SDS was investigated in this study. The interfacial properties measurements were conducted with Drop Shape Analyser (DSA 25), whereas the foam generation and stability properties were investigated via dynamic foam analyzer (DFA100). The emulsion stabilization and demulsification processes were investigated in Formulaction Turbiscan. Results showed an existence of optimum concentration of surfactant for obtaining the lowest contact angles, oil-water IFT reduction, as well as attaining maximum foam stability. The contact angle measured on rough core surfaces were smaller than the contact angle measured on smooth surfaces. Contact angles increased with increasing salnity concentration, but decreased with the increasing rock saturation time. Oil was more detrimental to foam stability when the generated foam was brought into contact with the resident oil, compared to when oil was added to the foaming solutions before foam generation. Lower contact angles, durable foam, and stable emulsion were produced in presence of oil and at high temperature via the synergy of nanoparticles and surfactants. Almost 66% decreased in contact angle was achieved with carbon nanotubes-SDS solutions, whereas Al 2 O 3 nanoparticles-HCTAB foam attained a viscosity of 99 mPa-s at 60 °C. The foam demonstrated shear thinning Newtonian fluids behaviors but attained a plateau after sometimes. The study suggests the conditions for optimization of conventional surfactants applications in conventional and unconventional reservoir. • Synergy of nanoparticles and surfactants on shale core wettability was studied. • Foams are less stable when they suddenly contacts the resident oil. • There is optimum surfactant concentration for maximizing interfacial activities. • Contact angle decreased by 66% in presence of carbon nanotubes-SDS solutions. • Al 2 O 3 -HCTAB foam attained a viscosity of 99 mPa-s at 60 °C.

Investigating the impact of a walnut-extracted surfactant on oil-water interfacial tension reduction and wettability alteration in carbonate rocks

ABSTRACT Various types of Enhanced Oil Recovery (EOR) methods have generally been used to recover the residual oil left in the pores after secondary recovery processes. Surfactant flooding has been in use for quite a long time and has shown to be an efficient chemical EOR method. However, chemical surfactants usually result in a high cost and unfavorable environmental impacts. On the other hand, natural surfactants can be a good and promising alternative to the use of conventional surfactants. This paper introduces a newly extracted surfactant from the leaves of a walnut tree and was named UKHS. The ultimate aim of this paper is to experimentally study the applicability of the walnut extracted surfactant in lowering interfacial tension (IFT) and altering wettability in the carbonate rock of the Kurdistan Region at a reservoir temperature of 80°C.In contrast to most other studies, we have used a synthesized reservoir brine, as the aqueous phase, and a light crude oil sample (from an oil reservoir in the Kurdistan Region), during the IFT measurements. Moreover, carbonate samples of Pilaspi formation in the Kurdistan Region were employed with the crude oil sample to measure the contact angles to determine the wettability.The results show that the UKHS solution at a CMC of only1 weight% has significantly lowered the contact angle from a strongly oil-wet state of nearly 165⁰ to a fairly water-wet state of 56.7⁰. On the other hand, the IFT reduction was trivial as it has reduced from solely 11.18 mN/m to 2.54 mN/m. The obtained results of the wettability alteration at a low CMC of 1 wt% witness the higher efficiency of UKHS in comparison to other natural surfactants. Thus, UKHS can be considered as a promising EOR agent to mobilize the residual oil within pores, mainly via the wettability alteration mechanism, whereas the contribution from the IFT reduction is rather small.

Comparative effect of zirconium oxide (ZrO2) and silicon dioxide (SiO2) nanoparticles on the adsorption properties of surfactant-rock system: Equilibrium and thermodynamic analysis

Recently, application of mixed system of zirconium oxide (ZrO 2 ) nanoparticles and surfactants for improving hydrocarbon recovery through oil-water interfacial tension reduction and rock-surface wettability modification has received significant attention. However, application of ZrO 2 nanoparticles for minimizing the adsorption and loss of surfactant molecules onto rock surfaces is yet to be thought-out. In this research, influence of ZrO 2 nanoparticles on the static adsorption of Triton X-100 (TX-100) and sodium dodecylbenzenesulfonate (SDBS) onto the surface of an adsorbent, with significant presence of positive and negative charges, was investigated through UV–Vis spectrophotometry method at different temperature. Adsorption behaviors were characterized via equilibrium and thermodynamic analysis. Adsorbent and adsorbate characterizations were conducted through Energy-dispersive X-ray spectroscopy (EDX) analysis, field emission scanning electron microscopy (FESEM) visualization, Fourier transform infrared spectroscopy (FTIR), X-ray diffraction (XRD) and electrokinetic study. The effectiveness of ZrO 2 nanoparticles in reducing surfactant adsorption was then compared with the performance of SiO 2 nanoparticles. The adsorption isotherm data analysis demonstrated that the highest values of correlation coefficient (R 2 ) and least error values were obtained using Langmuir isotherm model. Results showed that equilibrium adsorption of ZrO 2 -surfactant and SiO 2 -surfactant solutions onto the adsorbent surface is best fitted with the Langmuir model, suggesting the feasibility of monolayer coverage of nanoparticles-surfactants solutions onto the rock surfaces. The amount of surfactant adsorbed reduced in presence of nanoparticles and at elevated temperature. The ZrO 2 nanoparticles demonstrated significantly high capacity to decrease the extent of surfactant adsorption onto the adsorbent surface more than nanosilica. Precisely, at 303 K, the maximum adsorption capacity of TX100 considerably reduced from 2.216 mg/g to 1.250 mg/g (43.59%) and 0.767 mg/g (65.39%) in presence of SiO 2 and ZrO 2 nanoparticles. Likewise, the SDBS optimum adsorption capacity decreased from 0.466 to 0.316 mg/g (32.19%) and 0.048 mg/g (89.70%) in presence of SiO 2 and ZrO 2 nanoparticles respectively at 333 K. The study suggests that ZrO 2 nanoparticles are more promising nanomaterials for reducing the adsorption of surfactant onto rock surfaces, due to electrostatic repulsion between charged nano-surfactant complex and rock charged sites, as well as higher competition for the surfactant molecules. • Impact of ZrO 2 nanoparticles on surfactant adsorption behaviors onto rock surfaces was studied. • Performance of ZrO 2 nanoparticles was compared with SiO 2 nanoparticles. • Equilibrium adsorption of ZrO 2 -surfactant solutions was best fitted with the Langmuir model. • ZrO 2 nanoparticles are more effective for reducing adsorption process compared to nanosilica. • Higher absolute value of zeta potential and smaller nanoaggregates was formed by ZrO 2 particles.

Effects of synthesized nanoparticles and Henna-Tragacanth solutions on oil/water interfacial tension: Nanofluids stability considerations

Rising global energy demand has encouraged engineers to create and design new methods to improve oil recovery from reservoirs. In this study, feasibility of using Henna extract as a natural surfactant and synthesized nanoparticles (Titanium dioxide (TiO2), Silicon dioxide (SiO2), Graphene and composite of TiO2-Graphene) for reduction of oil-water interfacial tension has been experimentally investigated. Nanoparticles were synthesized via sol-gel method and XRD, FESEM, EDAX and FTIR tests were conducted to confirm the authenticity of this synthesizing materials. Nano-surfactants were stabled with a natural water-based suspending surfactant called Tragacanth extract, which could be introduced as a practical substitute for industrial nanoparticles' stabilizers in oil industry. After CMC determination of Henna extract surfactant, the optimal concentration of Tragacanth extract surfactant, with the purpose of nano-surfactants’ stabilization, was determined through particle size and zeta potential tests. Results of interfacial tension (IFT) measurements showed that the increase of Henna extract concentration from 0 wt% to 10 wt% reduced IFT between kerosene and water from 37.23 to 15.24 mN/m. Furthermore, adding 1 wt% of synthesized TiO2 nanoparticle to the Henna extract surfactant at its CMC value reduced IFT from 18.43 to 14.57 mN/m. As an impact of this significant reduction in IFT value, oil recovery factor could be improved drastically during EOR operations. Results proved that TiO2 nano-surfactant was as effective as industrial surfactants, which put human's and environment's health at risk and impose heavy economic strain on governments.

Synergistic influence of nanoparticles and surfactants on interfacial tension reduction, wettability alteration and stabilization of oil-in-water emulsion

In this study, the synergistic interaction of nanoparticles and surfactants were explored for oil-water interfacial tension (IFT) reduction, alteration of rock wettability, and stabilization of oil-in-water emulsion. The interfacial properties were investigated using drop-shape analyzer (DSA 25) while the pore scale visualization studies were conducted using the etched glass micromodels. The most stable surfactant-stabilized emulsion was formed in presence of cetyltrimethylammonium bromide (CTAB) while the order of increasing emulsion stability in presence of nanoparticles was obtained as follows: carbon nanotubes >copper oxide> silicon dioxide> aluminum oxide > titanium dioxide. Compared to pure nanofluids or surfactant solutions, the nanoparticles-surfactant solutions demonstrated promising tendency for significant reduction in oil-water interfacial tension and alteration of rock wetting properties. Specifically, the carbon nanotubes (CN) based nanofluids, reduced the contact angle of the rock from 68.73° to 65.5° (4.7%) while the Triton X-100 (TX 100) and CN-TX100 solutions reduced the contact angles to 10.65° (84.5%) and 7.0° (89.8%) respectively. The dominant mechanism of resident oil mobilization from the micro and dead-end pores was identified as emulsification-entrainment. A correlation exists between influence of nanoparticles-surfactant solutions on interfacial properties and resident oil mobilization from the micro and dead-end pores. The CN-CTAB solution that was the most effective in mobilization of the resident oil from the micro and dead-end pores significantly reduced the crude oil-water IFT to 0.63 mN/m. The mechanisms of IFT reduction, wetting properties alteration, as well as emulsion stabilization have been identified as the orientation of the particles at the interface and the electrostatic interaction between the nanoparticles and surfactant molecules. These procedures could be exploited to achieve significant reduction in IFT, rock wettability alteration and emulsion stabilization than could be achieved using pure nanofluids or surfactant solutions only.

The Potential Application of MnZn Ferrite Nanofluids for Wettability Alteration and Oil-Water Interfacial Tension Reduction

Recently, a non-invasive method of injecting magnetic/dielectric nanofluids into the oil reservoir was used for oil recovery application. The use of magnetic nanofluids in Enhanced Oil Recovery (EOR) has been reported to improve oil recovery. It is believed that the magnetic properties of nanoparticles (NPs) have a direct influence on the viscosity and wettability of nanofluid, and on oil-water interfacial tension (IFT). Thus, Mn0.5Zn0.5Fe2O4 (MnZn) ferrites may be a good candidate to be used in nanofluids for wettability alteration and oil-water IFT reduction due to their excellent magnetic properties, such as a high initial permeability and low magnetic losses. Therefore, this work investigated the potential of MnZn ferrite NPs to alter viscosity, wettability, and oil-water IFT. MnZn Ferrite NPs have been synthesized by a sol-gel auto-combustion process. The effects of calcination temperature varying from 300 °C to 700 °C on the phase formation, microstructures such as surface morphology, and magnetic characterizations were studied. MnZn ferrite nanofluids were prepared using synthesized MnZn NPs that dispersed into brine along with sodium dodecylbenzenesulfonate (SDBS) as a dispersant, and their effects on the wettability and oil-water IFT were studied. X-ray diffraction (XRD) measurements revealed that MnZn ferrite calcined at 300 °C and 400 °C were single phase. The average crystallite size calculated through Scherrer’s equation differed from 32.0 to 87.96 nm. The results showed that the nanofluid with MnZn particles calcined at 300 °C is the best nanofluid in terms of IFT reduction and base nanofluid’s wettability alteration. Moreover, the overall results proved that nanofluid with MnZn ferrite NPs can alter the wettability of base nanofluid, oil-nanofluid IFT, and nanofluid viscosity. This study provides insights towards a better understanding of the potential application of MnZn Ferrite nanofluids to Wettability Alteration and IFT Reduction in Enhanced Oil Recovery.

High-pressure homogenization treatment to recover bioactive compounds from tomato peels

By-products of tomato processing are rich in bioactive compounds and their recovery might bring significant economic and environmental benefits. High-pressure homogenization (HPH) (1–10 passes at 100 MPa) was used as a disruption method to recover valuable compounds from tomato peels, using solely water as process medium. Micronization of tomato peels suspensions by HPH reduced their size distribution below the visual detection limit, because of the complete disruption of individual plant cells. With respect to high-shear mixing (5 min at 20000 rpm), HPH processing (10 passes) caused an increased release of intracellular compounds, such as proteins (+70.5%), and polyphenols (+32.2%) with a corresponding increase in antioxidant activity (+23.3%) and reduction in oil-water interfacial tension (−15.0%). Remarkably, also the release of water-insoluble lycopene in the aqueous supernatant increased, enabling the recovery of up to 56.1% of the initial peel content, well above what reported in the literature when using organic solvents or supercritical CO2.

Combination of a new natural surfactant and smart water injection for enhanced oil recovery in carbonate rock: Synergic impacts of active ions and natural surfactant concentration

By increasing oil demand in carbonate reservoirs, enhanced oil recovery techniques play key role in improving oil production. Surfactant flooding and smart water injection are already well known as effective enhanced oil recovery techniques that increase oil recovery by reduction of oil-water interfacial tension and the alteration of rock wettability. In this work, a new plant-base natural surfactant, named Tribulus Terrestris is introduced and combined with smart water samples (i.e. synthetic seawater with different concentrations of active Ca2+, Mg2+ and SO42− ions) to determine their individual and integrated effects on reduction in interfacial tension, wettability alteration and oil recovery in carbonate rock samples.It was observed that increasing concentrations of SO42− up to 2.5 times resulted in maximum wettability restoration among active ions (by changing contact angle from 145.9° to 54.4°). Experimental results also showed that the effect of the concentration of active ions on wettability alteration was more significant compared to their effect on decreasing oil-water interfacial tension. In addition, the Tribulus Terrestris surfactant reduced oil-water interfacial tension considerably (from 45.3 mN/m to 13.5 mN/m at Critical Micelle Concentration of 0.3 wt %); hence, it was used as smart water modifier to integrate effects of wettability alteration (by smart water) and reduction in interfacial tension (by new natural surfactant). Core flooding experiments demonstrated increased oil recovery from 45.2% for distilled water injection up to 64% and 72% for smart water and combined smart water-surfactant respectively.

Interfacial Tension and Viscosity Alteration of Samarium Doped Yttrium Iron Garnet (YIG) Nanofluid under the Presence of Electromagnetic Waves

A study is presented which implies the knowledge of rare earth magnetic anisotropy, nanotechnologies with the advancement of electromagnetic (EM) waves to induce alteration on oil-nanofluid interfacial tension (IFT) and nanofluid viscosity. The study had been done by doping of Samarium rare earth into Yttrium Iron Garnet (YIG) nanoparticles to improve the magnetic properties of the YIG nanoparticles. The doping process has been done by sol-gel method at 1000oC and at the pH of 7. Samarium rare earth was doped into YIG nanoparticles at different composition (x = 0.00, 0.25, 0.50, 0.75, 1.00). The results show that a Samarium doping composition at x =1.00 at pH 7 resulted in the highest nanofluid wettability, highest magnetic saturation, highest reduction in oil-water interfacial tension (IFT), and the highest alteration in viscosity. Moreover, overall of the experiment proved that when EM wave applied to the Samarium doped YIG nanofluid it had resulted in the increment of viscosity, more reduction in oil-water IFT. The experiment proved that Samarium doping into YIG nanoparticles/nanofluid (Sm-YIG) under the presence of electromagnetic waves are theoretically correct to alter oil-nanofluid IFT and nanofluid viscosity. This can be seen from the ability of Sm-YIG under the presence of EM waves effect on oil-water IFT reduction, nanofluid viscosity increment, reduction in oil-water mobility ratio and nanoparticles magnetic saturation increment.

Development of surface treated nanosilica for wettability alteration and interfacial tension reduction

ABSTRACTThe present study examines and compares the effect of surface treatments of nano-silica using internal olefins sulphonates (IOS20–24 and IOS19–23), anionic surfactants. The effect of surface modification on colloidal stability, wettability alteration and oil-water interfacial tension reduction were analyzed. Silica nanoparticles were characterized using Field Emission Scanning Electron Microscope (FESEM) and integrated energy-dispersive X-ray spectroscopy (EDX) before and after surface treatment. Using Turbiscan classic, the optimal nanosilica concentration and inspection of the coated particles dispersion stability with the help of light transmission behavior through the nanofluid was carried out. The stability was found to be enhanced as the mean light transmission declined only after surfactant treatment in both IOS coated nano-silicas but IOS19–23 O-342 coated dispersions proved to be more stable among all three. RAME-HART Goniometer was used to perform interfacial tension (IFT) and contact angle measurements. IFT was found to be reduced by 48% after the surfactant treatment in case of IOS19–23 O-342 coated nanosilica. Both surface treatments of nanosilica and increasing silica concentration caused significant reduction and altering wettability towards more water wet. The results revealed that IOS coatings improved the efficiency of NPs dispersion in terms of altered wettability and reduced IFT that mimics their potential for EOR applications.

Toward mechanistic understanding of natural surfactant flooding in enhanced oil recovery processes: The role of salinity, surfactant concentration and rock type

Surfactant flooding has emerged as an interesting enhanced oil recovery (EOR) process due to wettability alteration and reduction of oil-water interfacial tension (IFT). Environmental concerns and high cost, cause synthetic surfactant flooding to become expensive and uneconomical in some circumstances. Natural surfactants are environment-friendly and less expensive than synthetic surfactants which recently have been proposed as alternatives for synthetic surfactants in EOR processes. However, the exact mechanism behind natural surfactant flooding as EOR process is an unsettled and complex issue that has not been completely understood. In this communication, the use of natural surfactants as an alternative for synthetic surfactants for wettability alteration of oil-wet rocks in EOR processes was investigated. Through the wide range of experiments, the performance of a natural surfactant named Cedar in the wettability alteration of carbonate and sandstone rocks was deeply studied. Moreover the effect of natural surfactant on oil-water interfacial tension was compared with common used synthetic surfactants. The results showed that Cedar is very efficient in wettability alteration of both carbonate and sandstone rocks and its effect is comparable with common used synthetic surfactants. In addition, it was found that the cationic surfactant is more effective than anionic surfactants in wettability alteration of carbonate reservoirs. On the other hand, the anionic surfactants are very effective in sandstone rocks. In addition, two distinct trends were observed for wettability alteration of surfactants at different salt concentrations. When the head of surfactant and rock surface carries the same charge, there is an optimum salinity for wettability alteration. Finally, the core flooding experiments demonstrated that natural surfactant can increase oil recovery efficiently.

Microbial enhanced oil recovery—a modeling study of the potential of spore-forming bacteria

Microbial enhanced oil recovery (MEOR) utilizes microbes for enhancing the recovery by several mechanisms, among which the most studied are the following: (1) reduction of oil-water interfacial tension (IFT) by the produced biosurfactant and (2) selective plugging by microbes and metabolic products. One of the ways of bacterial survival and propagation under harsh reservoir conditions is formation of spores. A model has been developed that accounts for bacterial growth, substrate consumption, surfactant production, attachment/filtering out, sporulation, and reactivation. Application of spore-forming bacteria is an advantageous novelty of the present approach. The mathematical setup is a set of 1D transport equations involving reactions and attachment. Characteristic sigmoidal curves are used to describe sporulation and reactivation in response to substrate concentrations. The role of surfactant is modification of the relative permeabilities by decreasing the interfacial tension. Attachment of bacteria reduces the pore space available for flow, i.e., the effective porosity and permeability. Clogging of specific areas may occur. An extensive study of the MEOR on the basis of the developed model has resulted in the following conclusions. In order to obtain sufficient local concentrations of surfactant, substantial amounts of substrate should be supplied; however, massive growth of bacteria increases the risk for clogging at the well inlet areas, causing injectivity loss. In such areas, starvation may cause sporulation, reducing the risk of clogging. Substrate released during sporulation can be utilized by attached vegetative bacteria and they will continue growing and producing surfactant, which prolongs the effect of the injected substrate. The simulation scenarios show that application of the spore-forming bacteria gives a higher total production of surfactant and the reduced risk of clogging, leading to an increased period of production and a higher oil recovery.

Experimental study of surface-modified silica nanoparticles in enhancing oil recovery

One of the main objectives of nanotechnology in the oil industry is to identify applications that could bring significant benefits to enhanced oil recovery. Therefore, it has attracted the attention of many researchers over the last decade. This paper experimentally investigates the efficiency of surface-modified silica nanoparticles in enhanced oil recovery. These nanoparticles improve oil recovery through two main mechanisms: oil–water interfacial tension reduction; and wettability alteration. Various concentrations of nanofluid were made, and their effect on wettability and interfacial tension were investigated to determine the optimum concentration for injection into core samples. The results indicate that a concentration of 4 g l −1 is the optimum concentration. Moreover, this paper reports the nanofluids’ potential in enhanced oil recovery of water-wet core plugs. The results of coreflood experiments reveal that oil recovery increases by 26.2% and total oil recovery considerably improves after the injection of nanofluid. In addition, filtration of the nanofluid before injection into the core was very effective in reducing the risk of possible permeability damage that occurred due to the deposition of large nanoparticle aggregates onto the rock surface.