CO2 foam properties and the stabilizing mechanism of sodium bis(2-ethylhexyl)sulfosuccinate and hydrophobic nanoparticle mixtures

Study on Formation and Migration Law of Foam in Fractures and Its Influencing Factors

This study focuses on the characteristics of foam generation, flow, and plugging in different reservoir fracture environments. Through visual physical model experiments and stone core displacement experiments, we analyze the flow regeneration of foam in a simulated reservoir fracture environment as well as its sealing and sweeping mechanisms. The findings reveal that low permeability reservoirs, with their smaller and more intricate fracture structures, are conducive to the generation of high-strength foam. This is due to the stronger shear effect of these fracture structures on the injected surfactant and gas mixture system, resulting in a denser foam system. Consequently, low permeability reservoirs facilitate a series of mechanisms that enhance the fluid sweep efficiency. Furthermore, the experiments demonstrate that higher reservoir fracture roughness intensifies the shear disturbance effect on the injected fluid. This disturbance aids in foam regeneration, increases the flow resistance of the foam, and helps to plug high permeability channels. As a result, the foam optimizes the injection-production profile and improves the fluid sweep efficiency. Stone core displacement experiments further illustrate that during foam flooding, the foam liquid film encapsulates the gas phase, thereby obstructing fluid channeling through the Jamin effect. This forces the subsequently injected fluid into other low-permeability fractures, overcoming the shielding effect of high-permeability fractures on low-permeability fractures. Consequently, this improves the fluid diversion rate of low permeability fractures, effectively inhibiting fluid cross-flow and enhancing sweep efficiency. These experimental results highlight the advantages of foam flooding in the development of complex reservoirs with low permeability fracture structures, demonstrating its efficacy in inhibiting fluid cross-flow and optimizing the injection-production profile.

Maximizing oil recovery: Innovative chemical EOR solutions for residual oil mobilization in Kazakhstan's waterflooded sandstone oilfield

The results of an experimental study to design a chemical flood scheme for a massive Kazakhstani oilfield with high water cut are presented in this paper. A meticulously formulated chemical flooding procedure entails injecting a blend comprising interfacial tension (IFT) reducing agents, alkaline/nanoparticles to control chemical adsorption, and polymer to facilitate mobility control. Overall, this well-conceived approach leads to a significant enhancement in the mobilization and production of residual oil. Experiments were conducted in Kazakhstan's Field A, one of the country's oldest oilfields with over 90% water cut and substantial remaining oil, to assess the efficiency of various hydrolyzed polyacrylamide (HPAM) derived polymers and surfactant solutions. Additionally, the effectiveness of alkaline and nanoparticles in minimizing chemical adsorption for the screened surfactant and polymer was investigated. These assessments were conducted under reservoir conditions, with a temperature of 63 °C, and using 13,000 ppm Caspian seawater as makeup brine. The performance assessment of the selected chemicals was carried out through a set of oil displacement tests on reservoir cores. Critical parameters, including chemical adsorption, interfacial tension, resistance factor, and oil recovery factor, were compared to determine the most effective chemical flooding approach for Field A. Both the surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) approaches were more successful in recovering residual oil by efficiently generating and delivering microemulsion, producing more than 90% of the remaining oil after waterflooding. Due to the low increase in recovery compared to SP and the complexity of applying ASP at the field scale, SP was recommended for the pilot test studies. This investigation underscores that the choice of chemicals is contingent upon the interplay between the specific characteristics of the oil, the geological formation, the injection water, and the reservoir rock. Consequently, assessing all potential configurations on reservoir cores is imperative to identify the most optimal chemical combination. The practical challenges at the field scale should also be considered for the final decision. The results of this study contribute to the successful design and implementation of tailored chemical flooding to challenging oilfields with excessive water cut and high residual oil.

Advances of polymer microspheres and its applications for enhanced oil recovery

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

Rheological Properties of Gel Foam Co-Stabilized with Nanoparticles, Xanthan Gum, and Multiple Surfactants

Gel foam has the advantages of gel and foam and shows good prospects for applications in the fields of fire prevention and extinguishing. Rheology has a significant impact on the application of gel foam, but there is little related research. In the present study, hydrophilic silica nanoparticles (NPs) and water-soluble polymer xanthan gum (XG) were combined with fluorocarbon surfactant (FS-50) and hydrocarbon surfactant (APG0810) to create gel foam. The foaming ability and foam drainage were evaluated. The gel foam's rheology, including its flow behavior and viscoelasticity, was systematically investigated. The results show that the foaming of the FS-50/APG0810 mixture decreases but the foam drainage increases in the presence of NPs and/or XG. All of the foams belong to the category of non-Newtonian fluids with shear thinning behavior. The flow curves of the foams are consistent with the Cross model. The presence of XG/NPs enhanced the foam viscoelasticity of the FS-50/APG0810 mixture. The silica NPs showed a better ability to enhance foam viscoelasticity but a worse ability to stabilize the foam compared to XG. This research can offer theoretical support for the industrial usage of gel foam.

On the mechanism of enhanced foam stability by combining carboxylated cellulose nanofiber with hydrocarbon and fluorocarbon surfactants

The effect of carboxylated cellulose nanofiber (CCNF) on the firefighting foam stability and stabilization mechanism is investigated. The results show that equilibrium surface tension of CTAB/FC1157 solution decreases when CCNF concentration increases to 0.5 wt%, while CCNF has little effect on that of SDS/FC1157 solution. Besides, when CCNF concentration of SDS/FC1157 solution increases to 1.0 wt%, the foam initial drainage is delayed for about 3 min. Increasing CCNF concentration can slow down foam coarsening process and liquid drainage process of SDS/FC1157 and CTAB/FC1157 solutions, improving the foam stability. The foam stability enhancement of CTAB/FC1157 solution is due to the formation of bulk aggregates and the increase of viscosity. However, the foam stability enhancement of SDS/FC1157 solution may be caused by the increase of viscosity. CCNF significantly reduces the foaming ability of CTAB/FC1157 solution when CCNF concentration is >0.5 wt%. Nevertheless, the foaming ability of SDS/FC1157 solution decreases significantly when CCNF concentration reaches 3.0 wt%, and its foaming ability remains higher than CTAB/FC1157 solution. The foaming ability of SDS/FC1157 solution is mainly dominated by viscosity, while that of CTAB/FC1157 solution is dominated by viscosity and adsorption kinetics. Adding CCNF is expected to enhance the stability of firefighting foam and increase the efficiency of extinguishing fire.

Applications of functional nanoparticle-stabilized surfactant foam in petroleum-contaminated soil remediation

Surfactant foam (SF) can be used to remediate petroleum-contaminated soil because of its easy transfer to inhomogeneous and low-permeability formations. Nanoparticles (NPs) not only stabilize SF under extreme conditions but also impart various functions, aiding the removal of petroleum contaminants. This review discusses the stabilization mechanisms of nanoparticle-stabilized SF (NP-SF) as well as the effects of NP size, chargeability, wettability, and NP-to-surfactant ratio on foam stability. SF stabilized by inert SiO₂ NPs is most commonly used to remediate soil contaminated with crude oil and diesel. Low dose of SF stabilized by nano zero-valent iron is cost-effective for treating soil contaminated with chlorinated organics and heavy metal ions. The efficiency and recyclability of Al₂O₃/Fe₃O₄ NPs in the remediation of diesel and crude oil contamination could be enhanced by applying a magnetic field. This review provides a theoretical basis and practical guidelines for developing functional NP-SF to improve the remediation of petroleum-contaminated soils. Future research should focus on the structural design of photocatalytic NPs and the application of catalytic NP-SF in soil remediation.

The interfacial and assembly properties of in situ producing silica nanoparticle at oil-water interface

In multiphase materials, structured fluid-fluid interfaces can provide mechanical resistance against destabilization, applicable for conformance control, Pickering emulsion, liquid 3D printing and molding, etc. Currently all research prepare the particle-ladened fluid-fluid interfaces by dispersing ex situ acquired particles to the immiscible interface, which limits their application in the harsh environment, such as oil reservoir which can impair particle stability and transport ability. Here, we investigated the interfacial and assembly properties of the interface where SiO2 nanoparticles (NPs) were in situ produced. The experimental results show that ammonia as catalyst could accelerate the processes of silica NPs formation as well as the interfacial tension (IFT) evolution. High temperature could not accelerate the reaction processes to achieve the lowest equilibrium IFT, but it induced the sine-wave IFT evolution curves regardless of the presence of ammonia. The equilibrium IFTs corresponded to the saturation states of interfaces trapping with SiO2 NPs, while the sine-wave fluctuating patterns of IFT were attributed to the alternating transition between interfacial jammed and unjammed states changing along with the reaction process. Silica NPs diffusing into aqueous phase with high salinity also showed good stability, due to the abundant surface decoration with in situ anchored organic species.

Experimental Investigation of Supercritical CO2-Rock-Water Interactions in a Tight Formation with the Pore Scale during CO2-EOR and Sequestration

In recent years, gas injection, especially CO₂ injection, has been acknowledged as a promising approach for enhanced oil recovery (EOR) and CO₂ capture and storage (CCS), especially for tight reservoirs. However, when CO₂ is injected into the oil reservoirs, it can disturb the equilibrium of the system and lead to chemical reactions between CO₂, formation water, and reservoir rocks. The reactions will alter some geochemical and physicochemical characteristics of the target reservoirs. However, the reactions still lack quantitative characterization at the pore scale, especially under reservoir conditions. Herein, we conducted an experimental study of the interactions between CO₂, brine, and rocks in the Mahu oilfield at 20 MPa and 70 °C. The low-field nuclear magnetic resonance (LF-NMR) measurements showed that the incremental amplitude for tight cores of CO₂-rock-water tests was larger than that for CO₂-rock tests, and the amplitude alteration presented significant differences corresponding to different types of minerals and pores. Furthermore, the interplanar spacing of the core samples was increased with the increase of reaction time in the CO₂-rock experiments but still lower than that in CO₂-rock-water tests. This research demonstrated evident changes in the geochemistry in tight reservoirs caused by CO₂, brine, and rock reactions. The results of this study may provide a significant reference for the exploration of similar reservoirs in the field of CO₂-EOR and CO₂ sequestration.

Ultrastable N2/Water Foams Stabilized by Dilute Nanoparticles and a Surfactant at High Salinity and High Pressure

The rapid development of unconventional oil and gas resources presents challenges for foam flooding for reservoirs with high salinity and high heterogeneity at elevated temperatures. In this study, hydrophilic anionic sulfonate-modified nanoparticles (NPs) exhibited a synergistic effect with a cationic surfactant in stabilizing N₂/water foam in the presence of concentrated divalent ions from ambient temperature up to 70 °C. With low concentrations of both the sulfonated NPs (SNPs) and cationic surfactant, the foams remained stable for 4 days at 50 °C and atmospheric pressure, while the surfactant-stabilized foams collapsed completely in 1 day. This stability mechanism of foams by the SNPs and cationic surfactant is described in terms of phase behavior, bulk shear rheology of the aqueous phase, and the dilational modulus of the gas-brine interface. The high surface elastic dilational modulus E' observed upon addition of the SNP provided stability against coarsening according to the Gibbs criteria. The cryo-SEM images also showed the compact bubble structure of foams provided by the SNPs. Consequently, very minor changes in the foam bubble size were observed at 208 bar (3000 psi) and 50 °C for up to 48 h with only 0.1 wt % or 0.3 wt % SNPs and 0.01 wt % Arquad 12-50, indicating excellent foam stability. The ability of the surfactant and NPs to stabilize foams at low concentrations broadens the application of foams in subsurface reservoirs at high temperatures and salinities.

Study on Thermal Stability of Gel Foam Co-Stabilized by Hydrophilic Silica Nanoparticles and Surfactants

The combination of nanoparticles (NP) and surfactant has been intensively studied to improve the thermal stability and optimize the performance of foams. This study focuses on the influence of silica NPs with different concentration on the thermal stability of gel foams based on a mixture of fluorocarbon (FS-50) and hydrocarbon (APG0810) surfactants. The surface activity, conductivity, viscosity, and foaming ability of the APG0810/FS-50/NPs dispersions are characterized. The effects of NP concentration on coarsening, drainage, and decay, as well as of the gel foams under thermal action, are systematically studied. Results show that NP concentration has a significant effect on the molecular interactions of the APG0810/FS-50/NP dispersions. The surface tension and conductivity of the dispersions decrease but the viscosity increases with the increase in NP concentration. The foaming ability of APG0810/FS-50 solution is reduced by the addition of NPs and decreases with the increase in NP concentration. The coarsening, drainage, and decay of the gel foams under thermal action slow down significantly with increasing NP concentration. The thermal stability of the gel foams increases with the addition of NPs and further increases with the increase in NP concentration. This study provides a theoretical guidance for the application for gel foams containing NPs and surfactants in fire-extinguishing agents.

Elastic gas/water interface for highly stable foams with modified anionic silica nanoparticles and a like-charged surfactant

HYPOTHESIS

Surface active anionic nanoparticles (NPs) with strategically designed covalent ligands may be combined with a liked-charged surfactant to form a highly elastic gas-water interface leading to highly stable gas/water foams.

EXPERIMENTS

The colloidal stability of the NPs was determined by dynamic light scattering, and the surface elastic dilational modulus E' of the interface by sinusoidal oscillation of a pendant droplet at 0.1 Hz, which was superimposed on large-amplitude compression-expansion cycles. The foam stability was measured with optical microscopy of the bubble size distribution and from the macroscopic foam height.

FINDINGS

The NPs played the key role the formation of a highly elastic air-water interface with a high E' despite a surfactant level well above the critical micelle concentration. Unlike the case for most previous studies, the NP amphiphilicity was essentially independent of the surfactant given the very low adsorption of the surfactant on the like-charged NP surfaces. With high E' values, both coalescence and coarsening were reduced leading to highly foam up to 80 °C. However, the surfactant facilitated foam generation at much lower shear rates than with NPs alone. The tuning of NP surfaces with ligands for colloidal stability in brine and simultaneously high amphiphilicity at the gas-water interface, over a wide range in surfactant concentration, is of broad interest for enabling the design of highly stable foams.

Directional motion of the foam carrying oils driven by the magnetic field

Foams are substances widely used the foam flooding technology, which aim to greatly improve the residual oil recovery. In the present study, we perform a comprehensive investigation on the oil removal process driven by the foam embedded with magnetic particles, under the action of the magnetic force. The experiment shows that the addition of magnetic particles has little effect on the stability of the foam. During the motion of the foam, its maximum displacement and maximum acceleration are fully explored. Such factors as the volume of the foam, the volume of the oil droplet, the mass concentration of magnetic particles, and the Young's contact angle of surfactant on solid are surveyed in detail. The function curves of the maximum displacement and the maximum acceleration with respect to these variables are obtained in the experiment, and the selection of some optimal parameters is advised. Moreover, the dimensional analysis has been conducted and several scaling laws are given, which are in agreement with the experimental results. These findings are beneficial to understand the oil displacement with the aid of magnetic field, which also provide some inspirations on drug delivery, robots and micro-fluidics.

Different strategies of foam stabilization in the use of foam as a fracturing fluid

An attractive alternative to mitigate the adverse effects of conventional water-based fluids on the efficiency of hydraulic fracturing is to inject foam-based fracking fluids into reservoirs. The efficiency of foaming fluids in subsurface applications largely depends on the stability and transportation of foam bubbles in harsh environments with high temperature, pressure and salinity, all of which inevitably lead to poor foam properties and thus limit fracturing efficiency. The aim of this paper is to elaborate popular strategies of foam stabilization under reservoir conditions. Specifically, this review first discusses three major mechanisms governing foam decay and summarizes recent progress in research on these phenomena. Since surfactants, polymers, nanoparticles and their composites are popular options for foam stabilization, their stabilizing effects, especially the synergies in composites, are also reviewed. In addition to reporting experimental results, the paper also reports recent advances in interfacial properties via molecular dynamical simulation, which provide new insights into gas/liquid interfacial properties under the influence of surfactants at molecular scale. The results of both experiments and simulations indicate that foam additives play an essential role in foam stability and the synergic effects of surfactants and nanoparticles exhibit more favorable performance.

Insight on Methane Foam Stability and Texture via Adsorption of Surfactants on Oppositely Charged Nanoparticles

We report the phase behavior of a dispersion of alumina-coated silica nanoparticles in the presence of an anionic surfactant (sodium fatty alcohol polyoxyethylene ether sulfate), and then describe the influence of surfactant/nanoparticle concentration ratio on the stability of methane foam as a potential fluid for enhanced oil recovery application. The surface tension of the methane/aqueous phase interface, surface charge, and size of the particle aggregates and amount of surfactant adsorption were characterized as a function of surfactant/nanoparticle ratio. Five adsorption stages, which are described in terms of the extent and type of the surfactant coverage on the nanoparticle surface, explain the behavior of the solution at different surfactant/nanoparticle ratios. The static foam generation experiments were conducted to monitor the variation of the foam stability and texture over the defined adsorption stages. The surface tension trends illustrate that the affinity of nanoparticles for the gas-liquid interface is strongly affected by the adsorption extent of AES molecules on the particle surface. At high surfactant/nanoparticle ratio, the adsorbed surfactant bilayer causes a high hydrophilicity of the particles that significantly pushed the particles away from the gas-liquid interface. At the most hydrophobic state of the particles which occurred at the ratio of 0.2, the foam structure collapsed quickly. The most stable foam with fine texture was found at surfactant/nanoparticle ratio less than 0.008 at which the particles are partially covered with surfactants and have smaller aggregate size. The findings provide a better understanding of the interaction between oppositely charged nanoparticle/surfactant pairs and how that interaction affects foam stability. It is demonstrated that substitution of absolute concentration by surfactant/nanoparticle ratio can truly govern the foam stability and texture. The results can be beneficial to predict the foam behavior in its numerous applications and whether interactions will be synergistic, antagonistic, or neutral.