Micromodel Experiments Research Articles

The conformance control and enhanced oil recovery performance of CO2 foam reinforced by regenerated cellulose

CO2 foam flooding is one of the most promising technologies for conformance control and enhanced oil recovery (EOR) in heterogenous tight oil reservoirs. However, it is challenging to maintain foam stability at in-situ high temperature and high salinity reservoir conditions, thus seriously limiting the flooding efficiency. Herein, a new approach of CO2 foam reinforced by regenerated cellulose (RC) was proposed and evaluated by multiple light scattering method and microscopic detection; afterwards, the conformance control and EOR performances were evaluated via flooding experiments at representative reservoir conditions of 85 °C and 59737.6 mg/L, using artificial micro-models and heterogenous core test. Results have demonstrated that: Compared with CO2 foam without RC, the foam with 1 % RC could elongate the foam half-life by ∼30 times (i.e., from 18 to 543 mins) and the drainage half-time by ∼4 times (i.e., from 2.5 to 9.5 mins), respectively; For the conformance control, the CO2 foam flooding with RC improved the sweep efficiency from the respective 42.4 % and 15.8 % to 95.4 % compared with water flooding and CO2 flooding in the micromodel experiments; the CO2 foam with RC increased the injection pressure from 0.20 to 3.1 MPa in the core flooding experiments, suggesting the diversion of fluid from high permeable to low permeable zone. In terms of the EOR, the CO2 foam flooding with RC improved the oil recovery from the respective 29.7 % and 12.9 % to 92.3 % in contrast with water flooding and CO2 flooding in micro-flooding experiments and from 35.5 % to 56.4 % by core-flooding experiments; the underlying mechanisms are attributed to oil emulsification, rock wettability alteration and foam deformation. These insights provide new approaches to maintain foam stability, improve conformance control and EOR performances in heterogenous tight oil reservoirs under harsh conditions.

Effect of a Natural Surfactant (Fenugreek Seeds) on Emulsification and Mobilization of Paraffins via Pore-Scale Micromodel Experiments.

The surface characteristics of minerals have been crucial in predicting the interactions between chemicals, particularly in chemical flooding. Thus, this paper evaluates the viability of natural surfactants derived from agricultural products for oil recovery studies using a micromodel filled with paraffinic oil. The study investigates the interfacial tension, viscosity, microscopic, dilution, and oil mobilization characteristics of the natural surfactants. The experimental setup involves conducting interfacial tension measurements between the surfactant solution and paraffinic oil using the Wilhelmy plate method and was found to be 14.2, 10.92, and 9.8 mN/m. Additionally, viscosity measurements and frequency sweep analysis were performed to assess the rheological properties of the prepared emulsion, which was stabilized using a natural surfactant. Microscopic evaluation depicts that, among the prepared emulsions, n-heptane emulsion seems more stable at both 30 and 90 °C. Moreover, dilution studies were conducted for each emulsion system, and the dilution ratio was varied from 1:5 to 1:1 (emulsion/saline solution). It was found that n-heptane emulsion possesses better stability at higher dilution (until a 3:5 ratio). Oil mobilization studies are conducted using a glass micromodel to simulate reservoir conditions and observe the displacement efficiency of the surfactant solutions. The results indicate that natural surfactants exhibit competitive interfacial tension reduction and viscosity modification properties compared to commercial surfactants. Furthermore, oil mobilization studies demonstrate the effectiveness of natural surfactants in enhancing oil recovery from paraffinic oil reservoirs. These findings suggest the potential of natural surfactants derived from agricultural products as sustainable alternatives for improving the oil recovery efficiency in petroleum reservoirs.

Polyetheramine enhanced biosurfactant/biopolymer flooding for enhanced oil recovery

The application of conventional alkali, surfactant and polymer in alkali/surfactant/polymer (ASP) flooding has exposed the inherent shortcomings of pollution and damage to reservoirs. Hence, finding new environmentally friendly alternatives is essential for the sustainable development of ASP flooding. In this paper, we proposed a novel ternary combination utilizing organic alkali polyetheramine, biosurfactant, and biopolymer as alternative chemical agents for ASP flooding. Specifically, the ASP system composed of polyetheramine D230, biosurfactant sophorolipid (SL) and biopolymer welan gum (WLG) exhibited excellent potential in improving oil recovery. The interfacial tension measurements proved that D230 could react with organic acids in crude oil to generate surface-active soaps, which cooperated with SL to reduce the oil–water interfacial tension to 10−2 mN/m. The rheological measurements demonstrated that the addition of D230 could increase the viscosity of low concentration WLG solution, but this phenomenon gradually disappeared with the rise of WLG concentration. Even at higher WLG concentration, D230 only caused a slight decrease in system viscosity, which facilitated the improvement of sweep efficiency. Emulsification and contact angle measurements indicated that D230/SL blend had outstanding emulsifying ability and successfully altered the quartz surface from oil-wet to water-wet. Core flooding experiments and micromodel experiments showed that the D230/SL/WLG system significantly enhanced oil recovery by 22.66 %, which was attributed to the high viscosity, low interfacial tension, excellent wettability reversal and emulsifying abilities of the system. The economic benefit assessment indicated that this ASP system has the potential to be economic, rendering it profitable even during periods of low oil prices. Furthermore, the EC50 value of 52,600 mg/L for D230/SL/WLG demonstrated its environmental friendliness.

Screening of sustainable biosurfactant produced by indigenous bacteria isolated from Egyptian oil fields for microbial enhanced oil recovery

Microbial enhanced oil recovery (MEOR) stands out as an environmentally and economically significant approach utilizing microorganisms and their bio-products to reduce residual oil, and hence improve oil recovery. Due to the pollution that synthetic surfactants entail and their very expensive costs, there is a growing necessity for clean, eco-friendly alternatives. This research focuses on exploring the potential of producing biosurfactants by indigenous bacteria isolated from Egyptian Oil Fields. Five crude oil and formation water samples were collected from four Egyptian Oil Fields located in the Western Desert (WD). Nine bacterial strains were isolated and screened for biosurfactant production using different assays, followed by the extraction and purification of crude biosurfactants. The most promising biosurfactant-producing strains that showed their ability to produce effective biosurfactant according to biosurfactant screening assays were selected for further studies and identified through 16S rRNA gene sequencing. Furthermore, core-flooding micromodel experiments were conducted to evaluate the effectiveness of these extracted biosurfactants compared to a synthetic surfactant, Sodium Dodecyl Sulfate (SDS), in improving oil recovery. Results showed that the most promising biosurfactant-producing strains that exhibited notable performance and ability to produce effective biosurfactants were namely A-LB, C-LB2, and B-YM2. Therefore, they were selected for further studies and identified through 16S rRNA gene sequencing. 16S rRNA gene sequencing results showed that namely A-LB, C-LB2, and B-YM2 were identified as Bacillus massiliigabonensis, Pseudomonas nitritolerans, and Aninetobacter seohaensis, respectively. Finally, core flooding results showed that the biosurfactant produced by Bacillus massiliigabonensis demonstrated significant performance by recovering 69.96% of additional oil, whereas 68.11% and 63.34% of additional oil were recovered using biosurfactants produced by Pseudomonas nitritolerans, and Aninetobacter seohaensis, respectively. It was also noticed that the biosurfactant produced by Bacillus massiliigabonensis demonstrated significant potential in improving oil recovery compared to the synthetic surfactant (61.78%), it outperformed 8.18% more additional oil. These findings validate the effectiveness of the produced biosurfactants over synthetic surfactants emphasizing their potential as sustainable and cost-effective alternatives for enhanced oil recovery in Egyptian oil fields.

Experimental investigation of the sequence injection effect of sea water and smart water into an offshore carbonate reservoir for enhanced oil recovery

This study explores enhanced oil recovery (EOR) strategies, with a focus on carbonate reservoirs constituting over 60% of global oil discoveries. While “smart water” injection proves effective in EOR for carbonate reservoirs, offshore application challenges arise due to impractical volumes for injection. To address this, we propose a novel continuous injection approach, systematically investigating it on a laboratory scale using the Iranian offshore reservoir, Sivand. Thirty-six contact angle tests and twelve flooding experiments are meticulously conducted, with key ions, potassium, and sulfate, playing pivotal roles. Optimal wettability alteration is observed at 4 times potassium ion concentration in 0–2 times sulfate concentrations, driven by ionic strength and charge interactions. Conversely, at 3–5 times sulfate concentrations, the optimal contact angle shifts to 2 times potassium ion concentration, suggesting a mechanism change linked to increasing sulfate ion ionicity. A significant wettability alteration, evidenced by a 132.8° decrease, occurs in seawater with a twofold concentration of potassium ions and a fivefold concentration of sulfate ions. Micromodel experiments introduce an innovative alternation of smart water and seawater injections. The first scenario, smart water followed by seawater injection, reveals negligible post-seawater injection oil recovery changes. In contrast, the second scenario yields a maximum recovery of 7.9%. The first scenario, however, boasts superior overall sweep efficacy, reaching approximately 43%. This research expands understanding of smart water and seawater injection in EOR, presenting a viable solution for optimizing offshore carbonate reservoir recovery. The insights contribute to evolving EOR methodologies, emphasizing tailored strategies for varying reservoir conditions.

Wettability Alteration Mechanisms in Enhanced Oil Recovery with Surfactants and Nanofluids: A Review with Microfluidic Applications

Modifying reservoir surface wetting properties is an appealing topic to the upstream oil and gas industry for enhancing hydrocarbon recovery as the shifting of reservoir rock surface wetting from oil-wet to water-wet has enhanced the oil recovery by as much as 70–80%. In the last few decades, research has been conducted on core flooding experiments to reveal wettability alteration mechanisms associated with macroscopic fluid flow in reservoirs. In recent years, the microscopic wetting state and fluid distribution behavior have been studied using micromodel experimental techniques to promote the fundamental mechanisms of wettability alteration. To provide the concurrent knowledge and technology development, this comprehensive review focuses on micromodel investigations for wettability alteration in chemical-enhanced oil recovery using surfactants and/or nanofluids that reveal microscopic behaviors on the wetting state, fluid distribution, and their associated mechanisms. This comprehensive review focuses on micromodel investigations for wettability alteration in chemical-enhanced oil recovery using surfactants and/or nanofluids that reveal microscopic behaviors on the wetting state, fluid distribution, and their associated mechanisms. Wettability characteristics and measurement techniques are thoroughly assessed to understand the critical role of wettability for enhanced oil recovery. With the microfluidic-based studies, the effect of relative permeability along with the pore network and wetting order on oil recovery have been discussed. Later on, the new development in phase diagram related to viscus fingering and capillary fingering regime have been reviewed via various micromodels. Then, the wettability alteration mechanisms and governing parameters by surfactant and nanoparticles are summarized. Additionally, recent micromodel experiments on surfactants and nanofluid-assisted enhanced oil recovery are reviewed and listed, along with their fabrication methods.

Remediation of DNAPL-contaminated heterogeneous aquifers using colloidal biliquid aphron: Multiscale experiments and pore-scale simulations

The heterogeneity of the aquifer seriously affects the remediation efficiency of dense non-aqueous phase liquid (DNAPL) due to the low contact efficiency for remediation reagents and DNAPL at macro scale and the restricted moving of DNAPL droplets by capillary forces in pore at micro scale. In this work, colloidal biliquid aphron (CBLA) as a remediation reagent was proposed, it has the rheological properties of shear thinning and the ultra-low interfacial tension between DNAPL. This work investigated the mechanisms and efficiencies of remediation DNAPL-contaminated heterogeneous aquifers using CBLA by sandbox and micromodel scale. The results indicated that CBLA could improve the mass transfer efficiency by both increasing the sweeping and extraction efficiency. The remediation efficiency of tetrachloroethylene (PCE) in aquifers with different permeability was above 99 % in sandbox, with the highest effluent concentration of 1.89 × 105 mg/L. Furthermore, at micromodel scale, CBLA could raise the remediation efficiency by improving the mobility and emulsification of PCE droplets. There was no PCE residue in the fine pore throats, and the remediation efficiency was 99.49 % in micromodel experiment and simulation. This work provided a promising remediation reagent for removing DNAPL from heterogeneous aquifers and laid a theoretical foundation for its practical application.

Enhancement of carbon dioxide storage efficiency using anionic surfactants

The injection of carbon dioxide into aquifers under the cap rock involves high capillary pressure, resulting in reduced injection efficiency as the distance from the injection well increases. Capillary pressure, determined by the interfacial tension (σ) and contact angle (θ) between immiscible fluids, significantly influences this process. Previous studies examined surfactant properties such as the interfacial tension and contact angle, aiming to enhance carbon dioxide injection efficiency. Most of the existing research in this field has focused on the enhancement of oil recovery. Therefore, this study conducted micromodel experiments and pore network simulations to assess the impact of anionic surfactants, namely SDS and SDBS, on the efficiency of carbon dioxide injection into submarine aquifers. The results of micromodel experiments showed a substantial improvement in injection efficiency with higher injection rates and the incorporation of surfactants. However, no significant influence on injection efficiency was shown between surfactant concentrations of 0.01 wt% and 0.02 wt%. The numerical analysis showed that interfacial tension more influenced on injection efficiency than the contact angle. Moreover, the introduction of surfactants resulted in an increased relative fluid permeability, concomitant with increased injection efficiency. Consequently, the utilization of surfactants holds significant promise in increasing the injection efficiency of carbon capture and storage (CCS).

Direct Investigation of Oil Recovery Mechanism by Polymer-Alternating-Gas CO2 through Micromodel Experiments

Direct Investigation of Oil Recovery Mechanism by Polymer-Alternating-Gas CO₂ through Micromodel Experiments

An amphiphilic nano calcium carbonate: Preparation, emulsification, interface properties, and displacement mechanism in low permeability reservoir

More extensive attention has been directed toward amphiphilic nanomaterials in the field of chemical enhanced oil recovery owing to they have the same excellent properties as surfactants. In this work, an amphiphilic nano calcium carbonate(ANCC) was prepared by chemical one-pot synthesis of NCC and alkyl acid. ANCC had a lipophilic property, which can make the oil and water were completely emulsified at the concentration of 500 ppm to form W/O emulsion with a particle size of 0.2–2.6 µm. ANCC had best dispersion effect at the solution of 0.1% Tween80. In the oil-water phase, ANCC can be adsorbed on the oil-water interface to reduce interface tension, and increase interface strength, and improve emulsion stability. The lipophilic slide can be changed from lipophilic to hydrophilic when immersed in the nanofluid. Using TW-ANCC (0.1% of Tween80 +500 ppm of ANCC) as the oil displacement fluid, which improved oil recovery by 23.3% in the single core displacement experiment and by 36.9% in the flat panel visualization experiment with comparing primary water flooding. The oil displacement mechanism of TW-ANCC was obtained by the etched glass micromodel experiment and the nuclear magnetic resonance experiment, the result shown that TW-ANCC can enhance oil recovery by reducing interface tension, changing rock wettability, reducing flow in high permeability zone, and expanding sweep volume in low permeability zones.

Alterations in wettability and immiscible fluid flows by bacterial biosurfactant production for microbial enhanced oil recovery: Pore-scale micromodel study

This study investigates alterations in wettability during bacterial growth and biosurfactant production and its ensuing impacts on immiscible fluid flow at a pore scale. Here, pore-scale experiments were carried out with two types of patterned micromodels. First, the experiments with a single-channel micromodel visually captured the real-time wettability alteration from oil-wet to water-wet while cultivating the model bacteria Bacillus subtilis, in which the bacterial cells and produced biosurfactant significantly lowered the contact angles, including static, advancing, and receding angles, by ∼70–90°. In addition, the emulsification-demulsification phenomena at brine-oil interfaces and the contact angle alterations by biofilms were also observed. Second, the surfactant-flooding process was emulated in the experiments with multi-channel micromodel while examining the effect of surfactant concentration on oil sweeping efficiency. The results of the multi-channel micromodel experiment show that a biosurfactant concentration of 70 mg/L, which is twice the critical micelle concentration, resulted in a lower contact angle, reduced residual oil saturation, and more homogeneous and stable patterns of oil displacement. Particularly, a significant level of variations in the contact angles at fluid-solid interfaces was observed in the multi-channel micromodel, and the extent of variation decreased with an increase in biosurfactant concentration. The presented results provide insights into pore-scale coupled microbial-hydrological processes in porous media as well as the biosurfactant-aided flooding in microbial enhanced oil recovery (MEOR).

Pore doublet micromodel experiments of evaporation influence on pre-event water entrapment and pre-event and event water interaction

The stable isotopic signature of xylem water differs from those of rainfall and river water. Without considering the water exchange through the vapor phase, this phenomenon implies that when the event water (new water) infiltrates the soil, a part of the pre-event water (old water) is isolated. The isolation and immobilization of old water are suspected because of the low matrix potential. Because evaporation is the main process that can reduce the matrix potential after quick gravitational drainage, we conjectured that after evaporation, the old water hides in small pores and increases the likelihood of air entrapment, which separates the new and old water. To examine and visualize the potential effect of evaporation on the interactions between old and new water, we performed a series of wetting–drainage–evaporation–wetting experiments within pore doublet micromodels (PDMs). The experimental results showed that air bubbles are trapped when the menisci of the residual liquid are sufficiently far from the inlet and outlet of the PDM. Evaporation can increase these distances, resulting in the formation of larger air bubbles. The air bubble trapped upstream prevents the invading liquid from quickly flushing the original residual liquid out of the PDM. Nevertheless, the invading wetting liquid is still able to bypass the trapped air bubbles and mix with the residual wetting phase via corner flow. In addition, the remobilization of the upstream bubble enhances the process of removing the old trapped liquid.

A study of the oil recovery potential and mechanisms of an alternative Alkaline-Surfactant-Polymer formulation for carbonate reservoir

Despite the promising nature of alkali-surfactant-polymer (ASP) flooding, its application is associated with various limitations that yield economic uncertainties about ASP projects. These limitations are aggravated in carbonate reservoirs where prevailing reservoir conditions attenuate the performance of various chemical agents in enhancing oil recovery. The goal of mitigating the impact of these limitations has led to research into the oil recovery potential of alternative chemical agents. Nevertheless, the literature has not reported a ternary combination of these alternative chemical agents. Therefore, this study focuses on investigating the potential of alternative ASP formulations composed of monoethanolamine (ETA), hexadecyl-3-methyl imidazolium bromide (C16mimBr), and Schizophyllan (SPG) for their enhanced oil recovery in carbonate reservoirs at high temperature (80 °C) and high salinity (4100 ppm) conditions. A conventional ASP formulation is deployed for comparative purposes. The current study is a sequel to our study on the oil recovery potential of an alkali-surfactant (AS) formulation made of ETA and C16mimBr. A comprehensive approach has been deployed to study the EOR potential of the proposed formulation. The approach included rheological measurements, core flood experiments, and micromodel experiments. The combination of ETA and SPG alleviates the detrimental effect of inorganic alkalis on HPAM. Therefore, the alternative ASP formulations showed better rheological properties than their conventional counterparts in bulk phase and porous media. The ETA–C16mimBr–SPG formulation also exhibited excellent EOR potential by recovering ∼27.05% additional oil, while the conventional counterpart achieved an additional oil recovery of ∼19.24%. Based on the results of the micromodel experiments, direct pore-to-pore displacement and emulsification are the main oil recovery mechanisms, and their occurrence depends on prevailing reservoir conditions. The study also confirms that wettability alteration as an oil recovery mechanism is more effective when the headgroup charge of the surfactant is the same as the surface charge of the rock. This study, therefore, reveals that a combination of organic alkali, surface-active ionic liquid, and biopolymer has excellent potential in enhancing oil recovery in carbonate reservoirs at high salinity–high-temperature conditions.

Temperature effects on alkaline flooding for heavy oil recovery in heterogeneous and homogeneous porous media: Pore scale evaluation

ABSTRACT Among the various methods of chemical enhanced oil recovery, alkaline flooding has a better potential to increase oil recovery in reservoirs containing acidic crude oil. This research investigated the effect of temperature on alkaline flooding (sodium hydroxide and sodium carbonate) on the enhanced oil recovery in two homogeneous and heterogeneous micromodels at temperatures of 25, 50, 75 and 90°C. Evaluation of the effect of temperature on oil recovery in micromodel experiments showed that sodium hydroxide increased the pH of the environment at low temperatures (25 and 50°C) due to its higher alkalinity and, this issue shows greater ability to emulsification and reduce interfacial tension, which ultimately increases oil recovery. In contrast, high temperatures (75 and 90°C) have a negative effect on oil recovery, so that oil recovery is greatly reduced. The high temperature causes the increased rate of the reaction between the crude oil sample and alkaline solutions, which in turn reduces the effect of IFT and, weakening the uniform enrichment of in situ surfactants cause problem for making water droplets within the oil phase. Finally, the increase in temperature to 90°C showed that the oil recovery rate was reduced to about 42% in the homogeneous model and 51% in the heterogeneous model. The achievements of this research lead to a better understanding of the effect of temperature parameter on various mechanisms of increasing heavy oil recovery such as reducing the IFT of oil/injectable solutions and producing W/O emulsion during alkaline flooding under different wetting conditions. Studies show that injecting alkaline by creating a W/O emulsion prolongs the breakthrough time and changes the finger pattern created during water flooding in a way that reduces the amount of oil bypassed, so that a significant increase is observed in the oil recovery factor.

Resonance-Enhanced Pulsing Water Injection for Improved Oil Recovery: Micromodel Experiments and Analysis

Enhanced oil recovery (EOR) is a crucial technology in the petroleum industry, influenced by several factors, including flooding fluids and methods. The adjustment of injection strategies and the application of vibration stimulation can significantly impact oil recovery, especially residual oil. In this study, we conducted experiments using a glass micromodel to investigate the effect of pulsing water injection on oil recovery. Our results show that when the pulse frequency matches the natural frequency of the micromodel, resonance occurs during the two-phase flow of pulse driving, which causes an increase in the amplitude of oscillation, enhances the mobility of oil, and improves recovery. The efficiency of the kinetic energy of displacement is also improved. However, when the frequency is 3 Hz, the absence of resonance leads to the opposite effect. In addition, we found that a greater amplitude increases the fluidity of oil. These findings have significant implications for the design of EOR strategies and methods. Our experimental results provide insight into the effect of pulse water injection on oil recovery and offer a potential strategy for the optimization of EOR techniques.

Optimizing Polymer Costs and Efficiency in Alkali-Polymer Oilfield Applications.

In this work, we present various evaluations that are key prior field applications. The workflow combines laboratory approaches to optimize the usage of polymers in combination with alkali to improve project economics. We show that the performance of AP floods can be optimized by making use of lower polymer viscosities during injection but increasing polymer viscosities in the reservoir owing to "aging" of the polymers at high pH. Furthermore, AP conditions enable the reduction of polymer retention in the reservoir, decreasing the utility factors (kg polymers injected/incremental bbl. produced). We used aged polymer solutions to mimic the conditions deep in the reservoir and compared the displacement efficiencies and the polymer adsorption of non-aged and aged polymer solutions. The aging experiments showed that polymer hydrolysis increases at high pH, leading to 60% higher viscosity in AP conditions. Micromodel experiments in two-layer chips depicted insights into the displacement, with reproducible recoveries of 80% in the high-permeability zone and 15% in the low-permeability zone. The adsorption for real rock using 8 TH RSB brine was measured to be approximately half of that in the case of Berea: 27 µg/g vs. 48 µg/g, respectively. The IFT values obtained for the AP lead to very low values, reaching 0.006 mN/m, while for the alkali, they reach only 0.44 mN/m. The two-phase experiments confirmed that lower-concentration polymer solutions aged in alkali show the same displacement efficiency as non-aged polymers with higher concentrations. Reducing the polymer concentration leads to a decrease in EqUF by 40%. If alkali-polymer is injected immediately without a prior polymer slug, then the economics are improved by 37% compared with the polymer case. Hence, significant cost savings can be realized capitalizing on the fast aging in the reservoir. Due to the low polymer retention in AP floods, fewer polymers are consumed than in conventional polymer floods, significantly decreasing the utility factor.

Synthesizing CNT-TiO2 nanocomposite and experimental pore-scale displacement of crude oil during nanofluid flooding

Metallic nanoparticles and carbon nanomaterials have been extensively studied in enhanced oil recovery. Carbon nanotube (CNT)/TiO2 nanocomposite is synthesized and investigated in terms of contact angle, interfacial tension (IFT), emulsion stability, etc. Its performance in oil displacement in porous media is evaluated through glass micromodel experiment. The synthesized CNT/TiO2 is composed of TiO2-based nanocomposites and CNTs as reinforcement phase. TiO2 is the dominant crystalline phase, and TiO2 nanoparticles cover on the CNTs. CNT/TiO2 nanocomposite is able to alter the wetting conditions of the rock from strong oil-wet to hydrophilic conditions and effectively reduce the interfacial tension. CNT/TiO2 nanocomposite plays an effective role in stabilizing the Pickering emulsions, and even forms stable emulsions at high temperature as 90 °C. For NaCl concentration of up to 2%, a stable emulsion can be formed even after 7 days. It is observed from glass micromodel experiments that the CNT/TiO2 nanofluid provides a higher recovery factor denoting its promising performance in enhanced oil recovery.

Prediction of spontaneous imbibition with gravity in porous media micromodels

In this work, theoretical modelling, quasi-three-dimensional (quasi-3D) simulations and micromodel experiments are conducted to study spontaneous imbibition with gravity in porous media micromodels. By establishing the force balance governing the spontaneous imbibition process, we develop a theoretical model for predicting the imbibition length against time in a rectangular capillary. The theoretical model is then extended to the prediction of a compact displacement process in a micromodel by using an equivalent width, which is derived by analogising the micromodel to a rectangular capillary. By simulating spontaneous imbibition in a rectangular capillary with various aspect ratios ( $\varepsilon$ ), we show that the application condition of the quasi-3D method is $\varepsilon \leqslant 1/3$ . Next, we simulate spontaneous imbibition in micromodels with various geometries and flow conditions. Fingering and compact displacement are identified for varying viscosity ratios and gravitational accelerations. At low (high) viscosity ratio of wetting to non-wetting fluids, an upward (downward) gravity can promote the stability of the wetting front, favouring the transition from fingering to compact displacement. In addition, we find that the depth-oriented interface curvature dominates the capillary effect during the imbibition, and such a mechanism is considered by introducing an equivalent contact angle into the theoretical model. With the help of equivalent width and contact angle, the theoretical model is shown to provide satisfactory prediction of the compact displacement process. Finally, a micromodel experiment is presented to further verify the developed theoretical model and the quasi-3D simulation.

Application of the Maxwell–Stefan theory in modeling gas diffusion experiments into isolated oil droplets by water

We have used the Maxwell–Stefan diffusion theory to model the mass transfer between tertiary-injected gas and residual oil blocked by water, in order to predict the time required for the rupture of the water barrier due to oil swelling. We have also designed and conducted a set of visualization micromodel experiments on various pure and multicomponent oil–gas systems to measure the water rupture time in tertiary gas injection processes. The experimental results show that the initial pressure and dimensions of the system, the oil and gas composition, and the gas solubility in water control the oil swelling process. The experimentally measured rupture times are then employed to evaluate the reliability of the model and to compare its accuracy with that of a similar one using classical Fick's law. Our modeling results show that both models are able to estimate the water rupture time for pure systems with an acceptable precision. As for multicomponent mixtures, however, only the Maxwell–Stefan theory is capable of modeling the molecular diffusion process correctly and yields values close to reality, while the use of Fick's law would lead to erroneous results. Deficiency of the latter model becomes more acute when the diffusion direction in reality is contrary to what the model indicates, which leads to failure in calculating any value for rupture time at all for these cases.

Bubble-growth regime for confined foams: Comparison between N2–CO2/foam and CO2/foam stabilized by silica nanoparticles

The use of foam technology in Pre-Salt reservoirs is a potential solution to control gas mobility in highly heterogeneous reservoirs. However, achieving stable CO2-foams under reservoir conditions can be challenging since high solubility in water of supercritical CO2 enhances coarsening and coalescence of bubbles. Coarsening is the evolution of foam structure with time due to gas diffusion between bubbles. In this phenomenon, gas normally diffuses from smaller to larger bubbles, which for confined foam is relevant because this ends up decreasing the number of bubbles in a determined area/volume of the pore space (foam texture). When foam texture coarsens, gas mobility control is impaired, and it can also affect foam rheology. Therefore, it is important to characterize bubble growth kinetics to compare strategies to reduce coarsening and investigate their impact on gas mobility reduction due to foam injection. In a previous work, we reported the use of nanoparticles and a CO2/N2 gas mixture as strategies for improving gas mobility of CO2-foams formed with a zwitterionic surfactant in a micromodel experiment. The present study focuses on quantitatively assessing the bubble growth regime related to coarsening for these two strategies. Indeed, bubble growth is a key parameter for population balance mathematical models that simulate CO2-foams in porous media. Image analysis was used to characterize the foam texture by calculating the bubble density and bubble size distribution of the foam confined in dead-end pores areas of the micromodel. Our results showed that, the number of trapped bubbles was twice as high for the foam formed with the gas mixture compared to those containing nanoparticles, and this higher bubble density was correlated with the higher pressure drop observed for this system, indicating lower gas mobility. The coarsening rates obtained by analyzing the change in trapped bubble area with time of CO2-foam containing nanoparticles (0.25 μm2 s−1) was in the same order of magnitude compared to that obtained by a CO2/N2 gas mixture-foam (0.44 μm2 s−1), under the same high-pressure high-temperature (HPHT) conditions. These results meant that both strategies were able to stabilize the weak foam formed between zwitterionic surfactant and CO2, and that the initial foam texture determined resistance to flow. The semi-automatic algorithm successfully identified the bubbles trapped within the system during the period of analysis, which allowed us not to add dyes that could change interfacial behavior at the water-gas interface. The novel results that evaluate the coarsening rate for CO2-foam under HPHT conditions can positively impact the estimation of foam destruction parameters for population balance models for more representative reservoir conditions of trapped gas. Our findings fill part of the gap in terms of evaluation of coarsening rate under more representative reservoir conditions, improving the understanding of kinetics of foam destruction. This information is relevant for establishing a correct range of the destruction term for populational balance models. Moreover, our results reveal that the type of strategy chosen to delay coarsening can significantly impact gas mobility reduction and that using nanoparticles impacted significantly interfacial properties of the formed foam.