With the gradual depletion of conventional hydrocarbon resources, low- and ultra-low-permeability reservoirs have become important targets for oil development. Nanoemul-sions exhibit great potential for enhanced oil recovery because of their favorable interfacialactivity, small droplet size, and excellent transport capability. However, the interfacial dy-namics and capillary mechanisms involved in microscale two-phase displacement processesremain poorly understood. In this study, a self-developed micro-capillary bundle apparatuswas used to investigate nanoemulsion displacement behavior in micrometer-scale capillar-ies. The interfacial behavior was quantitatively analyzed based on the relationship betweeninterface velocity and pressure difference (v-triangle P). The results show that the displacementprocess follows the classical Washburn equation, with a linear relationship between v and triangle P. During oil displacement, the capillary force remains negative and acts as a resistance,indicating a pressure-driven forced displacement mechanism. Environmental factors suchas temperature, electrolyte concentration, and wettability have limited effects, whereas poresize plays a dominant role. The addition of an appropriate amount of microspheres canreduce capillary resistance and lower the required driving pressure. The present findingsmainly reveal the interfacial motion characteristics and capillary mechanisms of nanoemul-sions in microscale pore throats, providing a fundamental basis for understanding fluidtransport behavior in low-permeability reservoirs.

COQ microbubble flooding has been proposed as a promising approach to suppress gas channeling, with potential benefits for oil recovery and COQ sequestration efficiency. However, harsh reservoir conditions deteriorate microbubble stability and performance. Although polymer addition improves microbubble stability and mobility control, the influence of the rheological properties of the continuous phase on microbubble generation in micro-channels remains unclear. In this study, a T-junction microchannel mimicking pore-throat junctions in porous media was used to investigate microbubble generation and breakup in shear-thinning viscoelastic fluids under ambient conditions, with the investigated parameter ranges covering a Weissenberg number of Wi = 1-10, a Weber number of We = 1-10, a capillary number of Ca = 0.59-48, and a flow behavior index of n = 0.2-0.6. Microfluidic experiments and numerical simulations based on a shear-thinning viscoelastic constitutive model indicate that microbubble morphology is governed by shear-thinning and elasticity: shear-thinning reduces apparent viscosity and promotes deformation, while elastic stresses induce pointed tails and negative wakes, which are associated with polymer relaxation and enhanced under shear-thinning conditions. Increasing shear-thinning and elasticity accelerates microbubble generation, shifts the breakup location upstream, and promotes the transition from slug to bubbly flow. Semi-empirical correlations were established to predict the dimensionless bubble length and generation frequency. This study clarifies the role of rheological properties in microbubble generation and provides mechanistic reference for the design of non-Newtonian micro-scale COQ foam systems in porous media.

CO2 microfoam flooding has emerged as a promising strategy for enhancing oil recovery and CO2 sequestration efficiency in low-permeability porous carbonate reservoirs. However, the instability of microfoam under harsh reservoir conditions poses a critical challenge to its practical application. Amphiphilic quantum dots, owing to their ultra-small size and exceptional interfacial activity, are ideally suited for stabilizing CO2 microbubbles while ensuring compatibility with narrow pore sizes. In this study, novel Janus silicon quantum dots (J-SiQDs) are synthesized and incorporated to stabilize CO2 microfoam. The synergistic effects of J-SiQDs and salt ions on microbubble stability are revealed at bulk, interfacial and molecular levels. The distribution and flow behaviors of fluids during J-SiQDs-enhanced microfoam injection are investigated within an oil-wet, calcium carbonate nanocrystals-coated micromodel, revealing the underlying mechanisms of oil recovery and COQ retention. Furthermore, the intrinsic relationship between the CO2 sequestration performance and microscopic microbubble formation dynamics is, for the first time, elucidated. This study pioneers the integration of amphiphilic JSiQDs with CO2 microbubbles, offering a novel pathway for enhanced oil recovery and geological CO2 storage in low-permeability porous carbonate reservoirs, as well as providing insights into other subsurface applications, including hydrogen storage and geothermal energy extraction.

Due to their high viscoelasticity and excellent plugging ability, surfactant foam systems can mitigate the effects of heterogeneity and have emerged as a key technology in tertiary oil recovery in recent years. Moreover, achieving ultra-low oil/water interfacial tension (IFT) is critical for enhanced oil recovery (EOR), as it facilitates the deformation and mobilization of oil droplets from pores. However, conventional surfactant systems often struggle to simultaneously achieve ultra-low oil/water IFT and high foam performance. To overcome this limitation, this study developed a composite surfactant system by combining small-molecule anionic and cationic surfactants with a nonionic surfactant, enabling both ultra-low oil/water IFT and high foam performance. The compound surfactants were evaluated for IFT, emulsification performance, and foam performance within a concentration range of 1–10 mM. Based on the comprehensive evaluation results, a concentration of 4 mM was selected for further investigation in a heterogeneous micro-model oil displacement experiment to analyze its displacement behavior. The results demonstrated that at a concentration of 2 mM, the foaming agent achieved the lowest oil/water IFT of 9.834 × 10− 4 mN/m, while at 4 mM, the foam composite index reached its peak value of 12,960 mL·min. The ability to reduce IFT was found to be approximately proportional to foam performance and inversely proportional to emulsification performance. The heterogeneous micro-model oil displacement experiment demonstrated that chemical flooding increased the recovery ratio by 24

CO2 flooding in low-permeability and tight oil reservoirs is frequently compromised by severe gas channeling, which significantly reduces oil recovery and sweep efficiency. While foam flooding can effectively mitigate CO2 channeling by trapping CO2 within lamellae, its stability deteriorates under harsh high-temperature, high-salinity reservoir conditions, compromising its effectiveness. Furthermore, foam flow in porous media involves constant foam generation, collapse and propagation, making its flow behaviors difficult to predict. To address these challenges, a new foaming agent with satisfactory regenerative capability is developed to maintain gas mobility control under harsh reservoir conditions. The multiphase flow behaviors during CO2 foam flooding are predicted using pore network modeling to obtain the corresponding relative permeability curves, which are further incorporated into a reservoir simulator to evaluate field-scale foam flooding performances, as well as optimize injection strategies. This multi-scale modeling approach establishes a quantitative link between pore-scale foam behaviors and field-scale oil recovery performances, offering new insights into carbon capture and utilization with enhanced oil recovery in low-permeability and tight reservoirs.

In recent years, the production of tight reservoirs with waterflooding in China has entered a progressively declining phase with unstable oil rate and higher water cut, rising challenges to any further enhancement of oil recovery. Targeting the high water cut and complex pore structure characteristics typical of these reservoirs, this work evaluates the reservoir compatibility of a microspheres-alternating-nanoemulsion flooding process and optimizes its injection strategy. Representative reservoir scenarios were first established; laser-particle-size analyzers and other laboratory instruments were then employed to quantify formulation-reservoir compatibility. A multiscale numerical study has been performed with CMG-STARS v.2022. The core-scale simulations systematically examined the influence of key factors on displacement efficiency improvement and water cut reduction, matched with the experimental results of core flooding tests. The combined experimental/numerical workflow furnishes a theoretical framework for optimizing the injection scheme. Beyond assessing formulation compatibility, the study delivers optimized injection parameters and strategies for microspheres-alternating-nanoemulsion flooding, providing both theoretical analysis and practical technology reference for improving oil recovery in tight reservoirs with higher water cut. Specifically, when the microsphere concentration increased from 0.1% to 0.3%, the minimum water cut was reduced by approximately 5%, while further concentration increases showed no significant additional impact on water content. Compared with water flooding, the relative permeability curve of the microspheres-alternating-nanoemulsion flooding system shifted entirely to the right. Numerical simulation of representative well groups revealed that a slug design with a microsphere-to-nanoemulsion ratio of 1:3 yielded the optimal enhanced oil recovery effect, and after ten years of production, the recovery factor increased by 0.46%.

Injecting carbon dioxide (CO2) in the form of foam into abandoned oil reservoirs offers a promising strategy for reducing the carbon footprints while enhancing oil extraction productivity. Chemicals such as polymers are commonly added to improve foam stability, thereby enhancing CO2 storage efficiency, but their use can lead to environmental pollution and formation damage. Here, a green CO2 foam with camellia oleifera saponin and a biodegradable surfactant fatty alcohol polyoxyethylene ether sulfonate (referred to as COS/APES foam) is constructed. The performance of COS/APES foam is compared with a highly stable foam containing a hydrophobic associating polymer (AES/HWAP foam) in terms of foaming ability, regeneration capability and CO2 storage and oil recovery efficiencies. Our findings demonstrate that COS/APES foam exhibits a higher regeneration capability, enabling its propagation into deep formations, thereby effectively improving the CO2 sweep efficiency. Reservoir simulations indicate that COS/APES foam achieves approximately 8.6 % higher CO2 storage and 7.4 % greater oil recovery than AES/HWAP foam, with a 5 % reduction in CO2 consumption. Over a geological timescale of 320 years, COS/APES foam significantly enhances residual trapping efficiency, delays the formation of the gas cap, while maintaining comparable storage stability to AES/HWAP foam. This study provides new insights, demonstrating that, contrary to the traditional focus on foam stability, prioritizing foam regeneration capability is essential for optimizing foam-assisted CO2 storage in abandoned oil reservoirs.

Surfactant-assisted CO2/N2-based CSI (SA CO2/N2-CSI) process emerges as a strategic solution to migrate the high energy consumption and carbon intensity associated with traditional thermal operations for heavy oil recovery. However, the interphase mass transfer makes the emulsification behavior in this process complex. In this study, the effect of in-situ emulsification on CO2/N2-CSI is assessed using a sandpack model and microchannel chip. Mesoscopically, SA CO2/N2-CSI outperforms conventional CO2/N2-CSI in terms of both oil recovery and CO2 storage, owing to the enhanced CO2 diffusion, oil solubilization, and foamy oil stability due to emulsification. Microscopically, the impact of emulsifier injection rate on oil removal efficiency in the dead-end pores becomes negligible when the injection rate exceeds 50 nL/min, providing insights to the emulsification mechanisms underlying the optimal pressure depletion rate (9 kPa/min) in SA CO2/N2-CSI. This study demonstrates the applicability of the SA CO2/N2-CSI in fostering sustainable heavy oil production and CO2 storage.

Surfactant-assisted CO 2 /N 2 -based CSI (SA CO 2 /N 2 -CSI) process emerges as a strategic solution to migrate the high energy consumption and carbon intensity associated with traditional thermal operations for heavy oil recovery. However, the interphase mass transfer makes the emulsification behavior in this process complex. In this study, the effect of in-situ emulsification on CO 2 /N 2 -CSI is assessed using a sandpack model and microchannel chip. Mesoscopically, SA CO 2 /N 2 -CSI outperforms conventional CO 2 /N 2 -CSI in terms of both oil recovery and CO 2 storage, owing to the enhanced CO 2 diffusion, oil solubilization, and foamy oil stability due to emulsification. Microscopically, the impact of emulsifier injection rate on oil removal efficiency in the dead-end pores becomes negligible when the injection rate exceeds 50 nL/min, providing insights to the emulsification mechanisms underlying the optimal pressure depletion rate (9 kPa/min) in SA CO 2 /N 2 -CSI. This study demonstrates the applicability of the SA CO 2 /N 2 -CSI in fostering sustainable heavy oil production and CO 2 storage.

Fractional flow analysis is an efficient tool to evaluate the gas-trapping performance of foam in porous media. The pore-scale simulation study and the core-scale experimental work have been bridged via the fractional flow analysis to distinguish the characteristics of foam displacement inside the tight porous media with varying absolute permeability, injection rate, and foam quality. In this work, the combined investigation suggests that conventional foam-enhancing strategies, pursuing higher foam quality and stronger foam regime, are inefficient and restricted in tight reservoirs that the critical Sw corresponding to the limiting capillary pressure has increased around 37~43%, which indicates severely weakened gas-trapping capacity as permeability reduces one order of magnitude. The moderate mobility adjustment and corresponding optimized fluid injectivity exerting from the “weak foam” flow presents a staged decline feature of decreasing water fractional flow, which implies the existence of the delayed gas-trapping phenomenon when water saturation reduces to 0.5~0.6. The finding has supported the engineering ideal of promoting low-tension gas (LTG) drive processes as a potential solution to assist field gas injection applications suffering from gas channeling. Also, the validation with core-flooding experimental results has revealed several defects of the current pore network model of foam displacement in tight porous media, including exaggerated gas trapping and overestimated confining water saturation. This study has innovatively demonstrated the feasibility and potential of optimizing the foam performance of gas trapping and mobility control in tight reservoirs, which provides a clue that may eventually boost the efficiency of the gas injection process in enhanced oil recovery or CO2 sequestration projects.

Foam injection, which can significantly reduce gas mobility and improve sweep efficiency, has been used as an enhanced oil recovery (EOR) technique for decades. In this work, a mechanistic pore network model is proposed to simulate foam propagation in porous media. The model includes wettability through critical pressures for pore filling events and tracks the motion of gas-water interface during foam propagation process. It also allows a quantitative assessment of the thermodynamic and flow properties of foam, such as mobilization pressure gradient, invasion morphology, and foam texture evolution.Our results show that the inclusion of wettability impacts the evolution of the capillary pressure signal, and the mobilization pressure gradient. Both increasing foam texture and reducing contact angle provide a similar effect on the invasion morphology: a transition from the regime of capillary fingering to compact displacement as indicated by fractal dimension and finger width. The effect of disorder depends on its coupling with wettability and foam texture: increasing disorder decreases the pattern compactness; decreasing contact angle or increasing foam texture smooths the gas-water interface, hence increasing compactness, leading to small sensitivity of the emergent pattern to disorder. The comparison between simulations and experiments shows that the proposed model is able to capture the relevant pore-level events that characterize the foaming gas drainage process in a microfluidic device filled with vertical posts and is reliable to be used for providing information needed for parameters in mechanistic foam simulators that are not accessible in conventional laboratory experiments.

Low-Tension-Foam (LTF) flooding is an emerging enhanced oil recovery technique for low-permeability carbo-nate reservoirs. Foam capacity is closely related to the salinity environment (or, equivalently, the phase behavior of the oil/water/surfactant system). Therefore, the interactions between microemulsion and foam components are of primary importance in the LTF process. In this study, the phase behavior of an oil/water/surfactant system under equilibrium is analyzed, firstly by assuming perfect mixing. Meanwhile, the formation kinetics of micro -emulsion are monitored through a novel low -field NMR technique, which is able to provide quantitative assess-ment on the microemulsion evolution characteristics. Then, foam stability is examined in the absence and in the presence of Winsor-I and Winsor-III type microemulsions. It is revealed that foam stability depends on the oil solubilization (oil swollen micelle size). A decrease in the oil swollen micelle size and micellar structure effective-ness, in conjunction with an increasing salinity, leads to lower foam stability in the presence of a Winsor-III type microemulsion.

Gas channeling caused by unfavorable mobility ratio is one of the key issues that limits total storage efficiency of CO2 during geological sequestration. Foam-assisted CO2 sequestration technology is a promising game changer that significantly improves CO2 storage efficiency. The pore-scale process of foam-assisted CO2 sequestration, in the absence and presence of remaining oleic phase, is studied with microfluidic experiments, followed by the comparison with corresponding pore network model incorporated with pore filling event-based algorithm. In this work, microfluidic investigation is carried out to study the pore-scale lamellae behavior during the foam-assisted CO2 displacement inside heterogeneous grain-based pore network. Dynamic gas storage efficiency and lamellae transport behavior of multiple injection modes are compared, including co-injection at constant flow rate, co-injection at constant pressure, and surfactant-alternating-gas process at fixed foam quality. Besides, the impacts from presence of remaining oleic phase and varying distribution of water saturation on formation of immobile foam bank and preferential flow of continuous CO2 are studied, followed by comparison with quasi-static modeling results based on pore filling event network (PFEN) algorithm. When oleic phase is absent, the experimental results show that the mobility adjustment ability of foam during CO2 sequestration is less effective at higher water saturation because of limited frequency of lamellae redistribution, which prevents further development of immobile foam bank. As water saturation reduces with continuous gas injection, active lamellae redistribution starts to weaken the preferential CO2 flow paths, form sufficient blockage along highly permeable region, and eventually divert discontinuous CO2 flow into unvisited region saturated with water. Finally, compared with ordinary foam-free CO2 sequestration process, introduction of foam effectively improves CO2 storage rate by making CO2 flow discontinuous and less mobile, even at unfavorable liquid saturation for mass transfer of foaming surfactant. The presence of remaining oleic phase has remarkable impacts on lamellae configuration of different foam regimes. Defoaming effect of oleic phase on foam displacement is apparent, but the impact is limited at high water saturation stage at which immobile foam bank has not sufficiently developed. Adjusting injection strategy can further optimize foam performance during CO2 sequestration in the presence of residual oil at lower water saturation by balancing the competition between reestablishment of immobile foam bank and frequency of activating preferential flow of continuous CO2. This work provides a pore-scale evaluation of representative stages during foam-assisted CO2 sequestration, which reveals in-situ lamellae behavior from the reduction of preferential CO2 flow to the formation of immobile foam bank. Experimental results have shown the detailed motion of lamellae redistribution, which eventually reveals the controlling roles of CO2 injection strategy, distribution of remaining water saturation, and presence of oleic phase during foam-assisted CO2 sequestration process.

Foam has been used for decades in petroleum industry for enhanced oil recovery (EOR) due to its mobility adjustment ability. A variety of mechanistic models have been proposed to study foam flow in porous media from multiple scales. In these models, such as population balance models, some important parameters (e.g., foam generation/coalescence rate, flowing foam fraction) are treated empirically since they cannot be obtained from conventional lab experiments. To improve the accuracy and reliability of foam description in these foam-assisted processes, pore network model interwoven with invasion percolation with memory (IPM) method has become a powerful tool in studying foam flow characteristics in porous media, which can predict relative permeability and flowing gas fraction with fully consideration of pore-scale mechanisms of foam generation, destruction, and propagation. However, the assumption of exactly sufficient incremental pressure difference used in conventional IPM-based pore-scale foam modeling is rigorous, not only making it difficult to conduct relevant experimental validations, but also creating potential algorithmic conflicts when simulates displacements in weak foam regime or displacements incorporated with foam coalescence mechanisms. In this study, a novel mixed-sorting rule, which proceeds the displacement by describing the transition between immobile foam bank and mobilized foam flow quantitively, is incorporated into IPM-based foam propagation model. In this way, the immobile foam bank is identified based on effective lamellae generation rate, whereas the mobilized foam flow is distinguished by frontal displacing velocity, respectively. Results estimated with proposed method successfully capture key properties that define pore-scale foam behavior at excessive pressure constraints from formation of immobile foam bank, foam mobilizing pressure thresholds, and fractal dimension of displacement pattern, etc.

Foam flooding is an efficient and promising technology of enhanced oil recovery that significantly improves sweep efficiency of immiscible displacement processes by providing favorable mobility control on displacing fluids. Although the advantages in flexibility and efficiency are apparent, accurate prediction and effective control of foam flooding in field applications are still difficult to achieve due to the complexity in multiphase interactions. Also, conventional field-scale or mesoscale foam models are inadequate to simulate recent experimental findings in feasibility of foam injection in tight reservoirs. Microscale modeling of foam behavior has been applied to further connect those pore-scale interactions and mesoscale multiphase properties such as foam texture and the relative permeability of foam banks. Modification on a microscale foam model based on a pore-filling event network method is proposed to simulate its propagation in grain-based pore networks with varying degrees of heterogeneity. The impacts of foam injection strategy and oil-weakening phenomena are successfully incorporated. Corresponding microfluidic experiments are performed to validate the simulation results in dynamic displacement pattern as well as interfacial configuration. The proposed modeling method of foam propagation in grain-based networks successfully captures the effects of lamellae configurations corresponding to various foaming processes. The results of the simulation suggest that the wettability of rock has an impact on the relevance between reservoir heterogeneity and the formation of immobile foam banks, which supports the core idea of the recently proposed foam injection strategy in tight oil reservoirs with severe heterogeneity, that of focusing more on the IFT adjustment ability of foam, instead of arbitrarily pursuing high-quality strong foam restricted by permeability constraints.

Foam injection, which can significantly reduce gas mobility and improve sweep efficiency , has been used as an enhanced oil recovery (EOR) technique for decades. In this study, a mechanistic physically plausible pore network model is proposed to study foam flow in porous media by taking both wettability and lamella effects into account. The model allows the determination of pore-scale instability events and tracks the motion of individual gas-water interfaces. It also allows a rigorous quantitative assessment of the thermodynamic and flow properties of foam, such as mobilization pressure gradient, displacement pattern, and foam texture evolution.Our results show that the incorporation of pore scale instabilities increases the mobilization pressure gradient and affects the gas invasion pathway (and consequently, the foam displacement efficiency). Increasing regeneration probability ( f reg ) and decreasing contact angle ( θ ) provide a similar effect: suppressing trapping, hence promoting sweep. Pore-level foam generation (snap-off, leave-behind) and destruction events dictate foam texture, which is of great importance to the success of mechanistic foam simulation. The disorder of porous media affects the threshold capillary pressure, hence modifying the gas invasion path. Increasing disorder destabilizes the gas front while increasing f reg increases the pattern compactness, these two effects counteract, leading to the smaller sensitivity of the emergent pattern to disorder at fine foam texture. The comparison between simulations and experiments show that the proposed model is able to capture the relevant pore-level events that characterize foam flow process in microfluidics and is reliable to be used to predict information on parameters in mechanistic foam simulators that are not accessible in conventional laboratory experiments.

The fracturing and well pattern optimization of fractured reservoirs is a hot spot in petroleum engineering. In this study, taking the tight oil reservoirs of the Yanchang Formation in the Ordos Basin as an example, an optimized plan of hydraulic fracturing and well pattern deployment of the fractured tight reservoir were systematically studied using a fluid-solid coupling model. The results show that the Chang 6 Member of Yanchang Formation mainly develop feldspar sandstone. A large number of vertical fractures are developed in Chang 6 Member, and they have significant shearing properties. The target sandstone reservoir is in the mid-diagenetic A stage. Natural fractures have a significant effect on the extension of hydraulic fractures. When the fracturing direction is parallel to the main strike of natural fractures, the extension distance of the hydraulic fractures is long and the fracturing scale is large; however, when the fracturing direction is orthogonal or oblique to the main strike of natural fractures, the extension distance of the hydraulic fractures is limited. Statistics show that the average length of hydraulic fractures when fracturing parallel to natural fractures is 1.3 times of that when fracturing perpendicular to natural fractures. In addition, after optimization of fracturing parameters, we found that the displacement should be controlled at 2–3 cubic meters/min, and the sand ratio should be controlled at 25%. The smaller the horizontal minimum principal stress difference between the fracturing layer and the shielding layer, the lower the elastic modulus, and the easier it is to control the fracture height. Microseismic monitoring results show that the half-fracture length and fracture height are mainly distributed in 80–140 m and 15–25 m, respectively. The optimized fracture half-length was 120 m and the half-fracture height was 20 m. Finally, the well pattern of the target layer is optimized considering natural fractures. Through this study, we found that the reverse five-spot well pattern is suitable for the efficient development of tight oil reservoirs of the Chang 6 Member in this area.

A comprehensive experimental study is performed to investigate the performance of alkali-surfactant (AS) assisted foam flooding as a means of tertiary Enhanced Oil Recovery (EOR) process in post-CHOPS reservoirs (i.e., reservoirs where cold heavy oil production with sand has been employed) and to elucidate how AS-assisted foam (i.e., foam stabilized by AS solutions) EOR of heavy oil is affected by oil-water interfacial tension (IFT) reduction and emulsion formation. Three surfactants (S) and the corresponding alkali-surfactant (AS) solutions with different oil-water IFT and emulsification properties are employed. The stability of foam in the presence of the solubilized oil, the coalescence time of an oil droplet at CO2-water interface (tc), together with the stability and heavy oil viscosity-reducing ability of oil-laden foam (OLF) for different chemical solutions are assessed. The results show that CO2 foam generated by AS(2) solution (with non-ultra-low IFT and the best emulsion stability) in the presence of oil solubilized in micelles is the most stable. Meanwhile, AS(2) OLF exhibits the longest tc and performs the best in improving heavy oil flowability, implying that the importance of emulsion stability and the pseudoemulsion film stability on the OLF stability. Micromodel experiments are performed to help rapidly identify promising AS formulation and to reveal the pore-scale mechanisms involved during AS-assisted foam EOR processes. It is shown that the emulsion stability of chemical solutions plays a key role in recovering heavy oil; despite the greater IFT, due to the formation of more stable oil-in-water emulsion, and the resulting better mobility control, as well as wettability alteration towards more water-wet state, AS(2)-assisted CO2 foam is found to be more favorable for recovering heavy oil (mu(o) = 1850 cP) in post-CHOPS oil reservoirs.

Foam has been used as an effective displacing fluid for gas mobility control in enhanced oil recovery (EOR) and subsurface remediation. In this study, a series of core flooding experiments are performed on cores with a wide permeability ranging from 3.3 to 2749 mD to evaluate the impact of foam quality and permeability on foam performance. It is found that the steady-state foam mobility control factor is related to permeability in a non-linear, non-monotonic manner. A full physics, mechanistic foam model is proposed by incorporating a novel flowing foam fraction relation grounded-up from pore-level observations, and a new kinetic expression of foam coalescence rate by oil based on pinch-off foam rupture mechanism into the population-balance framework of Almajid et al. (Advances in Water Resources, 2021, 150: 103877). The proposed model is applied to match foam flow experimental results in the absence and in the presence of oil. Results show that our model captures the high-quality and low-quality foam regimes observed in previous oil-free foam flow experiments. Within the medium permeability range, in the absence of oil, lower gas mobility is observed in the lower permeability core due to faster foam film thinning at higher capillary pressure, while in the presence of residual oil, the difference in foam mobility fades away due to the insignificant impact of capillary pressure on the stability of pseudoemulsion films.

CO2 foam is a promising candidate in enhanced oil recovery and reducing anthropogenic CO2 emission through geo-sequestration due to its CO2 mobility control ability. However, instability of CO2 foam stabilized solely by surfactant strongly retards its application. Here, two types of silica nanoparticles (NPs) with varied hydrophobicity are used with sodium bis(2-ethylhexyl) sulfosuccinate (AOT) to increase CO2 foam stability. Through foamability and foam stability experiments, together with complementary experiments such as measurements of CO2-water interfacial tensions, particle zeta potential, and adsorption isotherm of surfactant, the stabilization mechanisms of AOT-NPs aqueous dispersions on the CO2 foam films are revealed. Oil recovery experiments are performed in an oil-wet micromodel where high permeability channels are included to mimic wormholes in unconsolidated sandstone reservoirs during sand production. Results show that the nanoparticle surface hydrophobicity strongly influences the interactions between particles and AOT. Partially hydrophobic NPs (NPB) are much more efficient in generating and stabilizing CO2 foam than hydrophilic NPs (NPA) when mixed with AOT in a proportion of 1: 0.16 (wt%/wt%). AOT-NPB dispersions improve the recovery in two aspects: First, the synergistic interactions between AOT and NPB leads to the adsorption of AOT on particle surfaces, thus enhancing mechanical strength of bubbles. High quality foam encompasses a fine foam texture and provides higher resistance to the gas flow, leading to a more uniform sweep. Second, AOT-NPB dispersions reduces oil/water IFT, promotes emulsification forming oil in water (O/W) emulsions, and alters glass surface wettability, leading to substantial incremental oil recovery.