High salinity and high oil content present major challenges to the effectiveness of foam in enhanced oil recovery (EOR). This study introduces RCS, a novel oil-resistant foam system designed for reservoirs with salinity levels reaching 2.1 & times; 10 5 mg/L. RCS forms stable foams at oil-water ratios up to 60% and is effective across a wide crude oil viscosity range (10.8-7890 mPa & sdot;s). We investigated the film properties of oil-containing foam and the co-permeation behavior of the crude oil-N2-foam system to elucidate the mechanisms underlying foam stability and steady-state flow. RCS emulsified high-viscosity crude oil into stable, large droplets that accumulated within the plateau borders, reducing drainage. Even at concentrations as low as 0.01 wt%, RCS formed stable pseudoemulsion films that prevented intrusion into the gas-water interface, allowing the foam half-life to be mainly controlled by the dilatational viscoelasticity of the interface. With increasing oil-water ratios, both drainage resistance and dilatational modulus increased, extending the drainage and foam half-lives. Coreflood experiments showed that co-injection of RCS with N 2 and crude oil produced stable foams and in-situ emulsions. At 5% oil fractional flow, the critical foam quality (fg* ) remained unchanged compared to oil-free conditions, although the maximum apparent viscosity decreased by 29.8%. At 10% oil fractional flow, fg* shifted to a lower value, while the apparent viscosity in the low-quality regime increased markedly-exceeding that of the oil-free condition. These findings highlight that while crude oil more strongly impairs foam stability in porous media than in bulk, the formation of in-situ emulsions can partially offset or even enhance mobility control through a synergistic Jamin effect. Therefore, in-situ emulsification should be emphasized in foam applications within oil-containing environments. (c) 2025 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY license (http://creativecommons.org/licenses/by/4.0/).

At present， the CO2 huff and puff method is mainly used in international oilfields to improve the recovery of shale reservoirs. However， challenges arise during the development stage of high-cycle huff and puff， including poor boundary physical properties， limited regional conventional huff and puff effectiveness， and usability difficulties. Supercritical carbon dioxide （SC-CO2） has the characteristics of low viscosity， high density， and strong solubility. In order to reveal the huff and puff effect of SC-CO2， the CO2 huff and puff test was carried out on the core after SC-CO2 immersion treatment. The influence of the huff and puff period， the shut-in time， and the injection pressure on the enhanced oil recovery （EOR） of SC-CO2 was analyzed. The shale before and after the huff and puff process was scanned using low-field nuclear magnetic resonance technology to analyze the distribution and extraction of oil from the shale matrix pores. The results show that the cumulative recovery of the shale samples after SC-CO2 immersion treatment increases with the increase in huff and puff cycles， while the single-cycle recovery decreases with the increase in huff and puff cycles. The core permeability after immersion increases by 1-2 orders of magnitude， and the porosity increases by 3-4 times； the shale surface becomes more CO2-absorbent. The extraction capacity of SC-CO2 can be increased by extending the shut-in from 6 hours to 24 hours， resulting in an approximately 10% increase in the recovery. The cumulative recovery and the single-cycle recovery of shale increase with the rise in injection pressure. The recovery can increase by 8%-17% When the pressure increases from 6 MPa to 15 MPa. The saturated oil in shale primarily exists in micropores and mesopores in the shale matrix， and the maximum amount of oil is produced within the first cycle of huff and puff.

Underground hydrogen (H2) storage (UHS) is a pivotal technology for large-scale energy storage, yet accurate prediction of H2 plume behavior is critically challenged by the presence of carbon dioxide (CO2) as cushion gas. The vapor-liquid equilibrium (VLE) of H2-CO2-brine systems is essential for estimating storage capacity, but traditional cubic equations of state (EoS) like Peng-Robinson (PR) fail to account for hydrogen bonding in water. A novel compositional model that integrates the electrolyte Peng-Robinson-Cubic-Plus-Association (ePR-CPA) EoS with a modified free-volume (FV) viscosity model is presented to simulate H2 and CO2 geo-storage in saline aquifers. The proposed model accurately predicts VLE, density, and viscosity for H2-CO2-brine systems, demonstrating significant improvements over conventional Enhanced-Predictive-Peng-Robinson (E-PPR78) and Lohrenz-Bray-Clark (LBC) models. The model is implemented within the MATLAB Reservoir Simulation Toolbox (MRST) using both Overall Compositional Formulation (OCF) and Natural Variables Formulation (NVF) and is rigorously validated against commercial simulators (ECLIPSE, CMG) and a fugacity-activity model. The dissolution-diffusion-convection (DDC) process is investigated to assess the influence of salinity and CO2-H2 mixing on the plume. Results reveal that increasing salinity delays the onset of convection and reduces convective flux. Moreover, CO2 serves as a potential cushion gas because its mixing with H2 significantly reduces CO2 solubility and inhibits convective mixing with formation water. This work provides a robust, advanced compositional simulator based on an association EoS, offering a predictive tool for optimizing UHS and CO2 storage operations in saline aquifers.

CO2 channeling severely undermines sweep efficiency in fractured, low-permeability reservoirs, posing a critical challenge to enhanced oil recovery (EOR) and geological carbon sequestration. While foam injection is a proven method for CO2 mobility control in porous media, its performance in rough fracture systems remains insufficiently understood. This study systematically investigated the in-situ generation and transport behavior of three tailored supercritical CO2 foams using a novel high-temperature, high-pressure rough-fracture model under varying surface roughness coefficients (R-s) and injection conditions. Results indicate that increased roughness promotes foam generation through shear-induced disturbances but also accelerates film rupture due to excessive deformation. In low-roughness fractures (R-s <= 1.01), sufficient foam generation is essential, whereas in highroughness fractures (R-s >= 1.05), maintaining foam stability becomes equally important. A synergistic formulation combining hydrocarbon/fluorocarbon surfactants, xanthan gum, and nano-SiO2 enhances interfacial adsorption, increases bulk viscosity, and improves wall friction, achieving a balance between foam generation and stability. These effects are further amplified by optimizing foam quality and exploiting shear-thinning behavior. The findings deepen understanding of foam-fracture interactions and provide practical guidance for improving CO2-EOR and geological sequestration strategies in fractured, low-permeability reservoirs.

多孔介质中,含油泡沫处于破裂与再生的动态平衡.利用Waring Blender法对原油与两性离子表面活性剂(RC)溶液进行重复剪切模拟含油泡沫再生,深入研究RC溶液与不同含量原油(0～60％)作用后,溶液性质及其再生泡沫起泡能力与稳定性的变化规律.结果表明,RC分子在油相及油水界面分配令起泡体系中的RC质量分数显著下降(最大降幅达到72％),原油在RC胶束中增溶令液膜稳定性明显减弱,两者共同作用下,RC溶液的再生泡沫性能严重受损.含油量40％以内,随含油量增加,一次剪切含油泡沫的析液半衰期不断延长直至无油泡沫的2.4倍,而二次剪切含油泡沫的析液半衰期持续降低直至无油泡沫的27％.二次剪切时,由于油水界面张力降低造成油相被乳化为大量小尺寸油滴,无法阻碍排液且易随水相析出,液膜内油量减少,二次剪切含油泡沫的泡沫半衰期与一次剪切含油泡沫相差较小.研究有助于进一步认识含油泡沫的再生行为,并对耐油起泡体系的构建具有积极意义.

Foam flooding is a crucial enhanced oil recovery technique for profile control during the oil displacement process. The stability of the foam is the key factor for the success of foam flooding, but typical aqueous foams generally lose their stability in the presence of hydrocarbons because of their low oil tolerance. Non-aqueous foams possess outstanding stability in the presence of hydrocarbons as a result of their unique properties. However, few studies have been conducted on the stabilization mechanisms of non-aqueous foams in the presence of hydrocarbons. In this study, comparative experiments were performed to investigate differences in the stabilization mechanism between aqueous and non-aqueous foams. The results showed that a non-aqueous foam had excellent oil tolerance in a bulk foaming test. Then, the stabilization mechanisms of foams were investigated in terms of surface dilatational viscoelasticity and liquid film thinning. For a non-aqueous foam system, the maximum viscoelastic modulus of 55 mN/m occurred at a surfactant concentration of 5.0 wt%, which indicated that the foam was more stable. In a foam film thinning experiment, the thinning time of an aqueous foam system was shortened but the liquid film thickness was increased by crude oil, whereas crude oil increased the thinning time of a non-aqueous foam system but decreased its liquid film thickness. In a non-aqueous foam system, the film could remain stable for hours before rupturing, which indicated that its stability in the presence of an oil phase was excellent. These results are meaningful for the understanding of the stabilization mechanisms of oil-based foams and the employment of non-aqueous foams for enhanced oil recovery.

Foam flooding is a crucial enhanced oil recovery technique for profile control during the oil displacement process. The stability of the foam is the key factor for the success of foam flooding, but typical aqueous foams generally lose their stability in the presence of hydrocarbons because of their low oil tolerance. Non-aqueous foams could possess outstanding stability in the presence of hydrocarbons as a result of their unique properties. However, few studies have been conducted on the stabilization mechanisms of non-aqueous foams in the presence of hydrocarbons. In this study, comparative experiments are performed to investigate differences in the stabilization mechanism between aqueous and non-aqueous foams. The results show that a non-aqueous foam had excellent oil tolerance in a bulk foaming test. Then, the stabilization mechanisms of foams are investigated in terms of surface dilatational viscoelasticity and liquid film thinning. For a non-aqueous foam system, the maximum viscoelastic modulus of 55 mN/m occurs at the maximum surfactant concentration used which was 5.0 wt% for this set of tests, which indicates that the liquid film of FS22 non-aqueous foam was more stable. In a foam film thinning experiment, the thinning time of an aqueous foam system is shortened but the liquid film thickness is increased by crude oil, whereas crude oil increased the thinning time of a non-aqueous foam system but decreased its liquid film thickness. In a non-aqueous foam system, the film could remain stable for hours before rupturing, which indicates that its stability in the presence of an oil phase is excellent. These results are meaningful for the understanding of the stabilization mechanisms of oil-based foams and the employment of nonaqueous foams for enhanced oil recovery.

Cocamidopropyl hydroxyl sulfobetaine (CHSB) is one of the most promising foaming agents for high-salinity reservoirs because the salt in place facilitates its foam stability, even with salinity as high as 2 × 105 mg/L. However, the synergistic effects between CHSB and salt have not been fully understood. This study utilized bulk foam tests and thin-film interferometry to comprehensively investigate the macroscopic and microscopic decay processes of CHSB foams with NaCl concentrations ranging from 2.3 × 104 to 2.1 × 105 mg/L. We focused on the dilatational viscoelasticity and dynamic thin-film thickness to elucidate the high-salinity-enhanced foam stability. The increase in dilatational viscoelasticity and supramolecular oscillating structural force (ΠOS) with salinity dominated the superior stability of CHSB foam. With increasing salinity, more CHSB molecules accumulated on the surface with a lower diffusion rate, leading to high dilatational moduli and surface elasticity, thus decelerating coarsening and coalescence. Meanwhile, the number density of micelles in the thin film increased with salinity, resulting in increased ΠOS. Consequently, the energy barrier for stepwise thinning intensified, and the thin-film drainage slowed. This work conduces to understand the mechanisms behind the pronounced stability of betaine foam and can promote the widespread application of foam in harsh reservoirs.

The use of foam as a fluid for gas mobility control has become increasingly popular due to its effectiveness. However, the destabilization of aqueous foam by oil has led to a growing interest in nonaqueous foam. Despite this, there have been limited studies on the dynamic features of nonaqueous foam in fractures. In this study, we investigate the impact of roughness and fracture width on the flow behavior of non-aqueous foam using both microscopic visualization and macroscopic core flooding techniques. We also uncover the regeneration and regulation mechanisms of non-aqueous foam, while establishing a control group of aqueous foam for comparative purposes. Our experimental results show that as the roughness of the fracture increases, the pressure difference generated by both foams also increases, but decreases as the fracture width increases. Moreover, the optimal gas-liquid ratio for aqueous foam is 2:1, while that of nonaqueous foam is 1:2. Nonaqueous foam tends to be captured and deformed when transported through rough fracture surfaces. This deformation causes necking separation, which eventually leads to the generation of new foam. Furthermore, roughness anchors the foam, prolonging its stay in the fracture and increasing seepage resistance. The presence of kerosene in the fractured shale core reduces the stability of nonaqueous foam, as evidenced by a similar to 23.3% decrease in differential pressure.

The stability of betaine foam can be enhanced by salts in reservoirs, even the salinity up to 2×105 mg/L, which offers great potential for cost-effectively improving the gas mobility in high-salinity reservoirs. There is, however, a lack of understanding of the mechanisms behind this behavior. This paper focused on the surface and bulk phase properties of three betaines with alkyl chain lengths of C12 -C21 to probe the mechanisms leading to the high-salinityenhanced foam stability. Combining with the measurements of dilatational viscoelasticity, adsorption behaviors, surface relaxation, and micellar structure, the effects of salinity (2.3×104 -2.1×105 mg/L NaCl) on the surface and bulk phase properties were examined. With increasing salinity, betaine molecules adsorbed on the gas-water surface increased, and the molecule diffusion-exchange between the surface and bulk phase decelerated, resulting in the increased dilatational moduli and surface elasticity. The enhanced dilatational viscoelasticity slowed down the coarsening and coalescence, thus promoting the stability of betaine foam. The foam generated by oleicyl dimethyl amidopropyl carboxybetaine exhibited much stronger stability than the other betaine foams, especially when the NaCl concentration approached 2.1×105 mg/L. The wormlike micelle induced by high salinity dominated its superior stability.

体膨颗粒已广泛应用于高温高盐裂缝性油藏控水,且其封堵效果与颗粒尺寸、颗粒分流率密切相关.采用人工造缝的碳酸盐岩露头岩芯组模拟非均质裂缝储层,在130℃、19.8×104 mg/L条件下进行体膨颗粒裂缝堵水效果评价与改善实验.结果 发现,粒径过大、窄裂缝分流率过高的体膨颗粒可能加剧裂缝产液的非均质性,而粒径过小的体膨颗粒不适用于出水强度较高的储层.将可固化覆膜颗粒与体膨颗粒联用,前者在油藏高温下固化于宽裂缝内形成不可动筛网段塞,令后者从宽裂缝中突破的压力梯度显著高于窄裂缝,进而可有效改善非均质裂缝的产液剖面,并消除因体膨颗粒尺寸、分流率不当对裂缝封堵带来的负面影响.研究有助于进一步认识体膨颗粒的非均质裂缝封堵行为,对提高裂缝油藏的控水效果具有积极意义.

The stability of betaine foam can be enhanced by salts in reservoirs, even with salinity as high as 2 x 10(5) mg/L, which offers great potential for cost-effectively improving the foam performance in high-salinity reservoirs. There is, however, a lack of understanding of the mechanisms behind this behavior. This study focused on the surface and bulk phase properties of three betaines with alkyl chain lengths of C-12-C-21 to probe the mechanisms leading to the high-salinity-enhanced foam stability. The dilatational viscoelasticity, adsorption behavior, surface relaxation, rheology, and thin-film drainage were examined in a wide NaCl range of 2.3 x 10(4) to 2.1 x 10(5) mg/L. With increasing salinity, betaine molecules adsorbed on the gas-water surface increased, and molecule diffusion-exchange between the surface and bulk phase decelerated, resulting in increased dilatational moduli and surface elasticity. The enhanced dilatational viscoelasticity slowed coarsening and coalescence, thus promoting the stability of betaine foam. The foam generated by oleicyl dimethyl amidopropyl carboxybetaine exhibited much stronger stability than the other betaine foams, especially when the NaCl concentration approached 2.1 x 10(5) mg/L. The viscoelastic micelle induced by high salinity dominated its superior stability.

This study is primarily focusing on the adsorption behavior of alkyl polyglucosides (APG) in sandstones under high temperature and salinity, which is rarely reported before. The results indicate that the adsorption quantity of APG on the sandstone surface is concentration dependent and the adsorption process is spontaneous in terms of Gibbs free energy change (Delta G degrees), and the adsorption behavior can be exactly fitted by the Langmuir/Freundlich isotherm models. Under the high temperature, APG adsorption at the sandstone is proven to be an entropy-driven spontaneous process. It is also found that, with increasing of solution salinity, the adsorption quantity on sandstone surface increases sharply. The dynamic adsorption behavior of APG suggests that the saturated adsorption quantity is detected at 0.14-0.31 mg/g in porous media, which is much smaller than that under the static condition. Ultimately, the investigation verifies that APG has certain competitive advantages in terms of IFT reduction, wettability alteration, dynamic adsorption loss, pro-environment and cost, causing a great potential for application in enhanced oil recovery.

Oilfield chemists and engineers have searched a method for intelligent flooding of chemical-intervention-based process with self-regulating mobility in subterranean areas for decades. By designing ...

Preformed-particle-gel (PPG) treatments have been successfully used in injection wells to reduce excessive water production from high-temperature, high-salinity fractured reservoirs. However, PPG itself cannot be used in fractured producers because it tends to wash out after the wells resume production. Therefore, we proposed to combine curable resin-coated particles (CRPs) with PPG to control water production from fractured producers. In this paper, millimeter-sized tubes and fractured carbonate cores were designed to comprehensively investigate water-plugging behaviors of the combined system under the conditions of various fracture parameters and PPG/CRP sizes. Particular attention was given to control the PPG washout after production was resumed. The results showed the cured CRPs could generate immobile packs in fractures and dramatically mitigate the PPG washout. The small size of the CRPs and the small ratio of CRP size to tube diameter contributed low permeability and homogeneity to CRP packs. Meanwhile, the less-permeable and more-homogeneous CRP pack, as well as the larger-sized PPGs, contributed to a higher PPG breakthrough pressure gradient. Moreover, some of the PPG particles blocked in the CRP packs could be released through high-speed brine injection from producers, which indicated the recoverability of the water plugging. This study provides a promising approach to reduce the high-water-cut problem in fractured producers.

Foam flooding (or injection of foam) is a common technology to enhance oil recovery. Although the effects of permeability on foam flooding were well studied in many laboratory experiments, little research has been focused on the specificity of low permeability. In this paper, a series of constant-quality nitrogen foam flow experiments were conducted to investigate the effects of permeability on the foam performance and oil displacement efficiency. Moreover, the results indicated that foam can be generated in low permeability porous media. With uniform experimental conditions, the higher permeability core has a bigger recovery amplification and greater decreasing range of water cut decline. Furthermore, the effect of microscopic heterogeneities of low permeability reservoir on foam displacement is considered. Moreover, experimental comparative analysis with different microscopic heterogeneity cores showed that, in low permeability condition, homogeneous porous media has a better prospects of oil-displacement. Finally, in this work, the results of the permeability effects on the foam performance and oil displacement efficiency exemplify a potential to apply the technology to low permeability reservoir.

A major concern, in the foam flooding projects, is the stability of foam in the presence of oil. In this study we chose three foaming agents with different behaviors in the oil-bearing environments and examined their performance in terms of the emulsified oil and the pseudoemulsion films. The results indicate that the state of the emulsified oil or the pseudoemulsion films has a significant impact on foam stability. Two hypothesizes suggest that the role of emulsified oil played in foam stabilization can be summarized as increasing the emulsion stability and creating the viscous liquid phase, and interfacial adsorption and viscoelastic layers of pseudoemulsion films present a strong correlation with the foam stability. From the foam flooding experiments, the oil-enhanced foam is deemed to be more efficient in the oil displacement and the liquid diversion. [GRAPHICS] .

Preformed particle gel (PPG) treatment has been well-recognized as an efficient method to reduce excessive water production in fractured reservoirs. However, previous research on its plugging efficiency was mainly conducted in open fractures. In this paper, calcite-filled fracture models were designed to comprehensively investigate the water plugging performance of PPG in partially filled fractures which are extremely common in fractured reservoirs. Systematic plugging performance tests have proceeded under various calcite-filling conditions. The results show that the calcite particles can improve the breakthrough and retention of the PPG as well as the plugging efficiency. With increased size and concentration of the calcite particles, the PPG breakthrough pressure gradient increases, and the fracture permeability decreases. When the ratio of average calcite particle diameter to fracture width (R-C) is small (0.15), the fracture permeability is difficult to be further reduced by increasing PPG concentration or PPG size. However, when the R-C increases to 0.21, the plugging performance in fractures filled with more calcite particles or PPG particles, especially the latter, is better than that filled with larger calcite particles. This study provides new insight into the PPG treatment and will contribute to the water control in fractured reservoirs.

Foam has been applied in enhanced oil recovery (EOR) for more than sixty years. The surfactant-stabilized N-2/CO2 foams are two of the most widely used foams in foam EOR processes, and numerous oil reservoirs could potentially benefit from them. This paper comprehensively reviews the development of these foams over the past decade. We focused on the promising surfactant formulas and their corresponding mechanisms under different reservoir conditions, especially harsh conditions. The most recent studies have shown that low interfacial tension foaming surfactants are efficient in fractured/tight reservoirs, while CO2-switchable surfactants are well suited to CO2 foam in carbonate reservoirs with high temperatures. Pure surfactants and mixed surfactants that combine anions and cations contain superior foam properties. The surfactant aggregates, such as vesicles and wormlike micelles, could distinctly enhance the foam stability. However, the adsorption of the mixed surfactants on reservoir rocks and the temperature sensitivity of the complex structures should be given particular consideration. The phase behaviors involved in foam EOR processes are vital and much more complicated than those in other EOR processes. Thus, a better knowledge of the phase behaviors could further improve foam EOR performance. The results of this paper provide clues to N-2/CO2 foam EOR design and also promote the development of harsh reservoirs.

The formation heterogeneity is considered as one of the major factors limiting the application of foam flooding. In this paper, influences of formation properties, such as permeability, permeability distribution, interlayer, sedimentary rhythm and 3D heterogeneity, on the mobility control capability and oil displacement efficiency of foam flooding, were systematically investigated using 2D homogeneous and 2D/3D heterogeneous models under 120 °C and salinity of 20 × 10~4 mg/L. The flow resistance of foam was promoted as the permeability increased, which thus resulted in a considerable oil recovery behavior.In the scenario of the vertical heterogeneous formations, it was observed that the permeability of the high-permeable layer was crucial to foam mobility control, and the positive rhythm appeared favorable to improve the foam flooding performance.The additional oil recovery increased to about 40%. The interlayer was favorable for the increases in mobility reduction factor and oil recovery of foam flooding when the low permeability ratio was involved. For the 3D heterogeneous formations,foam could efficiently adjust the areal and vertical heterogeneity through mobility control and gravity segregation,and thus enhancing the oil recovery to 11%–14%. The results derived from this work may provide some insight for the field test designs of foam flooding.