Search Results (242)

The foaming of hydrogels presents a promising strategy for tailoring mechanical and radiological properties to replicate biological soft tissues for biomedical phantom applications. A computational fluid dynamics (CFD) framework is developed to predict void fraction distribution in alginate hydrogel precursor solutions aerated by air injection through a bottom nozzle. The objective is to use the framework for the design of the foaming system to match the desired gas-fraction distribution and radiological property. Seven parametric cases are investigated, varying inlet air velocity, alginate concentration, and surface tension. Results show that higher inlet velocities promote stronger jet penetration and greater gas accumulation, while increasing alginate concentration confines the bubble plume, with quasi-steady gas fractions displaying a non-monotonic trend with concentration. Elevated surface tension yields broader plume coverage and improved gas distribution uniformity at the expense of peak void fraction. The predicted void fractions map to Hounsfield Unit (HU) values of −34 to −103, corresponding to adipose and fatty breast tissue attenuation (−50 to −150 HU). The peak gas fraction at 5.0 wt% alginate yields −307 HU, approaching published experimental CT measurements for the same formulation (−460 to −233 HU). Full article

Hydrogen is a carbon-free energy carrier that can support decarbonization of the energy and transport systems. Its usage as a fuel in internal combustion engines can abate the pollutants and CO₂ emissions but also presents various challenges. Among these, the formation of under-expanded jets requires proper injector design and accurate control of the injection process. CFD can accelerate the development of hydrogen engine technologies towards market readiness. Low-dissipative density-based schemes are essential to accurately describe the complex flow structures, that affect mixture formation in under-expanded injections. In the present work, the AUSM scheme was implemented in the OpenFOAM library, and successfully used to simulate an experimental hydrogen-into-nitrogen injection. The numerical method, validated against experimental Schlieren images, was compared with the Kurganov–Noelle–Petrova scheme implemented in the current density-based OpenFOAM solver. The numerical results highlighted the reduced dissipation of the AUSM scheme, leading to improved jet penetration and gas mixing. The investigation demonstrated the superior performance of the AUSM scheme, suggesting it as an alternative OpenFOAM solver. Nevertheless, the study identified areas for improvement and critical issues associated with this type of simulations. Full article

Against the backdrop of the global trends toward lightweighting, multi-functionalization, and greening of materials, polypropylene (PP) has been extensively applied owing to its advantages of low density and low cost. However, its inferior foaming performance fails to meet high-end application requirements, which is primarily attributed to its low melt strength and restricted crystallization behavior. In this paper, the five-dimensional selection mechanism and classification of components for PP micro/nanocomposites fabricated via supercritical foaming are systematically summarized. The regulatory effects of micro/nano additives on the crystallization, rheological properties, and foaming behavior of PP are quantitatively analyzed. The parameter optimization windows of three foaming processes, namely batch foaming, extrusion foaming, and injection foaming, are integrated (e.g., a foaming temperature of 150–170 °C and a saturation pressure of 8–20 MPa). Additionally, the application progress of PP micro/nanocomposite foams in fields such as automotive lightweighting (with a weight reduction rate of 64.29%) and building thermal insulation (with a thermal conductivity as low as 29 mW/(m·K)) is outlined. The core novel insight of this work lies in clarifying the unified mechanism of crystal refinement induced by reinforcing agents with different geometric morphologies, which is dominated by the synergy between heterogeneous nucleation and steric hindrance. This finding provides theoretical and technical guidelines for the industrial-scale preparation of high-performance PP foams. Full article

This study addresses high water cut and low recovery in bottom-water sandstone reservoirs by optimizing CO₂ and N₂ foam flooding parameters. The key innovation is the pioneering application of fractal dimension to quantitatively characterize water coning morphology during composite gas flooding. A numerical simulation assessed composite gas type, injection gas ratio, sequence, speed, volume, and injection–production ratio. Fractal dimension quantified water coning. Optimal conditions were: 2:1 injection gas ratio (CO₂ then N₂ foam), 140 t/d injection speed, 0.31 PV volume, and 1:3.2 injection–production ratio. This achieved 39.52% recovery over 15 years—a 4.89% increase, adding 3.17 × 10⁴ t of oil. Fractal dimension fell to 1.672. Sensitivity analysis showed the injection gas ratio most affects oil output. The injection volume best suppresses water coning. The injection speed has low sensitivity. Key interactions exist between volume, gas type, and injection–production ratio. Injection gas ratio, volume, and injection–production ratio are crucial for development control. The proposed methodology presents a viable strategy for enhancing oil recovery in similar reservoirs, with broader implications for advancing CO₂ utilization and supporting carbon management objectives in the petroleum industry. Full article

Carbon dioxide injection is one of the most advanced and commercially proven methods of enhanced hydrocarbon recovery, and CO₂ injection has been shown to be very effective in conventional oil reservoirs and is gaining attention in gas, unconventional, and coalbed methane reservoirs. The advantages of CO₂ injection lie in the favorable phase properties and interactions with reservoir fluids, such as swelling, reduction in oil viscosity, reduction in interfacial tension, and miscible displacement in favorable cases. But the low viscosity and density of CO₂ compared to the reservoir fluids result in unfavorable mobility ratios and gravity override, resulting in sweep efficiency limitations. This review offers a broad and EOR-centric evaluation of the various CO₂ injection methods for a broad array of reservoir types, such as depleted oil reservoirs, gas reservoirs for the purpose of gas recovery, tight gas/sands, as well as coalbed methane reservoirs. Particular attention will be given to the use of mobility control/sweep enhancement techniques such as water alternating gas (CO₂-WAG), foam-assisted CO₂ injection, polymer-assisted WAG processes, as well as hybrid processes that combine the use of CO₂ injection with low salinity or engineered waterflood. Further, recent developments in compositional simulation, fracture-resolving simulation, hysteresis modeling, and data-driven optimization techniques have been highlighted. Operational challenges such as injectivity reduction, asphaltene precipitation, corrosion, and conformance problems have been reviewed, along with the existing methods to mitigate such issues. Finally, key gaps in the current studies have been identified, with an emphasis on the development of EHR processes using CO₂ in complex and low-permeability reservoirs, enhancing the resistance of chemical and foam methods in realistic conditions, and the development of reliable methods for optimizing the process on the field scale. This review article will act as an aid in the technical development process for the implementation of CO₂ injection projects for the recovery of hydrocarbons. Full article

Tight oil reservoirs are widely recognized as a critical successor in global unconventional energy development and are generally characterized by distinct geological features, including fine pore throats, pronounced heterogeneity, and a high concentration of clay minerals (e.g., montmorillonite and mixed-layer illite/smectite). Severe hydration, swelling, and fines migration are readily induced during water injection or conventional water-based fluid operations, thereby resulting in irreversible impairment of reservoir permeability. Despite the excellent injectivity and capacity for viscosity reduction associated with CO₂ flooding, sweep efficiency is severely compromised by viscous fingering and gas channeling, which are induced by the inherent low viscosity of the gas. While CO₂ foam technology is widely acknowledged as a pivotal solution for addressing mobility control challenges, its implementation is hindered by a primary technical bottleneck: the incompatibility between traditional water-based foam systems and strongly water-sensitive reservoirs. A dual challenge comprising water injectivity constraints and gas channeling is presented by strongly water-sensitive tight oil reservoirs. To address these impediments, three emerging low-damage CO₂ foam systems are critically evaluated in this review. First, the synergistic mechanisms of novel quaternary ammonium salts and polymers in inhibiting clay hydration and enhancing foam stability within modified water-based systems are elucidated. Next, the physical isolation strategy of substituting the water phase with a non-aqueous phase (oil/organic solvent) in organic emulsion systems is analyzed, highlighting advantages in wettability alteration and the mitigation of water blocking. Finally, the prospect of waterless operations using CO₂-soluble foam systems—wherein supercritical CO₂ is utilized as a surfactant carrier to generate foam or viscosify fluids via in situ formation water—is discussed. It is revealed by comparative analysis that: (1) Modified water-based systems are identified as the most economically viable option for reservoirs with moderate water sensitivity, wherein cationic stabilizers are utilized to inhibit hydration; (2) Superior wettability alteration and the elimination of aqueous phase damage are provided by organic emulsion systems, rendering them ideal for ultra-sensitive, high-value reservoirs, despite higher solvent costs; (3) CO₂-soluble systems are recognized as the future direction for “waterless” flooding, specifically tailored for ultra-tight formations (<0.1 mD) where injectivity is critical. Current challenges, such as surfactant solubility, high-temperature stability, and cost control, are identified through a comparative analysis of these three systems with respect to structure-activity relationships, rheological properties, damage control capabilities, and economic feasibility. What is more, an outlook is provided on the molecular design of future environmentally sustainable, cost-effective CO₂-philic materials and smart injection strategies. Consequently, theoretical foundations and technical support are established for the efficient exploitation of strongly water-sensitive tight oil reservoirs. By bridging the gap between reservoir damage control and mobility enhancement, this study identifies viable strategies for enhanced oil recovery. Crucially, it supports carbon neutrality and sustainable energy targets via CCUS integration. Full article

Enhanced oil recovery (EOR) in fractured reservoirs presents significant challenges due to fluid channeling and poor sweep efficiency. In this study, a synergistic EOR system was developed with polymer-based weak gel as the primary component and foam as the auxiliary enhancer. The system utilizes a low-concentration polymer (1000 mg·L⁻¹) that forms a weakly cross-linked three-dimensional viscoelastic gel network in the aqueous phase, inheriting the core functions of viscosity enhancement and profile control from polymer flooding. Foam acts as an auxiliary component, leveraging the high sweep efficiency and strong displacement capability of gas in fractures. These two components synergistically create a multiscale enhancement mechanism of “bulk-phase stability control and interfacial-driven displacement.” Systematic screening of seven foaming agents identified an optimal formulation of 0.5% SDS and 1000 mg·L⁻¹ polymer. Two-dimensional visual flow experiments demonstrated that the polymer-induced gel network significantly improves mobility control and sweep efficiency under various injection volumes (0.1–0.7 PV) and gravity segregation conditions. Numerical simulation in a 3D fractured network model confirmed the superiority of this enhanced system, achieving a final oil recovery rate of 75%, significantly outperforming gas flooding (65%) and water flooding (59%). These findings confirm that weakly cross-linked polymer gels serve as the principal EOR material, with foam providing complementary reinforcement, offering robust conformance control and enhanced recovery potential in fracture-dominated reservoirs. Full article

Severe reservoir heterogeneity in offshore oilfields often leads to dominant flow channels, high water cut, and low sweep efficiency during long-term water flooding. In this study, an in situ self-assembled composite foam system combining soft polymer particles with a low-interfacial-tension foaming agent was developed for profile control and enhanced oil recovery (EOR) in offshore heterogeneous reservoirs. The self-assembly characteristics and physicochemical properties of different particle systems were evaluated to optimize the composite foam structure. Static and dynamic experiments were conducted to assess foam stability, plugging performance, injectivity behavior, and oil displacement efficiency. Results show that the optimized composite foam undergoes in situ self-assembly under reservoir conditions, forming a stable particle–foam structure that enhances selective plugging and mobility control. Core flooding experiments demonstrate that the system increases oil recovery by up to 27.2% across a wide permeability range. Field application further confirms its effectiveness in regulating interlayer water absorption, stabilizing injection pressure, and reducing water cut. These results indicate that the proposed in situ self-assembled composite foam is a promising technique for integrated profile control and enhanced oil recovery in offshore heterogeneous reservoirs. Full article

The N Oilfield is the first offshore extra-heavy oilfield developed using thermal recovery methods, adopting cyclic steam stimulation (CSS) and commissioned in 2022. The development of offshore heavy oil reservoirs is confronted with numerous technical and operational challenges. Key constraints include limited platform space, stringent economic thresholds for single-well production, and elevated operational risks, collectively contributing to significant uncertainties in project viability. For effective exploitation of the target oilfield, a comprehensive strategy was proposed, which consisted of effective artificial lifting, steam channeling and high water cut treatment. First, to achieve efficient artificial lifting of the extra-heavy oil, an integrated injection–production lifting technology using jet pump was designed and implemented. In addition, during the first steam injection cycle, challenges such as inter-well steam channeling, high water cut, and an excessive water recovery ratio were encountered. Subsequent analysis indicated that low-quality reservoir intervals were the dominant sources of unwanted water production and preferential steam channeling pathways. To address these problems, a suite of efficiency-enhancing technologies was established, including regional steam injection for channeling suppression, classification-based water shutoff and control, and production regime optimization. Given the significant variations in geological conditions and production dynamics among different types of high-water-cut wells, a single plugging agent system proved inadequate for their diverse requirements. Therefore, customized water control countermeasures were formulated for specific well types, and a suite of plugging agent systems with tailored properties was subsequently developed, including high-temperature-resistant N₂ foam, high-temperature-degradable gel, and high-strength ultra-fine cement systems. To date, regional steam injection has been implemented in 10 well groups, water control measures have been applied to 12 wells, and production regimes optimization has been implemented in 5 wells. Up to the current production round, no steam channeling has been observed in the well groups after thermal treatment. Compared with the pre-measurement stage, the average water cut per well decreased by 10%. During the three-year production cycle, the average daily oil production per well increased by 10%, the cumulative oil increment of the oilfield reached 15,000 tons, and the total crude oil production exceeded 800,000 tons. This study provides practical technical insights for the large-scale and efficient development of extra-heavy oil reservoirs in the Bohai Oilfield and offers a valuable reference for similar reservoirs worldwide. Full article

Efficient soil conditioning is critical for controlling the mechanical behavior of sandy muck in earth pressure balance (EPB) shield tunneling. This study investigates the undrained shear response of sand conditioned with slurry, a newly developed bubble–slurry, and foam under vertical stresses of 0–300 kPa, considering different injection ratios and shear rates. Under atmospheric pressure, conditioning reduces both peak and residual shear strengths by more than 90% compared with untreated sand. Foam- and bubble–slurry-conditioned sands show stable strength within 6 h; after 24 h, peak strength increases from 0.39 to 4.67 kPa for foam-conditioned sand but only from 0.67 to 0.84 kPa for bubble–slurry-conditioned sand. Shear strength increases nearly linearly with shear rate, especially for residual strength. Pore-scale mechanisms were interpreted by considering bubble proportion and size, pore-fluid rheology, and surface tension. Rheology governs whether dynamic or viscous resistance dominates at different shear rates, while surface tension influences stress transmission through bubble stability and interparticle lubrication. The void ratio range of e/e_max = 1.00–1.36 was identified as achieving low shear strength and good flowability. Field application in Jinan Metro Line R2 confirmed that combined conditioning (25% foam + 13% slurry) reduced cutterhead torque by about 37% without spewing. Full article

Foam is a field-proven technique to reduce CO₂ mobility and mitigate the impacts of reservoir heterogeneity in CO₂-enhanced oil recovery (CO₂-EOR). However, foams are unstable and tend to break down in the presence of oil. Screening foam generation and stability in the presence of oil, at representative reservoir pressure and temperature, at core-scale is critical for successful upscaling. This study investigates the effect of oil on foam generation and stability across a range of foam qualities (f_g = 0.30 to 1.0) and injection velocities (4 ft/day to 16 ft/day). Foam quality and rate scans using Bentheimer sandstone cores were conducted in presence/absence of oil (n-decane and Troll crude) at reservoir conditions (60 °C and 180 bar). Foam quality scans co-injected supercritical CO₂ and foaming solutions with increasing foam quality (f_g = 0.30 to 1.0) to determine the optimal foam quality (highest apparent viscosity foam). T optimal foam quality was then used in rate scans to determine the effect of injection velocity on foam strength. In addition, two separate core floods at two fixed foam qualities (f_g = 0.30 and 0.70) were performed to determine the oil recovery factor during foam injection. Strong foam was generated, in both the presence and absence of oil, but oil significantly reduced foam strength. The foam apparent viscosity was reduced by ~93% (Troll crude) and ~90% (n-decane) compared to foam in the absence of oil. Increasing the surfactant concentration from 0.10 wt.% to 1.0 wt.% significantly enhanced the foam mobility control, with the apparent viscosity in the presence of oil increasing from 7.9 cP to 25.9 cP. The optimal foam quality in the presence of both oils ranged from f_g = 0.60 to 0.70. Foam rate scans revealed shear-thinning rheology (foam viscosity decreased at higher flow rates), which is beneficial for maintaining field-scale injectivity. This study provides critical insights into how oil impacts supercritical CO₂ foam strength, stability mechanisms, and oil recovery at reservoir conditions, crucial for field-scale implementation in CO₂-EOR and CO₂ storage projects. Full article

Background: The treatment of soft tissue vascular anomalies is a challenge in materials science, requiring injectable biomaterials that can conform to complex lesion architectures while providing controlled drug delivery. Conventional liquid sclerosants fail due to poor localization. This study reports on the formulation and clinical performance of an in situ-forming, drug-eluting composite foam designed to overcome these limitations. Methods: A multicomponent composite foam was formulated from a liquid phase containing bleomycin and polidocanol and a gaseous phase of room air using a standardized Tessari emulsification technique. The therapeutic performance of this composite was evaluated retrospectively in 14 patients with high-risk airway venous malformations (AVMs) by quantifying lesion volume reduction on magnetic resonance imaging (MRI) and assessing clinical outcomes. Biocompatibility was determined by monitoring adverse tissue reactions. Results: The injectable composite foam demonstrated superior clinical performance with a 100% therapeutic response rate. Full target lesion ablation, defined as a complete response, was achieved in 10 of 14 cases (71.4%), demonstrating the composite’s high efficacy. The material exhibited excellent biocompatibility, with adverse events limited to minor, localized mucosal necrosis (21.4%) that resolved without intervention, indicating predictable material-tissue interaction. Conclusions: The bleomycin-polidocanol composite foam is an effective, therapeutic biomaterial whose performance is directly linked to its unique physicochemical structure. This work validates a material-based strategy for treating complex vascular lesions and highlights the potential for further optimization of such injectable composites by enhancing their long-term stability. Full article

Fractured-vuggy carbonate reservoirs primarily have pores and caves as their main storage spaces with poor fracture development, resulting in low reservoir connectivity and strong heterogeneity. During nitrogen injection developments, the fluidity of the medium is poor, and gas tends to form dominant flow channels, leading to a short response time. Consequently, the displacement of crude oil in such reservoirs is limited, leaving a large proportion of residual oil trapped within the pore and vug systems. Based on the Tarim fractured-vuggy carbonate reservoir, a two-dimensional visualized physical model of the fractured-vuggy body was designed and constructed to conduct a foam-assisted gas displacement physical experiment. The research shows that foam has good oil recovery efficiency and dominant channel-blocking ability, which can effectively mobilize the residual oil in the fractures and vugs after gas displacement. In the vertical direction, the foam-assisted gas flooding mechanism primarily involves gravity segregation and interfacial tension reduction between oil and water; horizontally, it operates by selectively blocking large fractures and main channels, redirecting gas into smaller and more tortuous pathways, thus enhancing overall sweep efficiency. Once dominant flow channels develop, injecting salt-sensitive foam at a 2:1 gas–liquid ratio and 0.3 pore volume can raise the recovery factor from around 3% to nearly 19%, representing an improvement of about 16%, thereby boosting both gas flooding performance and overall field development efficiency. Full article

Cyclic solvent injection (CSI) with CO₂ is a promising non-thermal enhanced oil recovery (EOR) method for heavy oil reservoirs that also supports CO₂ sequestration. However, its effectiveness is limited by short foamy oil flow durations and low CO₂ utilization. This study explores how waterflooding and nanoparticle-assisted flooding can enhance CO₂-CSI performance through experimental and numerical approaches. Three sandpack experiments were conducted: (1) a baseline CO₂-CSI process, (2) a waterflood-assisted CSI process, and (3) a hybrid sequence integrating CSI, waterflooding, and nanoparticle flooding. The results show that waterflooding prior to CSI increased oil recovery from 30.9% to 38.9% under high-pressure conditions and from 26.9% to 28.8% under low pressure, while also extending production duration. When normalized to the oil saturation at the start of CSI, the Effective Recovery Index (ERI) increased significantly, confirming improved per-unit recovery efficiency, while nanoparticle flooding further contributed an additional 5.9% recovery by stabilizing CO₂ foam. The CO₂-CSI process achieved a maximum CO₂ sequestration rate of up to 5.8% per cycle, which exhibited a positive correlation with oil production. Numerical simulation achieved satisfactory history matching and captured key trends such as changes in relative permeability and gas saturation. Overall, the integrated CSI strategy achieved a total oil recovery factor of approximately 70% and improved CO₂ sequestration efficiency. This work demonstrates that combining waterflooding and nanoparticle injection with CO₂-CSI can enhance both oil recovery and CO₂ sequestration, offering a framework for optimizing low-carbon EOR processes. Full article

The rising level of atmospheric carbon dioxide (CO₂) is a major driver of climate change, highlighting the need to develop carbon capture and storage (CCS) technologies quickly. This paper offers a comparative review of three main groups of porous adsorbent materials—zeolites, metal–organic frameworks (MOFs), and activated carbons—for their roles in CO₂ capture and long-term storage. By examining their structural features, adsorption capacities, moisture stability, and economic viability, the strengths and weaknesses of each material are assessed. Additionally, five different methods for delivering these materials into depleted oil and gas reservoirs are discussed: direct suspension injection, polymer-assisted transport, foam-assisted delivery, encapsulation with controlled release, and preformed particle gels. The potential of hybrid systems, such as MOF–carbon composites and polymer-functionalized materials, is also examined for improved selectivity and durability in underground environments. This research aims to connect materials science with subsurface engineering, helping guide the selection and use of adsorbent materials in real-world CCS applications. The findings support the optimization of CCS deployment and contribute to broader climate change efforts and the goal of achieving net-zero emissions. Key findings include CO₂ adsorption capacities of 3.5–8.0 mmol/g and surface areas up to 7000 m²/g, with MOFs demonstrating the highest uptake and activated carbons offering cost-effective performance. Full article