Search Results (64)

Hydraulic flushing is an effective permeability enhancement technology for coal seams in underground coal mines and has been widely applied in several mining areas in China. However, in low-permeability coal seams, gas drainage from hydraulic flushing boreholes often enters a rapid depletion phase, and achieving secondary enhanced drainage remains a critical challenge. To address this issue, this study investigates a synergistic gas drainage technology that combines gas injection displacement with hydraulic flushing. Taking the No. 3 coal seam in the Lu’an mining area of China as the research object, the optimal process parameters of this synergistic technology are systematically determined through numerical simulation and validated by underground field tests. A fully coupled numerical model incorporating the adsorption–desorption–seepage processes of the CH₄/N₂/O₂ ternary gas system is established. The influences of injection spacing and injection pressure on drainage performance are systematically analyzed. Simulation results identify the optimal process parameters as an injection spacing of 3.5 m and an injection pressure of 1.4 MPa. Under these conditions, the relative coal permeability reaches a maximum of 1.06, the permeability enhancement zone fully covers the region between the injection and drainage boreholes, and the coal seam gas content decreases to the critical threshold of 8 m³/t in approximately 235 days. The model is quantitatively validated using 82-day field monitoring data from the synergistic module, with a relative error of approximately 1.1% between the simulated and field-derived recovery ratios. Subsequently, four sets of underground engineering trials—conventional drainage, gas injection displacement alone, hydraulic flushing alone, and the synergistic technology—are conducted in the target coal seam based on the optimized parameters. Statistical analysis of the 82-day field data shows that the synergistic technology achieves a cumulative pure methane volume of 4.83 m³, outperforming conventional drainage by 85.8% (4.83 m³ compared with 2.60 m³), gas injection alone by 23.5% (4.83 m³ compared with 3.91 m³), and hydraulic flushing alone by 52.4% (4.83 m³ compared with 3.17 m³). The mean flow rate of the synergistic module during the injection phase reaches 0.070 ± 0.012 L/min, significantly higher than that of gas injection alone (0.044 ± 0.011 L/min). This study provides economically feasible theoretical and technical support for efficient gas drainage in low-permeability coal seams in underground mines. Full article

Background/Objectives: Primary acquired lacrimal drainage obstruction (PALDO) is a common cause of epiphora. Although dacryoendoscopic recanalization (DER) is widely performed, its long-term success is limited by restenosis related to fibro-inflammatory processes. This study aimed to evaluate the efficacy of a novel Q-needle for targeted intraductal delivery of antifibrotic and anti-inflammatory agents during DER. Methods: A retrospective review was performed on 190 eyes treated with DER, silicone tube intubation (SI), and retrograde intraductal injection via the inferior meatus using a Q-needle. A mixture of dexamethasone (1 mL), 5-fluorouracil (1 mL), and triamcinolone acetonide (1 mL) was administered directly into the obstruction site under endoscopic visualization. Obstruction type was classified intraoperatively as secretory or structural based on dacryoendoscopic findings. Results: The overall surgical success rate was 92.1%, with significantly greater success in secretory-type PALDO compared to the structural type (96.8% vs. 87.4%, p = 0.031). These outcomes contrast with previous reports in which secretory-type PALDO was associated with poorer prognosis after DER. Conclusions: The improved outcomes in the secretory group suggest a potential role of combined antiproliferative and multi-phase anti-inflammatory therapy in effectively addressing the key mechanisms of restenosis. Q-needle–assisted intraductal injection during DER may represent a simple and safe adjunctive approach to improve surgical consistency and long-term patency in patients with PALDO. Full article

Gas condensate banking can significantly reduce near-well gas productivity by as much as ~60% in tight gas reservoirs. Existing treatment techniques are resource demanding and could alter the reservoir structure permanently. This study investigates the effectiveness of enhanced electrokinetic oil recovery (EK-EOR) as a low-impact alternative for treating condensate banks. Using compositional reservoir simulation (CMG GEM), the influence of key reservoir and operational parameters—porosity, permeability, producer well location (i, j), injection rate, and injection pressure—on cumulative gas production (CGP) was examined. A Box–Behnken design of experiments was employed to generate 62 simulation runs, and a proxy model was developed to approximate full-field responses. Statistical validation showed strong model fidelity (R² = 0.99, AAPE = 2.2%). The proxy was then optimized using a genetic algorithm (GA) to identify conditions that maximize gas recovery. Results indicate that lower injection rates and lower injection pressures maximize CGP through enhanced electro-osmotic flow and reduced water blocking, achieving a peak cumulative gas of 4.06 × 10⁸ ft³. A secondary optimum at high injection pressure could be attributed to re-pressurization and partial re-vaporization of condensate near the wellbore. Reservoir quality also exerted a strong control: higher permeability and moderate porosity favoured gas yield, while optimal producer placement near the reservoir boundary increased drainage efficiency. This study demonstrates a systematic optimization framework combining design of experiments, proxy modelling, and evolutionary algorithms to evaluate EK-EOR performance. Full article

Economic gas recovery from shale reservoirs is inherently difficult because of the extremely low permeability of these formations. To overcome this challenge, horizontal wells are drilled and subjected to multi-stage hydraulic fracturing treatments, which generate high-conductivity flow pathways. The adoption of these technologies has significantly boosted the economic recovery of gas from shale formations, particularly the Marcellus Shale, which stands as the most productive shale gas play in the United States. The effectiveness of a fracturing treatment in enabling economic gas production from shale reservoirs is governed by the characteristics of the fractures it creates. The propagation of initial fracture, during multi-stage hydraulic fracturing, modifies the initial stress conditions in the surrounding area, commonly referred to as a “stress shadow.” The stress shadow restricts the initiation and subsequent propagation of later fracture stages, leading to the development of less favorable fracture properties. As a result, the uneven contribution of individual fracture stages to gas flow ultimately diminishes overall gas recovery from the horizontal well. For efficient gas drainage from the shale, the fracture stages are often closely spaced. When fracture stages are placed in close proximity, the stress shadow effect can be intensified. Thus, accounting for the stress shadow is essential in the design of hydraulic fracture treatments. This study investigates how fracture spacing, injected fluid volume, and fluid type influence the magnitude of the stress shadow effect, its impact on fracture properties, and the resulting gas recovery from the Marcellus Shale. The goal is to facilitate the optimization of the hydraulic fracture design to mitigate the stress shadow impact and enhance gas production. Data from several Marcellus Shale horizontal wells, along with published findings, were compiled and analyzed to determine the petrophysical and geomechanical characteristics of the formation. These results were then used to construct a reservoir model representative of a Marcellus Shale horizontal well. Fracture properties, altered by the stress shadow, were assessed through hydraulic fracturing simulations and incorporated into the model. Ultimately, the reservoir model was employed to predict the production performance. The results of the investigation confirmed that close stage spacing intensifies the impact of the stress shadow. The stress shadow was found to impair fracture conductivity which negatively impacted gas recovery. The negative impact of the stress shadow on gas recovery was observed to gradually diminish as the production rate declined over time. The volume and type of the fluid injected during fracturing treatment can amplify the stress shadow’s impact. Full article

In response to the issues of low synergy efficiency between gas extraction and water injection, unclear procedural connections, and high costs in coal mine gas disaster prevention, this paper proposes a collaborative prevention technology for coal mine gas disasters termed “pump–injection–lock.” First, based on the kinetics of gas desorption in gas-bearing coal under different water-bearing conditions, an optimization model for the sequence of gas extraction and high-pressure water injection was developed. This model reduced the gas desorption rate in the experimental area by 32.5% and increased the effective extraction radius of boreholes by 18.7%. Second, based on the coupling relationship between water lock formation pressure, interfacial tension, and pore structure, a criterion model for process transition was constructed, enabling quantifiable identification of the transition node between “pump–injection.” The water lock’s inhibition of gas release duration was improved by over 25% compared to conventional water injection. Finally, by integrating the multiple effects of high-pressure water injection—enhancing permeability, softening, displacement, and flow limitation—a “multi-purpose” synergistic pathway was established. This increased the pre-drainage gas concentration in the test working face by 40%, the pure gas extraction volume by 28%, and reduced gas over-limit incidents by over 50%. Experiments and industrial trials demonstrated that the application of this technology in the 15^# coal seam of Yixin Coal Mine shortened gas extraction by 36%, reduced borehole engineering by 72.8%, eliminated gas over-limit incidents during mining, and cumulatively generated economic benefits exceeding 425 million yuan in the same year, significantly improving the efficiency and cost-effectiveness of gas disaster prevention. Full article

To address the issues of high energy consumption and high carbon emissions associated with the steam injection development of ultra-heavy oil in China, technological exploration focusing on electrical heating and solvent substitution was conducted. Firstly, experiments on the heat transfer and temperature rise characteristics in the near-wellbore formation via electrical heating revealed its feasibility. Considering that ultra-heavy oil reservoirs in China suitable for Steam-Assisted Gravity Drainage (SAGD) have already been converted to SAGD production, and considering the certain safety risks of solvent extraction, a development strategy of SAGD—Electrical Heating Solvent Extraction—SAGD was formulated. A multi-stage drainage theoretical model coupling SAGD with electrical heating solvent extraction was established. The similarity criteria for 3D-scaled physical simulation of electrical-heating-assisted production were derived. Through three-stage (SAGD—Electrical Heating Solvent Extraction—SAGD) scaled physical simulation experiments, the development performance of converting a SAGD-developed reservoir to thermal solvent extraction was analyzed. Results indicate that the higher the oil content in the electrically heated wellbore and nearby formation, the faster the heat transfer rate. This confirmed the decision to conduct experiments on electrical-heating-assisted solvent extraction (without steam injection) in SAGD-developed reservoirs. After the SAGD steam chamber reaches the top, switching to electrical heating solvent extraction results in a drainage zone along the flanks of the horizontal section comprising: a high-temperature zone of vaporized solvent from electrical heating, a medium-low temperature oil dissolution zone from the solvent, and an untouched zone. Along the horizontal section, it is divided into a solvent chamber rising zone, a slow expansion zone, and a rapid expansion zone. Experiments confirmed that electrical heating can vaporize the solvent, continuously expanding the drainage chamber scale. Furthermore, the solvent continues to function in the subsequent SAGD stage, increasing the recovery factor from 64.4% to 71.2%, an improvement of 6.9%. The established multi-stage coupled drainage theoretical model, compared with experimental and analytical calculations, showed an overall agreement rate of 95.3%, and can be used for production prediction in electrical-heating-assisted solvent extraction composite recovery. Full article

Gel treatments have been widely applied to control water production in oil and gas reservoirs. However, for water shutoff in dense gas reservoirs, most gel-based treatments focus on individual wells rather than the entire reservoir, exhibiting limited treatment depth, poor durability, and inadequate repeatability Notably, formation damage is a primary consideration in treatment design—most dense gas reservoirs have a permeability of less than 1 mD, making them highly susceptible to damage by formation water, let alone viscous polymer gels. Constrained by well completion methods, gelant can only be bullheaded into deep gas wells in most scenarios. Due to the poor gas/water selective plugging capability of conventional gels, the injected gelant tends to enter both gas and water zones, simultaneously plugging fluid flow in both. Although several techniques have been developed to re-establish gas flow paths post-treatment, treating gas-producing zones remains risky when no effective barrier exists between water and gas strata. Additionally, most water/gas selective plugging materials lack sufficient thermal stability under high-temperature and high-salinity (HTHS) gas reservoir conditions, and their injectivity and field feasibility still require further optimization. To address these challenges, treatment design should be optimized using non-selective gel materials, shifting the focus from directly preventing formation water invasion into individual wells to mitigating or slowing water invasion across the entire gas reservoir. This approach can be achieved by placing large-volume gels along major water flow paths via fully watered-out wells located at structurally lower positions. Furthermore, the drainage capacity of these wells can be preserved by displacing the gel slug to the far-wellbore region, thereby dissipating water-driven energy. This study evaluates the viability of placing gels in fully watered-out wells at structurally lower positions in an edge-water drive gas reservoir to slow water invasion into structurally higher production wells interconnected via numerous microfractures and high-permeability streaks. The gel system primarily comprises polyethyleneimine (PEI), a terpolymer, and nanofibers. Key properties of the gel system are as follows: Static gelation time: 6 h; Elastic modulus of fully crosslinked gel: 8.6 Pa; Thermal stability: Stable in formation water at 130 °C for over 3 months; Injectivity: Easily placed in a 219 mD rock matrix with an injection pressure gradient of 0.8 MPa/m at an injection rate of 1 mL/min; and Plugging performance: Excellent sealing effect on microfractures, with a water breakthrough pressure gradient of 2.25 MPa/m in 0.1 mm fractures. During field implementation, cyclic gelant injections combined with over-displacement techniques were employed to push the gel slug deep into the reservoir while maintaining well drainage capacity. The total volumes of injected fluid and gelant were 2865 m³ and 1400 m³, respectively. Production data and tracer test results from adjacent wells confirmed that the water invasion rate was successfully reduced from 59 m/d to 35 m/d. The pilot test results validate that placing gels in fully watered-out wells at structurally lower positions is a viable strategy to protect the production of gas wells at structurally higher positions. Full article

Hydraulic fracturing is a widely used stimulation technology in coalbed methane (CBM) fields. However, the coal reservoir damage caused by high-pressure hydraulic fracturing seriously affects the production effects, and the mechanism is not clear. Therefore, based on high-pressure water injection (HPWI), Fourier transform infrared spectroscopy (FTIR), and contact angle tests, the effects of HPWI on surface chemical properties and wettability of different rank coals were studied. The FTIR results show that surface functional groups of different rank coals have changed to varying degrees after HPWI. After HPWI, the content of Ash in Shaqu and Yonghong coal decreases by 2.29% and 27.91%, while it increases by 297.87% in Shaping coal. The C–O bond content in Shaping and Yonghong coal decreases by 6.32% and 15.19%, while the C–O bond content in Shaqu coal increases by 50.96%. The content of C=O in Shaping and Yonghong coal increases by 2.44% and 27.84%, respectively. The R₂CH₂ contents increase by 19.75% and 12.5% in Shaping and Shaqu coal, while decreasing by 6.48% in Yonghong coal. The RCH₃ content increases by 21.11% in Yonghong coal, while it decreases by 19.09% and 24.01% in Shaping and Shaqu coal. The content of cyclic associated hydroxy–hydrogen bond decreases by 41.25%, 63.92% and 65.86% in Shaping, Shaqu, and Yonghong coals, and the content of free hydroxyl group increases by 57.92%, 58.42%, and 93.71%. The f_ar^c of coal remains almost unchanged, the DOC increases by 20.21%, 126.77% and 0.24% in Shaping, Shaqu, and Yonghong coals, and the I decreases by 16.67% and 51.46% in Shaping and Yonghong coals, indicating that the ordering of coal becomes better, and the content of methylene carbon in the form of long straight chain increases after HPWI. The complexity and differences of changes in functional groups are mainly due to differences in coal structures caused by coalification. The contact angle tests show that the wetting contact angle of different rank coals decreased by 2.30% to 14.50%, revealing that the hydrophilicity of coals increases after HPWI. The decline rate of wetting angles in medium and high-rank coals was significantly higher than that of low-rank coal. This phenomenon discovered that the increase in hydrophilic functional groups caused by HPWI action leads to an increase in the hydrophilicity of coal samples, which is not conducive to the drainage efficiency in CBM development. Full article

Solvent-assisted steam-assisted gravity drainage (SA-SAGD) is an advanced hybrid oil recovery technique designed to enhance the extraction of heavy oil and bitumen. Unlike the conventional SAGD process, which relies solely on thermal energy from injected steam, SA-SAGD incorporates a coinjected solvent phase to improve oil mobility through the combined action of heat and mass transfer. This synergistic mechanism significantly reduces the demand for water and natural gas used in steam generation, thereby improving the energy efficiency and environmental sustainability of the process. Importantly, SA-SAGD retains the same well pair configuration as SAGD, meaning that its implementation often requires minimal modifications to existing infrastructure. This study explores the residual oil saturation following multi-component solvent coinjection in SA-SAGD using a linear sand pack model designed to emulate the properties and operational parameters of the Long Lake reservoir. Experiments were conducted with varying constant concentrations of cracked naphtha and gas condensate to assess their effectiveness in enhancing bitumen recovery. The results reveal that the injection of 15 vol% cracked naphtha achieved the lowest residual oil saturation and the highest rate of oil recovery, indicating superior solvent performance. Notably, gas condensate at just 5 vol% concentration outperformed 10 vol% cracked naphtha, demonstrating its effectiveness even at lower concentrations. These findings provide valuable insight into the phase behaviour and recovery dynamics of solvent–steam coinjection systems. The results strongly support the strategic selection of solvent type and concentration to optimise recovery efficiency while minimising steam consumption. Furthermore, the outcomes offer a robust basis for calibrating reservoir simulation models to improve the design and field-scale application of SA-SAGD, particularly in pilot operations such as those conducted by Nexen Energy ULC in the Athabasca Oil Sands. Full article

Introduction: Axillary reverse mapping (ARM) aims to reduce the risk of breast cancer-related lymphedema (BCRL) by preserving and limiting dissection of arm-draining lymphatics. The ideal type of dye and the location of injection, which maximize the sparing of lymphatics and improve outcomes of immediate lymphatic reconstruction (ILR), remain under-studied. The current literature reports inconsistent visualization of lymphatics using blue dye alone, whereas indocyanine green (ICG) near-infrared (NIR) lymphography has shown improved rates. However, optimized dual-dye workflows integrating breast–plastics co-surgery are lacking. Methods: A retrospective review of patients who underwent ILR following ALND for breast cancer between June 2021 and June 2023 was conducted. Patients who underwent ARM using our dual-dye technique were included, utilizing intradermal injections of indocyanine green (ICG) into the wrist and isosulfan blue (ISB) into the upper arm. Axillary reverse mapping channels were categorized by the type of dye used to visualize. Dye injection site, number of lymphatic channels visualized, channel diameter (mm), time-to-first channel, coordinates relative to fixed landmarks, ILR configuration, and pathologic findings were reviewed. Mann–Whitney U tests were used to compare channel visualization rates between types of dye. Results: Of 26 patients, 21 underwent dual-dye mapping and were included. A total of 115 ARM channels were identified: 99 (86%) via ICG and 29 (25%) via ISB. A total of 64 lymphaticovenous anastomoses were performed (mean: 2.46 per patient). Both dyes were identified in the axilla in only 11.7% of patients. At the end of the study, the lymphedema rate was 12%. Conclusions: We developed a reproducible dual-dye ARM technique for ALND with planned ILR, reducing lymphedema risk while maintaining oncologic safety. Dual-dye mapping reveals that proximal and distal lymphatics exhibit both overlapping and divergent drainage to axillary nodes. ICG’s higher axillary detection rate may reflect true anatomical differences or dye properties. These findings support the need for individualized lymphatic mapping during breast cancer surgery to guide preservation techniques and reduce the risk of BCRL. Full article

In recent years, rapid advancements in glaucoma research have led to the development of more effective treatments of this chronic and irreversible condition. Of these, Kahook Blade Dual (KDB) goniotomy and second-generation trabecular micro-bypass stent (iStent) are two novel biomimetic procedures which have designs inspired by the eye’s natural drainage mechanisms. In this retrospective study, we evaluated the safety and effectiveness of both surgeries by including 176 eyes from 110 patients: 142 eyes in the iStent group and 34 in the KDB group. The primary outcomes of this study were the proportions of patients in each group attaining a 20% reduction in IOP and a post-operative IOP < 19 mmHg. At the last follow-up, a 20% reduction in IOP was achieved by 67% of iStent inject patients and 50% of KDB patients (p = 0.07). The iStent group also showed a higher proportion of patients reaching an IOP of less than 19 mmHg (81% vs. 71% in the KDB group, p = 0.13). The number of medications did not decrease in either group from pre-op to the last follow-up. The KDB group had more failures (29.4% vs. 4.2%) and a significantly higher adverse event rate than the iStent inject group (47.1% vs 12.0%). Full article

The steam flooding–gravity drainage technology has become one of the effective alternative development methods in the middle and later stages of thin-layer ultra-viscous oil steam throughput, with predicted recovery rate of over 50%. Currently, there is a lack of relevant technical research on the composite swallowing and spitting preheating stage. This is in response to the slow preheating of the oilfield and the large differences in connectivity between injection and production wells. The dynamic analysis method was used to analyze the key factors that restrict the efficient connectivity of steam throughput preheating. Based on this, a series steam throughput preheating efficient connectivity technologies were proposed. Physical simulation, numerical simulation, and other methods were used to characterize and demonstrate the technical principles and operating of the efficient connectivity technology. The research results were successfully applied to the super-viscous oil reservoirs of the Fengcheng oilfield in Xinjiang. The results show that the main factors severely limiting the balanced and rapid connectivity between injection and production wells are the limited radius of steam coverage, low utilization degree oil layers, and frequent unilateral steam breakthroughs. The reservoir expansion transformation has improved the reservoir properties along the horizontal section, increasing the utilization rate of the horizontal section from 51% to 90%, achieving rapid connectivity injection and production wells, and shortening the conventional throughput preheating cycle by 3–4 cycles. The group combination steam injection method achieved a centralized increase in thermal energy, with the inter-well connectivity changing from unidirectional to a broader area The reasonable steam injection intensity was 15 t/m, the regional temperature field increased from 83 °C to 112 °C, and the steam area expanded by approximately 10 m. The multi-medium composite technology achieved a dual increase in steam coverage and profile utilization, with the steam coverage radius increasing by 15 m and the oil reservoir profile utilization increasing by more than 30%. The temporary plugging and fracturing of the reservoir achieved the sealing of inherited breakthrough channels, directing the steam to unused areas, increasing the utilization rate to 89.2%, and shortening the throughput preheating cycle by 3 cycles. This series of technologies has achieved remarkable results in actual application in super-heavy oilfield, which has certain reference significance for the efficient and low-carbon development of heavy oil steam throughput reservoir turning into drive and release. Full article

The air injection for brine drainage affects the thermodynamic characteristics of salt caverns in the operation of compressed air energy storage (CAES). This study develops a thermodynamic model to predict temperature and pressure variations during brine drainage and operational cycles, validated against Huntorf plant data. Results demonstrate that increasing the air injection flow rate from 80 to 120 kg/s reduces the brine drainage initiation time by up to 47.3% and lowers the terminal brine drainage pressure by 0.62 MPa, while raising the maximum air temperature by 4.9 K. Similarly, expanding the brine drainage pipeline cross-sectional area from 2.99 m² to 9.57 m² reduces the total drainage time by 33.7%. Crucially, these parameters determine the initial pressure and temperature at the completion of brine drainage, which subsequently shape the pressure bounds of the operational cycles, with variations reaching 691.5 kPa, and the peak temperature fluctuations, with differences of up to 4.9 K during the first cycle. This research offers insights into optimizing the design and operation of the CAES system with salt cavern air storage. Full article

This study investigates the feasibility and optimization of Expanding Solvent Steam-Assisted Gravity Drainage (ES-SAGD) in deep extra-heavy oil reservoirs, with a focus on the Shu 1-38-32 block in the Liaohe Basin. A modified theoretical model that accounts for steam quality reduction with increasing reservoir depth was applied to evaluate SAGD performance. The results demonstrate that declining steam quality at greater burial depths significantly reduces thermal efficiency, the oil–steam ratio (OSR), and overall recovery in conventional SAGD operations. To overcome these challenges, numerical simulations were conducted to evaluate the effect of hexane co-injection in ES-SAGD. A 3 vol% hexane concentration was found to improve oil recovery by 17.3%, increase the peak oil production rate by 36.5%, and raise the cumulative oil–steam ratio from 0.137 to 0.218 compared to conventional SAGD. Sensitivity analyses further revealed that optimal performance is achieved with cyclic injection during the horizontal expansion stage and chamber pressures maintained above 3 MPa. Field-scale forecasting based on five SAGD well pairs showed that the proposed ES-SAGD configuration could enhance the cumulative recovery factor from 28.7% to 63.3% over seven years. These findings clarify the fundamental constraints imposed by steam quality in deep reservoirs and provide practical strategies for optimizing solvent-assisted SAGD operations under such conditions. Full article

Foam-formed cellulose biocomposites provide a promising, innovative approach to creating lightweight and eco-friendly materials for utilization in packaging and insulation. This study investigates the production and characterization of temperature-resistant, mechanically stable cellulose fiber (CF) composite foams reinforced with alumina nanofibers (ANFs). To evaluate the impact of ANFs on rheology and drainage, CF suspensions were prepared at a concentration of 20 g/kg, with ANFs added at 2 wt% and 5 wt%. All foams exhibited shear-thinning behavior, with variations in flow characteristics influenced by ANF consistency and particle–bubble interactions. ANFs were integrated into the dry CF foam structure using two methods: (i) immersion in an ANF water suspension, and (ii) direct injection of the suspension into the foam matrix. Mechanical and thermal analyses of the dried CF foams with 2% ANFs demonstrated significant improvements in strength and thermal stability. Incorporating ANFs into CF-based foams enhances their rheological properties, improves mechanical and thermal performance, and reduces combustion rates. These results highlight the potential of ANF-reinforced CF foams for use in industries requiring biodegradable insulation and packaging materials. Full article