Emulsification is a crucial mechanism in chemical flooding for significantly enhancing oil recovery. This study utilizes a quantitative emulsification index (EI) to characterize oil-water emulsification capacity and employs molecular dynamics simulations to elucidate the underlying molecular mechanisms. The objective is to provide a theoretical basis for screening and designing high-performance surfactants, particularly for low-permeability reservoirs where enhancing emulsification is often more effective than solely pursuing ultra-low interfacial tension after water flooding. Experimental results from an emulsification characteristics analyzer demonstrate that sodium dodecylbenzene sulfonate SDBS (EI = 1.162) possesses a markedly stronger emulsification capacity compared to sodium dodecyl sulfate SDS (EI = 0.32). Molecular dynamics simulations reveal that the benzene ring in the SDBS molecule enhances its overall hydrophobicity, facilitating faster migration and more effective adsorption at the oil-water interface. This leads to the formation of a more compact and stable interfacial monolayer, which provides superior steric hindrance to inhibit droplet coalescence. Conversely, SDS molecules migrate slower and form a looser interfacial layer that relies primarily on electrostatic repulsion for stabilization, resulting in comparatively inferior emulsification performance. This research offers valuable theoretical insights for the screening and molecular design of surfactants aimed at chemical enhanced oil recovery in challenging low-permeability reservoirs.

Low-permeability reservoirs include well-developed fracture networks and significant variations in pore structure across multiple scales that are characterized by pronounced heterogeneity. The heterogeneity of the storage structure may evolve dynamically during CO2 flooding processes. Consequently, CO2 transport exhibits distinct anomalous diffusion behavior. Conventional advection-diffusion equation models fail to accurately capture this complex transport phenomenon. To fill this knowledge gap, the variable-order fractional derivative serves as a non-local operator expressed in a differential-integral form, which can effectively describe the global spatial correlation and temporal memory effects inherent in particle movement within heterogeneous media structures or complex flow fields. This study aims to investigate the mechanism of CO2 transport in low-permeability reservoirs using a variable-order fractional advection-diffusion equation (V-FADE) model. The finite difference method is well applied to numerically solve the variable-order fractional differential equation. Numerical experiments and field applications of the V-FADE model effectively capture the apparent positive skewness and the accelerating sub-diffusion phenomenon observed in gas breakthrough curves (BTCs). Furthermore, simulation studies demonstrate a strong correlation with experimental data reported in previous literature. The decrease in variable order leads to a heavier late-time tailing in BTCs. Notably, the time-dependent variable order alpha(t) serves as a key parameter that characterizes the temporal evolution of reservoir pore structure and microfracture connectivity during transport processes; meanwhile, the anomalous diffusion dynamics and the associated concentration tailing in BTCs are clearly explained. Therefore, aiming at the process and dynamic characteristics of CO2 transport in low-permeability reservoirs, an analysis of the influence of external environmental factors and pore-scale structural properties on oil displacement efficiency can provide valuable theoretical and technical guidance for reservoir production. This study not only aims to enhance oil recovery but also contributes to carbon storage and environmental protection.

Purpose Crude oil remains a cornerstone global energy resource, and its rheological and flow characteristics are critical to the efficiency and safety of extraction and pipeline transportation. Existing studies have largely relied on empirical correlations which often fail to capture the underlying physicochemical mechanisms and significant uncertainties arise when operational conditions deviate from the original data range. The purpose of this study is to analyze the rheological and heat transfer characteristics of crude oil to solve a series of problems in engineering applications caused by its complex nature.Design/methodology/approach In this study, a combined experimental and simulation approach is well used. Rheological experiments are conducted on four African crude oil samples using an Anton Paar MCR302 rotational rheometer under different temperatures and shear rates. Three constitutive models (Power-law, Bingham and Herschel-Bulkley) are compared via R 2 to determine the optimal model and parameters (K, n). The fitted results are then applied in Computational Fluid Dynamics (CFD) simulations of a horizontal straight pipe model to analyze velocity distribution, frictional resistance (f), Nusselt number (Nu) and heat transfer coefficient (h).Findings Four crude oil samples exhibit significant shear-thinning behavior and temperature dependence, belonging to pseudoplastic non-Newtonian fluids. The power-law model achieves the highest goodness of fit (R 2 = 0.9). The simulation results show that the power-law index (n) has a significant impact on flow and heat transfer. As the value of n increases, both the central velocity and the friction coefficient increase, while the Nu and h exhibit a decreasing trend, confirming that the shear-thinning behavior can enhance heat transfer efficiency. Viscosity decreases with rising temperature and stabilizes at high shear rates.Research limitations/implications For experiments, this study focuses on four crude oil samples from the only African region, and lacks of study on the complexity and diversity of crude oil in other regions. In numerical simulation, this study only conducted simulation analysis on straight pipes without simulation on complex pipes.Practical implications Through a combination of experimental measurements and numerical simulations, this study effectively reveals the rheological behavior, as well as the flow and heat transfer characteristics of crude oil, which can provide a solid theoretical basis for the efficient transportation of crude oil in pipelines.Social implications Efficient transportation of crude oil is beneficial for economic stability and daily life by ensuring a reliable supply of energy and derived products.Originality/value This study combines rheological experiments with CFD simulations using directly fitted power-law parameters from real crude oil samples. It quantifies how the power-law index n affects f, Nu and h, confirming that the flow and heat transfer characteristics of crude oil can be enhanced in shear-thinning performance. The results of this study provide a theoretical basis for flow assurance of crude oil in a pipe.

In this study, we successfully prepared polyurethane microcapsules with regular morphology, uniform particle size and excellent monodispersity by means of microfluidic technology. The microcapsules use surfactant as the core material and polyurethane as the wall material, which significantly improves the controllability and repeatability of the traditional microcapsule preparation method. The prepared microcapsules not only have a minimum particle size of 44.5 mu m, but also have a narrow particle size distribution (65-71 mu m) and an average diameter of 67.4 mu m, fully demonstrating excellent morphology control ability. In terms of performance evaluation, these microcapsules showed rapid targeted release characteristics in both light oil and heavy oil, especially in heavy oil, which could be completely dissolved within 10 s, indicating that they had good compatibility with oil molecules. Furthermore, the microcapsules encapsulated with AEO-3 surfactant can significantly reduce the oil-water interfacial tension from 27.68 mNm-1 to 6.67 mNm-1, which significantly enhances the peeling ability of oil droplets from the rock surface. In particular, when the concentration of microcapsules was 0.1 wt %, the Zeta potential of the dispersion system was -36.12 +/- 0.7 mV, indicating that the system had high stability and effectively prevented the aggregation or precipitation of microcapsules. In addition, the microcapsules can maintain morphological integrity under high salt (10 wt % NaCl, 7 wt % CaCl2) and high temperature (80 degrees C) conditions, showing excellent temperature and pressure resistance. Microscopic oil displacement experiments show that microcapsules can effectively enhance oil recovery by reducing oil-water interfacial tension and changing rock wettability, showing its great application potential in the field of enhanced oil recovery (EOR). These research results not only verify the advantages of microfluidic technology in the preparation of microcapsules, but also provide strong support for the development of intelligent oil displacement agents.

Anomalous diffusion in complex media such as subsurface porous formations in oil and gas fields and fractured reservoirs cannot be accurately described by classical integer-order diffusion models. Riesz fractional diffusion equations (RFDE) provide a powerful tool for capturing the nonlocal super-diffusion behavior, yet their analytical solutions are rarely available, and existing numerical methods often face a trade‑off between accuracy and geometric flexibility. A backward substitution method (BSM) is proposed, based on the Taylor expansion of Gaussian radial basis functions (RBFs), for solving RFDE in one to three dimensions. The novelty of the present work resides entirely in the spatial discretization. In the BSM, the solution is decomposed into a boundary part and a correction part. Owing to super-exponentially decaying coefficients in its Taylor expansion, the Gaussian RBF is replaced by a finite polynomial. Its Riesz derivative then becomes a closed-form sum of monomial derivatives, yielding a collocation method. Results show that for smooth solutions, the BSM achieves empirical convergence rates of 6 to 7 in the pre-asymptotic regime and produces errors of 10−6 to 10−8 even on coarse point sets, confirming its accuracy on benchmark RFDE problems. Extension to low-regularity solutions, common in real-world fractional models, requires further study.

Nanofluid flooding technology has attracted much attention as an effective way to enhance oil recovery in the development stage of high water cut in oilfields. Among them, 2D nanomaterials represented by graphene oxide are highly regarded. In this paper, an amphiphilic bifunctional graphene oxide (ABGO) was designed and synthesized by using the polymer template method. Subsequently, its interfacial activity, dispersion, and emulsifying properties were investigated. Finally, the ability of ABGO nanofluids to enhance oil recovery and its displacement mechanism were evaluated through microscopic flooding experiments. Experimental results demonstrated that ABGO exhibited excellent wettability alteration capability, successfully converting the rock surface from oil-wet to water-wet state while significantly reducing oil-water interfacial tension by up to 62.2%. In addition, ABGO exhibited good emulsifying ability, and the stable emulsion could be maintained for more than 24 h without demulsification. The results of microscopic flooding experiments showed that ABGO nanofluids can improve oil recovery by increasing the swept volume and oil washing efficiency. To a certain extent, this confirmed that ABGO has certain application potential in enhanced oil recovery.

PurposeThis study aims to investigate the mechanism underlying erosion caused by solid-liquid-gas multiphase flow in pipeline transportation. In CO2 flooding projects, the process of pipeline oil transportation is often accompanied by the presence of a small quantity of sand particles. Owing to the interaction of multiphase fluid flow (solid-liquid-gas), the inner walls of pipelines, particularly at bend locations, frequently experience significant erosion wear.Design/methodology/approachIn this study, experimental data from existing literature are integrated with computational fluid dynamics to systematically analyze the influence of key parameters, including particle concentrations, flow rates and velocities, on the erosion rate within coupling pipes. Through a rigorous comparative analysis of multiple erosion prediction models, the volume of fluid (VOF) model and the discrete phase model (DPM) are identified and used as the most appropriate methods for the current investigation.FindingsThe findings indicate that particle concentration and flow rates are the primary influencing factors on erosion rates, with the outer wall of curved pipes identified as the primary area of erosion and the maximum erosion rate is 1.539 x 10-2kg/m2/s. Additionally, this study integrates 90 degrees bend pipes with reducer pipes and compares their performance to standalone pipe structures. The results indicate that the maximum erosion rate of the coupling pipe decreases by up to 40% under various working conditions.Research limitations/implicationsThrough a rigorous comparative analysis of multiple erosion prediction models, the VOF model and the DPM are identified and used as the most appropriate methods for the current investigation.Practical implicationsThis study provides theoretical foundations and technical support for the engineering design and maintenance of coupling pipes, offering scientific guidance to reduce pipeline erosion and prolong equipment lifespan.Social implicationsOwing to the interaction of multiphase fluid flow (solid-liquid-gas), the inner walls of pipelines, particularly at bend locations, frequently experience significant erosion wear.Originality/valueThe present work provides theoretical foundations and technical support for the engineering design and maintenance of coupling pipes, offering scientific guidance aimed at reducing pipeline erosion and prolong equipment lifespan.

In this work, through mixing alkyl primary amines of CnH2n+1NH2 (n=6, HA; n=12, DA; n=18, ODA) and disodium 4-formylbenzene-1, 3-disulfonate (DFD) at 1:1 mol ratio, three novel dynamic imine surfactants (DFD-HA, DFD-DA and DFD-ODA) were synthesized. The imine bond was verified by infrared spectroscopy (IR) and nuclear magnetic resonance (NMR). After preparing the emulsion, DFD-DA exhibited superior stability among the three surfactants at lower concentrations (< 20 mM). Subsequently, an emulsifier system (DFD-DA/LHSB) with excellent interfacial activity and emulsification stability was obtained by blending DFD-DA with lauramidopropyl hydroxy sulfobetaine (LHSB). The system effectively reduced the interfacial tension to the order of 10(-2) mN/m. At a total concentration of 5 g/L and mole ratio (DFD-DA: LHSB = 1:2), the emulsion could be stable for more than 60 days. Contact angle measurements substantiated the superior wettability inversion capability of the system, facilitating the formation of oil-in-water emulsions more effectively. Furthermore, this system possesses remarkable CO2 responsiveness. After CO2 injection, the emulsion can be completely demulsified within 45 s in a broad mole ratio range. Changing the relative content of DFD-DA and LHSB can also dynamically regulate the demulsification rate of emulsion. In contrast to previous imine surfactants, the system can achieve full demulsification under higher pH conditions (about 6.0), thereby significantly enhancing the response efficiency and alleviating the equipment corrosion. This discovery provides a new approach to tackling the problems associated with surfactant flooding and heavy oil demulsification, holding important implications for enhancing oil recovery (EOR).

Nanoparticles exhibit significant potential in modulating oil‐water interfacial tension, altering rock wettability, and optimizing fluid flow for enhanced oil recovery. This study employs MD simulations to investigate the effects of surface‐modified nanoparticles (pure‐NP, alkyl‐NP, carboxylate‐NP) on interfacial tension, layer thickness, and displacement energy. Results reveal that alkyl‐NP reduces interfacial tension most effectively (32.57 mN·m⁻¹), followed by carboxylate‐NP (38.64 mN·m⁻¹) and pure‐NP (45.02 mN·m⁻¹). Alkyl‐NP also demonstrates the greatest reduction in oil‐particle interaction energy (−500 kcal/mol), while Pure‐NP and Carboxylate‐NP show weaker displacement capacity. Notably, nanoparticle addition significantly increases the interfacial layer thickness ( t oil : 9.5 ∼ 17.4 Å, t water : 7.9 ∼ 12.5 Å, t total : 13.4 ∼ 22.5 Å) compared to the pure system ( t oil = 4.8 Å, t water = 3.8 Å, t total = 6.5 Å). These findings suggest that nanoparticle systems enhance oil recovery by lowering interfacial tension, thickening interfacial layers, and improving crude oil stripping and migration. Alkyl‐NP emerges as the most promising modifier due to its superior interface control and energy reduction.

CO2 foam system has the functions of oil displacement, plugging, and fracturing, and plays an important role in improving oil and gas production. In this paper, the effectiveness and mechanism of different surfactant systems for CO2 foam and the methods to stabilize CO2 foam are reviewed. The effectiveness and mechanism of ionic, nonionic, and Gemini surfactant systems for CO2 foam were analyzed. The research status of CO2 foaming agent system, gas‐soluble CO2 foaming agent system, and CO2 intelligent response foaming agent system based on anionic, nonionic, and zwitterionic compounds was described. The mechanism of polymer and nanoparticles stabilizing CO2 foam system was also discussed. Through investigation, it is found that the performance of CO2 foam system compounded with various chemicals is better, and the research is relatively perfect and diversified, so we can pay attention to the refinement of the compounding process in the future. Sulfonation and modification of surfactants can further improve the properties of surfactants. The characteristics of Gemini surfactants, supercritical CO2, and CO2‐sensitive surfactants can be used to make CO2 foaming agent have the characteristics of easy recovery, sustainability, anti‐corrosion, on–off control, and fluidity control. There is still room for development of such surfactants. Using polymers and nanoparticles to stabilize foam is the future development trend. This paper provides guidance for the further development and field application of highly effective CO2 surfactant.

It is extremely difficult to investigate gas transport behaviors in naturally geological reservoirs with multiscale pores and fractures. It is widely recognized that Darcy's law and Fick's law are inadequate for describing particles motion in unconventional oil-gas reservoirs due to their complex pore structures and low permeability. The main objective of this study is to investigate gas seepage and diffusion characteristics in geological reservoirs by virtue of the Hausdorff fractal derivative model (HFDM) and fractal geometry theory. This study presents a novel nonlinear HFDM corresponding to the Hausdorff fractal order, porosity, and fractal dimension; it is well verified through comparison with the available model and existing experimental data and provides an excellent agreement with the experimental data. Moreover, this study indicates that the permeability decreases and the flow resistance increases with the increase of Hausdorff order (3. Meanwhile, the effective diffusion coefficient increases with the increase in fractal dimensions Df at different Hausdorff fractal orders (3. The proposed model can effectively analyze gas flow behaviors, gas permeability distribution, and variations in diffusion coefficients across different regions.

In the practical application of hydraulic rotating machinery, it is essential to thoroughly explore drag reduction and rheological characteristics of drag-reducing additives to optimize machinery efficiency and reduce equipment consumption. This paper combines simulation and experimental approaches to investigate the drag-reduction performance and rheological properties of drag-reducing additives. Numerical simulations are initially conducted to investigate the shear-thinning properties of drag-reducing fluid and explore variations in drag-reduction rate. Turbulent phenomena characteristics are described by analyzing turbulent statistical quantities. Subsequently, the rheological behaviors of polyethylene oxide (PEO), cetyltrimethyl ammonium chloride (CTAC), and their mixed solutions under different conditions are scrutinized using a rotational rheometer. The findings indicate that the drag reduction effect amplifies as the rheological index n and characteristic time λ decrease. The numerical simulations show a maximum drag reduction rate of 20.18%. In rheological experiments, a three-stage viscosity variation is observed in single drag-reducing additives: shear thickening, shear thinning, and eventual stabilization. Composite drag-reducing additives significantly reduce the apparent viscosity at low shear rates, thereby strengthening the shear resistance of the system.

The water-oil-rock system's surfactant and electrostatic interactions are essential for removing oil droplets from rock substrates. Our work illustrates the impact of surface charge on the oil contact angle in an ideal system comprising silica, water, and dodecane; smaller contact angles are observed for more polar substrates. Modifying the polarity of the model silica surface allows for the observation of the creation of heteromolecule channels and the process of stripping crude oil while accounting for the impacts of water flow and different types of surfactant molecules. In solutions containing ionic surfactants, the injection and diffusion of water molecules between the oil layer and the silica substrate are facilitated by the disturbance of the oil molecules by the surfactant molecules. By comparing different surfactants in water flow, the characterization of water molecular channels and the stripping process of crude oil can be observed. The disruption of oil molecules by the surfactant molecules has been found to enhance the injection and diffusion of water molecules between the oil layer and the silica substrate in solutions containing ionic surfactants. The size of the contact angle and the extension of the water channel are simultaneously greatly influenced by the surfactant's molecular characteristics and the substrate's polarity. These simulation results show that several factors influence the process of water molecule channel creation that water molecules diffuse, and the detachment of oil from the silica substrate is facilitated by the migration of surfactants to the bottom of the oil molecule and the electrostatic interactions between the water molecules and the silica substrate.

Amphiphilic Janus molybdenum disulfide (MoS2) nanosheets have emerged as promising candidates for enhanced oil recovery (EOR) due to their low cost and exceptional interfacial properties. Nevertheless, research on the modification methods for Janus MoS2 remains scarce. In this article, we prepared amphiphilic Janus molybdenum disulfide nanosheets (L-MoS2-C) by double-sided modification of molybdenum disulfide (MoS2) using a starch template method. Specifically, l-glutamic acid (l-Glu) with hydrophilic carboxyl group was grafted onto one side of the nanosheets, while cetyltrimethylammonium bromide (CTAB) with hydrophobic alkyl chain was used on the other. Fourier transform infrared spectroscopy (FTIR), scanning electron microscopy (SEM), X-ray diffraction (XRD), and energy-dispersive X-ray analysis (EDS) characterizations confirmed the functionalization of CTAB and l-Glu molecules over the surfaces of MoS2 nanosheets. Benefiting from the amphiphilic properties, L-MoS2-C nanosheets presented excellent dispersion stability in brine and spontaneously accumulate at the oil-water interface, forming an elastic interfacial film. At 0-10,000 mg/L NaCl concentration, the size distribution of L-MoS2-C was centered in the range of 300-500 nm. At an ultralow concentration (0.005 wt %), L-MoS2-C can reduce the interfacial tension by approximately 60% and stabilize emulsions as an emulsifier. Furthermore, L-MoS2-C possesses remarkable wettability alteration capability, altering the contact angle of the quartz plate surface from 104.3 to 30.3 degrees, thereby converting capillary resistance into driving force. Micromodel flooding and core flooding experiments demonstrate that these superior properties enable L-MoS2-C nanofluid to effectively mobilize remaining and residual oil after water flooding at an ultralow concentration, contributing an additional 15.1% oil recovery. This work introduces a novel amphiphilic modification method for MoS2, offering a low-cost, high-performance, and highly promising nanoflooding agent for tertiary oil recovery in sandstone reservoirs.

Nanofiltration (NF) is an efficient and economic separation technology which has great application potential in solving worldwide water shortage. Constructing interlayer is an effective approach to fabricate thin film composite (TFC) polyamide (PA) NF membranes with better performance. Herein, the polystyrene-polyacrylamide nanospheres with core-shell structure were synthesized using an emulsion polymerization method. The PA NF membranes were prepared via interfacial polymerization (IP) on the mixed cellulose esters microfiltration (MCE MF) membranes which modified with the core-shell structured nanospheres. The fabricated PA NF membranes showed good performance with a pure water permeability of 18.9 L & sdot;m � 2 & sdot;h- 1 & sdot;bar � 1 and Na2SO4 rejection of 97.4 %. The NF membranes also showed good antibiotics separation performance with rejection to levofloxacin (LEV), penicillin G (PG), tetracycline (TC), and erythromycin (ERY) of 97.1 %, 86.9 %, 92.2 %, and 96.4 %, respectively and efficient separation to antibiotics and NaCl. This work provides a feasible strategy to construct an interlayer of PA NF membranes with the core-shell structured polystyrene-polyacrylamide nanospheres.

Nanofluid flooding, as a new type of oil displacement technology in low permeability reservoirs, has attracted more and more attention due to its advantages of good injection, low reservoir damage, strong oil displacement ability, and intelligent response. Compared with spherical nanoparticles, Janus sheet nanomaterials have lower interfacial free energy and more limited rotation, can further prevent the diffusion of internal and external phase molecules, and form solid particle films with higher interfacial strength, showing excellent oil displacement performance. Janus nanosheets have a large specific surface area and abundant surface chemical groups, which have great application potential in enhancing oil recovery. Because of its sheet structure and unique physicochemical properties, molybdenum disulfide (MoS2) has attracted wide attention in enhancing oil recovery, but there is relatively little research on the Janus modification of MoS2 nanosheets. In this article, amphiphilic Janus molybdenum disulfide nanosheets (JSMS) were prepared by a one-pot method, and their microstructure and physicochemical properties were characterized and analyzed. Finally, through a core flooding experiment and microscopic displacement test, the ability and mechanism of JSMS nanofluids to enhance oil recovery were evaluated. The results showed that the JSMS had excellent interface properties because of its Janus structure. It can produce a strong, elastic interfacial film. At the same time, the JSMS nanofluid can realize wetting reversal of rock surfaces. The results of the core flooding experiments showed that JSMS had a good oil displacement effect. The JSMS nanofluid enhanced oil recovery effectively by 4.7% with low concentration (0.005 wt %). This work demonstrated the feasibility of the Janus MoS2 for enhanced oil recovery.

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

Understanding mechanical degradation is crucial for successful polymer flooding. In this study, the effects of stretching velocity, pore-throat ratio, polymer concentration, and migration distance on the mechanical degradation of HPAM were studied using a pore-throat model. Additionally, the contribution of tensile degradation at the entry point of the pore-throat model to the overall mechanical degradation was assessed through extrapolation. The experimental results indicate that tensile degradation at the entry point is the primary cause of the mechanical degradation, and its contribution is positively related to the flow rate. The mechanical degradation correlates positively with the stretching velocity (0.41 similar to 6362s(-1)), pore-throat ratio (6 similar to 60), and polymer concentration (500 similar to 2200mg/L). Moreover, higher flow rate amplify the effects of changes in polymer concentration and pore-throat ratio on mechanical degradation. As the migration distance increases, the mechanical degradation initially increases and then stabilizes in the pore-throat model, whereas in the sand-packed model, the mechanical degradation continues to increase with increasing migration distance. This study enhances our understanding of polymer mechanical degradation and offers insights for developing strategies to reduce mechanical degradation and improve polymer-enhanced oil recovery. Graphical Abstract