Multiphase Flow Experiments Research Articles

Multiphase flow simulations and experiments on electrochemical jet machining of rough surfaces of high-speed additive manufactured titanium alloys

ABSTRACT The application of titanium alloy parts manufactured by high-speed additive manufacturing in industry is currently constrained by the low surface accuracy. This severely constrains the potential of high-speed additive manufacturing for processing aerospace titanium alloy components. To address this issue, it is crucial to address the high-speed additive manufactured rough surface in order to enhance surface accuracy. As a highly flexible non-contact machining method, electrochemical jet machining is well-suited for surface post-treatment of additive manufactured titanium alloy parts due to its distinctive advantages, including the absence of tool loss, no cutting force, and no thermal effects. This paper examines the electrochemical jet machining of rough low-precision surfaces produced by high-speed additive manufacturing. The distribution characteristics of the machining electric field and machining flow field on extremely rough additive manufactured surfaces were investigated through simulation. A series of experiments were conducted to verify the effectiveness of the simulation. The research findings indicated that the cut-in electrochemical jet machining method effectively circumvented the adverse effects of rough surfaces on electrolyte flow, thereby allowing for high-quality machining. The surface roughness of titanium alloy samples produced by high-speed additive manufacturing was reduced from Ra 21.179–1.838 um, representing a 90% reduction.

Time‐And‐Space Averaging Applied to Intermittent Multiphase Flow Experiments

AbstractVarious researchers have studied fluctuations in pore‐scale phase occupancy during multiphase flow in porous media using synchrotron‐based X‐ray microcomputed tomography (micro‐CT). However, the impact of these fluctuations on the concept of a representative volume is not yet fully understood. In this study, we performed spatial and temporal averaging of multiphase flow experiments visualized with synchrotron‐based micro‐CT, focusing on oil saturation as the key parameter to determine a representative time‐and‐space average. Our findings revealed that a saturation value representative of both time and space was achieved during fractional flow experiments in drainage mode with fractional flows of 0.8, 0.5, and 0.3. Furthermore, we computed a range of relative permeabilities on the basis of whether momentaneous saturation or time‐and‐space averaged saturation was utilized for direct simulation. Our results highlighted the importance of time‐and‐space averaging in determining a representative relative permeability and indicated that the temporal and spatial scales covered in a typical micro‐CT flow experiment were sufficient to obtain a representative saturation value for sandstone rock under intermittent flow conditions.

The Impact of Autonomous Inflow Control Valve on Improved Oil Recovery in a Thin-Oil-Rim Reservoir

Summary Oil production from thin-oil-rim fields can be challenging as such fields are prone to gas coning. Excessive gas production from these fields results in poor production and recovery. Hence, these resources require advanced recovery methods to improve the oil recovery. One of the recovery methods that is widely used today is advanced inflow control technology such as autonomous inflow control valve (AICV). AICV restricts the inflow of gas in the zones where breakthrough occurs and may consequently improve the recovery from thin-oil-rim fields. This paper presents a performance analysis of AICVs, passive inflow control devices (ICDs), and sand screens based on the results from experiments and simulations. Single- and multiphase-flow experiments are performed with light oil, gas, and water at typical Troll field reservoir conditions (RCs). The obtained data from the experiments are the differential pressure across the device vs. the volume flow rate for the different phases. The results from the experiments confirm the significantly better ability of the AICV to restrict the production of gas, especially at higher gas volume fractions (GVFs). Near-well oil production from a thin-oil-rim field considering sand screens, AICV, and ICD completion is modeled. In this study, the simulation model is developed using the CMG simulator/STARS module. Completion of the well with AICVs reduces the cumulative gas production by 22.5% and 26.7% compared with ICDs and sand screens, respectively. The results also show that AICVs increase the cumulative oil production by 48.7% compared with using ICDs and sand screens. The simulation results confirm that the well completed with AICVs produces at a beneficial gas/oil ratio (GOR) for a longer time compared with the cases with ICDs and sand screens. The novelty of this work is the multiphase experiments of a new AICV and the implementation of the data in the simulator. A workflow for the simulation of AICV/ICD is proposed. The simulated results, which are based on the proposed workflow, agree with the experimental AICV performance results. As it is demonstrated in this work, deploying AICV in the most challenging light oil reservoirs with high GOR can be beneficial with respect to increased production and recovery.

Apparatus and methods for the calibration and correction of a polydispersed dust feeding system applied in multiphase flow experiments

Multiphase flow experiments allow the understanding of complex interaction mechanisms between particles and fluid structures under controlled conditions. In standard test rigs, the airflow is mixed with precise dust amount continuously, and accurate knowledge of the aerosol amount injected is mandatory to achieve reliable measurements and results. This work proposes the experimental procedure for calibrating an aerosol dosing and injection system. The purpose-built calibration system layout is explained in detail. To give a general perspective of the procedure, four test powders commonly used in multiphase flow tests have been used: Alumina, Silicon Carbide, and two grades of standard soil named Arizona Road Dust. Methodologies and criticisms are reviewed and assessed, and the final results are given in the form of calibration curves of the feeding system. Since the proposed correction is based on powder and flow characteristics, the proposed methodology can be applied to several cases and conditions.

Comparative analysis of hydrogen, methane and nitrogen relative permeability: Implications for Underground Hydrogen Storage

Underground Hydrogen Storage (UHS) is an emerging technology which aims to store terawatt-scale energy in the subsurface to alleviate daily and seasonal fluctuations in the ever-increasing renewable energy market. Depleted gas reservoirs and aquifers will be the main targets of storage which requires an understanding of the interaction between formation or cushion gas with native brine. A comprehensive comparison of the petrophysical and two-phase flow properties of the hydrogen-water, methane-water and nitrogen-water systems at in-situ conditions is the focus of our work. We conduct steady-state relative permeability experiments at 2.13 MPa and 298 K using identical capillary numbers of Nc=2.92×10−7 for all three systems. The saturation and in-situ contact angles are determined with segmentation of 3D micro-CT images. The contact angle of each system is almost identical at the irreducible water saturation, Swi, 44°, 46°, 45°, respectively, as is the interfacial tension of 72.0, 71.5 and 71mN/m, respectively. The capillary pressure-saturation relationships for each system have a maximum difference of 3.8 % which leads to approximately equivalent relative permeability in the Bentheimer sandstone core. The end-point relative permeabilities are krg0=0.049, krg0=0.045 and krg0=0.062 at irreducible water saturations of Swi=0.24, Swi=0.25 and Swi=0.23, respectively. All three gases demonstrate equivalent flow properties which indicates that both nitrogen and methane are suitable analogue gases for laboratory multiphase flow experiments and cushion gas to improve safety and the economics of commercial UHS projects. The results enable history matched depleted gas reservoir performance to be used as a guide for UHS.

Numerical and experimental investigation of 3D flow field bipolar plates for PEMFCs by metal 3D printing

The bipolar plate is one of the core components of a proton exchange membrane fuel cell (PEMFC). Its flow field structure directly affects the drainage and heat dissipation performance of the cell, as well as the transmission and distribution of the reaction gas. Compared with conventional 2D flow fields, novel 3D flow fields can provide superior gas–liquid mass transfer performance, significantly improving the performance of PEMFCs. However, traditional manufacturing processes fail to meet the associated molding needs, due to the complex structure of such plates. This research aims to investigate the metal 3D printing process, mass transfer law, and efficiency of 3D flow field bipolar plates, focusing on the influence of structural parameters on the gas–liquid mass transfer performance, by combining CFD multi-phase flow numerical simulations and experiments. The results indicate that the use of a 3D stepped flow field enhances the convection effect in the vertical direction due to the increase in Z-directional inflow, thus promoting oxygen transfer and reducing the accumulation of water. In particular, better gas–liquid mass transfer performance is achieved when the number of steps is 4. At 0.55 V, the measured power density of the Stepped-IV cell reached as high as 6727 W/m2, which is about 26 % higher than the conventional parallel flow field. This study provides an important technical and theoretical reference for the design and preparation of novel 3D complex flow fields.

Numerical Simulation and Experimental Investigation of Variable Mass Flow in Horizontal Wellbores: Single-Phase and Multiphase Analysis

Considering the current limitations and restricted scope of existing experiments, as well as the absence of corresponding numerical simulation verifications and comparisons, and the lack of actual case studies of variable mass flow calculation and comparison, this study focuses on high production oilfields in the Mideast and South China Sea. The objective is to investigate single-phase and multiphase variable mass flow through numerical and experimental simulations. The study develops linear regression equations to establish the relationship between the mixture pressure drop caused by side flow and the velocities of the main flow, as well as the ratio between side and main flow velocities. Actual calculations using these equations are provided. The comprehensive analysis reveals that, for a fixed total flow rate, an increase in the side versus main injection velocity ratio leads to an increase in pressure loss before and after the injection hole. In single-phase flow, the friction factor for side hole flow is generally higher than that for only axial main flow, with the same total flow rate. In multiphase flow, when the gas-liquid ratio (GLR) is relatively large, the side flow has minimal impact on pressure drop, while at lower GLR values, the side flow significantly increases the pressure drops. When predicting the pressure drop for single-phase variable mass flow in horizontal wellbores, it is appropriate to consider only the mixture pressure drop caused by the closest hole to the calculation section, assuming the injection hole flow rates are approximately equal. In terms of predicting the productivity of single-phase variable mass flow, it is crucial to consider the mixture pressure drop. Neglecting the mixture pressure drop can lead to relatively larger productivity prediction results, with potential production rate errors exceeding 50%. The accuracy of the prediction is influenced by the ratio of mixture pressure drop to production pressure differential, and the pressure along the external zone of the screen pipe is higher when considering the mixture pressure drop compared to when it is neglected. Additionally, the flow rate along the external zone of the screen pipe becomes more non-uniform when the mixture pressure drop is considered. Furthermore, the findings from the single-phase and multiphase flow experiments suggest that significant deviations in production rates may occur in scenarios with low gas-liquid ratio (GLR), highlighting the need for further investigation in this area.

Monitoring and Characterization of Gas Migration in Oil-Based Mud Using Fiber-Optic DAS and DTS

Summary Understanding gas dynamics in mud is essential for planning well control operations, improving the reliability of riser gas handling procedures, and optimizing drilling techniques, such as the pressurized mud cap drilling (PMCD) method. However, gas rise behavior in mud is not fully understood due to the inability to create an experimental setup that approximates gas migration at full-scale annular conditions. As a result, there is a discrepancy between the gas migration velocities observed in the field as compared to analytical estimates. This study bridges this gap by using distributed fiber-optic sensors (DFOS) for in-situ monitoring and analysis of gas dynamics in mud at the well scale. DFOS offers a paradigm shift for monitoring applications by providing real-time measurements along the entire length of the installed fiber at high spatial and temporal resolution. Thus, it can enable in-situ monitoring of the dynamic events in the entire wellbore, which may not be fully captured using discrete gauges. This study is the first well-scale investigation of gas migration dynamics in oil-based mud with solids, using optical fiber-based distributed acoustic sensing (DAS) and distributed temperature sensing (DTS). Four multiphase flow experiments conducted in a 5,163-ft-deep wellbore with oil-based mud and nitrogen at different gas injection rates and bottomhole pressure conditions are analyzed. The presence of solids in the mud increased the background noise in the acquired DFOS measurements, thereby necessitating the development and deployment of novel time- and frequency-domain signal processing techniques to clearly visualize the gas signature and minimize the background noise. Gas rise velocities estimated independently using DAS and DTS showed good agreement with the gas velocity estimated using downhole pressure gauges.

Enhancing pollutant removal from contaminated soils using yield stress fluids as selective blocking agents

This work presents a novel technique consisting in the use of yield stress fluids as blocking agents in porous media presenting pore-scale heterogeneities. The key feature of this method is that yield stress fluids only flow through the pores having a minimum size that depends on the applied pressure gradient. These fluids remain immobile in more and more pores as the pressure gradient is decreased. Therefore, the dimension of the pores which are invaded by the yield stress fluid can be controlled by adjusting the applied pressure gradient. Moreover, yield stress fluids are highly suitable blocking agents given the extremely high viscosity values that they exhibit in the pores. This allows for the diversion of the flow from greater to smaller pores during subsequent waterflooding stages, thus enhancing pollutant removal from the flow paths of small hydraulic conductance. A series of multiphase flow experiments were conducted in this study using well-characterized cores of artificial A10 sintered silicate. In these experiments, semidilute aqueous solutions of xanthan gum biopolymer were used as yield stress fluids to block the greatest pores. By doing so, considerably more pollutant was recovered by waterflooding. Furthermore, it was shown that an increase in polymer concentration does not always lead to a decrease in the size of the pores invaded by the blocking agent. Indeed, concentrated polymer solutions generate higher pressure gradients throughout the porous medium, which facilitates the invasion of small pores. Nevertheless, depending on the value of the yield stress-pressure gradient ratio, they may also develop extremely high viscosities that slow down their flow through such small pores. This work also presents a method to measure the volume of blocked pores using the results of tracer tests. The reported results suggest that using a polymer solution developing a yield stress as a selective blocking agent is a promising technique for soil remediation.

Experimental characterization of {text {H}}_2/water multiphase flow in heterogeneous sandstone rock at the core scale relevant for underground hydrogen storage (UHS)

Geological porous reservoirs provide the volume capacity needed for large scale underground hydrogen storage (UHS). To effectively exploit these reservoirs for UHS, it is crucial to characterize the hydrogen transport properties inside porous rocks. In this work, for the first time in the community, we have performed {text {H}}_2/water multiphase flow experiments at core scale under medical X-ray CT scanner. This has allowed us to directly image the complex transport properties of {text {H}}_2 when it is injected or retracted from the porous rock. The important effective functions of capillary pressure and relative permeability are also measured, for both drainage and imbibition. The capillary pressure measurements are combined with MICP data to derive a receding contact angle for the {text {H}}_2/water/sandstone rock system. The rock core sample is a heterogeneous Berea sandstone (17 cm long and 3.8 cm diameter). Our investigation reveals the interplay between gravitational, capillary, and viscous forces. More specifically, it illustrates complex displacement patterns in the rock, including gravity segregation, enhancement of spreading of {text {H}}_2 due to capillary barriers, and the formation of fingers/channel during imbibition which lead to significant trapping of hydrogen. These findings shed new light on our fundamental understanding of the transport characteristics of {text {H}}_2/water relevant for UHS.

Effects of Wettability and Minerals on Residual Oil Distributions Based on Digital Rock and Machine Learning

Abstract The wettability of mineral surfaces has significant impacts on transport mechanisms of two-phase flow, distribution characteristics of fluids, and the formation mechanisms of residual oil during water flooding. However, few studies have investigated such effects of mineral type and its surface wettability on rock properties in the literature. To unravel the dependence of hydrodynamics on wettability and minerals distribution, we designed a new experimental procedure that combined the multiphase flow experiments with a CT scan and QEMSCAN to obtain 3D digital models with multiple minerals and fluids. With the aid of QEMSCAN, six mineral components and two fluids in sandstones were segmented from the CT data based on the histogram threshold and watershed methods. Then, a mineral surface analysis algorithm was proposed to extract the mineral surface and classify its mineral categories. The in situ contact angle and pore occupancy were calculated to reveal the wettability variation of mineral surface and distribution characteristics of fluids. According to the shape features of the oil phase, the self-organizing map (SOM) method, one of the machine learning methods, was used to classify the residual oil into five types, namely, network, cluster, film, isolated, and droplet oil. The results indicate that each mineral’s contribution to the mineral surface is not proportional to its relative content. Feldspar, quartz, and clay are the main minerals in the studied sandstones and play a controlling role in the wettability variation. Different wettability samples show various characteristics of pore occupancy. The water flooding front of the weakly water-wet to intermediate-wet sample is uniform, and oil is effectively displaced in all pores with a long oil production period. The water-wet sample demonstrates severe fingering, with a high pore occupancy change rate in large pores and a short oil production period. The residual oil patterns gradually evolve from networks to clusters, isolated, and films due to the effects of snap-off and wettability inversion. This paper reveals the effects of wettability of mineral surface on the distribution characteristics and formation mechanisms of residual oil, which offers us an in-deep understanding of the impacts of wettability and minerals on multiphase flow and helps us make good schemes to improve oil recovery.

Relative Permeability of Hydrogen and Aqueous Brines in Sandstones and Carbonates at Reservoir Conditions

AbstractGeological hydrogen storage in depleted gas fields represents a new technology to mitigate climate change. It comes with several research gaps, around hydrogen recovery, including the flow behavior of hydrogen gas in porous media. Here, we provide the first‐published comprehensive experimental study of unsteady state drainage relative permeability curves with H2‐Brine, on two different types of sandstones and a carbonate rock. We investigate the effect of pressure, brine salinity, and rock type on hydrogen flow behavior and compare it to that of CH4 and N2 at high‐pressure and high‐temperature conditions representative of potential geological storage sites. Finally, we use a history matching method for modeling relative permeability curves using the measured data within the experiments. Our results suggest that nitrogen can be used as a proxy gas for hydrogen to carry out multiphase fluid flow experiments, to provide the fundamental constitutive relationships necessary for large‐scale simulations of geological hydrogen storage.

Repeatability in a multiphase pipe flow case study

A high degree of repeatability is most often an underlying assumption for research and development based on multiphase flow experiments. In this paper repeatability in multiphase flow experiments are studied through an experimental campaign with 28 replicates for 11 unique settings.The experiments were conducted in a flow loop with multiple injections of oil, water and air. A high degree of repeatability was found, with relative replicate deviations in volume flow rates and pressure drops of 0.1% in magnitude. Further, several potential causes of replicate deviations were studied, and firmer control of temperature of the inflow fluids is proposed as a means to improve repeatability in volume flow rates and pressure.We conclude that for practical use, the presented category of multiphase experiments sufficiently meets underlying repeatability assumptions.

Core-scale investigation of the effect of heterogeneity on the dynamics of residual and dissolution trapping of carbon dioxide

Geologic heterogeneity, which commonly exists in target reservoirs for CO2 sequestration, has a significant effect on CO2 trapping. In this study, we performed Darcy-scale multiphase flow experiments on a heterogeneous rock with in-situ imaging techniques to obtain X-ray images of CO2 saturation during both drainage and imbibition. Residual trapping was assessed using the initial-residual characteristic curve. The distribution of residual CO2 saturation widened as the initial saturation increased, implying that the capillary heterogeneity becomes increasingly important with higher initial CO2 saturation. During dissolution, we discovered new flow regimes in heterogeneous media and proposed a quantitative scaling relationship for their temporal evolution. The high-porosity layers showed a descending slope of ~0.4 during the early stage of dissolution, whereas it decreased by an order of magnitude (slope ~ 0.04) during the later stage. The high-capillarity layers, however, showed a single descending trend during dissolution. The highly time-resolved images of CO2 saturation provide a detailed understanding of the dynamic processes of both residual and dissolution trapping in heterogeneous media, which contributes to a wide range of applications, including environmental remediation, CO2 sequestration, and the enhancement of energy resources from hydrocarbon reservoirs.

Extreme capillary heterogeneities and in situ fluid compartmentalization due to clusters of deformation bands in sandstones

Previous work has shown that individual deformation bands act like capillary barriers and influence fluid saturation. More common in nature, however, are clusters of deformation bands that form complex three dimensional geometries. The aim of this study is to analyze the extent and mechanisms of fluid compartmentalization due to clustered bands. Drainage multiphase fluid flow experiments were performed on a Navajo sandstone core sample characterized by diversely oriented clusters of deformation bands, that sub-divide the host rock into several compartments. Medical X-ray CT images were acquired while nitrogen was injected at progressively higher flow rates into a water-saturated core during transient and steady-state conditions. Spatial and temporal analyses of the non-wetting phase plume migration suggest that deformation bands act like capillary barriers and contribute to the development of an extremely tortuous saturation front. Differential pressure behavior across the core is linked to the breakthrough of N2 into the individual compartments, resulting in highly variable N2 saturation throughout the experiment. Migration into downstream compartments occurs via the exceedance of capillary entry pressure in portions of the bands. Simulation models of simplified systems demonstrate that capillary end effects and discontinuities in the deformation bands impact fluid saturation. The experiments and models presented here show that clusters of deformation bands have the potential to strongly compartmentalize a sandstone reservoir. Hence, prior analysis of the geometry of deformation band structures in a reservoir could significantly reduce the risk of overestimating reservoir capacity, and improve predictions of fluid mobility.

Well-scale multiphase flow characterization and validation using distributed fiber-optic sensors for gas kick monitoring.

Early detection of a gas kick is crucial for preventing uncontrolled blowout that could cause loss of life, loss of assets, and environmental damage. Multiphase flow experiments conducted in this research demonstrate the capability of downhole fiber optic sensors to detect a potential gas influx in real-time in a 5000 ft deep wellbore. Gas rise velocities estimated independently using fiber optic distributed acoustic sensor (DAS), distributed temperature sensor (DTS), downhole gauges, surface measurements, and multiphase flow correlations show good agreement in each case, demonstrating reliability in the assessment. Real-time data visualization was implemented on a secure cloud-based platform to improve computational efficiency. This study provides novel insights on the effect of circulation rates, gas kick volumes, backpressure, and injection methods on gas rise dynamics in a full-scale wellbore.

Low-Frequency Distributed Acoustic Sensing for Early Gas Detection in a Wellbore

An unexpected and unwanted influx of gas or “kick” into the wellbore during hydrocarbon drilling can cause catastrophic blowout incidents, resulting in human casualties, ecological damage, and asset losses. The ability of the oil and gas industry to control gas kick depends on our ability to accurately detect and monitor gas migration in a borehole in real-time. This study demonstrates the application of optical fiber-based Distributed Acoustic Sensors (DAS) for early detection and monitoring of gas in wellbore. Multiphase flow experiments conducted in a 5000 ft. deep test-well are analyzed for different injection, circulation, and pressure conditions. In each case, the low-frequency component of DAS demonstrates a superior capability to detect gas signatures both inside the tubing and the annulus of the well, even at small gas volumes. In comparison, the high-frequency DAS data seems limited in detail. The gas influx velocity was calculated using the frequency-wavenumber analysis of the gradient of the low-frequency DAS phase with respect to time, which shows good agreement with theoretical velocity estimates using flow models and surface gauge measurements. This study demonstrates a novel workflow to analyze low-frequency DAS to qualitatively and quantitatively map gas influx in a wellbore.

X-ray microcomputed imaging of wettability characterization for multiphase flow in porous media: A review

With the advent of X-ray micro-computed tomography which is now routinely used, pore- scale fluid transport and processes can be observed in three-dimensional (3D) at the micro-scale. Multiphase flow experiments that are conducted under in situ imaging scanning conditions can be utilized to study the pore-scale physics relevant to subsurface techno- logical applications. X-ray micro-tomographic imaging is a non-destructive technique for quantifying these processes in 3D within confined pores. This paper presents a review for the usage of X-ray micro-computed tomography experiments to investigate wettability effect on multiphase flow. The fundamental workflow of combining experiments with pore-scale in situ imaging scanning such as equipment requirements, apparatus design and fluid systems are firstly described. Then imaging analysis toolkit is presented for how to quantify interfacial areas, curvatures, contact angles, and fluid properties through these images. Furthermore, we show typical examples, illustrating recent studies for the wettability characterization by using X-ray micro-computed imaging. Cited as : Zou, S., Sun, C. X-ray microcomputed imaging of wettability characterization for multiphase flow in porous media: A review. Capillarity, 2020, 3(3): 36-44, doi: 10.46690/capi.2020.03.01

An experimental system and procedure of unsteady-state relative permeability test for gas hydrate-bearing sediments

Reliable estimations of the relative permeability of gas and water in hydrate-bearing sediments (HBS) and the dependency of the relative permeability on hydrate saturation are critical to predict the productivity of a hydrate reservoir. Yet, this remains poorly estimated owing to lack of experimental data associated with difficulties in conducting multiphase flow experiments in HBS. Recognizing the experimental challenges, this study intends to develop and validate a new experimental system and procedure of unsteady-state relative permeability test that can generate reliable and reproducible flow measurements in HBS. Gas hydrate is considered as a part of solid matrix in the sediment, so one of the challenges is to maintain a constant hydrate saturation, which is achieved in this experimental study using tight pressure-temperature (P-T) control near the hydrate stability boundary. The measured differential pressure across the specimen, methane injection flow rate, and volume of displaced brine are used to calculate the relative permeability by adopting a conventional Buckley-Leverett theory-based interpretation method. Residual brine saturation calculated for the hydrate-bearing specimen is higher than that of hydrate-free specimen, presumably due to decrease in pore size, increase in heterogeneity of solid matrix, and increase in size distribution of solid matrix and pore in the presence of hydrates. Further studies are necessary to represent the results of the unsteady-state flow experiment in HBS with a gas hydrate-dependent relative permeability model.

Multiphase vortex flow patterns in slab caster mould: insights of air vortex interaction and plant data analysis

ABSTRACT Vortexing in continuous slab casting can entrain mould powder and thus damage the slab quality. In this investigation, a 0.4-scale water caster has been employed to explore the interaction between air and vortices. Black sesame seeds are injected into the water to get the better visualisation of air-vortex interaction. Momentum exchange between ascending air bubbles and vortexing has caused variations in both frequencies and characteristics of the vortices. SEN port clogging would introduce multiphase flow asymmetry. The consequence of the multiphase flow asymmetry on air bubbles sizes is explained. In order to reconcile the observations of water model experiments, mould powder entrained sliver data has been collected for analysis. ROCK clustering algorithm is applied on this data set. The largest cluster produced by the algorithm represents the data combination of shallow submergence depth, high casting speed and high value of SEN operation duration. This result is in perfect tune with the observations of multiphase water flow experiments.