Experimental study on the transition between stratified and non-stratified horizontal oil-water flow

The effect of oil and water velocities, pipe diameter and oil viscosity on the transition from stratified to non-stratified patterns was studied experimentally in horizontal oil-water flow. The investigations were carried out in a horizontal acrylic test section with 25.4 and 19 mm ID with water and two oil viscosities (6.4 and 12 cP) as test fluids. A high-speed video camera was used to study the flow structures and the transition. At certain oil velocity, stratified flow was found to transform into bubbly and dual continuous flows as superficial water velocity increased for both pipe diameters using the 12 cP oil viscosity. The transition to bubbly flow was found to disappear when the 6.4 cP oil viscosity was used in the 25.4 mm pipe. This was due to the low E?tv?s number. Transition to dual continuous flow occurred at lower water velocity for oil velocity up 0.21 m/s when 6.4 cP oil was used in the 25.4 mm ID pipe, while for U_so > 0.21 m/s, the transition appeared at lower water velocity with the 12 cP oil.The effect of pipe diameter was also found to influence the transition between stratified and non-stratified flows. At certain superficial oil velocity, the water velocity required to form bubbly flow increased as the pipe diameter increased while the water velocity required for drop formation decreased as the pipe diameter increased. The maximum wave amplitude was found to grow exponentially with respect to the mixture velocity. The experimental maximum amplitudes at the transition to non-stratified flow agreed reasonably well with the critical amplitude model. Finally, it was found that none of the available models were able to predict the present experimental data at the transition from stratified to non-stratified flow.     

Single-beam gamma densitometry measurements of oil–water flow in horizontal and slightly inclined pipes

Gamma densitometry is a frequently used non-intrusive method for measuring component volume fractions in multiphase flow systems. The application of a single-beam gamma densitometer to investigate oil–water flow in horizontal and slightly inclined pipes is presented. The experiments are performed in a 15 m long, 56 mm diameter, inclinable stainless steel pipe using Exxsol D60 oil (viscosity 1.64 mPa s, density 790 kg/m³) and water (viscosity 1.0 mPa s, density 996 kg/m³) as test fluids. The test pipe inclination is changed in the range from 5° upward to 5° downward. Experimental measurements are reported at three different mixture velocities, 0.25, 0.50 and 1.00 m/s, and the inlet water cut is varied from 0 to 1. The gamma densitometer is composed of radioactive isotope of Am-241 with the emission energy of 59.5 keV, scintillation detector [NaI(Tl)] and signal processing system. The time averaged cross-sectional distributions of oil and water phases are measured by traversing the gamma densitometer along the vertical pipe diameter. Based on water volume fraction measurements, water hold-up and slip ratio are estimated. The total pressure drop over the test section is measured and frictional pressure drop is estimated based on water hold-up measurements. The measurement uncertainties associated with gamma densitometry are also discussed. The measured water hold-up and slip ratio profiles are strongly dependent on pipe inclination. In general, higher water hold-up values are observed in upwardly inclined pipes compared to the horizontal and downwardly inclined pipes. At low mixture velocities, the slip ratio decreases as the water cut increases. The decrease is more significant as the degree of inclination increases. The frictional pressure drop for upward flow is slightly higher than the horizontal flow. In general, there is a marginal difference in frictional pressure drop values for horizontal and downwardly inclined flows.     

Upward and downward inclination oil–water flows

The effect of upward (+5°, +10°) and downward (−5°) pipe inclinations on the flow patterns, hold up and pressure gradient during two-liquid phase flows was investigated experimentally for mixture velocities between 0.7 and 2.5 m/s and phase fractions between 10% and 90%. The investigations were performed in a 38 mm ID stainless steel test pipe with water and oil as test fluids. High-speed video recording and local impedance and conductivity probes were used to precisely identify the different flow patterns. In both positive and negative inclinations the dispersed oil-in-water regime extended to lower mixture velocities and higher oil fractions compared to horizontal flow. A new flow pattern, oil plug flow, appeared at both +5° and +10° inclination while the stratified wavy pattern disappeared at −5° inclination. The oil to water velocity ratio was higher for the upward than for the downward flows but in the majority of cases and all inclinations oil was flowing faster than water. At low mixture velocities the velocity ratio increased with oil fraction while it decreased at high velocities. The increase became more significant as the degree of inclination increased. The frictional pressure gradient in both upward and downward flows was in general lower than in horizontal flows while a minimum occurred at all inclinations at high mixture velocities during the transition from dispersed water-in-oil to dual continuous flow.     

An inverse dispersed multiphase flow model for liquid production rate determination

The aim of this study is to develop a model for the determination of the superficial velocities in horizontal and slightly inclined oil–water pipe flow conditions by using pressure gradient and mixture density information. In this article an inverse model is suggested for a dispersion of oil in water and of water in oil. This approach permits to select dispersed flow conditions from a set of experimental data, and uses a new hybrid model for the effective viscosity. A set of 310 oil–water experimental data points collected on an experimental set-up of length L = 15 m and diameter D = 8.28 cm at various (slight) orientations is used to validate the inverse method. The comparison between model reconstructions and measured flow velocities show a reasonable agreement.     

Effect of glycerol addition on phase inversion in horizontal dispersed oil-water pipe flows

The effect of interfacial tension on the phase inversion process during horizontal pipe flow of an oil-aqueous solution was investigated. Interfacial tension was varied by adding small amounts of glycerol in the water phase. At these glycerol concentrations the density and viscosity of the aqueous phase changed by 1% or less. Exxsol™ D140 (5.5 mPa s, 828 kg m⁻³) was used as the oil phase. The experiments were carried out in a 38 mm ID acrylic test pipe. The phase continuity and appearance of phase inversion were investigated using conductivity (wire and ring) probes and an Electrical Resistance Tomographic (ERT) system. The ERT also provided diagrams of the phase distribution in a pipe cross section. Drop size distribution was monitored using a dual impedance probe. It was found that starting from a water continuous flow with increasing oil fraction at constant mixture velocity the mixture inverted initially in the middle of the pipe (measured at 19 mm from the top pipe wall) while a higher oil fraction was required for inversion at the top (measured at 4 mm from the top pipe wall) and finally the rest of the pipe. The addition of glycerol did not affect the phase fraction where the initial inversion occurred but caused an increase in the oil fraction needed to complete the inversion. The drop size measurements were used to explain this behaviour. Pressure drop was found to decrease with increasing oil fraction but this trend reversed when inversion spread to the pipe wall and the oil continuous phase came in contact with it.     

Slip ratio in dispersed viscous oil-water pipe flow

In this article, dispersed flow of viscous oil and water is investigated. The experimental work was performed in a 26.2-mm-i.d. 12-m-long horizontal glass pipe using water and oil (viscosity of 100 mPa s and density of 860 kg/m³) as test fluids. High-speed video recording and a new wire-mesh sensor based on capacitance (permittivity) measurements were used to characterize the flow. Furthermore, holdup data were obtained using quick-closing-valves technique (QCV). An interesting finding was the oil-water slip ratio greater than one for dispersed flow at high Reynolds number. Chordal phase fraction distribution diagrams and images of the holdup distribution over the pipe cross-section obtained via wire-mesh sensor indicated a significant amount of water near to the pipe wall for the three different dispersed flow patterns identified in this study: oil-in-water homogeneous dispersion (o/w H), oil-in-water non-homogeneous dispersion (o/w NH) and Dual continuous (Do/w & Dw/o). The phase slip might be explained by the existence of a water film surrounding the homogeneous mixture of oil-in-water in a hidrofilic-oilfobic pipe.     

Influence of gas injection on phase inversion in an oil–water flow through a vertical tube

An experimental study has been made of the influence of gas injection on the phase inversion between oil and water flowing through a vertical tube. Particular attention was paid to the influence on the critical concentration of oil and water where phase inversion occurs and on the pressure drop increase over the tube during phase inversion. By using different types of gas injectors also the influence of the bubble size of the injected gas on the phase inversion was studied. It was found that gas injection does not significantly change the critical concentration, but the influence on the pressure drop is considerable. For mixture velocities larger than 1 m/s, the pressure drop over the tube increases with decreasing bubble size and at inversion can become even larger than the pressure drop during the flow of oil and water without gas injection.     

Bubble and liquid turbulence characteristics of bubbly flow in a large diameter vertical pipe

The bubble and liquid turbulence characteristics of air–water bubbly flow in a 200 mm diameter vertical pipe was experimentally investigated. The bubble characteristics were measured using a dual optical probe, while the liquid-phase turbulence was measured using hot-film anemometry. Measurements were performed at six liquid superficial velocities in the range of 0.2–0.68 m/s and gas superficial velocity from 0.005 to 0.18 m/s, corresponding to an area average void fraction from 1.2% to 15.4%. At low void fraction flow, the radial void fraction distribution showed a wall peak which changed to a core peak profile as the void fraction was increased. The liquid average velocity and the turbulence intensities were less uniform in the core region of the pipe as the void fraction profile changed from a wall to a core peak. In general, there is an increase in the turbulence intensities when the bubbles are introduced into the flow. However, a turbulence suppression was observed close to the wall at high liquid superficial velocities for low void fractions up to about 1.6%. The net radial interfacial force on the bubbles was estimated from the momentum equations using the measured profiles. The radial migration of the bubbles in the core region of the pipe, which determines the shape of the void profile, was related to the balance between the turbulent dispersion and the lift forces. The ratio between these forces was characterized by a dimensionless group that includes the area averaged Eötvös number, slip ratio, and the ratio between the apparent added kinetic energy to the actual kinetic energy of the liquid. A non-dimensional map based on this dimensionless group and the force ratio is proposed to distinguish the conditions under which a wall or core peak void profile occurs in bubbly flows.     

Slope effect on core-annular flow

To facilitate the flow of heavy viscous oils in a pipe, a water-lubricated transport is generally used. The water migrates into the regions of high shear at the pipe wall where it lubricates the flow. The pumping pressures are balanced by wall shear stresses in the water, the process therefore requires pressures comparable to pumping water alone, with no dependence on the viscosity of the oil. This means that significant savings in pumping power can be derived from this process, provided that it is well monitored. Indeed, the flow of a water/oil mixture in a pipe has two main characteristics. First, the fluids can adopt different spatial arrangements called flow regimes, and second, the presence of a water layer at the channel wall significantly reduces the global pressure drop. In this paper, an experimental investigation was performed on the effect of pipe slope and fluids flow rates on flow regimes, pressure drop and interfacial instability.     

Multiphase drag reduction: Effect of eliminating slugs

Two-phase pressure drop measurements were taken for air/water mixtures in a 0.052-m diameter horizontal pipe with special focus on the superficial liquid velocity range of 0.03–1.2 m/s at superficial gas velocities of 3.8, 5.2, and 6.6 m/s. It was found that the addition of 400 ppm of sodium dodecyl sulfate (SDS) to the water reduced the pressure drop by 25–40% when compared to equal flow rates without SDS. The pressure drop reduction occurred where the SDS eliminated the occurrence of the intermittent flow present with water. It was also found that the same concentration of SDS had virtually no effect on single phase liquid pressure drop. The pressure drop reduction appears to be due solely to the suppression of intermittent flow patterns.     

Simultaneous entrainment of oil and water droplets in high Reynolds number gas turbulence in horizontal pipe flow

We develop a 1D cross sectional concentration profile model for oil and water droplets that coexist in the turbulent gas phase (of Re ∼ 10⁶) in near horizontal stratified pipe flows. Entrainment of the oil and water mixture from a liquid film near the bottom of the pipe into the gas is modeled based on earlier single-fluid entrainment correlations. A Gamma distribution for the droplet sizes based on the breakup of liquid filaments, is adopted. An explicit algebraic–exponential formula for the total concentration profile for either phase can then be derived.     

Experimental study on oil–water flow in horizontal and slightly inclined pipes

Oil–water two-phase flow experiments were conducted in a 15 m long, 8.28 cm diameter, inclinable steel pipe using mineral oil (density of 830 kg/m³ and viscosity of 7.5 mPa s) and brine (density of 1060 kg/m³ and viscosity of 0.8 mPa s). Steady-state data on flow patterns, two-phase pressure gradient and holdup were obtained over the entire range of flow rates for pipe inclinations of −5°, −2°, −1.5°, 0°, 1°, 2° and 5°. The characterization of flow patterns and identification of their boundaries was achieved via observation of recorded movies and by analysis of the relative deviation from the homogeneous behavior. A stratified wavy flow pattern with no mixing at the interface was identified in downward and upward flow. Two gamma-ray densitometers allowed for accurate measurement of the absolute in situ volumetric fraction (holdup) of each phase for all flow patterns. Extensive results of holdup and two-phase pressure gradient as a function of the superficial velocities, flow pattern and inclinations are reported. The new experimental data are compared with results of a flow pattern dependent prediction model, which uses the area-averaged steady-state two-fluid model for stratified flow and the homogeneous model for dispersed flow. Prediction accuracies for oil/water holdups and pressure gradients are presented as function of pipe inclination for all flow patterns observed. There is scope for improvement for in particular dual-continuous flow patterns.     

Viscous oil–water flows in a microchannel initially saturated with oil: Flow patterns and pressure drop characteristics

Immiscible viscous liquid–liquid two-phase flow patterns and pressure drop characteristics in a circular microchannel have been investigated. Water and silicone oil with a dynamic viscosity of 863 mPa s were injected into a fused silica microchannel with an inner diameter of 250 μm. As the microchannel was initially filled with the silicone oil, an oil film was found to always form and remain on the microchannel wall. Different flow patterns were observed and classified over a wide range of water and oil flow rates. A flow pattern map is presented in terms of Re, Ca, and We numbers. Two-phase pressure drop data have also been collected and analyzed to develop a simple correlation for slug, annular and annular-droplet flow patterns in terms of superficial water and oil velocities.     

Effect of drag reducing polymer on air–water annular flow in an inclined pipe

Drag reduction (DR) for air and water flowing in an inclined 0.0127 m diameter pipe was investigated experimentally. The fluids had an annular configuration and the pipe is inclined upward. The injection of drag reducing polymer (DRP) solution produced drag reductions as high as 71% with concentration of 100 ppm in the pipeline. A maximum drag reduction that is accompanied (in most cases) by a change to a stratified or annular-stratified pattern. The drag reduction is sensitive to the gas and liquid superficial velocities and the pipe inclination. Maximum drag reduction was achieved in the case of pipe inclination of 1.28° at the lowest superficial gas velocity and the highest superficial liquid velocity. For the first time in literature, the drag reduction variations with the square root of the superficial velocities ration for flows with the same final flow patterns have self-similar behaviors.     

Experimental study on interfacial waves in stratified horizontal oil–water flow

Interfacial wave characteristics were studied experimentally in horizontal oil–water pipe flows during stratified flow and at the transition to dual continuous flow, where drops of one phase appear into the other (onset of entrainment). The experimental investigations were carried out in a stainless steel test section with 38 mm ID with water and oil (density 828 kg/m³and viscosity 5.5 mPas) as test fluids. Wave characteristics were obtained with a high speed video camera and a parallel wires conductivity probe that measured the instantaneous fluctuations of the interface. Experiments were conducted at 2 m and at 6 m from the inlet. Visual observations revealed that no drops are formed when interfacial waves are absent. It was also found that waves have to reach a certain amplitude before drops can detach from their crests. Wave amplitudes are increased as the superficial velocities of both phases increase. In the stratified region, the mean wave amplitude decreases by increasing the oil–water input ratio while mean wavelength increases as the slip velocity between the two-phase decreases. At the onset of entrainment, the mean amplitude and length are found to be a function of the relative velocity between the oil and water layers and of the turbulence in each layer.     

The effect of pipe diameter on the structure of gas/liquid flow in vertical pipes

Experimental work on two-phase vertical upward flow was carried out using a 19 mm internal diameter, 7 m long pipe and studying the time series of cross-sectional average void fractions and pressure gradient which were obtained simultaneously. With the aid of a bank of published data in which the pipe diameter is the range from 0.5 to 70 mm, the effect of pipe diameter on flow characteristics of two-phase flow is investigated from various aspects. Particularly, the work focuses on the periodic structures of two-phase flow. Average film thicknesses and the gas flow rate where slug/churn and churn/annular flow transitions occur all increase as the diameter of the pipe becomes larger. On the other hand, the pressure gradients, the frequencies of the periodic structures and the velocities of disturbance waves decrease. The velocity of disturbance waves has been used to test the model of Pearce (1979). It is found that the suggested value of Pearce coefficient 0.8 is reasonable for lower liquid flow rates but becomes insufficient for higher liquid flow rates.     

Numerical and experimental study of an axially induced swirling pipe flow

In-line flow segregators based on axial induction of swirling flow have important applications in chemical, process and petroleum production industries. In the later, the segregation of gas bubbles and/or water droplets dispersed into viscous oil by swirling pipe flow may be beneficial by either providing a pre-separation mechanism (bubble and/or drop coalescer) or, in the case of water-in-oil dispersions, by causing a water-lubricated flow pattern to establish in the pipe (friction reduction). Works addressing these applications are rare in the literature. In this paper, the features and capabilities of swirling pipe flow axially induced by a vane-type swirl generator were investigated both numerically and experimentally. The numerical analysis has been carried out using a commercial CFD package for axial Reynolds numbers less than 2000. Pressure drop, tangential and axial velocity components as well as swirl intensity along a 5 cm i.d. size and 3 m long pipe were computed. Single phase flow experiments have been performed using a water–glycerin solution of 54 mPa s viscosity and 1210 kg/m³ density as working fluid. The numerical predictions of the pressure drop were compared with the experimental data and agreement could be observed within the range of experimental conditions. The experiments confirmed that swirl flow leads to much higher friction factors compared with theoretical values for non-swirl (i.e. purely axial) flow. Furthermore, the addition of a conical trailing edge reduces vortex breakdown. Visualization of the two-phase swirling flow pattern was achieved by adding different amounts of air to the water–glycerin solution upstream the swirl generator.     

Experimental investigation of air–oil slug flow using capacitance probes,hot-film anemometer,and image processing

Despite the importance of air–oil slug flows to many industrial applications, their available data reported in the literature are limited compared to air–water slug flows. The main objective of the present study is to explain how air–oil slug flow parameters can be experimentally investigated using hot-film anemometry, capacitance sensors and image processing. Experiments were performed using air–oil slug flow through a horizontal pipe for air superficial velocities ranged from 0.01 m/s to 0.65 m/s and oil superficial velocities ranged from 0.03 m/s to 2.3 m/s. The signal obtained from the hot-film anemometer was used to determine the time-averaged local void fraction and liquid velocity and turbulence intensity for air–oil slug flow. The capacitance signals along with the data obtained by image processing of the flow were used to determine the elongated bubble length and velocity. The measurements techniques used found to describe in detail the internal structure of the slug flow. Finally, the experimental results were compared to existing models and correlations.     

Effect of pipe inclination on holdups/velocity ratios of oil-water flow without and with addition of drag-reducing polymer

In petroleum industries, the demand for effective design and operation of the oil-water transport systems is very high, and holdup of each phase is one of the important hydrodynamic parameters needed for such design and operation. This parameter can be affected by several factors one of which is the presence of the drag-reducing polymers in the oil-water flow. Therefore, the focus of this experimental study is on the effect of the drag-reducing polymer on the holdups and by extension, velocity ratios of the oil-water flow. Specifically, the investigation of the holdups and velocity ratios of the oil-water flow before and after the addition of the drag-reducing polymer was carried out in horizontal (0^ᴼ) and different inclined (−5^ᴼ, +5^ᴼ and +10^ᴼ) acrylic pipe with 30.6-mm ID. The investigation was conducted using flow conditions of 0.4, 0.8 and 1.6 m/s mixture velocities and 0.1–0.9 input oil volume fractions at each inclination. In each experimental run, the holdup of each phase was measured after steady flow was achieved using quick closing valves. Thereafter, the master solution of the polymer which was prepared at 2000 ppm water was injected at controlled flow rates to provide 40 ppm of the polymer in the water phase and the measurement was repeated. It was found generally that the water holdups and hence, the velocity ratios were increased after the addition of the polymer particularly in water-dominated flow regions. The velocity ratios also increased with the increase in the mixture velocities at these same flow regions. Finally, water was found to flow faster for separated flow at 0.4 m/s while for the dispersed flow regions at higher mixture velocities, the dispersed phase was in general the faster flowing phase.