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.     

Investigation on heavy crude-water two phase flow and related flow characteristics

In this paper, heavy crude oil–water flows are studied in a horizontal stainless steel test section with 25.4 mm ID and overall length of 50 m. Crude oil (viscosity = 628.1 mPa s, interfacial tension with water = 10.33 mN/m at 60 °C) and water, collected from an oilfield, were used as test fluids. Visual observations, local sampling and pressure drop measurements were used to identify the flow patterns and their transitions. It was found that in all conditions studied there was a water-in-oil emulsion present. At low mixture velocities and water fractions this occupied the whole pipe cross section. As the velocity or the volume fraction increased water appeared to segregate. At high water fractions and mixture velocities annular flow appeared with the water-in-oil emulsion in the core surrounded by a water layer. The results were compared with those from a model oil with the same viscosity. At low water fractions there was a similarity between the patterns observed with the two oil systems characterized by water segregation from an oil continuous dispersion with increasing water fraction or mixture velocity. However, at high water fractions an oil-in-water dispersion formed with the model oil that was not seen with the crude oil. Pressure drop was generally higher for the crude oil system compared to the model one, while in both cases it decreased when water started to segregate and form layers in contact with the pipe wall. The differences between the two oil systems are attributed to the natural surfactants present in the heavy crude oil (such as asphaltenes and resins), which tend to accumulate on the water/oil interface, retard film drainage and maintain the stability of water drops in oil.     

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.     

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.     

Experimental investigation on the slip between oil and water in horizontal pipes

This work is devoted to study of the slip phenomenon between phases in water–oil two-phase flow in horizontal pipes. The emphasis is placed on the effects of input fluids flow rates, pipe diameter and viscosities of oil phase on the slip. Experiments were conducted to measure the holdup in two horizontal pipes with 0.05 m diameter and 0.025 m diameter, respectively, using two different viscosities of white oil and tap water as liquid phases. Results showed that the ratios of in situ oil to water velocity at the pipe of small diameter are higher than those at the pipe of big diameter when having same input flow rates. At low input water flow rate, there is a large deviation on the holdup between two flow systems with different oil viscosities and the deviation becomes gradually smaller with further increased input water flow rate.     

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.     

Experimental flow pattern map,slippage and time–frequency representation of oil–water two-phase flow in horizontal small diameter pipes

We detect the flow structures of a horizontal oil–water two-phase flow in a 20 mm inner-diameter pipe using 8-channels radial mini-conductance probes. In particular, we present an experimental flow pattern map that includes 218 flow conditions and compare this map to the flow pattern transitional boundaries predicted by published models. In addition, using the Adaptive Optimal Kernel Time–Frequency Representation, we analyze the conductance fluctuating signals and characterize the flow pattern in terms of the total energy and dominant frequency. Based on the liquid holdup measurements using the quickly closing valve technology combined with three parallel-wire capacitance probes, we investigate the slip effect between the oil and water phases under various flow conditions. The results show that the flow structures greatly affect the slippage, and the slip ratio is sensitive to flow pattern variations.     

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.     

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.     

Three-dimensional flow pattern visualization and bubble size distributions in stationary and transient upward flashing flow

For the first time, an experimental three-dimensional reconstruction and visualization of stationary and transient flashing flow in a vertical pipe (47 mm diameter) is presented. The measurements have been performed by means of wire-mesh sensors. This type of sensor delivers two-dimensional void-fraction distributions in the pipe cross-section where it is mounted with a maximum sampling rate of 10,000 frames per second. A sampling rate of 1200 frames per second has been used in this work. Steam bubbles have been identified from the wire-mesh data and their complete three-dimensional reconstruction has been performed by taking into account the steam bubble velocity. For the estimation of the bubble velocity, two wire-mesh sensors positioned at a small axial distance from each other have been used. The velocity has been determined by cross-correlation of the two wire-mesh signals, by direct identification of the traveling time of the steam bubbles between the two sensors and by means of a drift-flux model. A comparison between the three methods of bubbles velocity measurement is reported. Stationary and time-dependent bubble size distributions have been derived. The stationary radial void-fraction profiles have been decomposed according to bubble size classes and compared with the results obtained with an equilibrium model.     

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.     

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.     

Three phase liquid–liquid–gas flows in 5.6 mm and 7 mm inner diameter pipes

Three phase liquid–liquid–gas flow maps in pipes of medium inner diameters (5.6 mm and 7 mm), are presented. A low viscosity paraffin oil (4.5 × 10⁻³ Pa s viscosity and 818.5 kg m⁻³ density at 20 °C), deionised water and air are flowing concurrently in Schott Duran^® glass pipes. A decreasing pipe diameter changes the flow pattern maps and also the behavior of the transition boundaries. Flow patterns are determined by high speed photography. To illuminate the pipe, laser induced fluorescence (LIF) is applied. The laser sheet is cutting through the axial vertical plane of the pipe. The laser light excites a fluorescent dye (uranine) in the water phase to separate the phases optically. The resulting flow maps are compared with literature data and a theoretical model.     

Numerical modeling and experimental investigation of gas–liquid slug formation in a microchannel T-junction

Gas–liquid two-phase flow in a microfluidic T-junction with nearly square microchannels of 113 μm hydraulic diameter was investigated experimentally and numerically. Air and water superficial velocities were 0.018–0.791 m/s and 0.042–0.757 m/s, respectively. Three-dimensional modeling was performed with computational fluid dynamics (CFD) software FLUENT and the volume of fluid (VOF) model. Slug flow (snapping/breaking/jetting) and stratified flow were observed experimentally. Numerically predicted void fraction followed a linear relationship with the homogeneous void fraction, while experimental values depended on the superficial velocity ratio U_G/U_L. Higher experimental velocity slip caused by gas inlet pressure build-up and oscillation caused deviation from numerical predictions. Velocity slip was found to depend on the cross-sectional area coverage of the gas slug, the formation of a liquid film and the presence of liquid at the channel corners. Numerical modeling was found to require improvement to treat the contact angle and contact line slip, and could benefit from the use of a dynamic boundary condition to simulate the compressible gas phase inlet reservoir.     

Trapped water displacement from low sections of oil pipelines

The study is motivated by the problem of pipeline corrosion due to water accumulation at low spots. Lab-scale experiments were conducted to identify the critical conditions required for the onset of water displacement by oil flow from a low horizontal section into an upward inclined section of the pipeline. Two test loops with pipe diameters of 27 mm and 41 mm I.D. with diesel flow were used. Water withdrawal from tapping valves distributed along the up-hill section enabled to follow the water displacement for oil flow rates exceeding the critical value.     

Investigation of two-phase flow pattern,liquid holdup and pressure drop in viscous oil–gas flow

An experimental investigation was carried out on viscous oil–gas flow characteristics in a 69 mm internal diameter pipe. Two-phase flow patterns were determined from holdup time-traces and videos of the flow field in a transparent section of the pipe, in which synthetic commercial oils (32 and 100 cP) and sulfur hexafluoride gas (SF₆) were fed at oil superficial velocities from 0.04 to 3 m/s and gas superficial velocities from 0.0075 to 3 m/s.     

Heat transfer to air–water annular flow in a horizontal pipe

Two-phase air–water flow and heat transfer in a 25 mm internal diameter horizontal pipe were investigated experimentally. The water superficial velocity varied from 24.2 m/s to 41.5 m/s and the air superficial velocity varied from 0.02 m/s to 0.09 m/s. The aim of the study was to determine the heat transfer coefficient and its connection to flow pattern and liquid film thickness. The flow patterns were visualized using a high speed video camera, and the film thickness was measured by the conductive tomography technique. The heat transfer coefficient was calculated from the temperature measurements using the infrared thermography method. It was found that the heat transfer coefficient at the bottom of the pipe is up to three times higher than that at the top, and becomes more uniform around the pipe for higher air flow-rates. Correlations on local and average Nusselt number were obtained and compared to results reported in the literature. The behavior of local heat transfer coefficient was analyzed and the role of film thickness and flow pattern was clarified.     

The characteristics of gas/liquid flow in large risers at high pressures

Although most of the work reported on two-phase flows are limited to small pipe diameters, two-phase flow in large risers are increasingly being encountered in the petroleum and nuclear industries. In the present work, a wire mesh sensor was employed to obtain void fraction and bubble size distribution data and visualizations of steam/water flow in a large vertical pipe (194 mm in diameter) at 46 bar. For comparison purposes, measurements were made at similar phase velocities and physical properties to a dataset for nitrogen/naphtha flow in a similar-sized riser. There exist significant differences between both sets of data. Churn-turbulent flow is observed in the present work instead of slug flow, and this differs from the intermittent and semi-annular flow patterns reported for nitrogen/naphtha data. The mean void fraction of the nitrogen/naphtha data is higher than that of the present steam/water data due to the differences in purity in the liquid phases. Furthermore, core peak distributions are observed for the present work in contrast to the flatter profiles deduced for the nitrogen/naphtha using a power law relationship.     

Effect of drag reducing polymers on oil–water flow in a horizontal pipe

Measurements of drag-reduction are presented for oil–water flowing in a horizontal 0.0254 m pipe. Different oil–water configurations were observed. The injection of water soluble polymer solution (PDRA) in some cases produced drag reduction of about 65% with concentration of only 10–15 ppm. The results showed a significant reduction in pressure gradient due to PDRA especially at high mixture velocity which was accompanied by a clear change in the flow pattern. Phase inversion point in dispersed flow regime occurred at a water fraction range of (0.33–0.35) indicated by its pressure drop peak which was disappeared by injecting only 5 ppm (weight basis) of PDRA. Effect of PDRA concentration and molecular weight on flow patterns and pressure drops are presented in this study. Influence of salt content in the water phase on the performance of PDRA is also examined in this paper.     

Experiments with a Wire-Mesh Sensor for stratified and dispersed oil-brine pipe flow

Two-phase oil–water flow was studied in a 15 m long horizontal steel pipe, with 8.28 cm internal diameter, using mineral oil (having 830 kg/m³ density and 7.5 mPa s viscosity) and brine (1073 kg/m³ density and of 0.8 mPa s viscosity). Measurements of the holdup and of the cross-sectional phase fraction distribution were obtained for stratified flow and for highly dispersed oil–water flows, applying a capacitive Wire-Mesh Sensor specially designed for that purpose. The applicability of this measurement technique, which uses a circuit for capacitive measurements that is adapted to conductive measurements, where one of the fluids is water with high salinity (mimicking sea water), was assessed. Values for the phase fraction values were derived from the raw data obtained by the Wire-Mesh Sensor using several mixture permittivity models. Two gamma-ray densitometers allowed the accurate measurement of the holdups, which was used to validate the data acquired with the capacitive Wire-Mesh Sensor. The measured time-averaged distribution of the phase fraction over the cross-sectional area was used to investigate the details of the observed two-phase flow patterns, including the interface shape and water height. The experiments were conducted in the multiphase-flow test facility of Shell Global International B.V. in the Netherlands.