Crude oil-water flow in horizontal pipes

Robbert Kroes, Lene Amundsen and Rainer Hoffmann

August 27, 2013

Abstract

Flow experiments are presented for three different crude oil - water systems in horizontal pipes. An X-

ray tomograph is used to determine the concentration distribution of water over the cross section of the pipe.

The three crude oil - water systems showed different behavior than model oil - water systems in previously

published studies, both in terms of the concentration distribution and the pressure gradient. An oil-water flow

model has been developed by Amundsen et al. (2009). This model of the oil-water flow is tested against the

experimental data. The model is able to replicate both the pressure gradient and the concentration distribution

of crude oil - water flow for almost all operating conditions. The model does not apply in the region of

transition from stratified to fully dispersed flow.

1 Introduction

The complicated rheological behavior of oil-water mixtures makes transportation of these fluids complex. Much

research has been performed on oil-water flows, but a complete understanding has not yet been obtained.

The distance of pipeline transport of the well fluids has increased due to intensifying of offshore oil and gas

exploration. Optimizations of pipeline operations for simultaneous transport of oil and water requires knowl-

edge of the behavior of the flow of oil - water mixtures.

Transportation of oil and water can result in different characteristic distributions of oil and water. The

different distributions are often called flow regimes or flow patterns. Reliable estimation of the flow regimes

in oil-water pipe flows are required for many processes in the petroleum industry. The pressure gradient of

horizontal pipe flows can be very much dependent on the flow regimes that occur. Better prediction of flow the

pattern will yield a better design of multiphase pipeline systems in the petrochemical industry.

1

Dense packed water droplets Dense packed oil droplets

Inhomogeneous water in oil Inhomogeneous oil in water

Homogeneous water in oil Homogeneous oil in water

(a) Dispersed flows

Smooth interface, full seperation Wavy with partly dispersed layers

Wavy with fully dispersed layers

(b) Stratified flows

Figure 1: Flow regimes (Elseth (2001); Amundsen (2011))

1.1 Oil-water flow regimes

Since the 1950’s a large number of researchers has studied the flow regimes occurring in oil-water flows. Dif-

ferent researchers have used different classifications of the flow patterns. In the present study, two main flow

regimes are discussed: Stratified flow and dispersed flow. Both flow regimes can be divided into sub regimes

with a more detailed description of the flow structures.

Dispersed flows have only one continuous phase. The other phase is dispersed in the continuous phase in

the form of droplets. The droplets can be dispersed over the whole pipe cross-section, but they can also form a

densely packed layer. Furthermore, the dispersion over the whole pipe cross-section can be either homogeneous

or inhomogeneous. Figure 1a shows examples of different flows that are classified as dispersed flows.

Stratified flows have two separate layers, each with a different continuous phase. Each layer can be partly

or fully dispersed (Soleimani, 1999). According to Elseth (2001), the interface between the two continuous

layers can be either smooth or wavy. A schematic representation of stratified flow regimes is shown in figure

1b.

Studies of the flow regimes of real crude oil and water flows at real life conditions are very scarce. Valle

and Utvik (1997) published one of the first studies on crude oil-water systems. They observed that the mixture

velocity has a minor influence on the water cut at which the transition takes place from dispersed flow to

stratified flow. When the mixture velocity is above the critical velocity for which dispersed flow appears, then

a dispersed flow appears for water cuts below 45% and stratified flows appear for water cuts above 45%. Valle

(2000), who has used both model oils and crude oil, observed that in most cases the mixture velocity does

influence the transition from dispersed flow to stratified flow.

2

1.2 Pressure gradient

Different studies show that the flow regime affects the pressure gradient of multiphase pipe flow. Trallero

(1995) observed a small decrease in the pressure gradient when the flow transits from stratified to dispersed. A

decrease of the pressure gradient was also observed in the transition from stratified with a smooth interface to

stratified with a wavy interface by Valle and Kvandal (1995). Valle (2000) measured similar pressure gradients

for stratified flows and single-phase flows, while Lovick and Angeli (2004) measured a lower pressure gradient

in two-phase flow than in single-phase oil flow. In crude oil experiments, Valle (2000), Valle and Utvik (1997)

and Utvik et al. (2001) observed a peak in the pressure gradient during the transition from oil continuous flow

to stratified flow. Wahumpurage et al. (2008) and Elseth (2001) found a peak in the pressure drop at high water

cuts in model oil systems.

Valle (2000), Solbakken and Schüller (2001) and Utvik et al. (2001) showed the differences between flows

of a recombined hydrocarbon-water system and a system with a model fluid. The differences are significant

in terms of flow regimes and pressure drops. Although the physical properties of the fluids were similar, they

found that the relative pressure drop of real crude oil flows can be up to 50% lower than that of the systems with

the model fluid.

1.3 Concentration distribution experiments

Experiments in which the concentration distributions have been measured are quite rare, especially for crude

oil flows. Both Elseth (2001) and Amundsen (2011) measured the concentration distribution of a of a mixture

of Exxsol and water using a traversing gamma densitometer. Amundsen (2011) states that crude oil - water

systems are expected to behave differently from Exxsol - water systems. Fairuzov et al. (2000) measured the

concentration distribution in experiments with crude oil and water, employing a multi-point sampling probe. He

found that in stratified oil-water flow, complete separation does not occur. According to Fairuzov et al. (2000),

there is always a small amount of water dispersed in the oil layer (> 1.5%) .

1.4 Modeling oil-water flows

A model that can successfully predict the behavior of simultaneous flow of oil and water is of great value in

the petroleum industry. Accurate models for the prediction of the concentration profiles are not yet available in

commercial software. Models for fully dispersed flows were outlined by Mols and Oliemans (1998) and Valle

(2000). Amundsen et al. (2009) presented a model to simulate both fully dispersed flow and stratified flow.

3

1.5 Objectives

Many experimental work has been performed on flows of model oil and water. However, more detailed ex-

periments for real life conditions are necessary to develop and validate simulation models and to improve our

understanding of the behavior of oil-water flows.

In this study, we present results of experiments on two-phase flow regimes for three different crude oil-

water systems in horizontal steel pipes. An X-ray tomograph enables us to obtain the concentration distribution

of the phases in the oil-water flow. This information is used to investigate the behavior of oil-water flows at

different flow conditions. Experiments have been performed for different inlet water cuts and mixture velocities.

The experimental data is used to find the effects of water-cut and mixture velocity on the flow behavior, as

recommended by Amundsen (2011). Different water salinities have been used in the experiments to study

the influence of the water salinity on the concentration profiles. A comparison between the concentration

distributions measured in the present crude oil experiments and the concentration distributions measured in

model oil experiments performed by Elseth (2001) gives more insight in the differences between the behavior

of model oil and that of crude oil.

The results from the present experiments are used to test the performance of a model that is able to predict

the concentration distribution and pressure gradient of oil-water pipe flows. An investigation of the differences

between the predictions of the oil-water flow model and the experimental data from four different experimental

campaigns highlights the future work that is needed in the modeling of oil-water flows.

2 Experimental facilities

The experiments have been performed in the test rig that is located in the Multiphase Flow Laboratory at

Statoil’s Research Centre Porsgrunn, Norway. A schematic layout of the test rig is shown in figure 2. This test

facility has been used for flow regime studies (Hoffmann et al. (2012b)), as well as for wax deposition studies,

as described by Hoffmann et al. (2012a). The test section consists of a two-inch pipe of stainless steel. The

latter is important for simulating flow at field conditions, see Angeli and Hewitt (2000).

Before the experiments start, both phases are preheated in a heat exchanger. During the experiments, water

and oil are pumped separately from the separation tank. The oil and water streams are led into an Y-shaped

mixing device, which initializes a stratified flow at the inlet of the pipe. The Y-shaped mixing device has an

internal separating blade inside, which prevents excessive mixing of the two phases (figure 3). Oil and water

then flow through a 17 m long pipe section in which the flow develops.

4

Oil heatexchanger

Water pump

Water heatexchanger

Mixingdevice

Test section withwater annulus

X-raytomograph

Window

Inflow

straighteningsection

Oil pump

Water heatexchanger

Viscometer &Pre-separator

Tank/separatorwithphaseindicator

Oil

Water

Emulsionzone

Figure 2: Schematic overview of the test rig

After the inflow section, the flow enters a window section for visual observation of the flow structure.

Downstream of the window section the concentration distribution is measured by an X-ray tomograph (see

section 2.3). Subsequently, the fluids enter the test section, which can be cooled by a water annulus. The

cooling enables to to simulate subsea conditions and creates the possibility to trigger wax deposition. For the

experiments in this study, the water temperature of the cooling water was set equal to the temperature of the

oil-water flow.

separatingblade

oil

water

Figure 3: Mixing device

Downstream of the test section, the flow is pre-separated and finally the oil and water enter the main sepa-

rator. This large separation vessel with a maximum volume of 4200 liters has been designed to provide a long

retention time and to prevent wax depletion of the circulating oil. In the vessel oil and water are separated by

gravity so that separate mono-phases can be pumped again into the test section. Density measurements in front

of each pump monitor the separation quality for the oil and for the water phase.

5

During an experiment, all standard parameters are logged continuously: Temperature, flow rates, density

and pressure drops over two parts of the inflow section and over the whole test section.

2.1 Flow development section

The mixing device introduces oil into the upper half of the joint pipe and water into the lower half. Downstream

of the mixing device it is important to have a flow development section before the actual test section in order

to achieve a fully developed flow. According to Grassi et al. (2008), the literature does not provide the length

after which liquid-liquid flows are fully developed. In his literature study, Grassi pointed out that many authors

use data from their facilities for the validation of fully-developed flow models, though being aware of a possible

mismatch. The flow development lengths considered in the study of Grassi vary between 80 and 275 times the

pipe diameter. In addition there is one straightening section of 480 times the pipe diameter. In the present set-up,

the entry length is well above the average used length: it is more than 300 times the pipe diameter. However,

the flow development section is curved, which can have an adverse effect on the flow development.

2.2 Separation

Inspection of the density of both phases before they re-enter the mixing device, enables to check whether or

not the phases have been separated sufficiently in the settling tank. Analysis of the constantly logged density of

both phases indicate that the separator is able to separate the oil and water completely in almost all cases. There

were only two experiments in which the phases were not completely separated before re-entering the mixing

device. In the experiments with oil A (see section 3), up to 8% water was still dispersed in oil in the experiment

for the case of an inlet water cut of 40% and a total flow rate of 15m3/h. Up to 5% oil was still dispersed in

water, in the experiments with oil B and high salinity water for the case of an inlet water cut of 50% and a total

flow rate of 20m3/h.

Analysis of the constantly logged pressure gradient showed that the influence of these small amounts of

dispersions had no effect on the pressure drop. A constant pressure gradient was measured over the complete

duration of these experiments.

2.3 X-ray tomography

An X-ray tomograph was used to measure the concentration distribution over the cross section of the pipe before

the flow enters the test section. The tomograph was built by Innospexion AS. It consists of two pairs of X-ray

6

sources and detectors, so that the concentration distribution can be measured along a horizontal and a vertical

transverse.

The water concentration is calculated from X-ray measurements, averaged over 30 seconds. The water

concentration for a two-phase flow as a function of the vertical position y (figure 4) is calculated by comparing

the measured X-ray intensities for the oil-water flow with the intensity for single-phase oil flow and the one for

single-phase water flow (see Hoffmann and Johnson (2011)).

source1

Test section

source2

cam2

cam1

oil

water

x-raydetectors

Po

sitio

n (

y)

Position (x)

Figure 4: Layout x-ray measurement in the present study

3 Fluid properties

Three measurement campaigns have been performed for three different combinations of oil and water. Two

different types of North Sea gas condensates were used, and three different water compositions. In the experi-

ments, the density is measured online using a Coriolis flow meter (Correolus Promass 63F), the viscosities are

measured using a rheometer (Physica MCR 301) and the interfacial surface tension is measured using a pendant

drop method (Teclis equipment).

In addition to the experiments with crude oil, data of an experimental campaign with Exxsol D60 (model

oil) and water are used for comparison. The experiments with Exxsol D60 and water were presented by Elseth

(2001). That experimental campaign was also performed in a two inch steel pipe test section and the oil and

water flows were mixed by a Y-shaped mixing device, similar to the one described in section 2. The physical

fluid parameters of Exxsol D60 are listed in table 2.

7

3.1 Oil A and water

The first experimental campaign has been conducted using a North Sea gas condensate and formation water

(see table 1). The physical fluid properties are listed in table 2. These properties are shown for the operating

conditions: p = 1 bar and T = 25◦C (wax appearance temperature (WAT ) = 30◦C)

In order to enhance fast separation, an emulsion breaker was added to the oil. A concentration of 100 ppm of

the emulsion breaker Tretolite DMO 86538 of Baker Petrolite was present in the oil A during the experiments.

All measurements of the physical properties were performed after the addition of the emulsion breaker.

Salt Concentration [mg/l]Na2SO4 49

NaCl 361KCl 389

CaCl2 44

Table 1: Salt concentration in the formation water in experiments with oil A

3.2 Oil B and water

Two experimental campaigns have been performed using another North Sea gas condensate. Both campaigns

have been performed with water with different salt contents, one series with a low salinity (LS) water and one

series with a high salinity (HS) water. The physical fluid properties for the fluids in these experiments are

included in table 2. Again, these properties are shown for the operating conditions, which are: p = 1 bar and

T = 40◦C (WAT = 30◦C) for the experiments with the different water salinities.

In a previously conducted wax deposition campaign, a wax inhibitor had been added to the oil phase. The

used wax inhibitor is FX2886 from Nalco with a concentration of 500 ppm. All physical property measurements

were performed after the addition of this wax inhibitor.

The low salinity water has a concentration of 3g/l NaCl, the high salinity water has a concentration of

300g/l NaCl.

Physical property Oil A -water

Oil B -LS-water

Oil B -HS-water

Exxsol D60 -water

Oil density(kg/m3

)8.5 ·102 8.1 ·102 8.1 ·102 7.90 ·102

Water density(kg/m3

)1.00 ·103 1.00 ·103 1.15 ·103 1.00 ·103

Oil viscosity (Pa s) 6.2 ·10−3 3.2 ·10−3 3.2 ·10−3 1.64 ·10−3

Water viscosity (Pa s) 8.9 ·10−4 1.0 ·10−3 1.4 ·10−3 1.02 ·10−3

Interfacial tension (N/m) 1.6 ·10−2 1.6 ·10−2 1.6 ·10−2 4.3 ·10−2

Table 2: Physical properties of the fluids used

8

4 Experimental results

4.1 Experimental matrix

Experiments have been performed for different flow rates and input water cuts. The experiments with oil A

have been performed at total flow rates of 5 m3

h (0.64m/s), 10 m3

h (1.28m/s) and 15 m3

h (1.92m/s) and water cuts

varing from 10% to 90%, in steps of 10%. The experiments with oil B have been performed at total flow rates

of 5 m3

h (0.64m/s), 10 m3

h (1.28m/s), 15 m3

h (1.92m/s), 20 m3

h (2.57m/s) and 25 m3

h (3.21m/s) and water cuts

again varing from 10% to 90%, in steps of 10%.

4.2 Visual observations

Camera pictures of the flow regimes of all crude oil experiments are shown in figure 5. The stratified flow

regimes that occur in the experiments at low flow rates are clearly visible. As the total flow rate increases,

the flow becomes more and more dispersed and the mixtures appear dark. At the low velocity experiments, the

observed layer if clear water at the bottom of the pipe corresponds with the results from the X-ray measurements

(see section 4.3). Simultaneously, in the high velocity experiments, the dark mixture that is observed visually

corresponds to the high amounts of dispersions measured by the X-ray thomograph.(see section 4.3)

4.3 Concentration distributions

4.3.1 Comparison between experimental results for oil A-water and oil B - LS-water

X-ray tomography is used to determine the concentration distribution along a vertical line in the cross section

of the pipe. Figure 6 shows the water concentrations, determined from the X-ray tomography, as function of

height in the pipe for the experiments with oil A and water, compared with the results of the experiments with

oil B and low salinity water.

For the lowest mixture velocity, the flow is stratified with almost no dispersion in both layers for both

oil-water systems. Only for an inlet water cut of 20%, the water layer contains some dispersed oil.

In the experiments with a total flow rate of 10m3/h (1.28 m/s), the flow is mostly in the dispersed flow

regime. The stratified flow regimes that do occur for this flow rate have more dispersion in both layers. However,

complete separation still occurs for an inlet water cut between 50% and 60%. At this flow rate, the flow with oil

B and low salinity water shows more separation than the flow with oil A and water.

The effect, that the flow is mostly in the dispersed flow regime becomes even more clear for a total flow rate

9

0.64 m/s

20% 30% 40% 50% 60% 70% 80%

1.28 m/s

1.92 m/s

(a) Oil A - water

(b) Oil B - LS water

(c) Oil B - HS water

Figure 5: Visual observations for various combinations of flow rate (m/s) and water cut(%)

10

of 15m3/h (1.92 m/s). Stratified flow regimes still appear for water cuts around 50%, but complete separation

is not observed anymore. At this flow rate, the flow with oil A and water is an almost homogeneous dispersion,

especially for high and low water cuts. For oil B and low salinity water the flow is less homogeneous, especially

for water cuts around 50%.

An explanation for the differences between the behavior of the two mixtures is the difference in the fluid

properties. The viscosity of oil A (µ=6.2 cP) is larger than the viscosity of oil B (µ=3.2 cP). Due to this higher

viscosity, turbulent dispersive forces are more prominent and therefore less separation occurs. This corresponds

with the observations: the differences are most significant in the high velocity experiments, for which the

dispersive forces are most prominent.

Top Bot0

1

Wa

ter

fra

ctio

n

Top Bot0

1Water cut 30%

Top Bot0

1Water cut 40%

Top Bot0

1Water cut 50%

Top Bot0

1Water cut 60%

Top Bot0

1Water cut 70%

Top Bot0

1Water cut 80%

Top Bot0

1

Wa

ter

fra

ctio

n

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Height

Top Bot0

1

Wa

ter

fra

ctio

n

Water cut 20%

Height Top Bot0

1

Height Top Bot0

1

Height Top Bot0

1

Height Top Bot0

1

Height Top Bot0

1

Height Top Bot0

1

Height

Oil B - LS-water

Oil A - Water

1.9

2 m

/s1.2

8 m

/s0.6

4 m

/s

Figure 6: Comparison between the concentration distributions of oil A - water and oil B - LS-water along avertical transverse through the pipe

4.3.2 Comparison between experimental results for oil B - LS-water and oil B - HS-water

The concentration distributions obtained for oil B - high salinity water and for oil B - low salinity water are

compared in figure 7. Again, the flow patterns for the lowest total flow rate are all stratified. The results for the

flow with low and high salinity water hardly differ for the lowest flow rate, because the phases are in both cases

completely separated. A small difference between the high and low salinity results is observed for inlet water

cuts of 20%. The water layer of the flow with low salinity water has slightly more dispersion than the water

11

layer of the flow with high salinity water.

For the total flow rates of 10m3/h (1.28 m/s), 15m3/h (1.92 m/s) and 20m3/h (2.57 m/s) the flows are

stratified for water cuts around 50% and dispersed for other values of the water cut. The flow is more dispersed

for the higher total flow rates. Also increasingly more homogeneous dispersions are observed for increasing

flow rates. The differences between the results of the experiments with high salinity water and the ones with

low salinity water are more significant at these flow rates for water cuts around 50%.

The results for the highest flow rate show almost only dispersed flow. Just as for the lowest total flow rate,

the difference between the flows with high salinity water and those of the low salinity water is very small.

The main difference between the flows with high and low salinity water is the density ratio (B-LS: ρwρo

= 1.23,

B-HS: ρwρo

= 1.42). The higher density ratio in the flows with high salinity water will cause stronger buoyancy

forces. At the lowest velocity, the flow is almost fully separated and therefore differences in the buoyancy forces

have only a small effect on the concentration profiles. The differences are clearly visible in the flow regime for

which the flow is not fully separated, but also not homogenous dispersed. The stronger buoyancy forces cause

more separation in the case of flow with high salinity water. For the higher velocities, the turbulent forces are

dominant and the difference in buoyancy forces has negligible effect.

Top Bot0

1

Wate

r fr

action

Water cut 10%

Top Bot0

1Water cut 20%

Top Bot0

1Water cut 30%

Top Bot0

1Water cut 40%

Top Bot0

1Water cut 50%

Top Bot0

1Water cut 60%

Top Bot0

1Water cut 70%

Top Bot0

1Water cut 80%

Top Bot0

1Water cut 90%

Top Bot0

1

Wate

r fr

action

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Wate

r fr

action

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Wate

r fr

action

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Height

Top Bot0

1

Wate

r fr

action

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Oil B -HS-water

Oil B -LS-water

3.2

1 m

/s2.5

7 m

/s1.9

2 m

/s1.2

8 m

/s0.6

4 m

/s

Figure 7: Concentration distributions for flows of oil B - LS-water and for oil B - HS-water along the verticaltransverse through the pipe

12

4.3.3 Comparisons with Exxsol D60

Figure 8 shows the concentration profiles for comparable mixture velocities obtained for Exxsol D60 - water,

oil A - water and oil B - low salinity water. The measured concentration profiles for the model oil systems differ

significantly from the ones for the crude oils, especially at the high mixture velocities. The results for Exxsol

D60 and water show stratified flow for a larger range of velocities than seen for the crude oil - water systems.

For the crude oil, dispersed flows appears over a large range of conditions, while the model oil shows stratified

flow for almost all water cuts.

Due to the higher interfacial tension between the model oil and water (σ = 4.3 ·10−2 N/m), than between

crude oil and water(σ = 1.6 · 10−2 N/m), the drop size in both layers increases. This, together with a larger

density ratio for Exxsol - water ( ρwρo

= 1.27) compared to crude oil - water (B-LS: ρwρo

= 1.23, A: ρwρo

= 1.18),

causes stronger separation effects driven by gravity. Furthermore, due to the lower viscosity of Exxsol D60

compared to that of crude oil, the wall shear stress becomes smaller, leading to smaller effects due to turbulent

dispersion.

Top Bot0

1

Wate

r fr

action

Water cut 20%

Top Bot0

1Water cut 30%

Top Bot0

1Water cut 40%

Top Bot0

1Water cut 50%

Top Bot0

1Water cut 60%

Top Bot0

1Water cut 70%

Top Bot0

1Water cut 80%

Top Bot0

1

Wate

r fr

action

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

1.34 m/s

Top Bot0

1

Top Bot0

1

Top Bot0

1

Height Top Bot0

1

Height Top Bot0

1

Height

1.28 m/s

Umix

1.28 m/s

0.67 m/s

0.64 m/s

0.64 m/s

2.00 m/s

1.92 m/s

1.92 m/s

2.50 m/s

2.57 m/s

Wate

r fr

action

Wate

r fr

action

Height Height Height Height

Umix

Umix

Umix

Oil B - LS-water

Oil A - water

Exxsol D60 - water

Figure 8: Concentration distributions for oil A - water, oil B - LS-water and Exxsol D60 - water, along a verticaltransverse through the pipe

13

4.4 Standard deviations of the measured water concentration

The X-ray measurements have been performed over a period of 30 seconds with a sample frequency of 40 Hz.

By analyzing the time variation of the measured water concentration, interfacial characteristics can be detected.

Figure 9 shows the standard deviation of the water concentration for the measurement results for the three crude

oil systems.

In Figure 9, a clear distinction is visible between the standard deviations of the measurements of the water

concentration in stratified flow compared to that in dispersed flows. The peaks in the distribution of the standard

deviation indicate the position of the interface between the oil and water continuous phases. The position of

the interfaces hardly differs in the stratified flow regimes in all the three oil-water systems, which results in the

clear peak in the standard deviations, especially for the lowest flow rates.

For higher flow rates and water cuts around 50%, the flow is still stratified. For these measurements, the

standard deviation is therefor still higher than for the dispersed flow regime, but the peak broadens. The wavi-

ness of the interface spreads over a larger area, but the variation over time decreases. This is because there is no

sharp interface anymore between the two continuous phases, because the dispersion is relatively dense close to

the interface.

Top Bot0

std

−w

at fr

ac

Water cut 10%

Top Bot0

Water cut 20%

Top Bot0

Water cut 30%

Top Bot0

Water cut 40%

Top Bot0

Water cut 50%

Top Bot0

Water cut 60%

Top Bot0

Water cut 70%

Top Bot0

Water cut 80%

Top Bot0

Water cut 90%

Top Bot0

std

−w

at fr

ac

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

std

−w

at fr

ac

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

std

−w

at fr

ac

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

Top Bot0

std

−w

at fr

ac

HeightTop Bot0

HeightTop Bot0

HeightTop Bot0

HeightTop Bot0

HeightTop Bot0

HeightTop Bot0

HeightTop Bot0

HeightTop Bot0

Height

Oil A - water Oil B - LS-water Oil B - HS-water

3.2

1 m

/s2

.57

m/s

1.9

2 m

/s1

.28

m/s

0.6

4 m

/s

Figure 9: Standard deviations of measurements of the water concentration in flows of oil A - water, oil B-LS-water and oil B - HS-water, along a vertical transverse through the pipe.

14

4.5 Pressure Gradient

The measured pressure gradient is shown as a function of the water cut in figure 10. For oil A - water flow, the

dispersions with an oil continuous phase result in a higher pressure gradient than the dispersions with a water

continuous phase. This is as expected since the viscosity of oil A is higher than that of water.

For oil B - water, a peak in the pressure gradient is observed at higher velocities and water cuts around 50%.

At this flow conditions, the flow is dispersed with oil as the continuous phase with high amounts of dispersed

water. After transition to water as the continuous phase and oil as the dispersed phase, the pressure gradient

drops to approximately the pressure gradient of single-phase water flow. According to crude oil experiments by

Valle (2000), an oil continuous layer becomes more viscous when the amount of dispersed water increases. A

higher fluid viscosity will result in a higher pressure gradient.

The pressure gradient as a function of the water cut for the model oil shows a different behavior than that for

the crude oils. A decrease in the pressure drop is observed for low values of the water cut for mixture velocities

of 2m/s and 2.5m/s. According to Soleimani (1999), the presence of the water drops can suppress turbulence,

which will cause a reduction of the drag and therefor a decrease in the required pressure gradient.

The differences between the pressure gradient required for the crude oil - water systems and the ones for

model oil - water system can be caused by the different surface-active chemicals that are present in the crude

oils. Also the added wax inhibitor and emulsion breakers can affect the apparent viscosity of the emulsion and

therefor the required pressure gradient.

0 20 40 60 80 1000

200

400

600

800

1000

1200

water cut [%]

Pre

ssu

re g

rad

ien

t [P

a/m

]

Oil A - water

0.64m/s

1.28m/s

1.92m/s

(a) Oil A - water

0 20 40 60 80 1000

500

1000

1500

2000

2500

3000

water cut [%]

Pre

ssu

re g

rad

ien

t [P

a/m

]

Oil B − LS water

Oil B − HS water

0.64m/s

1.28m/s

1.92m/s

2.57m/s

3.21m/s

(b) Oil B - HS-water and oil B - LS-water

0 20 40 60 80 1000

100

200

300

400

500

600

700

800

900

1000

water cut [%]

Pre

ssu

re g

rad

ien

t [P

a/m

]

Exxsol D60 − water

0.67m/s

1.34m/s

2.00m/s

2.50m/s

(c) Exxsol D60 - water

Figure 10: Pressure gradient required for the flow of oil - water systems as function of the water cut. Differentvalues of the mixture velocity.

15

4.6 Flow regimes

4.6.1 Phase inversion

In order to set up the flow regime map, the water cut must be known for which the flow changes from oil

continuous to water continuous. The pressure gradient as function of the water cut (see section 4.5) reveals at

which inlet water cut the flow switches from oil continuous to water continuous.

For the flow with oil A at a mixture velocity of 1.92m/s, the first water continuous dispersion appears at an

inlet water cut of 60%. From figure 6 it can then be seen that the water cut at which phase inversion occurs is

about 50%, which is just below the minimum local water concentration at these conditions.

A similar approach is used to determine the water cut at which phase inversion occurs for the flows with oil

B - low salinity water and oil B - high salinity water. In both systems, for a mixture velocity of 3.21m/s, the first

water continuous dispersion with appears at an inlet water cut of 60%. From figure 7 it can now be seen that

also for these flows, the inversion water cut is around 50%, just below the minimum local water concentration

at these conditions.

The value of the water cut for phase inversion for Exxsol is assumed to be 50%, which is the same value as

used by Amundsen (2011).

4.6.2 Flow regime maps

The flow regimes observed for the four different oil-water systems, based on a inversion water cut of 50%, are

shown in figure 11. In these flow regime maps, the orange color indicates the region of operating conditions

in which oil continuous dispersed flows occur (x), the green color indicates the region in which stratified flows

occur (o) and the blue color indicates the region in which the flow is water continuous (+). Within the regime

with stratified flow and the regime with dispersed flow, the flows can be subdivided into different types. In this

study we only focus on the transition between dispersed flow and stratified flow, in which the dispersed flow has

only one continuous phase and the stratified flow has two layers with different continuous phases. Three effects

are observed:

First, from a comparison between figures 11c and 11d it becomes clear that the water salinity has influence

on the flow regime that will appear. Since the density difference is larger in the case of high salinity water, the

region with stratified flow is somewhat larger.

Secondly, the region with stratified flow for the oil A - water system is smaller than that for the oil B - low

salinity water system. This can be explained by the viscosity of oil A being almost twice as high as the viscosity

of oil B. A higher viscosity will cause more turbulent dispersion, and therefore phase separation takes place at

16

higher water cuts. In addition, the density ratio of oil A - water ( ρwρo

= 1.18) is slightly larger than the density

ratio of oil B and low salinity water( ρwρo

= 1.23). This will cause more phase separation in the oil B-LS water

system.

Finally, large differences are observed between the flow regime map of the Exxsol D60 - water system and

that of the crude oil - water systems. The lower oil viscosity of Exxsol D60 compared to that of the crude oils,

yields less turbulent dispersion. Besides that, the interfacial surface tension of Exxsol D60 and water is much

higher than that of the crude oil - water systems (Exxsol D60: σ = 43 mN/m, crude oils: σ = 16 mN/m). The

drop sizes will be larger in the Exxsol - water systems due to the higher interfacial surface tension. Gravitational

forces have more effect on larger droplets and therefore separation will be more important for the Exxsol - water

systems.

0

0.5

1

1.5

2

2.5

3

3.5

0% 20% 40% 60% 80% 100%

Mix

ture

ve

loci

ty [

m/s

]

Water cut [-]

Oil continuousdispersions

Water continuousdispersions

Stratified flows

(a) Oil A - water

0

0.5

1

1.5

2

2.5

3

3.5

0% 20% 40% 60% 80% 100%

Mix

ture

ve

loci

ty[m

/s]

Water cut [-]

Oil continuousdispersions

Stratified flows

Water continuousdispersions

(b) Exxsol D60 - water

0

0.5

1

1.5

2

2.5

3

3.5

0% 20% 40% 60% 80% 100%

Mix

ture

ve

loci

ty [

m/s

]

Water cut [-]

Oil continuousdispersions

Water continuousdispersions

Stratified flows

(c) Oil B - LS-water

0

0.5

1

1.5

2

2.5

3

3.5

0% 20% 40% 60% 80% 100%

Mix

ture

ve

loci

ty [

m/s

]

Water cut [-]

Oil continuousdispersions

Water continuousdispersions

Stratified flows

(d) Oil B - HS-water

Figure 11: Flow regime maps for the four oil-water systems considered, determined from the results of X-raytomography

17

5 Model

The experimental data are compared with results of a model that is able to predict the concentration of the

dispersed phase in each liquid layer. This model, in which a two-fluid model is combined with a dispersion

model, has been presented by Amundsen et al. (2009) and Amundsen (2011). In the numerical simulations

of this study, which are based on this model, all parameters are computed in the same way as described by

Amundsen (2011), unless stated otherwise.

5.1 Dispersion model

The essential building blocks of the dispersion model are the computation of the turbulent forces and the buoy-

ancy forces acting on droplets in a dispersed flow. The concentration profile of the dispersed phase is modeled as

a balance between these forces. The concentration profile in the dispersed layer of a fully developed steady-state

flow is described by:

Vtφ +Γdφ

dz= 0 (1)

In this equation, Vt is the terminal velocity, Γ is the turbulent diffusion coefficient and φ(z) is the local con-

centration of the dispersed phase at a distance z from the interface. The first term in equation 1 represents the

buoyancy effects acting on the particles (droplets) and the second term represents the dispersion effects acting

on the particles (droplets) .

In order to solve equation 1, expressions for the terminal velocity Vt and the turbulent diffusion coefficient

Γ are required, as well as one closure relation from mass conservation.

5.1.1 Terminal velocity

In order to determine the terminal velocity, an approximation for the size of the droplets of the dispersed phase

is needed. In the present simulations, the drop size model as proposed by Brauner (2001) is used, which predicts

the maximum drop size. For the computation of the maximum drop size in dense dispersions, in which local

coalescence is prominent, the Brauner model uses the well-known Hinze model (Hinze, 1955) combined with a

model based on the local energy balance The expression for the maximum drop size according to Hinze (1955)

is given as:

(dmax)0 = 0.725(

σ

ρc

)0.6( D2 f u3

ρc (1−φ)

ρm

)0.4

(2)

18

Where σ is the interfacial tension, ρc the density of the continuous phase, ρm the mixture density, u the mixture

velocity, f the Darcy friction factor, φ the local concentration of the dispersed phase and D the hydraulic

diameter. The expression for the maximum drop size as a result of energy conservation follows from:

(dmax)ε = 3.06(dmax)0 CH

(φ

1−φ

)0.6

(3)

CH is a constant which needs to be specified by the user. In the numerical simulation, the maximum drop size

is assumed to be the maximum of both values:

dmax = (dmax)0Max

[1, 3.06CH

(φ

1−φ

)0.6]

(4)

An advantage of the model by Brauner (2001) compared to the Hinze model used by Amundsen (2011) is that

the Brauner model is able to predict the maximum drop size in both dilute and non-dilute systems, while the

Hinze model needs to be corrected in case of non-dilute systems.

As expressed by Amundsen (2011), the well-known terminal velocity V∞ in an infinite homogeneous medium

is determined based on the assumptions that the drop size distribution is given by a Rosin-Rambler distribution

(dmean = 0.557dmax) and the drag coefficient is given by the relation of Jayanti and Hewitt (1991) (CD = 18.5Re0.6p

).

V∞ =−sign(∆ρ)

√4dmean|∆ρ|g

3ρ fCD(5)

With ∆ρ = ρp − ρ f , g the gravitational acceleration and ρp and ρ f denoting the particle and fluid density

respectively. The modified terminal velocity Vt in a dispersed medium is subsequently determined:

Vt =V∞(1−φ)n (6)

V∞is the terminal velocity of a single particle falling in a stagnant liquid. In equation 6, the exponent n needs to

be specified by the user within the range of 2.39 - 4.65, see Richardson and Zaki (1954), under the assumption

that the droplet diameter is small compared to the pipe diameter.

5.1.2 Turbulent diffusion coefficient

As in the model of Amundsen (2011), the turbulent diffusion coefficient Γ is expressed according to Mols

and Oliemans (1998). With the assumption that particle inertia and crossing trajectories do not influence the

19

turbulent diffusion, the turbulent diffusion coefficient can be expressed as a function of the hydraulic diameter

D and the friction velocity u∗.

Γ = 0.049u∗D (7)

With the friction velocity following from τw and ρm denoting the wall shear stress and the mixture velocity

respectively:

u∗ =√

τw/ρm (8)

5.1.3 Closure relations

In case of fully dispersed flow, with only one continuous phase and assuming no slip between the droplets and

the continuous phase, the closure relation is given by the area averaged volume fraction of the dispersed phase

being equal to the input volume fraction.

In case of stratified flow, it is assumed that the concentration of the dispersed phase at the interface is known.

The concentration at the interface has to be specified by the user. Given that the concentration at the height of

the interface is known, the holdup profiles in the water layer (0 < z < h) and the oil layer (h < z < D) can be

determined from the closure relation that the concentration at z = h equals the inversion concentration.

5.2 Two fluid model

In the two layers, the concentration profiles of the dispersed phase can be computed when the height of the

interface is known. This height is computed in an iterative procedure of the two fluid model. This procedure is

similar to that described by Amundsen (2011).

When an interface height is assumed, the concentration of the dispersed phase can be computed and the

mixture properties can be determined. Once the mixture properties are known in the two layers, the expression

for conservation of momentum can be expressed as a function of the interface height hi:

F(hi) =−τoc(hi)Soc(hi)

Aoc(hi)+

τwc(hi)Swc(hi)

Awc(hi)+ τi(hi)Si(hi)

(1

Awc(hi)+

1Aoc(hi)

)(9)

In equation 9, A denotes the cross-sectional area of the flow, S the perimeter and τ the shear stress. Momentum

is conserved when F(hi) = 0. When the interface height is found to be at a position for which the thickness

of one of the layers is smaller than three times the drop size, the flow is assumed to be fully dispersed and the

concentration profile can then be calculated from the dispersion model.

In order to be able to calculate the shear stresses, the mixture viscosity must be known. In the model, the

20

mixture viscosity is determined as proposed by Pal and Rhodes (1989), who described the mixture viscosity as

a function of the viscosity of the continuous phase and the dispersed phase concentration.

µm = µc

1+φ

φ0

µ0.40

µ0.40 −1

− φ

φ0

2.5

(10)

in which µc denotes the viscosity of the continuous phase, µ0 is a dimensionless reference viscosity and φ0 =

φµ=µ0 . We use µ0 = 100 and φ0 = 0.765 for an oil continuous flow and µ0 = 10 and φ0 = 0.642 for a water

continuous flow.

6 Results numerical simulations

For the numerical simulations, the fluid properties are set to have the values as shown in table 2 and the inversion

water cut is set to be 50% (see section 4.6.1). Two simulation parameters have to be chosen. For the hindered

settling factor n (eq. 6) a value of 3.0 is used in the simulations and the constant CH (eq. 3) is set to be 1.

6.1 Concentration distributions

In figures 12, 13, 14 and 15, the results from the numerical simulations are compared with the experimental data

presented earlier in section 4. The present method is seen able to predict the concentration distribution with a

reasonable accuracy in most cases.

The differences between the predicted results and the measured results are very small at the lowest mixture

velocities, for which the phases are completely separated. The method is also successful in predicting the

concentration profile for the high velocities at which the flows are fully dispersed, but the method predicts

slightly more separation in this case.

The largest differences occur in the profiles that are marked with a gray background. These are all in the

transition region from stratified to fully dispersed flows. At these conditions, neither the separation forces, nor

the dispersive forces are dominant, but the concentration distribution is a result of a sensitive equilibrium be-

tween those two forces. The method is probably too general to compute the correct drop sizes for all conditions.

21

1.9

2 m

/s

Oil A - water

Simulation

1.2

8 m

/s0.6

4 m

/s

Top Bot0

1W

ate

r fr

actio

n

Water cut 20%

Top Bot0

1Water cut 30%

Top Bot0

1Water cut 40%

Top Bot0

1Water cut 50%

Top Bot0

1Water cut 60%

Top Bot0

1Water cut 70%

Top Bot0

1Water cut 80%

Top Bot0

1

Wa

ter

fra

ctio

n

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Wa

ter

fra

ctio

n

Height Top Bot0

1

Height Top Bot0

1

Height Top Bot0

1

Height Top Bot0

1

Height Top Bot0

1

Height Top Bot0

1

Height

Figure 12: Comparison between predicted and measured concentration distributions: oil A - water

Simulation

Oil B -LS-Water

wa

ter

fra

ctio

n

3.2

1 m

/s

Water cut 10%

Top Bot0

1Water cut 20%

Top Bot0

1Water cut 30%

Top Bot0

1Water cut 40%

Top Bot0

1Water cut 50%

Top Bot0

1Water cut 60%

Top Bot0

1Water cut 70%

Top Bot0

1Water cut 80% Water cut 90%

Top Bot0

1

wa

ter

fra

ctio

n

2.5

7 m

/s

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

wa

ter

fra

ctio

n

1.9

2 m

/s

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

wa

ter

fra

ctio

n

1.2

8 m

/s

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Height

wa

ter

fra

ctio

n

0.6

4 m

/s

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Figure 13: Comparison between predicted and measured concentration distributions: oil B - LS-water

22

Simulation

Oil B -HS-Water

Top

wate

r fr

action

Water cut 10%

Top Bot0

1Water cut 20%

Top Bot0

1Water cut 30%

Top Bot0

1Water cut 40%

Top Bot0

1Water cut 50%

Top Bot0

1Water cut 60%

Top Bot0

1Water cut 70%

Top Bot0

1Water cut 80% Water cut 90%

Top Bot0

1

wate

r fr

action

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

wate

r fr

action

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

wate

r fr

action

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Height

wate

r fr

action

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

Top Bot0

1

Height

3.2

1 m

/s2.5

7 m

/s1.9

2 m

/s1.2

8 m

/s0.6

4 m

/s

Figure 14: Comparison between predicted and measured concentration distributions: oil B - HS-water

Wa

ter

fra

ctio

n

2.5

0 m

/s

Wa

ter

fra

ctio

n

2.0

0 m

/s

1.3

4 m

/s0.6

7 m

/s

Wa

ter

fra

ctio

nW

ate

r fr

actio

n

Exxsol D60 - water

Simulation

Top Bot0

1Water cut 20%

Top Bot0

1Water cut 30%

Top Bot0

1Water cut 40%

Top Bot0

1Water cut 50%

Top Bot0

1Water cut 60%

Top Bot0

1Water cut 70%

Top Bot0

1Water cut 80%

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

Top Bot0

1

HeightTop Bot0

1

HeightTop Bot0

1

Height

Figure 15: Comparison between predicted and measured concentration distributions: Exxsol D60 - water

6.2 Pressure gradients

The pressure gradients that have been measured during the experiments are shown together with the predictions

in figure 16. The red lines show the predictions of the simulation method. Discontinuities are seen at the

transitions between fully dispersed flows and stratified flows. Different models and closure relations used for

23

fully dispersed flows and stratified flows lead to the observed discontinuities.

The simulation method is successful in predicting the pressure gradients of the crude oil experiments, but

the pressure drop is slightly over-predicted. The method predicts a stronger increase in the pressure drop for an

increasing concentration of water in the oil continuous flows than is observed in the experiments. The viscosity

model over-predicts the apparent viscosity, resulting in this over-prediction of the pressure drop.

In figure 16a, the prediction of the pressure gradient in the stratified region for the highest mixture velocity

shows some unexpected behavior. This can be a result of closure relations in the dispersion model which are

too general to produce good predictions in all cases.

Large differences are observed between the prediction of pressure gradient and the experimental data for

the case of Exxsol D60 - water flows, as can be seen in figure 16b. The present method does not capture the

drag reduction effects that are discussed in section 4.5. Furthermore, the method does not predict a peak in the

pressure gradient for high water cuts and low mixture velocities.

Simulation program:

Oil A − water: 0.64m/s 1.28m/s 1.92m/s

0 20 40 60 80 1000

500

1000

1500

water cut [%]

Pre

ssure

gra

die

nt [P

a/m

]

(a) Oil A

Simulation program:

Exxsol D60 - water: 0.67m/s 1.34m/s 2.00m/s 2.50m/s

0 20 40 60 80 1000

200

400

600

800

1000

1200

water cut [%]

Pre

ssure

gra

die

nt [P

a/m

]

(b) Exxsol D60

Simulation program:

Oil B − LS water: 0.64m/s 1.28m/s 1.92m/s 2.57m/s 3.21m/s

0 20 40 60 80 1000

500

1000

1500

2000

2500

3000

water cut [%]

Pre

ssure

gra

die

nt [P

a/m

]

(c) Oil B-LS

Simulation program:

Oil B − HS water: 0.64m/s 1.28m/s 1.92m/s 2.57m/s 3.21m/s

0 20 40 60 80 1000

500

1000

1500

2000

2500

3000

water cut [%]

Pre

ssure

gra

die

nt [P

a/m

]

(d) Oil B-HS

Figure 16: Comparison of predicted and measured pressure gradients

24

7 Conclusions

Results of crude oil-water flow experiments have been presented in which the concentration distribution was

captured by an X-ray tomograph. The X-ray tomograph has proved to be a valuable tool in analyzing the details

of oil-water flows. The information from these detailed measurements has been used to validate the oil-water

model from earlier publications. In addition, data from these crude oil - water experiments have been compared

with data from model oil - water experiments. The crude oil - water flows were found to show a behavior

different from that of the model oil-water flows. This suggests that when the behavior of crude oils is to be

investigated, real crude oils should be used.

As expected, a higher density ratio in the oil - high salinity water system, compared to that of the oil - low

salinity water systems, affects the flow behavior. The concentration distributions of the oil - high salinity water

system showed more separation than that of the oil - low salinity water systems . Although the different density

ratio resulted in different concentration distributions, only small differences were observed in the flow regimes

that occurred. A different oil viscosity has larger effects on the flow regime map. A higher oil viscosity causes

more turbulent dispersion and therefore less stratification and more dispersed flows.

A comparison between results of a two-fluid dispersion model and the experimental data showed that the

model is able to predict both the concentration distribution and the pressure gradient of crude oil-water flows.

The largest uncertainties in the prediction of the concentration distributions were found in the transition region

between stratified flow and fully dispersed flow. Further work should be focused on computation of the size of

the drops in this part of the flow regime map.

In general, the used prediction method is able to predict the pressure drop of crude oil - water systems,

but again more work is needed to improve the performance in the transition region between fully dispersed and

stratified flows. The method however failed to predict the pressure drop of model oil-water flow. Drag reduction

effects that were presumably present in the model oil-water flows were not captured by this method.

Acknowledgments

The authors would like to thank Dr. Hu of Institute for Energy Technology Norway, Prof. Dr. Ir. H.W.M.

Hoeijmakers of the University of Twente, The Netherlands, and Dr. Valle and Dr. Yang of Statoil ASA, Norway,

for sharing their knowledge and their valuable suggestions and discussions.

25

ReferencesL. Amundsen, R. Schulkes, and M. Melaaen. Oil-water flow: experiements and model development. In 14th International Conference on

Multiphase Production Technology, Cannes, France, 2009.

Lene Amundsen. An experimental study of oil-water flow in horizontal and inclined pipes. PhD thesis, The Norwegian University ofScience and Technology (NTNU), Trondheim, Norway, 2011.

P. Angeli and G. F. Hewitt. Flow structure in horizontal oil-water flow. International Journal of Multiphase Flow, 26:1117 – 1140, 2000.

M. Brauner. The prediction of dispersed flows boundaries in liquid-liquid and gas-liquid systems. International Journal of MultiphaseFlow, 27:885 – 910, 2001.

G. Elseth. An Experimental Study of Oil / Water Flow in Horizontal Pipes. PhD thesis, The Norwegian University of Science andTechnology (NTNU), Trondheim, Norway, 2001.

Y. V. Fairuzov, P. Arenas-Medina, J. Verdejo-Fierro, and R. Gonzalez-Islas. Flow pattern transitions in horizontal pipelines carrying oil-water mixtures: Full-scale experiments. Journal of Energy Resources Technology, 122:169 – 176, 2000.

B. Grassi, D. Strazza, and P. Poesio. Experimental validation of theoretical models in two-phase high-viscosity ratio liquid-liquid flows inhorizontal and slightly inclined pipes. International Journal of Multiphase Flow, 34:950–965, 2008.

J. O. Hinze. Fundamentals of the hydrodynamic mechanism of splitting in dispersion processes. AIChE Journal, 1:289–295, 1955.

Rainer Hoffmann and George William Johnson. Measuring phase distribution in high pressure three-phase flow using gamma densitometry.Flow Measurement and Instrumentation, 22:351 – 359, 2011. doi: 10.1016/j.flowmeasinst.2011.02.005.

Rainer Hoffmann, Lene Amundsen, Zhenyu Huang, Sheng Zheng, and H. Scott Fogler. Wax deposition in stratified oil/water flow. EnergyFuels, 26:3416–3423, 2012a.

Rainer Hoffmann, Lene Amundsen, Reidar B. Schüller, and Ruben Schulkes. Measuring phase distribution using external thermal excita-tion. Flow Measurement and Instrumentation, 2012b. doi: 10.1016/j.flowmeasinst.2012.04.008.

S. Jayanti and G. Hewitt. Review of literature on dispersed two-phase flow with a view to cfd modelling. Technical report, AEA-APS-0099,AEA Petroleum Services, Harwell Laboratory, Oxon, UK., 1991.

J. Lovick and P. Angeli. Experimental studies on the dual continuous flow pattern in oil-water flows. International Journal of MultiphaseFlow, 30:139 – 157, 2004.

B. Mols and R. V. A. Oliemans. A turbulent diffusion model for particle dispersion and deposition in horizontal tube flow. InternationalJournal of Multiphase Flow, 24:55–75, 1998.

R. Pal and E. Rhodes. Viscosity/concentration relationships for emulsions. Journal of Rheology, 33:1021 – 1045, 1989.

J. F. Richardson and W. N. Zaki. Sedimentation and fluidisation: Part i. Trans. Instn Chem. Engrs., 32:35–53, 1954.

T. Solbakken and R. B. Schüller. Multiphase flow experiments on a high pressure recombined gas/condensate/water system. In BHR Group2001 Multiphase ’01, 2001.

A. Soleimani. Phase distribution and associated phenomena in oil-water flows in horizontal tubes. PhD thesis, Imperial College of Science,Technology and Medicine, London, UK, 1999.

J. L. Trallero. Oil-water flow patterns in horizontal pipes. PhD thesis, The University of Tulsa, 1995. Fluid Flow Projects Eighty-EighthResearch Report.

O. H. Utvik, T. Rinde, and A. Valle. An experimental comparison between a recombined hydrocarbon-water fluid and a model fluid systemin three-phase pipe flow. Journal of Energy Resources Technology, 123:253 – 259, 2001.

A. Valle. Three Phase Gas-Oil-Water Pipe Flow. PhD thesis, Imperial College of Science, Technology and Medicine, London, UK, 2000.

A. Valle and H. K. Kvandal. Pressure drop and dispersion characteristics of separated oil/water flow. In The First International Symposiumon Two-Phase Flow Modelling and Experimentation Rome, Italy: 9-11 October, 1995, 1995.

A. Valle and O. H. Utvik. Pressure drop, flow pattern and slip for two phase crude oil/water flow: Experiments and model predictions. InInternational Symposium on Liquid-Liquid Two Phase Flow and Transport Phenomena Antalya, Turkey: November 3-7 1997, 1997.

A. S.K. Wahumpurage, B. M. Halvorsen, and M. C. Melaaen. An experimental investigation of oil-water flow in horizontal pipe using pivand gamma measurements. Technical report, Telemark University College, Porsgrunn, Norway, 2008.

26