spe-163148-pa-p[1]

Experimental Study of High-ViscosityOil/Water/Gas Three-Phase Flow in

Horizontal and Upward Vertical PipesS. Wang, H.-Q. Zhang, C. Sarica, and E. Pereyra, University of Tulsa

Summary

In this experimental study, measurements and observations havebeen carried out for high-viscosity oil/water/gas three-phase flowsin horizontal and upward vertical pipes. Oil with viscosities be-tween 0.15 and 0.57 Pas corresponding to temperatures from37.8 to 15.6C, filtered tap water, and natural gas at 2.59 MPapressure are used as the three phases. Superficial oil and watervelocities range from 0.1 to 1.0 m/s, and superficial gas velocityvaries from 1.0 to 5.0 m/s. The internal diameter of the pipe is5.25 cm. The experimental measurements include pressure gradi-ent and liquid holdup. The flow-pattern and slug characteristicsare observed and the images are recorded with a high-speed videocamera system through a high-pressure sapphire window. The ex-perimental results are compared with the predictions of the Zhangand Sarica (2006) unified model (UM), and the discrepancies areidentified.

Introduction

Heavy oil constitutes a significant portion of the worlds total oilreserve. It is discovered and produced all around the world and hasbecome one of the most important future hydrocarbon resources,with ever-increasing world energy demand and depletion of con-ventional oils. However, heavy oil possesses high viscosity, whichposes many challenges for its production and transportation.

Three-phase flow of oil, water, and gas is of particular impor-tance for the oil industry. This frequently occurs in wells, risersand flowlines before reaching the downstream processing facili-ties. Most of the oil and gas reservoirs naturally contain waterwhich generally has high salinity. Water could also be injectedinto the reservoir to maintain pressure at the later stage of produc-tion. Understanding of the three-phase flow phenomena is neces-sary in order to better design the production and transportationsystems. Most of the previous experimental research, correlationand model developments were conducted using low-viscosityconventional oils or other liquids. Acikgoz et al. (1992) carriedout the first experimental investigation of three-phase flow pat-terns in horizontal pipes. Pan et al. (1995) performed similar hori-zontal experiments. The tests were conducted at 0.5 MPa pressureand in a 38.0-m-long horizontal, 7.62-cm-ID pipe. Woods et al.(1998) reported oil/water/air upward vertical flow in a 2.52-cm-ID Perspex pipe with a 1.8-m test section. Nine flow patterns wereidentified based on visual/video observations and pressure techni-ques. Langsholt and Holm (2001) studied oil/water/gas flows insteeply inclined pipes. Hewitt (2005) studied oil/water/air three-phase flows in a 38.0-m-long, 7.62-cm-ID stainless-steel pipe.Keskin et al. (2007) proposed a two-step classification method foroil/water/gas three-phase flow patterns. Twelve flow patternswere identified for horizontal flows.

High-viscosity oil multiphase flow behaves very differentlythan low-viscosity oil multiphase flow. Significant discrepancieswere also observed in model comparisons. Very few studies havebeen conducted on high-viscosity oil/water/gas three-phase flow

until very recently. Bannwart et al. (2009) investigated heavy oil/water/air flows in horizontal, upward vertical, and inclined pipes.This oil has a viscosity of 34.95 Pas. Flow patterns were identi-fied from analogies with gas/liquid flow. In horizontal flow, thepresence of gas would considerably increase the pressure losscompared with oil/water two-phase flow. On the other hand, thepressure loss would be reduced with the injection of water causedby lubrication and with the process of keeping oil from touchingthe pipe wall. In upward vertical pipes, where the gravitationalterm plays an important role, the three-phase pressure drop can bereduced to as low as 5% of the single-phase oil pressure drop.Poesio et al. (2009) examined the effect of air on horizontal oil/water intermittent flow. Two oils with viscosity of 0.9 and 1.2Pas were used. It was found that with the increase of superficialair velocity, the total pressure drop would increase accordingly. Ahybrid model for pressure-drop prediction based on the Lockhart-Martinelli method was proposed and compared with experimentaldata, and it showed fairly good agreement.

So far, very few experimental studies have been conducted onhigh-viscosity oil/water/gas three-phase pipe flows, none at ele-vated pressure and with natural gas. Many aspects of the hydrody-namic behavior are not well understood. The performance ofthe current mechanistic models against high-viscosity oil ex-perimental results also needs to be assessed. This experimentalstudy is part of the Tulsa University High-Viscosity Oil Projects(TUHOP), which aims at a comprehensive understanding of mul-tiphase flow of high-viscosity oil with water and gas. The horizon-tal and upward vertical flow conditions are chosen to simulatemultiphase flows in horizontal and vertical wells and in surfacetransportation lines.

Experimental Facility

Multiphase Flow Loop. The high-viscosity oil/water/gas flowtests were conducted on the TUPDP high-pressure multiphaseflow loop. This system was previously used by Vuong et al.(2009), Akhiyarov et al. (2010), and Sridhar et al. (2011) to inves-tigate oil/water and oil/gas two-phase flow behaviors. This facilityconsists of three main systemsoil, water, and gas systems, andthree auxiliary systems: instrumentation air, glycol temperaturecontrol, and data-acquisition systems.

The current overall process schematic of the multiphase flowloop is shown in Fig. 1. The facility is capable of conductingsingle-phase and multiphase experiments at pressures up to 6.9MPa, temperatures from 4.4 to 71.1C, and inclination anglesfrom 2 to 90 from horizontal. The test section consists of a U-shaped, 5.25-cm-ID, Schedule 40, 340 stainless-steel pipe. Thetotal length of the pipe is 48.8 m. It is mounted on a boom so thatany inclination angle within the experimental range can beselected using a hydraulic hoist attached to an 18.3-m-high tower.The test section is partially jacketed with a 10.16-cm nominal di-ameter CPVC pipe over a length of approximately 16.2 m for heatexchange of temperature control.

Fig. 2 is the schematic of the test section. A chilled mixture ofglycol and water (50/50%) can be circulated inside the annulus ofthe jacket and/or through a heat exchanger countercurrently to themultiphase mixture flowing in the inner pipes. The glycol flowhelps to create a simulated cold ambient environment or maintaintest fluid at a constant temperature. The test section consists of a

CopyrightVC 2013 Society of Petroleum Engineers

This paper (SPE 163148) was revised for publication from paper OTC 23129, first presentedat the Offshore Technology Conference, Houston, Texas, USA, 30 April5 May 2012.Original manuscript received for review 6 January 2012. Revised manuscript received forreview 10 January 2013. Paper peer approved 14 January 2013.

306 August 2013 SPE Production & Operations

U-shaped, 5.25-cm-ID stainless-steel pipe with a length of 24 mfor each leg. The first segment is a 3.35-m-long hydraulic devel-oping section. The second segment is a 7.43-m-long thermaldeveloping section. The pressure drop in this section is measuredby a differential pressure transducer and is used for monitoringthe flow development. The third segment is also a 7.43-m-longlongitudinal measurement section. This section is used to deter-mine the pressure drop by a differential pressure transducer. Thereare ten resistance temperature detectors (RTD) located equidistantalong this section to obtain test fluids and glycol-mixture tempera-tures. Two quick closing valves (QCV) at the inlet and outlet areinstalled for liquid holdup measurement. The last segment is a1.52-m-long removable spool piece. It has a high-pressure sap-phire window through which flow pattern and flow behavior canbe observed and recorded with a high-speed video camera. Thetotal internal volume of the system is approximately 15 m3. The

volumes of oil and water storage tanks of the facility are 4 and 2.4m3, respectively. The oil viscosity is monitored constantly withthe pipe viscometer. Low-shear Moyno progressing cavity pumpsare used to circulate oil and water. The 12- to 18-hour time inter-vals between daily experiments help to separate the oil, water,and gas. There are no significant emulsion problems.

Measurements and Instrumentation. Flow Pattern. Flow pat-tern is identified by observing the flow behavior through the high-pressure sapphire window using a high-speed video recordingsystem. To better observe the flow characteristics, a PhotronTM

high-speed video camera is used to take video images with a pixelresolution of 10241024 up to 1,000 frames per second (fps). Themaximum shutter speed is 100,000 fps with a reduced resolution.Side views and cross-sectional phase distributions correspondingto different flow patterns will be illustrated in the next section.

GasSystem Oil Return Line

Oil/Water Separator

Oil Tank

Water Tank

Water Heat Exchanger

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Fig. 1Process schematic of multiphase flow loop.

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GLYCOLGLYCOLGLYCOLGLYCOLGLYCOLGLYCOLGLYCOLGLYCOLGLYCOLGLYCOLGLYCOLGLYCOL

44 5 ft5 ft

11 Hydraulic Developing SegmentHydraulic Developing SegmentThermal Developing SegmentThermal Developing SegmentLongitudinal Measurement SegmentLongitudinal Measurement SegmentRemovable Spool PieceRemovable Spool Piece

223344

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G-L SEP

Fig. 2Schematic of test section.

August 2013 SPE Production & Operations 307

Pressure Gradient. Differential pressures are measured bytwo differential pressure transducers. One differential pressuretransducer is used in the single-phase oil pipe viscometer sectionto determine live oil viscosity, and the other is installed to mea-sure the pressure drop over the longitudinal measurement segment.

Liquid Holdup. Liquid holdups are measured by using the7.4-m longitudinal measurement segment. Fluids flowing in thetest section are trapped inside this long pipe by using two QCVslocated at both ends of this segment. The QCVs can be com-pletely closed from an open position within 1.5 seconds. Thetrapped oil/water/gas mixtures are allowed to separate for 5minutes and then the pipe is raised to upward vertical position.The water is drained into graduated cylinders from a drainageport immediately above the bottom QCV. The oil is left in thepipe and its volume can be back-calculated from the differentialpressure transducer readings.

Test Fluid. The fluids used in the experiments consist of arefined mineral oil (Lubsoil ND-50), filtered Tulsa city tap water(no salinity), and natural gas supplied by Oklahoma Natural GasCompany. The Lubsoil ND-50 oil was selected because of its rela-tively high viscosity. Tap water was filtered before being fed tothe facility. The oil has the following physical properties:

API gravity: 28.5Density: 884.4 kg/m3 at standard conditionsDead-oil viscosity: 1.1 Pas at 15.6CSurface tension: 35.75 dynes/cm at 19.8CInterfacial tension with water: 30.4 dynes/cm at 19.8CPour and flashpoint temperatures:15 and 266C, respectively.

Test Matrix. On the basis of the research objectives and facilitylimitations, high-viscosity oil/water/gas three-phase tests havebeen carried out for both horizontal and upward vertical flows.The experimental ranges are as following:

Superficial oil velocity: 0.1 to 1 m/sSuperficial water velocity: 0.1 to 1 m/s

Superficial gas velocity: 1 to 5 m/sWater cut: 17 to 77%On the basis of a rheological study, Li (2009) determined that

the oil/water-phase inversion point for the Lubsoil ND-50 occursbetween 15 to 20% water cut. When the water-flow rate is lowand oil is continuous in the flow loop, it is hard to maintain a sta-ble water flow rate because of the high discharge pressure. Thus,most tests were conducted within the water-continuous region.Live-oil viscosities with dissolved natural gas are 0.15, 0.28, and0.57 Pas, corresponding to temperatures of 37.8, 26.7, and15.6C, respectively. The pressure in the test section is maintainedat approximately 2.59 MPa.

Experimental Results

Flow Pattern. Oil/water/gas three-phase flow patterns have beenviewed as a combination of gas/liquid and oil/water flow patternsby authors including Bannwart et al. (2005), Trevisan and Bann-wart (2006), Keskin et al. (2006), and Bannwart et al. (2009).Gas/liquid flow patterns observed during this study are intermit-tent (INT) and stratified (STR). For gas/liquid intermittent flow,the oil/water flow patterns need to be specified in both the slugbody and the film region. For gas/liquid stratified flow, oil/waterdistribution in the liquid film needs to be classified. Four flow pat-terns are identified by analyzing the images obtained with thehigh-speed video camera system for the three-phase flows in hori-zontal and upward vertical pipes. Schematic drawings of the crosssectional views and side views from the high-speed camera atslug body and film region for each flow pattern are shown in Figs.3 through 12. Descriptions of the four flow patterns are presentednext.

1. INT(O/W-S&SOW-F). As shown in Figs. 3 and 4, gas andliquid are in intermittent flow (or slug flow). Oil is dispersed inwater within the slug body. A continuous water layer may be pres-ent at the bottom of the slug body depending on the turbulent in-tensity. In the film region, oil and water are stratified. Very fewgas bubbles are entrained by liquid in the film region. This flow

Gas phase withthick oil film onthe wall

Oil layer

Water layer

Oil and gasdispersedin water

(a) (b)

Fig. 3Horizontal intermittent flow with oil-in-water dispersion slug and stratified oil and water film, denoted as INT(O/W-S&SOW-F). (a) Slug body region; (b) liquid film region.

(a) (b)

Fig. 4Snapshots of horizontal INT(O/W-S&SOW-F) (lO5 0.28 Pas, vSO5 0.1, vSW5 0.1, vSG5 1 m/s). (a) Slug body region; (b) liq-uid film region.


pattern occurs at low superficial gas velocities such as vSG 1 and2 m/s and relatively low superficial oil and water velocities.

2. INT(O/W-S&O/W-F). As shown in Figs. 5 and 6, gas andliquid are in intermittent flow (or slug flow). Oil is dispersed inwater in both the slug body and film region. This is the dominantflow pattern for horizontal flows in this study when superficial gasvelocity is at or higher than 2 m/s. In upward vertical flows, this isthe only flow pattern observed (as shown in Figs. 7 and 8). Withincreasing either superficial oil or superficial water velocities, liq-uid holdups or velocities would increase in the three-phase flow,causing more intensive turbulence in both the slug body and filmregion. Therefore, the free water layer at the bottom of the slugbody disappears because of turbulent mixing. Stratified oil waterlayers in the film region changed to oil in water dispersion.Depending on the flow rate, oil droplets could be distributed acrossalmost the whole liquid-film section.

3. INT(W/O-S&W/O-F). As shown in Figs. 9 and 10, gas andliquid flow pattern is intermittent (or slug). Water is dispersed inoil in both the slug body and film region. Oil is the continuousphase. This is confirmed with the high frictional-pressure gradientmeasurement in the test section. Because of water-pump


Oil dispersed inwater layer


(a) (b)

Fig. 5Horizontal intermittent flow with oil-in-water dispersion slug and oil in water dispersion film, denoted as INT(O/W-S&O/W-F). (a) Slug body region; (b) liquid film region.

(a) (b)

Fig. 6Snapshots of horizontal INT(O/W-S&O/W-F) (lO5 0.28 Pas, vSO50.3, vSW5 0.3, vSG5 2 m/s). (a) Slug body region; (b) liq-uid film region.

Water filmwith oildispersion


Gas core

(a) (b)

Fig. 7Vertical intermittent flow with oil-in-water dispersion slug and oil in water dispersion film, denoted as INT(O/W-S&O/W-F).(a) Slug body region; (b) liquid film region.

(a) (b)

Fig. 8Snapshots of upward vertical INT(O/W-S&O/W-F)(lO5 0.28 Pas, vSO50.3, vSW5 0.3, vSG5 2 m/s). (a) Slug bodyregion; (b) liquid film region.


limitations, only a few low water-cut tests close to the inversionpoint were performed with this flow pattern.

4. STR(O/W-F). At superficial gas velocity vSG 5 m/s, thegas/liquid flow pattern changes from intermittent (INT) to strati-fied (STR) flow. As shown in Figs. 11 and 12, oil and gas areentrained and dispersed in the water-continuous phase, whichtraveled on the pipe wall as a film. Because of the high shearstress between gas and liquid, liquid droplets are also entrained inthe gas phase. In the film oil, water and gas are well mixed andcan be viewed as a homogenous mixture. The film spreads upwardaround the pipe wall, causing a concave interfacial shape.

It is observed that in horizontal flows, by keeping superficialoil and water velocities constant, increasing the superficial gas ve-locity will cause the flow pattern to shift from INT to STR flow.On the other hand, keeping superficial gas velocities constant andincreasing superficial oil or water velocity will cause the flow pat-tern in the film region to change from stratified oil water (SOW)

to oil in water (O/W) or water in oil (W/O) dispersion, dependingon water fraction and inversion point.

In upward vertical flows within the current experimentalranges, the only flow pattern observed is INT(O/W-S&O/W-F).The oil and water are well mixed in the slug body with significantentrained gas. In the film, the oil and water are also mixed. Gasstays in the liquid film until being picked up by the next upcomingslug. At low gas-flow rate, the liquid film falls downward and ispicked up by the upcoming slug.

In Fig. 13, current high-viscosity oil/water/gas three-phase hor-izontal flow patterns are compared with Keskin et al. (2007) low-viscosity (lO 0.0135 Pas) horizontal three-phase flow patternsat 50% water cut. The brown and blue solid curves are the oil/gasand water/gas flow pattern transition boundaries predicted by theZhang and Sarica (2006) unified model assuming two-phase flowconditions. Because of the narrower test range and high oil viscos-ity of this study, only three out of twelve flow patterns identified


Waterdispersed in oillayer

Water andgas dispersedin oil

(a) (b)

Fig. 9Horizontal intermittent flow with water-in-oil dispersion slug and water in oil dispersion film, denoted as INT(W/O-S&W/O-F). (a) Slug body region; (b) liquid film region.

(a) (b)

Fig. 10Snapshots of horizontal INT(W/O-S&W/O-F) (lO5 0.28 Pas, vSO5 0.5, vSW5 0.1, vSG51 m/s). (a) Slug body region; (b) liq-uid film region.

Liquid Film Region

Gas phase withoil film on thepipe wall

Oil and gasdispersedin water layer

Fig. 11Horizontal stratified gas-liquid flow with oil in waterdispersion film, denoted as STR(O/W-F).

Liquid Film Region

Fig. 12Snapshot of Horizontal STR(O/W-F) (lO5 0.28 Pas,vSO5 0.3, vSW50.3, vSG5 5 m/s).


by Keskin can be used for comparison. They are intermittent-watercontinuous (IN-WC), stratified-stratified (ST-ST), and stratified-water continuous (ST-WC). Unlike current flow pattern classifica-tions, Keskin et al. didnt consider the differences between oil andwater distributions in the liquid slug and film region. At high viscos-ity, oil moves slower because of high friction. Compared with low-viscosity oil multiphase flow, the film height is much greaterbecause of its slower velocity (as shown in Figs. 4, 6, 10, and 12).The low oil velocity and high liquid holdup are the main reasonsthat the slug-flow region on a flow pattern map expands signifi-

cantly compared with low-viscosity oil multiphase flow as observedin experiments and predicted by the Zhang and Sarica UM.

Pressure Gradient. Three-Phase Pressure Gradient. In hori-zontal flow, pressure gradient is only caused by friction betweenthe fluids and the pipe wall, assuming the acceleration pressuregradient is negligible. In upward vertical flow, frictional and grav-itational terms are presented separately. The inversion point of theoil and water mixture is at approximately 20% water cut, basedon laboratory experiments.

The measured frictional three-phase pressure gradients areplotted with respect to water cut at 0.5-m/s superficial oil veloc-ities in Figs. 14 and 15a. Both horizontal and upward verticalcases show that with the increase of superficial gas velocities, fric-tional pressure gradient increases. There is also a clear trend ofthe pressure gradient increasing within the oil-continuous region,peaking around the inversion point, and then decreasing againwith the increase of water cut. At around 4050% water cut, itreaches the minimum value and then increases again. This meansthere is an optimum water cut that gives the minimum pressuregradient. The water cut increase (by increasing vSW) within theoil-continuous region does not reduce the pressure gradient. Theminimum pressure gradient seems to move to lower water cutwith the increase of superficial oil velocities. Probably with moreoil in the pipe, core annular flow can be formed, and the water-lubrication effect is more significant.

In upward vertical flows, gravitational pressure drop is meas-ured from the hydrostatic head of the fluids trapped by the QCVsat both ends of the test section. Frictional pressure can be calcu-lated by subtracting the gravitational pressure drop from the total

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Fig. 13Three-phase flow pattern comparison between Keskin (2007) observations and current study for horizontal flows with50% water cut. (a) Keskin (2007) observations; (b) current study (lo5 0.15 Pas).

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Fig. 14Three-phase frictional pressure-gradient measure-ments in horizontal flow at lo5 0.15 Pas.

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Fig. 15Three-phase pressure-gradient measurements in upward vertical flow at lo5 0.15 Pas. (a) Frictional pressure gradientvs. water cut; (b) gravitational pressure gradient vs. water cut.


pressure drop, which is measured by the differential pressuretransducer. At the same superficial oil velocity and water cut, thehigher the superficial gas velocity, the lower the gravitationalpressure gradient, as shown in Fig. 15b. This is caused by thelower liquid holdups at higher gas velocities. Because the gravita-tional pressure gradient term is dominant in upward vertical flow,the total pressure gradient shows the same trend as the gravita-tional pressure gradient.

Comparison With Two-Phase Flow. Horizontal oil/gas two-phase data were acquired in the current study. Vertical oil/gastwo-phase flow data were collected by Akhiyarov (2010) for hisMS thesis using the same flow loop, with the same fluids and sim-ilar test conditions. These data are used to study the water-lubrica-tion effect for oil/gas two-phase flow and the gas-injection effectfor oil/water two-phase flow, respectively, in Figs. 16 and 17.

As shown in Fig. 16, the same superficial gas and total superfi-cial liquid velocities are used to compare oil/water/gas three-phase flow and oil/gas two-phase flow results in horizontal pipes.At low water cut (e.g., 17% with oil/water either stratified orwater in oil dispersed), the three-phase frictional pressure gra-dients are comparable or slightly higher than the correspondenttwo-phase frictional pressure gradients. This suggests that waterinjection does not help to reduce pressure gradient in oil continu-ous region. By increasing water cut to 23, 38, and then 50%, fric-tional pressure gradient is significantly reduced to as low as 30%.After water cut is higher than 50%, further increasing the waterflow rate will not produce any more benefit.

Fig. 17 presents current oil/water/gas three-phase pressure gra-dients compared against Akhiyarov (2010) oil/gas two-phaseupward vertical flow pressure gradients. The superficial liquid ve-locity is the same for both current three-phase flow and Akhiyar-ovs two-phase flow. Due to different test matrices and insufficientdata, only 50% water cut three-phase flow pressure drop experi-mental results are used to compare with oil/gas two-phase flow. Itcan be observed when water is used to replace part of the oil in theupward vertical oil/gas flow that the frictional pressure gradient isgreatly reduced. However, the gravitational pressure gradients areclose between two-phase and three-phase flows. In upward verticalpipe with medium flow rates, the gravitational pressure gradient isusually much higher than the correspondent frictional pressuregradient. As a result, the reduction on the total pressure gradient islimited with water injection based on the observations in thisstudy. In upward vertical flow, water is mixed with oil and someentrained gas. As long as the water remains continuous, water cutchange may not affect the overall liquid holdup, which determinesthe gravitational pressure gradient.

Comparison With Model Predictions. The measured three-phase pressure gradients are compared with the predictions in theZhang and Sarica (2006) UM in Figs. 18 and 19. Zhang and Saricadeveloped the UM based on slug dynamics. Both slug characteris-tics and transitions from slug flow to other flow regimes can be pre-dicted by solving the continuity and momentum equations of slugflow. It can be seen that there is significant scatteredness in thecomparisons. Most of the overpredictions correspond to horizontal

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Fig. 16Oil/water/gas frictional pressure gradient compared with oil/gas frictional pressure gradient (current study) in horizontalflow at lo5 0.15 Pas, various water cut, same vSL and vSG. (a) Three-phase vs. two-phase pressure gradient; (b) pressure-gradientratio vs. water cut.

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Fig. 17Three-phase pressure gradient compared with Akhiyarov (2010) oil/gas pressure gradient in upward vertical flow atlo5 0.15 Pas, 50% water cut, same vSL and vSG, all corresponding to INT(O/W-S&O/W-F). (a) Three-phase vs. two-phase pressuregradient; (b) pressure-gradient ratio vs. mixture velocity.


slug flows with oil in water slug and stratified oil water film INT(O/W-S&SOW-F). For vertical flow, the UM can predict the positivefrictional pressure gradient because the liquid film falling back isallowed in the momentum equations. The gravitational pressuregradient is underpredicted. This is caused by the underprediction ofthe liquid holdup by the model. The UM also underpredicts the ver-tical frictional pressure gradient as a general trend.

Holdups. Three-Phase Holdup. Fig. 20 shows the oil and waterholdups in horizontal flows. It is shown that with the increase ofwater cut, oil holdup decreases while the water holdup increases.With the combined effect, the total liquid holdup in the pipe is rel-atively stable, with a small dip at around 4050% water cut corre-sponding to all superficial gas velocities. Holdups in upwardvertical pipes exhibit similar trends.

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Fig. 19Measurements of pressure gradient compared with Zhang and Sarica (2006) UM predictions in upward vertical three-phase flows. (a) UM predictions vs. frictional pressure gradient; (b) UM predictions vs. gravitational pressure gradient.

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Fig. 18Measurements of frictional pressure gradient compared with Zhang and Sarica (2006) unified model (UM) predictions inhorizontal three-phase flows. (a) UM predictions vs. frictional pressure gradient; (b) pressure-gradient ratio vs. mixture velocity.

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SO = 0.5 m/s


SO = 0.5 m/s

Fig. 20Measured holdups in oil/water/gas horizontal flows for lo5 0.15 Pas. (a) Oil holdup vs. water cut; (b) water holdup vs.water cut.


Comparison With Two-Phase Flow. Approximately 50 hori-zontal oil/gas flow experiments were performed using the samefluids and facilities along with the three-phase flow study. At thesame total superficial liquid velocities, experimental results showliquid holdups in horizontal oil/water/gas flow are generally lowerthan horizontal oil/gas flow (Fig. 21). This suggests that in hori-zontal three-phase flow, the liquid phase flows faster because ofwater lubrication. In upward vertical flow, liquid holdups are gen-erally the same between the two-phase and three-phase flows, asshown in Fig. 22.

Comparison With Model Predictions. The three-phase hold-ups are compared with Zhang and Sarica (2006) UM predictionsin Fig. 23. As a general trend, the UM underpredicts most of theoil and water holdups. The discrepancy between the predicted val-ues and experimental results is likely caused by the closure rela-tionships used within the UM. These correlations were developedon the basis of low-viscosity oil multiphase flow experimentalresults. Correlations suitable for both low- and high-viscosity oilmultiphase flows are needed to improve the model performance.

Conclusions

Experiments on high-viscosity oil/water/gas flows in horizontaland upward vertical pipes have been carried out. Four three-phaseflow patterns are identified by combining gas/liquid flow patternand oil/water mixing status within experimental range. Comparedwith low-viscosity multiphase flow, the slug flow region expandssignificantly due to high oil viscosity and low liquid film velocity.Water injection can lubricate the flow and significantly reduce the

frictional pressure gradient. This is most beneficial for horizontalflows. The maximum reduction of horizontal oil/gas pressure gra-dient occurs at approximately 4050% water cut. For upward ver-tical flow, the water injection effect on total pressure gradient islimited due to the dominance of gravitational pressure gradient.The Zhang and Sarica (2006) UM gives reasonable predictionsfor water continuous flow. However, the pressure drop and hold-ups are underpredicted as a general trend. The closure relation-ships (such as slug liquid holdup, slug translational velocity,interfacial friction factor, and entrainment fraction) used in theunified model were developed on the basis of low-viscosity multi-phase flow experimental results. They need to be modified, ornew closure relationships need to be developed, to fully incorpo-rate the viscosity effect.

Nomenclature

dp/dLF frictional pressure gradient, Pa/mdp/dLG gravitational pressure gradient, Pa/mdp/dLT total pressure gradient, Pa/m

Exp experimental resultsG-L SEP gas/liquid separator

HL total liquid holdupHO oil holdupHW water holdupUM Zhang and Sarica (2006) unified modelvM mixture velocity, m/svSG superficial gas velocity, m/svSL superficial liquid velocity, m/s

0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1

HL,

Thr

ee

HL, Two

0.15 Pas Horizontal+15%

25%

0.5

0.7

0.9

1.1

1.3

0 2 4 6 8

HL,

Thr

ee/H

L, T

wo

M (m/s)

0.15 Pas Horizontal

(a) (b)

Fig. 21Three-phase total liquid holdups compared with current oil/gas liquid holdup in horizontal flows for lo50.15 Pas, samevSL and vSG. (a) Three-phase vs. two-phase liquid holdup; (b) holdup ratio vs. mixture velocity.

0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1

HL,

Thr

ee

HL, Two

0.15 Pas Vertical +20%

10%

0.5

0.7

0.9

1.1

1.3

1.5

0 2 4 6 8

HL,

Thr

ee/H

L, T

wo

M (m/s)

0.15 Pas Vertical

(a) (b)

Fig. 22Three-phase total liquid holdup compared with Akhiyarov (2010) oil/gas liquid holdup in upward vertical flows forlo5 0.15 Pas, same vSL and vSG. (a) Three-phase vs. two-phase liquid holdup; (b) holdup ratio vs. mixture velocity.


vSO superficial oil velocity, m/svSW superficial water velocity, m/slo oil viscosity, Pas

Acknowledgment

The authors would like to thank the TUHOP member companiesfor supporting this research project.

References

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0

0.2

0.4

0.6

0.8

1

HO

, UM

0.57 Pas Horizontal0.28 Pas Horizontal0.15 Pas Horizontal0.28 Pas Vertical0.15 Pas Vertical

+100%

80%0

0.5

1

1.5

2

2.5

HO

, UM

/HO

, Exp


0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1

HW

, UM

HW,Exp


+15%

60%

0

0.5

1

1.5

2

0 2 4 6 8

HW

, UM

/HW

, Exp

M (m/s)

0 0.2 0.4 0.6 0.8 1HO,Exp

0 2 4 6 8M (m/s)


(a) (b)

(c) (d)

Fig. 23Measured holdups compared with Zhang and Sarica (2006) UM predictions in three-phase flow. (a) UM predictions vs. oilholdup experimental results; (b) oil holdup ratio vs. mixture velocity; (c) UM predictions vs. water holdup experimental results; (d)water holdup ratio vs. mixture velocity.


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Fac & Const 1 (2): 17. SPE-95749-PA. http://dx.doi.org/10.2118/95749-PA.

Shufan Wang is currently a Flow Assurance Consultant withMSi Kenny. email: [email protected]. Hisresearch interests include oil/water/gas multiphase flow, high-viscosity oils, and slug-flow modeling. Before joining the Univer-sity of Tulsa (TU), he focused mainly on CO2 pipeline corrosion.He holds a BS degree in materials science and engineeringfrom the Beijing University of Chemical Technology, an MSdegree in chemical engineering from Ohio University, and aPhD degree in petroleum engineering from TU.

Hong-Quan Zhang is an Associate Professor of Petroleum Engi-neering at TU, and serves as the director of the universitys Arti-ficial Lift Projects (TUALP, www.tualp.utulsa.edu). email: [email protected]. From 19982003, he was a seniorresearch associate of the Tulsa University Fluid Flow Projects(TUFFP). From 20032012, he served as the Associate Directorof TUFFP and principal investigator of the Tulsa University High-Viscosity Oil Projects (TUHOP). Before joining TU in 1998, he wasan Associate Professor and Professor at Tianjin University. In1993 and 1994, as an Alexander von Humboldt Research Fel-low, he conducted research at the Max Planck Institute ofFluid Mechanics and the German Aerospace Research Estab-lishment in Gottingen, Germany. Zhang holds BS and MS

degrees from Xian Jiaotong University and a PhD degree fromTianjin University, China.

Cem Sarica is currently a Professor of Petroleum Engineeringand the director of three industry-supported consortia at TU:Fluid Flow, Paraffin Deposition, and Horizontal Well Artificial LiftProjects. He was an Associate Professor of Petroleum and Nat-ural Gas Engineering at the Pennsylvania State University andan Assistant Professor of Petroleum and Natural Gas Engineer-ing at Istanbul Technical University (ITU) before joining TU. Hehas over 100 publications, mostly in SPE journals and proceed-ings, and his research interests include production engineer-ing, multiphase flow in pipes, flow assurance, and horizontalwells. He holds BS and MS degrees in petroleum engineeringfrom ITU and a PhD degree in petroleum engineering from TU.He currently serves as a member of SPE Projects, Facilities andConstruction Advisory Committee and a member of the SPEProduction and Operations Award Committee. He has previ-ously served as a member of the SPE Production Operationsand Books Committees, and was a member of the SPE JournalEditorial Board between 19992007. He is also the recipient ofthe 2010 SPE International Production and Operations Award,and was recognized as a Distinguished Member of SPE in 2012.

Eduardo Pereyra is a research associate with the Fluid FlowProject at TU. His research interests include multiphase flow sys-tems and transport, flow assurance, and separation technolo-gies. Pereyra has appeared in several refereed journals andhas written conference papers in these areas. Pereyra holdstwo BE degrees, one in mechanical engineering and one insystems engineering, from the University of Los Andes, Vene-zuela, and MS and PhD degrees in petroleum engineeringfrom TU.


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