Analyzing Multiphase Flow in Horizontaland Deviated Wells

Production logging determines where gas, oil and water enter a wellbore and measures the flow rate and relativepercentage volume, or holdup, of each phase. In horizontal and high-angle wells, the phases often stratify, so conven-tional logging techniques using a fullbore spinner do not capture the details of multiphase flow. A new tool has beendesigned for high-angle wells that can analyze multiphase flow across a complete wellbore. This article describes theFlow Scanner tool and its successful application in the Gulf of Suez and the North Sea.

Oilfield Review Interactive, Number 4

John BaldauffTrevor RungeGulf of Suez Petroleum CompanyCairo, Egypt

John CadenheadAhmadi, Kuwait

Marian FaurClamart, France

Njål GrønnerødHydroBergen, Norway

Samuel HarveyAtyrau, Kazakhstan

Cholid MasHo Chi Minh City, Vietnam

Rob NorthBeijing, China

Gary OddieCambridge, England

Executive EditorMark Andersen

Graphics DesignTracy Evans Productions

Web DesignHieu Do

For help in preparation of this article, thanks to Karim Al-Sayed, Tripoli, Libya; Mark Brandie and Jinglu Wang, Aberdeen; Roopa Gir, Houston; Martin Isaacs, Sugar Land,Texas, USA; and Dominique Sabina, Clamart, France.FloView, Flow Scanner, GHOST (Gas Holdup Optical Sensor Tool), MaxTRAC, NODAL, PIPESIM, PLA (Production Log Advisor), PS Platform and RSTPro (ReservoirSaturation Tool) are marks of Schlumberger.© 2007 Schlumberger. All rights reserved.

Logging Wellbore FlowOperators obtain production logs to analyze dynamic well performance and assess the produc-tivity or injectivity of different zones. Production logging also helps diagnose problem wells ormonitor the results of a stimulation or completion operation.

Most production logging tools were originally developed for use in vertical or near-verticalwells. The single, centered spinner measured flow across only about half of the cross section.Sensors that determined phase and other fluid properties were often several meters away fromthe spinner.

In high-angle and horizontal wells, the phases often stratify, but can also exhibit slug flowor other complex behaviors (below). A conventional production-logging toolstring gives anincomplete picture of such wellbore flow. Laboratory tests show significant deviation from

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Stratified flow Wavy stratified flow

Plug flow Slug flow

Dispersed bubble flow Annular flow

> Types of flow. The flow regime present at a given wellbore location depends on borehole deviation; the proportion ofeach phase present; relative density differences, surface tension and viscosity of each phase; and average velocity.Stratified flow occurs in horizontal wells when two or more phases are separated by gravity. Wavy stratified flow is aresult of interference between two stratified phases traveling at different velocities. Plug flow results from large bubblesof one phase becoming entrained in another phase. Slug flow is similar to plug flow, but the entrained bubbles arelarger. Dispersed bubble flow occurs when small bubbles of one phase are uniformly distributed in another phase.Annular flow is characteristic of gas flowing at high velocities in the center of a borehole with liquid flow confined to athin film on the wellbore walls, although small bubbles of liquid may flow in the gas stream.

1. Baldauff J, Runge T, Cadenhead J, Faur M, Marcus R, Mas C, North R and Oddie G: “Profiling and Quantifying Complex Multiphase Flow,” Oilfield Review 16, no. 3 (Autumn 2004): 4–13.2. Théron B, Vu-Hoang D, Rezgui F, Catala G, McKeon D and Silipigno L: “Improved Determination of Gas Holdup Using Optical Fiber Sensors,” Transactions of the 41st SPWLAAnnual Logging Sympo-sium, Dallas, June 4–7, 2000, paper GG.

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stratified horizontal flow when a flow loop is tilted as little as 2° fromhorizontal (above). At a 40° angle, some of the water phase flowsbackward and recirculates.

Because no wellbore is truly horizontal for any significant dis-tance, flow regimes can vary dramatically over the 100-ft [30-m] orgreater length of a conventional production logging toolstring. Thestratified or complex flow typical in high-angle wells could not be eval-uated by a fullbore spinner, which measures an average velocity ofthe fluid flowing in its path.

The Flow Scanner horizontal and deviated well production log-ging tool has new design features to measure the complexities of flowin highly deviated wells.1 The tool has five minispinners and six pairsof probes to determine the phases and their positions across a well-bore diameter. These measurements are contained within a morecompact, 16-ft [4.9-m] long sonde. This new tool reports velocity andphase holdup in real time.

Sensing Fluid Phase and VelocityThe new Flow Scanner tool relies on three types of devices for fluidphase and velocity measurements: minispinners, electrical probesand optical probes (above right).

The minispinner is a new spinner design. Its 1-in. [2.54-cm]diameter provides a localized velocity measurement. One spinner ismounted on the tool body that rests on the bottom of a wellbore, andfour others are on an articulating arm that spans the wellbore diameter.

Specialized design and finely engineered bearings give the spin-ners a high accuracy when spinning in either direction. They respondto flow in gas, oil or water.

A low-frequency electrical probe for water holdup measurementhas been used reliably in Schlumberger production logging tools forseveral years. The probe tip senses the electrical impedance of thefluid touching it. Thus, each of the six FloView holdup measurementprobes distinguish water, which is low-impedance, from high-imped-ance oil and gas.

The final critical component is the GHOST Gas Holdup OpticalSensor Tool, another technology Schlumberger has used for severalyears.2 This device is sensitive to a fluid's index of refraction. Gas,having a low refractive index, is much more reflective than either oil orwater. Five GHOST probes are paired with the FloView probes.

The electrical probe measures the presence of water and theoptical probe measures the presence of gas; the oil phase is deter-mined by difference for each probe pair. Both types of probe havesmall tips that measure tiny droplets of fluid.

90°

92°

88°

> Laboratory flow-loop tests. Video clips show complex flow in a laboratory flow looptilted at angles of 90°, 92°, 88° and 40° (not shown here).

TimeThreshold

Flow

Gas holdup = Time above thresholdTotal time

GasWater Oil

Water holdup =Time in short circuit

Total timeTime

Flow

Connector Probe-holding bracket

Conductive tipCeramic insulator

Ground electrode(for oil continuousphases)

> Electrical and optical probes. FloView electrical probes (top) discriminate betweenhydrocarbons and water based on resistivity. GHOST probes (bottom) discriminate gasfrom water or oil based on optical reflectivity. The small tips of both probes make themsensitive to very small bubbles.

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Measurements Span a WellboreThe Flow Scanner sonde deploys eccentrically so that one minispinnerand one set of electrical and optical probes remain on the low sideof a wellbore (below left). The other four minispinners are mountedon the leading strut of an articulating arm, and five pairs of probesare mounted on its trailing strut, effectively flanking the minispinners(below right).

The probes at the upper and lower sides of the wellbore canobtain measurements even if only small volumes of a phase are pres-ent in those locations.

The tool deploys in a compact configuration of 1.668-in. [42.9-mm]diameter. The articulating arm can span any wellbore diameter from2.875 to 9 in. [73.0 to 228.6 mm].

The Flow Scanner sonde is combinable with the PS Platformnew-generation production services platform, and it can be conveyed

by wireline, coiled tubing, or tractor. The optimal conveyance methoddepends on the specific wellbore configuration.

With the arm extended, the tool can log moving up or down a bore-hole. The close proximity of measuring elements on the tool ensuresthat the fluid profile is relevant to a given location in the borehole.

If the profile must be determined with even greater accuracy, thetool can scan across the wellbore at a station. The articulating armopens slowly, precisely locating fluid interfaces as the probes passthrough them.

Measurements from the five spinners, 12 phase probes, caliperand a relative-bearing device on the toolstring can be transmitted tosurface in real time. Analysis can be performed immediately both inscanning mode and in logging mode, allowing decisions to be madewhile the tool is in place.

> Comparison of a fullbore spinner and the Flow Scanner tool. A fullbore spinner measuresaverage phase velocity in the center of a wellbore (right). In contrast, the Flow Scannertool measures velocity at five points across the diameter of a wellbore (left).

> Flow Scanner spinner and probe configuration. The Flow Scanner tool incorporates17 sensors. Its articulating arm has four 1-in. diameter minispinners mounted on thefront strut and five each of the GHOST optical probe and the FloView electrical probemounted on the back strut. An additional minispinner and one pair of probes aremounted on the tool body. The one-inch diameter of the minispinner allows it to samplea small portion of the flow. It is able to measure low or high rates of fluid flow movingeither forward or backward with respect to the tool.

Optical GHOST probe

Electrical FloView probe

Minispinner cartridge withintegrated one-wire detector

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Interpreting FlowFlow Scanner data can be processed in real time, so that criticaldecisions concerning wellbore flow can be made immediately. Theinterpretation process starts with readings from the six pairs of opticaland electrical probes to determine phase profiles of gas and waterholdup. The oil-holdup profile is deduced from those of gas andwater. Phase interfaces are defined as the regions where the flow islocally multiphase.

Phase velocities are obtained from minispinner rotation rates.Visualization software can use an automated calibration routinebased on theoretical parameters (below). This automated methodconverts minispinner rotation to phase velocity in a single pass of thetool. Velocity is multiplied by holdup to determine flow rate for eachphase. More accurate phase velocities can be obtained by processingdata obtained from multiple passes with the tool moving at differentspeeds (right).

> Interpretation software for profiling flow. The Flow Scanner monitor box softwareshows the wellbore orientation, spin rate for each minispinner, and the phasedetermination from the phase probes of the Flow Scanner tool. The Flow Scannerinflow profiler software provides a holdup profile, with gas (red) and water (blue) phasemeasurements as data points and a smooth profile through the data. The oil profile(green) is obtained by difference.

> Calibrating Flow Scanner minispinners. Flow Scanner results can beanalyzed in real time using standard parameters for measurements in oil,water and gas. These parameters can be refined for specific well conditionsby analyzing multiple passes over the same interval, taken at different cablespeeds (top). The average spinner rate over this interval is plotted against thecable speed to obtain a best-fit line for positive and negative rotationdirections (bottom). A separate correlation based on the best-fit line is madefor each minispinner.

10150

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–100–80–60–30306080120

3. Borling DC, Powers BS and Ramadan N: “Water Shut-off Case History Using Through Tubing Bridge Plugs; October Field, Nubia Formation, Gulf of Suez, Egypt,” paper SPE 36213, presented at the 7thAbu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, October 13–16, 1996.

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Case StudiesOil fields of the Gulf of Suez offer a variety of challenges for produc-tion logging measurements. This mature producing region containsabout 100 platforms in 45 fields with more than 300 producing wellsand 100 water injectors.3 These aging reservoirs produce viscous oilsat high water cuts. Many have deviated to horizontal completions.The Flow Scanner tool is ideal for interpreting the resulting compli-cated flow regimes.

In a North Sea well, Hydro sought to determine whether oilproduction came from a main wellbore or a lateral connected by aY-junction. The company determined flow contributions using a FlowScanner sonde conveyed by downhole tractors.

Logging a High-Angle WellProduction began in 1978 from a Gulf of Suez field. In 1996, the oper-ator initiated a waterflood program to provide pressure maintenancefor the limited aquifer influx. The field is now approaching its eco-nomic limit, so the operator uses production logs to help maximize oilrecovery by locating areas for water shutoff (WSO). This field has a

faulted, dipping, anticlinal structure characterized by homogeneous,well-connected sands. The reservoir permeability generally increaseswith depth, ranging from 200 mD at the top to 1,000 mD at the base.

A gas lift well under consideration for possible WSO had an incli-nation of 37° and produced through six perforated intervals. Well testsin late 2003 indicated a total production rate of 2,058 bbl/d [327 m3/d]with 97% water cut. A conventional production logging survey was runto evaluate individual interval contributions and to identify sources ofwater production, but it yielded ambiguous results. It suggested thatall oil entered below the logged section.

The operator deployed a Flow Scanner tool to provide a quanti-tative flow analysis. The Flow Scanner minispinner and FloViewholdup data indicated complex flow patterns along the wellbore thatthe conventional spinner survey could not resolve. Several areas ofrecirculating water appear on the low side of the borehole in thevelocity images. In addition, the FloView data demonstrated that oilwas flowing in a small part of the cross section along the upper sideof the wellbore. In contrast to the conventional log, Flow Scanner logsindicated oil flowing from several sets of perforations in the loggedinterval (above).

Fullbore SpinnerVelocity

Conventional PL

Spinner Stationsrps ft/min0 3 -40 40 0.92 1.0

Flow Scanner

GradiomanometerFluid Density

Conventional PL Flow Scanner

Flow Profile

Flow Scanner

WellSketch

Depth,ft

Flow Profile

Conventional PL

X,350

X,400

Velocity

Velocity Image Water-Holdup Imageft/min0 40

Density Stationsg/cm30.9 1.2

Fluid Densityg/cm30.9 1.2

Water Flow

Oil Flow

Water Flow

Oil Flow

> Improved results using the Flow Scanner tool in a Gulf of Suez wellbore. In this welbore, a conventional Gulf ofSuez well production logging, or PL, tool gave inadequate results. A Flow Scanner tool run over the same intervalprovided more complete and markedly different results. The perforation locations are shown in red in the well sketch(Track 7). A sixth set of perforations was below the logged interval, where the tools could not reach. As the tool moveddownward past the top perforations (at about X,352), the oil flow rate decreased. The conventional production log(Track 5) did not show increased oil production from this set of perforations, but the Flow Scanner probes (Track 6)clearly show increased oil saturation. Both tools detected water entering at the third set of perforations (X,384 toX,392). Water also enters from the fourth set of perforations (X,405 to X,425). The oil flow gradually decreasesthrough this set, which is not shown in the conventional log. The conventional production log was interpreted to showthat all oil production came from the sixth set of perforations, below the logged interval shown here. The Flow Scannerresult correctly indicated that the upper two sets of perforations were producing clean oil. Since there weremeasurements across the wellbore diameter, the Flow Scanner data also show that flow in this deviated wellbore ismore rapid along the top, which is on the right-hand side of the velocity track (Track 2). The water-holdup track (Track 4)shows that oil is flowing in that part of the well.

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Based on these new results, a workover operation was plannedto optimize oil production. Engineers wanted to isolate the high water-cut zones in the bottom of the well. Using PLA Production Log Advisorsoftware, they evaluated results of setting plugs in the intervalbetween X,375 and X,400 (below). A sealing shale at about X,400

offered isolation from other producing intervals in the reservoir. Theoperator set the plug between perforations at that same location. Aninefold increase in oil production and a payback in less than a weekdemonstrated the effectiveness of the Flow Scanner tool.

Production log interpretation PIPESIM NODAL analysis

PLA Production Log Advisor

Production results

Gas

Oil

Water

Gas

Oil

Water

Initial WaterRate

Gamma Ray

APIGamma Ray

0 100

Initial OilRate

Temperatureand Pressure

InitialFlow Profile

PredictedFlow Profile

WellSketch

Depth,ft

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X,400

bbl/d0.0 2,500

Water

bbl/d0.0 100

Oil

psiWorkover Pressure1,625 2,497

psiWell Pressure

1,625 2,497

deg FWell Temperature249 250

bbl/dInitial Total Flow

0 4,000

bbl/dInitial Liquid Flow0 4,000

bbl/dInitial Water Flow

Estimated Total Flow

Estimated Liquid Flow

EstimatedWater Flow0 4,000

bbl/d0 4,000

bbl/d0 4,000

bbl/d0 4,000

< Prediction software for well remediation. Analystsuse PLA Production Log Advisor software to predictthe outcome of proposed remedial operations. PLAsoftware uses log input to define zonal reservoirparameters, such as the gamma ray (top, Track 1),water and oil flow rates (Tracks 2 and 3), and temper-ature and wellbore pressure (Track 4). The initial flowprofile combines the oil and water flow data (Track 5).The log data are passed to the PIPESIM module ofthe NODAL production system analysis package,which creates a model to match the measured ratesand pressures as closely as possible (bottom). In thiscase from the Gulf of Suez, isolation provided by abridge plug in the wellbore worked in conjunction withthe tight spot indicated by the gamma ray log at aboutX,395 ft. This location for a bridge plug had the bestresult in the PLA analysis, predicting an improvementin oil flow rate from 82 bbl/d [13 m3/d] to 609 bbl/d[97 m3/d], while the water flow rate increased onlyfrom 2,031 to 2,447 bbl/d [323 to 389 m3/d]. After theplug was set in the field and rates were optimized, theoil and water rates were 556 and 2,532 bbl/d [88 and403 m3/d], respectively. The online animation allowsthe viewer to test setting a plug in several locations.

4. Baldauff et al, reference 1.

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Avoiding Water in a Horizontal WellA field in the Gulf of Suez experienced reservoir pressure declinefrom an initial pressure of 2,600 psi [17.9 MPa] to as low as about1,100 psi [7.6 MPa] in some wells.4 The 120-ft [37-m] column of high-viscosity oil is sandwiched between a gas cap and a fairly activeaquifer. Wells here frequently experience gas and water coning. Testsrevealed that water cut ranged from 70% to 98%.

Since the cost of a typical well intervention is US $250,000, mini-mizing unnecessary or ineffective operations was vital. The fieldincludes horizontal wells with large-bore completions and multiphase-flow regimes, complicating the determination of flow profiles.

The operator planned an intervention in a nearly horizontal,J-shaped well. The well trajectory has a low point beyond the heel ofthe well, and then the well path rises gradually. Perforated zones arebeyond the heel of the well.

The operator needed to accurately assess water cut and tolocate oil and water entry points. Using electric-line coiled tubing,engineers ran both a Flow Scanner tool and a PS Platform productionservices logging string for comparison (above). They conducted upand down passes at three different running speeds. An RSTProReservoir Saturation Tool was also run with the Flow Scanner sondeto determine oil/water and gas/oil contacts.

The fullbore spinner failed to detect the main producing zone.The Flow Scanner data indicated that most of the oil came from therising portion of the horizontal section. The perforations at greater truevertical depth (TVD) produce most of the water. The RSTPro meas-urement confirmed that the perforations at greatest TVD were at orbelow the oil/water contact. Based on these results, the lower zoneswere shut off and reperforated above the heel of the well in a zoneabout 800 to 1,000 ft [244 to 305 m] shallower than previous perfora-tions at about 70° deviation. The gross oil rate increased from300 bbl/d [48 m3/d] to 500 bbl/d [79 m3/d]. The increased productionpaid for interventions in two other wells.

PerforationsOil/water contact

X,300

rps

-46

TVD

Z,442

Z,400

TVD

Holdup

Velocity

Z,442

Z,400

Measured depth, ft

Fullbore spinner

Y,500Holdup0 1

Velocityft/min-120 100

Flow

Profile

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Measured depth, ft

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X,500

X,600

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> Determining flow in a horizontal wellbore. These Flow Scanner holdup and velocity images from a Gulf of Suezhorizontal well indicate one of the up passes at 50 ft/min [15.3 m/min] (middle, above well trajectory). The velocityprofile shows little activity until Y,120, where velocity increases on the low side of the hole, and water appears in theholdup image. Although most of the velocity is attributed to the water on the low side, the holdup levels also indicatesome oil flowing at this point. The conventional fullbore spinner indicates a slight uphill flow in this interval, possiblyattributed to reverse recirculation of the oil being carried down the wellbore and then circulating back uphill. The FlowScanner flow profile (top) results from the combination of the velocity and holdup profiles. The most significant oil entryfrom the perforations at about Y,100 is missed by the conventional production logging tool (bottom).

5. Alden M, Arif F, Billingham M, Grønnerød N, Harvey S, Richards ME and West C: “Advancing Downhole Conveyance,” Oilfield Review 16, no. 3 (Autumn 2004): 30–43.Baldauff et al, reference 1.

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Production Logging with Tractor ConveyanceHydro ran a production log in a North Sea well that had a lateral con-necting to the main wellbore at a Y-junction.5 The Brage field, whichlies about 125 km [78 miles] west of Bergen, Norway, in the NorthSea, is mature and has produced about 85% of its estimated recover-able reserves. Both laterals produce, but there are no perforationsabove the junction. The log was designed to determine whether onelateral could be shut off to decrease the water cut.

Conveyance-planning software indicted that a system with threeMaxTRAC downhole well tractor units could safely convey the toolstring,including the Flow Scanner sonde, into the Y-junction and beyond(below). The tubular inside diameter (ID) above the junction was 7.74 in.,and the entries into the upper and lower laterals were 3.437-in. ID.

1

2

3

4

5

6

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> Conveying into a Y-junction. A 111⁄16-in. toolstring including a Flow Scanner sonde (green) and three MaxTRAC units (red) was successfully conveyed into a Y-junction. The twoback tractors conveyed the toolstring through the 7.74-in. tubular to the junction (1). As the toolstring approached the Y-connector, the Flow Scanner sonde was lowered to thebottom of the horizontal wellbore (2). The Y-connector shoulder guided the sonde into the lower 3.437-in. lateral at the junction, followed by the first tractor, still in a retracted state(3). The middle tractor was retracted and the front one enabled (4). The first and last tractors alternated as drive units to convey the middle tractor into the lateral (5). The lasttractor was retracted, and the first and second tractors pulled the toolstring into the lateraL (6). Once all tractor sections were inside the lateral, the first one retracted, and the jobcontinued with the second and third tractors providing the motive force (7). Spacers between the tractors were required for rigging up the string. Other parts of the loggingtoolstring are not shown for simplicity. In this figure, the vertical scale is exaggerated.

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The MaxTRAC tractor conveyed the string into the lower lateralto a point about 40 m [130 ft] beyond the junction, but before the per-forated zone. The logging engineer set the tractor grips against thetubular wall to obtain stationary Flow Scanner data. Even with the wellshut in at surface, this stationary log indicated fluid movement. Afterthe well was opened to flow, a second Flow Scanner log showed thatonly water flowed at this location.

Selective inflow performance analysis used pressures and flowrates of the shut-in and flowing logs (left). This analysis showed a16-bar [232-psi] pressure difference between the two laterals thatcaused the shut-in crossflow.

The tractor arms retracted and the toolstring was pulled out usingwireline cable. At a position far above the Y-connection, the tractorgrips again set to hold at a station. A Flow Scanner log measured flow-ing rates and holdup. About 6% of the flow above the junction was oil.Because all of the production into the lower lateral below the Y-junctionwas water, Hydro shut off that lateral to improve productivity.

> Brage flow evaluation. Production logging results from a Brage well were analyzedusing Flow Scanner inflow profiler software (top). The velocity profile was fairly flat andsmall amounts of oil were detected at each probe. The electrical FloView holdupmeasurement probes measured small droplets of oil in the water, as illustrated in theupper right window of the Flow Scanner monitor box software (bottom).

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