44

Steve BamforthBP Exploration Operating Co. Ltd.Poole, England

Christian BessonKen StephensonColin WhittakerCambridge, England

George Brown BP Exploration Operating Co. Ltd.Sunbury on Thames, England

Gérard CatalaGilles RouaultBernard ThéronClamart, France

Revitalizing Production Logging

Thousands of high-angle and

horizontal wells have been

drilled in the last ten years.

As a result, there are many

mature fields with complex

well production problems.

Today, new technology and

better understanding of fluid

flow in wellbores have

revived production logging

methods for all types of wells.

Gilbert ConortMontrouge, France

Chris LennDubai, United Arab Emirates

Brad RoscoeRidgefield, Connecticut, USA

For help in preparation of this article, thanks to AshokBelani, Schlumberger Wireline & Testing, Montrouge,France; John Ferguson, Schlumberger CambridgeResearch, Cambridge, England; Yves Manin,Schlumberger Riboud Product Center, Clamart, France;

Oilfield Review

Jean-Rémy Olesen, Beijing, China; DeWayne Schnorr,Anchorage, Alaska, USA; Antonio Jorge Torre, TechnicalEditing Services, Houston, Texas, USA; and Amal Vittachi, GeoQuest, Dallas, Texas.BorFlo, CPLT (Combinable Production Logging Tool),FloView, FloView Plus, PLT (Production Logging Tool), PL Flagship, PVL (Phase Velocity Log), RST (ReservoirSaturation Tool), TDT (Thermal Decay Time) and WFL (Water Flow Log) are marks of Schlumberger.

Winter 1996 45

For decades, production logs have beenused in new wells to optimize ultimaterecovery and to help avoid potential pro-duction problems. In older wells, these logsaid in diagnosing declining production andplanning remedial work.1

From the outset, production logging (PL)has been used to determine the dynamic pat-terns of flow rates of water, oil and gas understable producing or injecting conditions byanswering the following questions: Howmuch of the well is flowing? Which zones areproducing oil, water and gas? How much ofeach type of fluid is flowing from each zone?

Ideally, PL techniques should identify eachfluid, measure the volume fraction of eachfluid in the pipe—called the holdup—andits velocity, and from these compute flowrates.2 Traditional PL measurements use tur-bine flowmeters called spinners for velocity,gradiomanometers for density, capacitancefor holdup, manometers for pressure and

thermometers for temperature. Of these fivemeasurements, only velocity and densitytend to be used in traditional quantitativePL analysis.

The reliability of the data generated bytraditional PL logging depends almostexclusively on the type of well beinglogged. In vertical wells with high flowrates—usually from 200 to 5000 B/D [30 to800 m3/d], depending on the tool used andthe pipe diameter—these PL measurementsand their analysis usually produce reliableresults. However, in some wells, phenom-ena such as flow behind casing or inter-zone flow make traditional PL difficult.

The upsurge in deviated and horizontalwells creates boreholes with very differentfluid flow characteristics from vertical wells,adding further complexity to multiphaseflow and radically changing the physics andtechnology of fluid-flow measurement(above). In gas-and-liquid or oil-and-waterflow, the lighter phase moves rapidly alongthe high side of the borehole, establishing a

circulating current that often causes a back-flow along the lower side (see “Fluid FlowFundamentals,” page 61).

Depending on the borehole deviation, thevelocity and holdup of the different phasescan change dramatically for any given flowrate. In these circumstances, traditional PLmeasurements may become unreliable.3This article looks at how new techniques arehelping to shed light on flow in complexvertical wells, and to deliver PL measure-ments in deviated and horizontal wells.

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Cuttings Fractures

Water

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■■The challenges facing production log-ging in horizontal wells. Trapped fluidscan directly affect production and influ-ence the data from a production log, espe-cially sensors such as spinners and capac-itance tools. Because horizontal wellsinevitably have doglegs and undulations,stagnant water may lie either inside or out-side the casing in low areas at the bottomof the well; stagnant gas may accumulateon the high side of drainhole undulations.These nonflowing fluids distort measure-ments. Changes in the flowing cross-sec-tional area have a direct impact on spin-ner response (inset, left). Horizontal wellsare frequently completed uncemented,using prepacked screens or slotted linerswith external casing packers (ECPs). AnECP that fails to set properly or formationcollapse create volume changes thataffect flow velocities. Faults, fractures andformation instabilities may cause fluidcrossflow. Cuttings on the low side of theborehole may alter fluid velocities andresult in erroneous readings.

1. Wade RT, Cantrell RC, Poupon A and Moulin J: “Pro-duction Logging (The Key to Optimum Well Perfor-mance,” Journal of Petroleum Technology 17 (Febru-ary 1965): 137-144.

2. For an authoritative treatment of multiphase flow: HillAD: ”Production Logging-Theoretical and Interpreta-tive Elements,” SPE Monograph 14, 1990.

3. Brown G: ”Using Production-Log Data From Horizon-tal Wells,” Transactions of the SPWLA 36th AnnualLogging Symposium, Paris, June 26-29, 1995, paper SS.

46 Oilfield Review

When to Run Production LogsGenerally, PL has two important applica-tions: measuring well performance withrespect to reservoir dynamics and analyzingmechanical problems in the borehole.Although decisions to run production logsusually depend on specific reservoir eco-nomics, there are general guidelines.

First, PL may be used in new wells to eval-uate initial production and verify theintegrity of the completion—for example,indicating where there is flow behind cas-ing. When initial performance does notmeet expectations, information from PL mayoften point to remedial work to optimizeproduction and suggest different completiontechniques for future wells.

A special use of PL in horizontal, high-ratewells is to verify friction-induced productionloss in long drainholes. This friction losssometimes negates any extra productivityexpected from the long drainhole, and abetter choice would be to drill multiple,shorter lateral sections in a stacked or fan-shaped pattern.4

Second, PL should be considered for anywell that shows sudden decreases in pro-duction or increases in gas/oil ratio (GOR)or water cut.

Third, just as a yearly checkup by a physi-cian is prudent, PL may be used periodicallyto detect problems such as water or gas con-ing, or fingering before extensive productionloss occurs. This is particularly important fordump-flood wells, where PL is the onlymonitoring method.5

Fourth, injection wells may be initiallyanalyzed and then monitored with PL.Knowledge of where injected fluids aregoing is critical for avoiding undesiredflooding that leads to serious problems suchas casing-annulus crossflow, the creation ofunswept and trapped hydrocarbons, andwater-wet damaged formations.

1:200 m

X50

X25

Radius of Bit0 10

Openhole Sw

1993100 p.u. 0

Openhole Porosity

50 p.u. 0

Openhole Porosity

50 p.u. 0

Downhole Flow Rate0 B/D 10000

RST Oil1996

1996

100 p.u. 0

Openhole Sw 1993

50 p.u. 0

Openhole Fluid Volume

1996

50 p.u. 0

RST Fluid Volume

GR (C.H.)-GR (O.H.)1 0 0

Borehole Water

Borehole Oil

Casing Wall

Assumed CementSheath

Formation

Perforated Zone

Nonmovable Oil (O.H.)

Water

Shale 1

Shale 2

Feldspar

Quartz

Calcite

RST Oil 1996

Water

Oil

Gas

Scales

4

Zone

3

2

1

■■Openhole CPLT-RST evaluation from South China Sea. Track 1 (left) contains a wellsketch with casing (black) and a cemented casing-formation annulus (gray hatching).Uranium scale was indicated by the difference in natural gamma ray activity betweenthe openhole and most recent cased-hole gamma ray survey. Track 2 contains the open-hole log and the latest RST water saturation analysis. Track 3 shows the production logsand static-fluid volume analysis in the formation. The top of Zone 3 at X41 and the tophalf of Zone 2 at X47 still shows some unproduced oil. Zones 1 and 4 are completelydepleted. The production logs shows most of the water production coming from the top ofZone 2 at X46 m.

Winter 1996 47

The ability to carry out downhole PL mea-surements in a stabilized well underdynamic conditions is the key to successfulproduction management. The resultingdownhole flow-rate determination may becompared with stabilized surface flow rates.This quantitative comparison betweendownhole and surface flow rates allowsdetection of any surface-to-downhole dis-crepancies caused by such factors as tubingleaks, thief zones, unwanted fluid entries orother hydraulic malfunctions.

Production Logging in Vertical Wells Increasingly, operators incorporate PL intotheir reservoir monitoring programs. Today,this often includes cased-hole saturationlogging techniques—such as thermal-neu-tron decay time or carbon-oxygen measure-ments—run in combination with traditionalPL tools to provide an enhanced under-standing of reservoir dynamics.6

The RST Reservoir Saturation Tool can beused to make a snapshot of reservoir satura-tion. Repeating these measurements overtime helps monitor changes in reservoir sat-uration. But the dynamic description offlow conditions obtained from productionlog profiles is absolutely necessary tounravel complex commingled productionin a many wells.

For example, to gain a clear picture of pro-duction dynamics in a declining reservoir, theCPLT Combinable Production Logging Toollog and the RST technique were used in com-bination in a reservoir located in the PearlRiver Mouth basin in the South China Sea.

The reservoir, a sand-shale sequence, wasproducing from four commingled sand-stone formations, and the operator neededto understand current reservoir productionon a layer-by-layer basis. The CPLT-RSTreservoir monitoring suite was deployed in

a well located at the top of the reservoir(previous page). Openhole well evalua-tions, with the latest hydrocarbon volumefrom RST C/O monitoring, showed thechanges in reservoir saturations.

The lowest zone had been completelydepleted, as had about half of the nextzone. A cased-hole versus openhole gammaray comparison revealed evidence of sub-stantial scale buildup in the lowest perfo-rated zones. This indicated that large vol-umes of water had been produced from thelower zones, and scale could potentiallyplug perforations.

The production logs provided the key tounderstanding what was happening in thewell. The flowmeter and gradiomanometerprofiles showed that there was only a littlefluid production, mostly water, coming fromthe lowest perforations. About 60% of thetotal water production came from the sec-ond lowest set of perforations, and most ofthat from just 2 m [6.5 ft] of the upper sec-tion of perforations.

Surprisingly, the RST monitor log indicatedthat water production was coming from afully oil-bearing part of the formation. It wassuspected that the water was coning upfrom the bottom part of the zone, now com-pletely depleted of hydrocarbons. Logs fromother wells, downdip in the reservoir, con-firmed this conclusion. Reducing the draw-down pressures may allow production of thebypassed hydrocarbons, still contained inthis zone, to continue.

In the well’s second highest perforatedzone, the RST monitor logs showed a signif-icant oil-water contact (OWC). The lowesthalf of the zone was fully depleted, whereasthe upper half was untouched by produc-tion. Unexpectedly, production log profilesindicated greater hydrocarbon productionthan water, perhaps because scale hadplugged the lower perforations in thewatered-out part of the zone. The upper per-forations in this zone did not appear to beplugged by scale, yet the production profiles

showed minimal contribution over theentire interval. This result confirmed thediagnosis from RST monitoring logs that theupper formation layer had been swept of allmovable hydrocarbons.

Another example, this time in a verticalwell with a thief zone and borehole waterentry, occurred in India’s offshore BombayHigh field, operated by Indian Oil and Nat-ural Gas Commission (ONGC). The reser-voir was under waterflood, and the operatorneeded to identify zones of water entry andto determine whether flow was occurringbehind the casing. It was also suspectedthat injection water had broken throughand was being produced from one of fivesets of perforations.

A WFL Water Flow Log tool was com-bined with the PLT Production Logging Toollog to distinguish between flow inside andoutside the casing (see “Fluid-Flow LoggingUsing Time-of-Flight,” page 50). The down-hole flow rates were complex. The top ofthe lowest set of perforations, Zone 5, pro-duced only small quantities of water. Therewas a large increase in water flow comingfrom the second lowest set of perforations.A modest amount of oil, 400 BOPD[63 m3/d], was also produced from thiszone. The middle set of perforations, Zone3, also produced 1000 BWPD [160 m3/d]with only a small amount of oil. The secondhighest set of perforations showed no fluidproduction (next page).

4. Hill D, Neme E, Ehlig-Economides C and MollinedoM: ”Reentry Drilling Gives New Life to Aging Fields,”Oilfield Review 8, no. 3 (Autumn 1996): 4-17.

5. In dump-flood wells, water is produced from anaquifer and injected into a producing formation in thesame well.

6. Albertin, I, Darling, H, Mahdavi, M, Plasek R, CedeñoI, Hemingway J, Richter P, Markley M, Olesen J-R,Roscoe B and Zeng W: “The Many Facets of PulsedNeutron Cased Hole Logging,” Oilfield Review 8, no. 2 (Summer 1996): 28-41. An essential input for RST-A C/O monitoring logging isthe oil holdup in the borehole. The PL gradiomanome-ter provides this measurement.

48 Oilfield Review

With the top set of perforations—Zone 1—the picture changed dramatically. Here,more than half of the production from thefour zones below disappeared into the for-mation. Zone 1 was acting as a major thiefzone, consuming 120 BOPD [19 m3/d] andabout 2200 BWPD [350 m3/d] from thewell. This unusual crossflow, verified byWFL results, indicates a pressure differentialbetween the two formation layers, whichwas not present when the well was initiallyput on production. The WFL survey alsoindicated that there was no channelingbehind the casing.

Armed with this knowledge, the operatorhad two choices for remediation—squeezethe perforations in the lowest zones (3 to 5)to prevent water production, or isolateZones 1 and 2 using a dual-completionscheme, putting the long string on gas lift,and allowing continued production of 400BOPD [64 m3/d] from Zone 4.

Nonvertical Production LoggingOnce a well substantially deviates fromvertical and multiphase flow becomescomplex, spinner tools often indicate onlyreverse flow—especially when the spinneris not centralized in the borehole, but lyingnear the bottom where the reverse flow isfound (next page, right).7 Capacitance toolsmay also measure the lower, denser phaseof the fluid giving misleading holdup data.As the well’s angle increases to horizontal,flow becomes entirely stratified, and theaveraged mixture velocity from a flowmeterspinner alone is meaningless.

Other phenomena affect PL measurementsin deviated and horizontal wells. For exam-ple stagnant fluids may confuse sensors;fractures and faults may allow crossflow;and failed external packers may introducevariable flow regimes (see page 45).

Horizontal and many deviated wells areoften completed either open hole, withuncemented slotted liners or withprepacked screens.8 Such completionsintroduce other special fluid-flow and pro-duction problems that usually are notencountered in vertical, cased wells—suchas flow restrictions due to the logging tool inthe pipe forcing fluids to channel throughthe liner-formation annulus. Furthermore, a

0 12 24 36 48 600

300

600

900

1200

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cp

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ount

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0 12 24 36 48 600

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API

Measured FluidVelocity ft/min

1:200

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Measured FluidDensity gm/cm3

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MeasuredTemperature

°F

WFLWater Flow Rate

BWPD

243 245

ReconstructedFluid Velocity

ft/min

0 125

ReconstructedFluid Density

gm/cm3

0 125

DownholeFlow Rate

B/D

Gas

Oil

Water

0.0 6000.0

0.0 6000.0

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Near

Zone

■■Thief zone in vertical well. The PLT-WFL interpretationanalysis indicated that Zone 1 is removing more than120 BOPD and 2200 BWPD from the well. Crossflow hadbeen set up by the injection and production schemes.At X354, the WFL decay-time distributions showed aflow rate over 2000 BWPD inside the casing (inset,above right). At X393 m, the WFL decay-time distribu-tions showed that no flow was detected (inset, right).

Winter 1996 49

special problem occurs near the uphole endof a slotted liner. Here, annular fluids areforced out of the annulus back into the lineror casing, resulting in significant turbulencethat tends to mix the fluids. This turbulencecan encourage backflow to develop on thelow side of the hole, which can seriouslyaffect flowmeter readings.

In horizontal wells completed with con-ventional cemented liners, flowmeter spin-ner profiles look more like their verticalcounterparts, often showing smooth, distinctevenly-separated profiles when recorded atdifferent speeds.9 However, cementing inhorizontal wells is usually not as successful

as in vertical wells because the liner isdecentralized within the borehole, oftenleading to cement voids and channels withaccompanying annular production.

Other problems in horizontal completionsinclude acceleration of fluids due to gravitywhen undulations in the well profile are suf-ficiently large. If peaks of the flowmeter mea-surements are taken as representative of thefull mixture velocity, the trend is an increasein velocity where the well turns downwardand a decrease as the flow reaches thetrough of the undulation. Backflow alwaysappears to occur in inverted, undulatingwells where the heavy phase falls down thelow side of the drainhole. In many cases, theheavy phase (usually water) simply circulatesin the sump and is not produced.

Delivering Data from Deviated WellsSuccess in isolating crossflow problems inthe offshore Bombay well convinced theoperator to try a combined WFL-PLTapproach in a cased-hole, deviated well thatwas producing oil, water and gas. The oper-ator was unsure of the exact location of thewater entry zones and whether these couldbe sealed off using cement squeezes toreduce water cut.

Again, channeling behind casing was sus-pected. This time, the WFL measurementsshowed this, and confirmed the PLT measure-ments in a difficult environment. The spinnertool data below X050 indicated downflow,the temperature gradient suggested possibleupward fluid movement and the gra-diomanometer tool showed a single-phasefluid below X050—a very confusing picture.

The spinner measurement was presumedunreliable in this zone, as it had insufficientresolution to measure low apparent flow.The thermometer was affected by fluidmovement inside and outside the casing,but could not differentiate between the twoflow regions. The WFL data helped resolvethe dilemma, by distinguishing betweenflows inside and outside the casing (aboveleft). In this case, water was flowing outside

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Water flowGas flow

■■Backflow as drain-hole moves towardsvertical. In highlydeviated or horizon-tal wells and at lowfluid velocities,buoyancy forcestend to segregatefluids. The lighterphase flows in theupper part of thepipe draggingalong with it someof the heavierphase. Sometimespart of the heavierphase moves down-wards due to grav-ity, causing a circu-lation within thepipe. Badly central-ized flowmeters inthe lower portion ofthe deviated pipewill respond to thisdownward flow.

7. In this article, the range of deviated wells will includemoderate to the so-called “high angle” 30° to 85°from vertical; horizontal wells range from 85° to 95°.

8. Brown G, reference 3.9. Spinner turn rates are calibrated by logging at different

cable speeds.

Cou

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s400

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012 24 36 48 60

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1760

1320

Time, sec

12 24 36 48 60

Time, sec

Velocity = 8.5 ft/minRate = 439 BWPD

BackgroundTotal count rate

BackgroundTotal count rate

Velocity = 8.8 ft/minRate = 850 BWPD

■■Distinguishing between water flow insideand outside casing. Time-of-flight gammaray time-decay distributions indicatedwhether the flow is inside or outside thecasing. The lower graph shows theresponse when water is flowing inside thecasing. The blue shaded area reflects thefinal time-decay response to flowing waterafter the background and standing watersignals have been removed. The blue areahad a sharply peaked response, whichindicated that the slug of activated waterflow occurred in a smooth cross-sectionalpipe area without dispersion. The topgraph indicates the magnitude and shapeof the time-decay response when flow isoutside casing. Here the time distributionwas much broader, reflecting slug disper-sion as it flowed around the outside of cas-ing. Lower total counting rates are due togamma ray attenuation in the casing.

(continued on page 52)

50 Oilfield Review

Several years ago, the WFL Water Flow Log tech-

nique was introduced using the TDT-P Thermal

Decay Time tool to provide water-velocity data,

first in vertical wells, then later in deviated and

horizontal wells.1 Today, the RST Reservoir Satu-

ration Tool log provides water-velocity information

with more precision.2 A burst of fast neutrons from

the RST tool activates oxygen atoms in a small

region surrounding the neutron source in the tool.

This includes any oxygen in the water flowing in

the pipe. Oil does not contain oxygen and there-

fore is not affected. Activated oxygen atoms, in a

process like fluorescence, give off radiation, in the

form of gamma rays, radiating for a short time

after the neutron burst.

Moving water in the pipe will carry a cloud of

activated oxygen with it past the detectors in the

tool (above right). The time between the neutron

burst and the detection of the activated water cloud

will be a time-of-flight for the water flow in the

pipe, and is used to compute water velocity. The

half-life of the oxygen activation is only seven sec-

onds, so after a few minutes, the activation radia-

tion has subsided to an undetectable level, making

the measurement environmentally safe.

There are two detectors in the RST tool.The tool

can use a variable neutron burst width from 0.1 to

3 sec with delays from 3.5 to 20 sec to measure

water-flow rates from as low as 6 ft/min [1.8 m/min]

to as high as 500 ft/min [152 m/min]. The RST tool

may be inverted to measure downward water flow.

An additional gamma ray (GR) detector may be

incorporated in the logging tool string to measure

higher velocities.

The RST-WFL technique may be used to mea-

sure other parameters. The total activation count

rate is proportional to the volume of water acti-

vated by the neutron burst, and therefore is a mea-

sure of the water holdup in the pipe. The time pro-

file, or shape, of the activation count rate

distribution carries information about whether the

activated water is flowing near the tool in the bore-

hole or behind the casing pipe in the annulus.

Fluid-Flow Logging Using Time-of-Flight

CasingMinitron

Water

Oil

Near countrate

Far countrate

GR countrate

■■WFL Water Flow Log Measurements. A short burst of neutrons activates oxygenin the surrounding water, and flowing water carries the activated cloud at the watervelocity. Source-detector distances and time-of-flight are used to determine thewater velocity.

0 10 20 30 40 50 60 70 80 90 Time, sec

Casing

Water

Oil

PVL Phase Velocity Log sonde

Oil-miscible marker RST tool

Near detector borehole sigma indicatorMarker signal

■■ PVL Phase Velocity Log technique. A slug of oil-miscible marker fluid is injectedinto the flowing oil phase, and is detected by the RST tool. The time-of-flightbetween injection and slug detection along with the distance between the injectortool and RST detector gives the oil velocity. The same process is used for waterphase-velocity measurements except a water-miscible marker compound is injectedinto the heavier phase.

Winter 1996 51

For horizontal wells, fluid flows are stratified,

with the light phase moving rapidly in the upflow

sections of the well along the high side of the

borehole. Slight changes in borehole deviation

cause large changes in fluid holdup and the veloci-

ties of different phases, making it necessary to

know all fluid velocities. Spinners are usually not

applicable in stratified flow, and radioactive trac-

ers are useful useful only for water-velocity mea-

surements, because there are no oil-miscible

forms available. Radioactive tracers also have

strict procurement and safety issues.

The PVL Phase Velocity log also uses a time-of-

flight method to measure both oil and water veloc-

ities.3 This technique uses a chemical marker that

is injected into either the oil or water stream. The

time the marker takes to reach the detector is a

measure of fluid velocity (previous page, bottom).

The chemical marker contains a high concentra-

tion of the element gadolinium, which has a large

thermal neutron absorption cross section. The RST

tool senses the large increase in the borehole

absorption cross section caused by the passage of

the gadolinium slug (above).

A high concentration of gadolinium chloride

[GdCl3] in water is used as a water-miscible

marker. It has the high density and low viscosity

necessary for the water-phase measurements. For

the oil-phase measurements, a new, gadolinium-

rich compound, with low density and viscosity is

used. These markers are safe to handle, even in

concentrated form, and pose no environmental

threat when injected into borehole fluids.

Flow-loop experiments at Schlumberger Cam-

bridge Research, Cambridge, England have vali-

dated the PVL measurements under a large variety

of flow conditions. Both single-phase oil and water

measurements show excellent agreement between

PVL-measured and actual flow rates (above). Two-

phase measurements, using oil and water or gas

and water, demonstrate the ability to measure sep-

arately each phase in a segregated flow (right).

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■■PVL water velocity measurements in the flow-loop.Water velocity measurements made using the PVLtechnique for horizontal stratified two-phase flow (oiland water), where the water holdup was kept at 50%,show good agreement with actual controlled flowrates. The error bars are dominated by the samplingfrequency of the borehole absorption measurement.

200

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Deviation, degree85 87 89 91 93

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■■Two-phase velocity measurements in theSchlumberger Cambridge Research flow loop. Oil andwater velocity measurements made using the PVLtechnique in a laboratory flow loop with two-phaseflow where the water flow rate was maintained con-stant at 1500 BWPD. The loop was tilted from 85 to92 degrees and the water and oil velocities measuredfor oil flow rates ranging from 750 to 3800 BOPD.The results show that small deviations from horizon-tal can cause large changes in the measured fluidvelocities.

1. Lenn C, Kimminau S and Young P: “Logging of WaterMass Entry in Deviated Well Oil/Water Flows,” paperSPE 26449, presented at the 68th SPE Annual Techni-cal Conference and Exhibition, Houston, Texas, USA,October 3-6, 1993.

2. Albertin et al, reference 6, main text.3. Roscoe BA and Lenn C: ”Oil and Water-velocity Log-

ging in Horizontal Wells Using Chemical Markers,”paper SPE 37153, presented the 1996 SPE Interna-tional Conference on Horizontal Well Technology,Calgary, Alberta, Canada, November 18-20, 1996.

52 Oilfield Review

the casing below X050 m causing the tem-perature to change faster than the localgeothermal gradient. Above X050 m, theWFL data revealed flow inside the casing, ingood agreement with the production log-ging interpretation (right).

The WFL interpretation helped pinpointthe three-phase production to Zones 2 and3. Only gas and oil enter the well fromZone 1. The WFL data show that water, frombelow Zone 5, flowed behind the casing.With a clear understanding of the produc-tion problems in the well, the operatorcould choose between two remedial treat-ments—eliminating all water production byclosing Zones 2 and 3, simultaneously cut-ting potential oil production by a third; orsimply decreasing water cut by repairing thecement below X050 m.

The next field example shows how a newPL holdup and velocity imaging toolhelped determine the correct remedialaction for a well on the North Slope,Alaska, USA operated by ARCO Alaska Inc.and BP Exploration (next page, left).10

The 49° deviated well, was flowing at1141 BOPD [181 m3/d] with 82% water cutat surface and a GOR of 2583 ft3/bbl. Fourzones were originally perforated, and tradi-tional PL interpretation based on density,velocity and temperature indicated mixedwater and oil production in the lower threezones, and gas in the top two. For example,in the lowest perforated zone, the gra-diomanometer showed a reduction in fluiddensity, usually interpreted as first hydrocar-bon entry. Based on traditional PL measure-ments and interpretation, only this lowestzone would be produced, and all upperzones would have been plugged.

A completely different picture emergedusing the recently introduced FloView imag-ing tool (see, “Advantages of Holdup andBubble Imaging in Production Logging,”page 54). The FloView water holdup curveremained at 100% in the lower zone. Thedensity drop measured by the traditional gra-diomanometer probably occurred when thetool moved from a dense sump fluid lyingbelow the lowest perforated zone into lighterwater produced from the first set of perfora-tions. Next, the FloView holdup detected asmall hydrocarbon entry in Zone 2, and alarge entry in Zone 3, as seen in the FloViewholdup map.

Well Sketch15 in. -15

Downhole Flow Rate 0 B/D 4000

WFL Water Rate0 B/D 4000

1

X025

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WFL Far blue-25 ft/min 100

WFL Near green-25 ft/min 100

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Theor.Dens6.6 1.10

gm/cm3

Theor. Temp235 240

°C

Theor. Pres1010 1090

psi

Fluid density0.6 1.10

gm/cm3

Temperature235 240

°C

Pressure1010 1090

psi

MatrixCement

ProductionPerforations

Shale

Water

Oil

Gas

WFL Water Rates

3

X050

4

X075

5

Flow outside

Outside velocities

■■Water flow logs at different depths in a deviated well. Track 1 (left) shows a well sketchand perforations at each zone. Track 2 shows WFL velocity results. The next three tracksshow PL density, temperature and pressure measurements. Results of flow model analysisare shown in Track 6 (right). The reconstruction of PL measurements (dashed red) basedon the flow model analysis is shown along with the original (solid black) PL measure-ments in Track 5. Three detectors were used by the WFL to cover a wide range of flows.Water velocities inside the casing, derived from the near detector are shown as green cir-cular tadpoles, while the far detector readings are shown in blue and the gamma rayreadings in red. The triangular-shaped tadpoles represent readings for flow outside thecasing. In this display, the 45° angle of the tadpole tails show an upflow in the well.Downward flow would be indicated by tails pointing 45° downward.10. Vittachi A and North RJ: ”Application of a New

Radial Borehole Fluid Imaging Tool in ProductionLogging Highly Deviated Wells,” paper SPE 36565,presented at the SPE Annual Technical Conferenceand Exhibition, Denver, Colorado, USA, October 6-9, 1996.

Winter 1996 53

In addition, the FloView bubble (or hydro-carbon) velocity map pinpointed the firstsignificant hydrocarbon entry midway upZone 3. The caliper readings, shown as acasing cross-section profile, supported theidea that the gradiomanometer interpreta-tion was adversely influenced by changes incasing diameter between Zones 1 and 3. Arestriction in the casing at X900 ft caused anincrease in both spinner and FloView veloc-ity measurements.

Just above X900 ft, between Zones 3 and4, there was a reduction in average FloViewbubble velocity. The FloView imagesshowed a narrow band of hydrocarbon inthis section of the well—low water holdup

and higher bubble velocity throughout thetop section of the casing. This zoneappeared to have water backflow shown bycomparing an overlay of two passes of theFloView velocity, one going up the well anda second traveling downhole. A large sepa-ration between the up and down passes wasseen in the region experiencing the waterbackflow. The upgoing FloView pass readhigher hydrocarbon velocity than the down-going pass. This occurred because waterwas flowing backwards down the pipe, car-rying hydrocarbon bubbles down with itagainst the upward motion of the tool. Thisabnormal separation in FloView velocities isan easily recognized flag to spot reverseflow in the well.

Farther up the well, the opposite occurred.Starting at Zone 4, the upgoing FloViewpass had a lower hydrocarbon velocity thanthe downgoing pass. This occurs becausehydrocarbon bubbles, carried by theupward flowing water, were moving alongwith the upward moving tool—a sign of sig-nificant hydrocarbon entry in Zone 4.

The downhole flow rates and profiles com-puted from the imaging measurements weresignificantly different from those determinedusing traditional PL measurements alone.Flow rates calculated using data from thisnew technique were within 8% of actualproduction rates (above). Based on theseresults, the recommendation to the operatorwas to plug off all the zones except Zone 3,the only significant oil producer.

The overlay techniques shown in thisexample can be used as a qualitativemethod of identifying zones of hydrocarbonentry and water backflow.

FloViewHydrcarb.

Velocity (down)

Oil

Water

Gas

Gradio Density

0.6 gm/cm3 1.1

Temperature

218 °F 223

0.5 v/v 1

FloViewHoldup

FloViewHoldup Map Downhole Flow

Profile

0 10,000B/D

Spinner Velocity

25 ft/min 375

0 ft/min 350

FloViewVelocity (up)

FloViewVelocity Map

0.6 1.0

v/v

0 350

ft/min1:600 ft

Perfs

Casing

GR

0 150API

X800

X1000

X900

1

2

3

4

■■Identifying fluid entry. The holdup map in Track 2 and the hydrocarbon velocity map in Track 4, from an Alaskan well show the first hydrocarbon entry in Zone 3. The center of each map track represents the high-side of the casing. The difference between the up(dashed red) and down (solid red) passes of the FloView imaging tool in Track 3 indicatesbackflow (shaded grey area where curves cross over) at X900, and hydrocarbon production (unshaded crossover) in Zones 3 and 4.

4

Production, B/D

3

2

1

0 20001000 3000 4000

Conventional PL Results

4

Production, B/D

Zon

e

3

2

1

0 2000 4000

PL Results with FloView

Gas

Oil

Water

Gas

Oil

Water

1000 3000

Zon

e

■■Comparing production logging tech-niques. Downhole production from eachzone was measured using conventionalPL techniques and compared with thosefrom the new FloView imaging technique.The new technique showed that onlyZone 3 had significant oil production.

54 Oilfield Review

The 111⁄16-in. FloView production logging tool

makes four independent measurements of bore-

hole fluids, distributed in different quadrants of the

pipe cross section (right).

The self-centralized device uses matchstick-

sized, electrical probes to measure the resistivity

of the wellbore fluid—high for hydrocarbons and

low for water. The probes are located inside of

each of the tool’s four centralizer blades to protect

them from damage, and their azimuthal position

within the pipe cross section is measured.

The FloView imager may be run in up to 95⁄8-in.

casing. Each probe is sensitive to the local resis-

tivity of the fluid within the pipe and generates a

binary output when their sharp leading edges

impinge on droplets of oil or gas in a water-contin-

uous phase, or conversely, water in an oil-continu-

ous phase (next page, left). Assuming the fluids

are distinct and not in an emulsion form, and that

the bubble size is larger than the tip of the probe

(less than 1 mm), both water holdup and bubble

count measurements may be obtained from the

binary output of the probe.1

Water holdup is computed from the fraction of

the time that the probe is conducting, and bubble

count comes from the average frequency of the out-

put. In a water-continuous phase, an increasing

bubble count means an increasing hydrocarbon

velocity, and vice versa in an oil-continuous phase.

In biphasic fluid flow, the oil or gas holdup may be

obtained from a closure relationship with the water

holdup—the closure relation simply states that the

sum of the holdups of all the phases equals unity.

The probes cannot discriminate oil from gas.

Even in three-phase fluid flow, this device still

yields an accurate water holdup measurement.

Averaged local outputs for holdup and bubble

count are determined for each of the four individ-

ual probes. The outputs from each of these probes

are combined to map local stratified holdup.

In a typical two-phase environment, the FloView

tool has many advantages over the gradiomano-

meter (next page, right). Jetting of producing fluid

in front of perforated zones or changes in pipe

diameter because of scale or restrictions have a

venturi pressure effect on gradiomanometer

response. The gradiomanometer does not mea-

sure density directly, but measures the gravitation

pressure gradient with differential sensors over a

known vertical height difference. For this reason,

gradiomanometer measurements are more diffi-

cult in highly deviated wells and are impossible in

horizontal wells because the vertical separation

between sensor measure points is reduced and the

measurement loses resolution. Finally, if the flow

velocity is sufficiently high, friction will affect the

gradiomanometer response.

Advantages of Holdup and Bubble Imaging in Production Logging

■■Flow-imaging tool and holdup images. The FloView imaging tool has four probes, which map the local waterholdup in the borehole (inset above). FloView images show increasing water holdup as deviation decreasesand correlate well with flow loop photos.

Probe

Probe

Probe

FloView images

ConnectorCeramicinsulator

0

0.5

Water holdup

0.440.48

91º90º89º80º

0.580.71Flow rate1500 B/D

Deviationfrom vertical

1

Conductivetip

Probe holdingbracket

Casing

Flow loop photos

1. During most field tests, bubble sizes vary between 1and 5 mm, within the requirements of the probes. Onlyat high flow rates (in excess of 2 m/sec [6.5 ft/sec]) aresmaller bubble sizes experienced that might affect theholdup and bubble-count measurements.

Winter 1996 55

Probe output

Conducting

Time

Notconducting

Probe

Flow

Oil

Gas

■■Principle of local probe measurement. Oil and gas do not conduct electriccurrent, but water does. Water holdup is determined by the fraction of timethe probe tip is conducting. Bubble count is determined by counting thenonconducting cycles.

Jetting,venturieffects

Gradio

Secondoilentry

First oilentry

Waterentry

FloViewholdup

FloViewbubblecount

Stagnantwater

Mud

Frictioneffects

Third oilentry

■■FloView tool and gradiomanometer comparison in two-phase flow. At the bottomof the well (middle), there is frequently some mud and dense stagnant water. Thegradiomanometer (right) responds to density change, and will detect the densitydecrease above the stagnant fluid, which in many cases might be mistaken for oilentry. FloView probes do not respond to the water change since both water andstagnant water are conductive. Therefore, the holdup (left) remains at 100% andthe bubble count stays at zero. The next zone is producing water, typically oppositeperforations. The gradiomanometer detects another density change, and as before,this change may be misinterpreted as an oil entry, because the produced water isinvariably less dense than the stagnant water. Once again, FloView probes do notrespond to this water change since both waters are conductive. At the first oil entryin the next zone, the outputs of the FloView probes will indicate less than 100%water holdup, and the bubble count will start to increase. The gradiomanometerdensity will also record the change, if enough oil enters, and the oil density is suffi-ciently different from the produced water. As the tool passes across additional oilentries, FloView water holdup will continue to decrease and the bubble count willincrease. The gradiomanometer will also register these oil entries with a decreasingdensity, if the oil entries change the mixture density significantly.

56 Oilfield Review

Horizontal Wells: The Flagship ProjectDuring 1994, British Petroleum ExplorationOperating Co. Ltd. and Schlumberger Oil-field Services established a joint initiative—“The Flagship Project”—to develop newtechniques for the diagnosis and treatmentof high-angle and horizontal well produc-tion problems.

The diagnosis part of this project involveddevelopment of new PL tools. First, a noveltool string incorporating sensors targeted atthe stratified flow regimes encountered inhorizontal and near-horizontal wells wasdeveloped—combining the CPLT tool, anextra gamma ray detector, the RST tool,FloView Plus tool, fluid marker injector anda total flow rate spinner tool (above).11 Thisequipment is now being used in the NorthSea and the Middle East to make quantitativeflow-rate measurements of oil and water incemented and perforated liners, with a long-term goal of being able to measure three-phase flow in uncemented liners.

The first application of this tool string wasto resolve flow profiles and monitor move-ment of OWCs in the Sherwood sandstonereservoir, in the Wytch Farm field that strad-dles the coastline of southern England. Usingextended-reach drilling technology, at leastten onshore wells were drilled with stepoutsof up to 8000 m [26,248 ft] and havingreservoir sections of up to 2700 m [8858 ft].The wells have electrically submersiblepumps (ESPs) and produce up to 20,000BOPD [3178 m3/d]. To manage the field, BPemploys production logging on selectedwells to assess flow profiles with respect to

reservoir zones and to monitor the move-ment of OWCs. This information is used todetermine future well trajectories, optimizestandoff from the OWC and target futurewell intervention needs, such as to shut offwater and add secondary perforations.

GR RST

FloView toolsBubble velocityWater holdup

RST Reservoir Saturation ToolOil holdupGas indicator

FloView Plus tool

WFL Water Flow LogWater velocityWater holdupWater flow-rate index

CPLT

CPLT CombinableProduction Logging ToolPressure and temperature

Fluid markerinjector

Spinner

Total flow rate

Gamma raydetector

PVL Phase Velocity LogMarker injection for oiland/or water velocity

■■The PL Flagship tool string. This composite string consists of the CPLT Combinable Production Logging Tool, an RST module with anextra gamma ray tool, used for water flow logging and PVL Phase Velocity Logging, a FloView Plus fluid imaging tool, a fluid markerinjector tool used with the PVL, and a total flow rate spinner tool. The two imaging FloView tools are mounted with their probes alignedfor enhanced coverage of the borehole cross section.

Water holdup

Above 0.94

0.88 - 0.93

0.82 - 0.87

0.76 - 0.81

0.71 - 0.75

0.65 - 0.70

0.59 - 0.64

0.53 - 0.58

0.47 - 0.52

0.41 - 0.46

0.35 - 0.40

0.29 - 0.34

0.24 - 0.28

0.18 - 0.23

0.12 - 0.17

0.06 - 0.11

Below 0.5

Average holdup = 0.261

■■Holdup image from Wytch Farm 1F-18SP well. Multiple positions of the imaging probesprovide a detailed local holdup image. From this image, the local holdup profile is com-bined with the different phase velocities to determine multiphase fluid-flow rates.

11. Lenn C, Bamforth S and Jariwala H: ”Flow Diagnosisin an Extended Reach Well at the Wytch Farm Oil-field Using a New Tool string Combination Incorpo-rating Novel Production Technology,” paper SPE36580, presented at the SPE Annual Technology Con-ference and Exhibition, Denver, Colorado, USA,October 6-9, 1996.

12. Roscoe B: ”Three-Phase Holdup Determination inHorizontal Wells Using a Pulsed Neutron Source,”paper SPE 37147, presented at the 1996 SPE Interna-tional Conference on Horizontal Well Technology,Calgary, Alberta, Canada, November 18-20, 1996.

Winter 1996 57

Three Wytch Farm wells were chosen toevaluate the new Flagship tool string—twowith water cut and one a dry-oil producer.The first water-cut well 1F-18SP was drilledto a 4450 m [14,600 ft] total depth, with ahorizontal displacement of nearly 3800m [12,468 ft]. Once the main drainhole wasdrilled through the productive section, thewell trajectory was dropped to penetrate theOWC. This permits future logging of theOWC as it moves. The reservoir was perfo-rated 33 m [106 ft] above the initial OWC,giving an initial estimated productivity index(PI) of 100 B/D/psi.

Production started at 15,000 B/D [2384 m3/d] dry oil, declining after threeyears to a rate of 13,000 B/D [2066 m3/d]fluid with a 9 to 14% water cut at the timeof logging. This well was selected to test thenew tool string because it had the highestwater cut in the field, penetrated the OWCand presented the best opportunity forcoiled tubing intervention.

Despite using a revolutionary tool stringfor this trial, the logging objectives were typ-ical of any PL job: To determine the sourceof water production, identify the oil andwater profile in the well and assess eachzone’s contribution, and determine anymovement of the OWC in the reservoir.

Analysis of the PL data revealed that thewell was producing fluid along the entirelength of its perforated section. Water pro-duction was occurring only in the lowestperforations—in the toe of the well—possi-bly due to coning in a zone of high verticalpermeability, rather than a general move-ment of the OWC.

The RST-Sigma saturation monitor logsshowed that the OWC had moved up only10.8 m [35 ft] from its original position. Theindependent WFL velocity and the PVLwater-velocity measurements both showedgood agreement with the PL results. In addi-tion, oil-velocity measurements wereobtained from the PVL tool.

Local probes on the FloView tool providedholdup distribution images of the fluids,confirming that the flow was stratified (previ-ous page, bottom). In addition, RST-C/Oratio and borehole salinity from the RST-Sigma logs were used for holdup analysis(see “Multiphase Holdup Measurements,”right).12 All three methods—FloViewImages, C/O ratio, and borehole salinity—provided similar results, confirming trendsor conclusions about holdup analysis. Flowprofiles were computed from the velocityand holdup measurements for both oil andwater phases.

Multiphase holdup measurements are made with

the basic RST C/O measurement, which is usually

used to determine the volume of oil in the forma-

tion. The carbon and oxygen signals are generated

by fast neutron inelastic scattering, which leaves

these elements in high-energy excited states that

decay immediately by gamma ray emission.

Most carbon-oxygen excitations take place within

15 to 23 cm [6 to 9 in.] of the tool. This means all

C/O measurements are sensitive to the local ele-

mental concentrations, and therefore to the relative

amount of oil and water holdup in the borehole as

well as the saturations in the formation (above).

The RST-A tool has two detectors with one more

and one less sensitive to the borehole environ-

ment by virtue of their spacing from the source.

Gamma ray spectra from both detectors lead to

relative elemental carbon and oxygen yields,

which are used to solve simultaneously for the vol-

ume of formation oil and the borehole oil holdup.1

The RST C/O crossplot response and RST-A

inelastic near-to-far count rate ratios are used

together to determine multiphase fluid holdup.

The inelastic spectra give carbon-oxygen ratios and

detector count rates. The crossplot near detector

C/O ratio response is determined primarily by the

oil holdup in the borehole and the far detector C/O

response by the oil volume in the formation. The

near-to-far inelastic count rate ratio primarily

depends on the overall borehole density, which is

related to the borehole gas holdup.2 Two-phase (oil

and water) holdup is determined using the crossplot

C/O response, while both crossplot and count rate

ratios are used simultaneously for holdup determi-

nation in three-phase (oil, water and gas) solutions.

Multiphase Holdup Measurements

1. Roscoe B: ”Three-Phase Holdup Determination inHorizontal Wells Using a Pulsed Neutron Source,”paper SPE 37147, presented at the 1996 SPE Interna-tional Conference on Horizontal Well Technology,Calgary, Alberta, Canada, November 18-20, 1996.

2. An approach to measure borehole gas holdup with afullbore backscatter gamma ray density tool can befound in: Kessler C and Frisch G: “New Fullbore Pro-duction Logging Sensor Improves the Evaluation ofProduction in Deviated and Horizontal Wells,” paperSPE 29815, presented at the 1995 Middle East OilTechnical Conference, Manama, Bahrain, March 11-14, 1995.

YG = 0.00

YG = 0.33

YG = 0.67

YG = 1.00

Gas Holdup Response

Casing

Cou

nts

Inel

astic

N/F

rat

ioFa

r C

/O r

atioEnergy

Porosity

Near C/O ratio

C/O Model Response

Inelastic Spectrum Gas

RSTTool

Water

YG

YW

YO

YG

Borehole

oil

Borehole water

Form

atio

n oi

l

Form

atio

n w

ater

Carbon

Oxygen

Near and Far count rate

Near and Far C/O ratio

■■Multiphase holdup from RST tool. Inelastic spectra (left) lead to carbon-oxygen ratios and near-and-fardetector count rates. The crossplot of near and far C/O ratio responses are determined primarily by oil holdupYO in the borehole (lower right plot) and oil volume in the formation. The near-to-far inelastic count rate ratio(upper right plot) primarily depends on the overall borehole density which is related to the borehole gasholdup, YG.

58 Oilfield Review

The data acquisition capability of the toolstring allows most critical parameters to bedetermined by alternative independentmethods—for example, C/O and imagingholdup data, or WFL and PVL velocity datasupported by spinner measurements—instilling greater confidence in the results.

The new tool string clearly identified allthe water entry points in the well, confirmedthat the downhole flow was stratified, andproved that water and oil flow rates couldbe accurately determined using the newphase velocity and C/O-based holdup mea-surements. The upper perforations were pro-ducing oil. Oil flow rates derived from thePVL velocity and C/O holdup, within 500B/D [80 m3/d], were 12,500 B/D[1986 m3/d]. The water-flow rates derivedfrom the PVL and WFL measurements,within 500 B/D, were 3500 B/D [556 m3/d].

In the second water-cut well to be loggedwith the PL Flagship tool string, water entrywas found to be not from the toe as before,but from a nonsealing intersecting fault. Thelogs showed that water was being drawn upthrough the fault from the OWC.

In the third well—a dry-oil producer—thePVL oil-velocity measurements were testedagainst a fullbore spinner flowmeter in thehorizontal drainhole completed with sandscreens. The PVL data matched the spinnervelocity, which functioned effectively inmonophasic production.

Tying It All Together—InterpretationTraditional PL interpretation for verticalwells primarily uses density from the gra-diomanometer to compute oil and waterholdup, and the averaged measuredflowmeter velocity from the spinner to com-pute fluid-flow rates using the slip velocitycomputed from a fluid model.13 Pressure,temperature and other data are largelyignored by conventional PL analysis.

However, such a limited approach is inad-equate for most wells. By using all availableproduction logging data, more completeanswers may be delivered with greater confi-dence. The BorFlo production logging ana-lyzer is being introduced to do this (aboveright). This single interpretation package usesphysical models based on fluid dynamics indeviated and horizontal boreholes, relatingthe physics of fluid flow to the parametersmeasured by the PL tools (see “InterpretingMultiphase Flow Measurements in Horizon-tal Wells,” next page). With this interactivePL interpretation tool, measurements may bestacked, tool responses calibrated and flow-rate solutions determined.

Multiple measurement of productionparameters—such as fluid velocities fromspinners, WFL and PVL logging runs, as wellas holdup measurements from imaging toolsand RST logs—enable delivery of optimizedsolutions to the fluid-flow dynamics. Knowl-edge of sensor responses allows the opti-mization to be based on the confidence lev-els of each logging measurement.

This forward-modeling program tests theresults of different flow conditions, based onmany iterations, to determine the most likelydownhole fluid-flow regime that is consis-tent with all the borehole geometries, well-bore environment, and observed productionlogging and surface measurements.14

Fluid Velocity

Stacking

Calibrations

Blocking

Flow RateSolution

Final Results

Initialization

ToolIncoherence

ToolIncoherence

Solver

Flow Model

Tool Model

7800

7600

7700

Spin - rpm

CableSpeed

Bot. Top Slope Intercept7750 7700 .21 .027800 7750 .22 .03

7800

7600

7700

Flow Velocity Temp

Inputs

Data Editing

Depth Matching

Log Inputs Well and FluidCharacteristics

7600

7700

7800

Calibrations

Reconstruction

Depth Matching

Report and Well Sketch

GasOil

Water

Lowerperfs

Upperperfs

■■BorFlo overview. The PL interpretation program allows the engineer to do log stacking,calibrations and define well and fluid characteristics interactively. The interpretationmatches the PL measurements with those determined by a fluid-flow model based on dif-ferent flow conditions occurring at each interval.

13. Slip velocity is the difference between the two-phaseaverage velocities. For discussion of traditional pro-duction log interpretation: Hill AD, reference 2.

14. For example, the Duckler analytical model is used todetermine parameters of the gas/liquid flow regime,and the volumetric model developed by Choquetteand Piers separates the oil/water regime. For more onthe development and use of the constrained solverPL interpretation models such as PLGLOB: Torre J,Roy MM, Suryanarayana G and Crossoaurd P: ”Gowith the Flow,” Middle East Well Evaluation Review13 (1992): 26-37.

A new fluid dynamics-based interpretation model

called the Stratflo model has been developed to

compute oil-water flow rates from logging mea-

surements in high-angle and horizontal wells.1 The

model depends on basic flow equations, which, in

turn, depend on dynamic parameters such as fluid

velocities and holdup, and static parameters such

as well diameter, borehole deviation, and fluid

densities and viscosities. Frictional terms at the

casing wall are based on monophasic results

(right). At the phase interface a simple flat inter-

face frictional model is assumed. A correlation for

the frictional factor between the two phases has

been developed from flow-loop measurements.

The model is based on the principle that the

pressure variation ∆P along the axis of the well in

each phase is equal. In steady state, the pressure

variation in each phase has a hydrostatic compo-

nent, which depends on density and the borehole

deviation (the difference in height of the vertical

positions), and a frictional component, which can

be divided into two parts: the shear stress on the

wall for oil Tow and water Tww, and the shear stress

on the fluid interface Ti.

The steady-state model simply sets the pres-

sure in the oil ∆Po equal to the pressure drop in

the water ∆Pw, by defining a function

F = ∆Po – ∆Pw = 0.

In this model, the function F depends on dynamic

parameters such as flow rates and holdup, as

well as static parameters, such as flowing diam-

eter D, deviation angle, θ, fluid densities ρo and

ρw, and viscosities, µo and µw. For example, in

terms of the dynamic parameters Vw water veloc-

ity and Vo oil velocity and Yw water holdup, the

function can be expressed as

F(Vw, Vo, Yw) = 0.

This function is a nonlinear algebraic equation

and a function of three independent variables.

To use the model, readily-measured parameters

such as local holdup and velocity measurements

may be used for two of the necessary input

dynamic parameters. With the mass conservation

equations, which relate flow rates, velocities and

water holdup, the model can be solved for other

combinations of inputs, depending on available

data. Outputs are computed from the flow model

and mass-conservation equations using a root-

finding technique.

The flow model gives good results up to about

6000 B/D [953 m3/d] for each phase—the limit

where the simple flat interface starts to degener-

ate as the mixing layer grows. The model accu-

rately accounts for the variation in holdup at differ-

ent borehole angles and flow rates (right).

Interpreting Multiphase Flow Measurements in Horizontal Wells

θ

Tow

Tww

Vo

Vw

Ti

∆P in water = ∆P in oil

Pressure Drop Wall friction (Tw)Interfacial friction (Ti)

Gravity (ρ,devi) ∆P

∆P

∆h ρo

ρw

■■Stratified flow model. The flow model for two-phase flow equates the pressure difference due to thehydrostatic head (which depends on borehole devia-tion angle θ), ∆h, and the wall, Tw, and interfacial, Ti,friction components for each of the two fluids.

1.0

Wat

er h

old

up

Deviation, deg87

0.8

0.6

0.4

0.2

088 89 90 91 92

Flow modelFlow modelFlow=800 B/D

Flow=7000 B/D

■■Measured and predicted holdup variation. Holdupwas measured at different deviations and flow ratesin the Schlumberger Cambridge Research flow loopand compared with results predicted by the stratifiedflow model StratFlo. The results show the rapid vari-ation in holdup with borehole deviation at low flowrates (red curve), as well as the reduced holdup sen-sitivity at a high flow rate (yellow curve). The resultsare shown for a water cut of 50%.

1. Theron BE and Unwin T: ”Stratified Flow Model andInterpretation in Horizontal Wells,” paper SPE 36560,presented at the 1996 SPE Annual Technical Confer-ence and Exhibition, Denver, Colorado, USA, October6-9 1996.

Winter 1996 59

The OutlookThe ongoing development effort in under-standing three-phase flow is deliveringresults—including detailed gas holdup andvelocity measurements—that are reshapingPL services. However, there is still an impor-tant flow domain not adequately covered bytoday’s technology—environments wherethere is low water holdup and significantdrainhole deviation. Work is under way atSCR to understand the complex fluiddynamics, flow instabilities and phase mix-ing in all regions. This experimentationtogether with hydrodynamic modeling willlead to better future understanding andmanagement of flow in the borehole (right).

Improved instrumentation and tool tech-nology are also promising faster, more effi-cient and lower-cost services—some usingslickline. Other applications will see per-manent downhole sensors used for produc-tion monitoring.15 These devices arerapidly becoming more sophisticated, mea-suring properties other than temperatureand pressure—such as hydrocarbons andphase mixing.

The outlook for production logging is cer-tainly brighter now that it has been at anytime during the last decade. Operators canlook forward not only to a better under-standing of their reservoirs, but also to useof this knowledge for more effectively man-aging their assets.

—RH

■■Computed 3D droplet-averaged simulations of two-phase flow showing the effects ofshear instabilities. Mapped projections of fluid holdup are shown for horizontal (top) andvertical (middle) lateral cross section of the borehole and at four positions cutting verticallyacross a borehole (bottom). Oil (red) rises due to buoyancy forming an emulsified layer ofoil on the high side of the pipe. The lighter, upper layer flows at a higher velocity than doesthe water (blue). This shear flow becomes unstable and an instability occurs that causesthe emulsion of oil to disperse in the water: large eddies mix the two phases up. Then theprocess repeats farther up the pipe. Such fluid simulations help scientists test fluid-flowmodels under many conditions and design better methods to measure their properties.

Technology Forum

In conjunction with the Schlumberger ClientLink initiative, Oilfield Review announces its first online technology discussion.

The Production Logging Web-Forumis an interactive site for comments on this article, inquiries about technology, or open

discussions concerning production logging tools, interpretation and applications.

To access this forum, point your browser to the following URL:www.connect.slb.com/forums/pl/

If you have problems making the connection, please E-mail:skipton@slb.com

15. Baker A, Gaskell J, Jeffery J, Thomas A, Veneruso T,and Unneland T: ”Permanent Monitoring—Lookingat Lifetime Reservoir Dynamics,” Oilfield Review 7,no. 4 (Winter 1995): 32-46.

60 Oilfield Review