A NEW ERA IN PRODUCTION LOGGING: DEFINING .../media/Files/resources/mearr/num7/...A NEW ERA IN PRODUCTION LOGGING: DEFINING DOWNHOLE FLOW PROFILES For decades, production and reservoir

A NEW ERA IN PRODUCTION LOGGING: DEFINING DOWNHOLE FLOW PROFILES

For decades, production and reservoir engineers have sought to measure fluid flow rates andproperties in the wellbore. Early measurement techniques focused on establishing fluid velocityusing a single, centrally positioned spinner. This remained the principal fluid-logging tool forproduction engineers for many years.

The latest production-logging methods provide a much more detailed picture of fluid distributions,temperatures, pressures, and flow rates. In addition, many of the limitations of conventionalproduction-logging tools have been overcome and reliable data can now be gathered in highlydeviated and horizontal wells.

In this article, Antoine Elkadi and Murat Zeybek explain how the latest developments in production-logging techniques can help production and reservoir engineers to make better-informed decisionsabout well and field management.

6 Middle East & Asia Reservoir ReviewNumber 7, 2006

Production logging is the measurement of fluid parametersand flow contributions on a zone-by-zone basis to yieldinformation about the type and movement of fluids within andnear the wellbore. This well-established production-loggingtechnique provides vital information about well performanceand can help engineers to identify potential problems and takeremedial action before production is interrupted. Productionlogging also helps production and reservoir engineers tounderstand where the various fluids enter the well. This enablesthem to identify optimal solutions, such as selecting whichunwanted fluid entry zones should be shut off or which poorlyproducing layers require perforation and/or stimulation.

The principal aim of production logging is to measure theperformance of producing and injecting wells by gatheringdiagnostic data, for example, information indicating theefficiency of perforation. When extensive production-loggingcampaigns are conducted as part of a reservoir monitoring orsurveillance program, operating companies can use the datato assess the individual reservoir compartments and establishtheir contributions to oil and gas production or water cut.The information gained from production logging can be usedto help companies in defining field economics and thus tomake the most appropriate decisions for field developmentand reservoir management.

However, traditional production-logging methods havelimitations in many of today’s wells, wellbore conditions, andfluid types. Wellbore conditions have a large effect on thequality of the data obtained. In vertical wells with high fluidflow rates, the data acquired are accurate and reliable.However, multiphase flow conditions exist in many deviatedand horizontal wells. In these wells, conventional production-logging tools are often inadequate and may give misleadingresults (Fig. 1). In the 1990s, the industry began to drill largenumbers of deviated and horizontal wells, and so the need tounderstand and measure fluid flow within complex flowregimes became increasingly important and necessitated thedevelopment of new tools and techniques.

A clearer pictureProduction logging helps to provide information on flow rate(fluid velocity from spinner rotation), density, temperature, andpressure. In traditional production logging, only the flow rateand density readings were used for quantitative analysis. Thetemperature and pressure data were used in a qualitative wayto compute in situ flow properties and to locate the zoneswhere fluids were flowing into or out of the well (Fig. 2).

Today, production logging provides engineers with a broadrange of fluid measurements, including temperature andpressure data. The additional information can be used to

improve the quality of interpretations and is particularly usefulin highly deviated wells and those with low production rates.

Modern tools and techniques can provide zone-by-zonemeasurements of flow rates and fluid parameters and so yieldinformation on the type of fluid movement within and nearthe wellbore. For example, the PLT* Production Logging Tooldetects mechanical problems, breakthrough, and coning;monitors flow profiles, production, and injection; detects thiefzones and channeled cement; and helps to evaluate single- andmultilayer well tests.

Identifying unwanted water and/or gas entries becomesmore complicated because of the interactions between oil,water, and gas at downhole conditions. Oil and water areimmiscible, but gas is miscible with oil, depending on thepressure and temperature, and with water in small quantities.At a specific pressure and temperature, both oil and water canabsorb gas until the saturation point is reached. Above thisgas-saturation limit, the gas remains as a separate phase. Thismeans that in the wellbore, oil and water both containingdissolved gas and free gas bubbles may coexist and flowtoward the wellhead (Fig. 3). The proportions of these fluids in the production stream have a direct influence on theseparation process and, ultimately, on the production rates thatcan be achieved for a particular field or reservoir.

Making sense of multiphase conditionsInterpreting production-logging data and determiningdownhole flow profiles in single-phase flow conditions are,usually, straightforward processes. Flow profiledetermination in multiphase conditions is much morecomplicated. Factors including holdup, slippage velocity, andphase segregation combine to greatly complicate flowbehavior. The holdup, for example, is defined as thepercentage by volume of the borehole contents (i.e., gas, oil,and water) measured over a cross-sectional area. This cross-sectional area is typically the inner diameter of theproduction string (casing or tubing). Holdup can bemeasured at different places throughout the productionstring and can vary dramatically with borehole deviation andfluid flow rate. Under multiphase conditions, light phasesmove faster than heavier phases by an amount known as theslippage (slip) velocity. Engineers must therefore determinethe downhole holdup when attempting to interpretproduction logs obtained under multiphase flow conditions.

The main objective for production logging in three-phase-flow wells is usually to establish the flow rates for oil, water,and gas. However, characteristics such as stratification, misting,annular flow, and recirculation can make accuratequantification extremely difficult. Flow rate is a function ofholdup and velocity. Engineers who want to evaluate the flowrate of each phase at every depth level along the survey intervalmust map fluid velocities and holdups inside the wellbore.

Middle East & Asia Reservoir Review Number 7, 2006 7

Oil flow

Water flow

Figure 1: Problems can be encountered with conventionalproduction-logging tools as a result of multiphase flow.

Gas entry

Temperature

Dept

h

Geothermalgradient

Flow without gas entry

Flow with gas entry

Figure 2: Temperature profiles can be used to indicate where fluidsare entering the wellbore.

The quality of the data acquired from traditional production-logging methods depends on the downhole well conditions.These methods are accurate and reliable for vertical wells withhigh fluid flow rates, but for deviated and horizontal wells withstratified, multiphase flow the data acquired may be misleading. The need for understanding and measuring downhole multiphasefluids with complex flow regimes emerged during the 1990swhen the era of drilling deviated and horizontal wells started.

Figure 3: In the wellbore, oil and water both containing dissolvedgas and free gas bubbles may coexist and flow toward the wellhead.Their proportions in the production stream have a direct influenceon the separation process required at surface.

Fugitiveemissions

Process heatinput andelectrical

power input

Well streamfluids from

subsea

Cooling seawaterfrom process

To producedwater system

Gas for fuel useand injection

Crude oil tostorage

Gas toflare

Oil separation system

8 Middle East & Asia Reservoir ReviewNumber 7, 2006 Middle East & Asia Reservoir Review Number 7, 2006 9

Flow structure in deviated andhorizontal wells In vertical wells, oil and water are mixed across the entirewellbore. The velocity profile is smooth, and the water holdupprofile varies gradually across the borehole. Averagedmeasurements across the wellbore, such as those obtainedusing conventional production-logging tools, are generallyadequate to determine the velocity and the holdup in thistype of flow regime.

However, once the wellbore deviation exceeds more than afew degrees (say 20°), the centrally positioned sensors ofconventional production-logging tools become much lessreliable. Phase segregation and small changes in wellinclination and flow regimes all influence the flow profile.Logging problems typically occur when conventional tools runin deviated wells encounter topside bubbly flow, heavy phaserecirculation, or stratified layers flowing at different speeds.

Flow-loop laboratory experiments that simulate conditionsin the wellbore have shown that the flow regimes thatdevelop in highly deviated wells can be extremelycomplicated (Fig. 4). These flow regimes are controlled byfactors including the borehole size and deviation, the fluid

logging system has five microspinners and six pairs ofelectrical and optical holdup probes that are activateddownhole once the tool has reached the survey interval. Thiscombination of small sensors ensures almost total wellborecoverage. The microspinners evaluate local fluid velocity, andthe electrical and optical probes measure the local water andgas holdups.

In the borehole, the sensors are positioned so that themeasurements map the fluid velocities and holdups across theborehole at every depth. This enables engineers to derive amuch better estimate of the flow rates for the individualphases within the flow regimes.

Using the Flow Scanner tool in deviated and horizontalwells gives operators a better understanding of productionregimes and enables them to define more accurate flowprofiles and, consequently, to plan more efficient workover orproduction strategies, which will improve the ultimatehydrocarbon recovery.

The Flow Scanner tool was developed using computationalfluid-dynamics simulations. Hundreds of flow-loop tests andfluid-dynamics simulations were conducted to optimize thetool’s architecture and the sensor deployment. Unlikeconventional systems, the Flow Scanner tool was designed to runeccentered because it is difficult to centralize a tool in horizontalor highly deviated wells. When in the wellbore, the tool opens upinto a characteristic triangular configuration (Fig. 5).

Five one-inch-diameter microspinners are mounted on thefront arm. Because the tool is designed to rest on the base of thetriangle when driven into the hole, the spinners line up along thevertical axis of the wellbore. In this way, the phase velocitiesalong a vertical axis can be mapped at every depth point.

Figure 4: The flow regimes that develop in highly deviated wells can be extremely complex.

holdup, and the velocity, density, and viscosity of each phase.Tests have also shown that even a 1° variation in welldeviation can have a dramatic effect on fluid distribution,holdup, and velocity.

Flow-loop studies have also revealed the ineffectiveness ofconventional logging tools in multiphase flows once there isstrong phase segregation. The measurements made areinadequate for describing complicated flow regimes. Inaddition, conventional tool sensors are usually spread over along toolstring, which makes the measurements even moredifficult to make.

Mapping fluid velocitiesTwo of the most significant challenges in developing a newgeneration of production-logging tools were extendingmeasurement coverage across the diameter of the boreholeand making measurements in a shorter depth interval overthe wellbore.

One solution was to develop a tool with a range of smallsensors that covered the full width of the wellbore and couldbe placed close together to improve depth resolution. TheFlow Scanner* horizontal and deviated well production-

Using the Flow Scanner tool indeviated and horizontal wellsgives operators a betterunderstanding of productionregimes and enables them todefine more accurate flowprofiles and, consequently, toplan more efficient workoversor production strategies, whichwill improve the ultimatehydrocarbon recovery.

Figure 5: The design and development of the Flow Scanner tool were guided by hundreds offlow-loop tests to establish the most suitable architecture and sensor deployment system.

Middle East & Asia Reservoir Review Number 7, 2006 1110 Middle East & Asia Reservoir ReviewNumber 7, 2006

In wells containing two or moreimmiscible fluid phases, wellboredeviation causes phases with differentdensities to separate out with a mixinglayer of dispersed bubbles betweenthem. In two-phase systems, the flowstructures are characterized by thewidth of the mixing layer. One of thekey factors influencing flow structure iswell deviation. The thickness of themixing layer is fixed for a givenborehole diameter and deviation. Thecomposition of the produced fluidsdetermines the position of the mixinglayer. As the overall fractional volumeof water in the wellbore (i.e., the waterholdup) changes, the mixing layermoves across the borehole’s diameter.

The effect of borehole deviation onmixing and flow structure iscomplicated, even in relatively simpletwo-phase systems such as thosecontaining only water and oil. Threeprincipal types of flow structures can bedefined on the basis of well deviation.

Near-vertical wellsIn near-vertical wells, the oil and waterphases are fully mixed across the entirewellbore cross section. Even for wellswith a deviation of less than 20°, themixing layer is large and the twophases are mixed across the boreholewith a smooth velocity profile.

However, as soon as the wellboredeviates further, gravity creates ahigher concentration of oil in theupper section of the borehole. Theprofile of the local water holdup beginsto vary across the wellbore (Fig. 6A).

Deviated wellsIn wells deviated at angles between 20and 85°, portions of the wellbore crosssection have monophasic flow but theoverall flow structure is more complex(Fig. 6B). Heavy phases, typically water,segregate at the bottom of theborehole because of gravity, and themixing layer is located in the upperpart of the wellbore and containsdispersed bubbles of oil or gas. Inmixed gas-liquid flow, the structurecan be more complex. The gas can flowin slugs instead of small bubbles. This flow structure has large velocitygradients and local holdupdistributions. At low flow rates, wateris frequently recirculating and thewater velocity at the bottom of theborehole may be negative.

At high flow rates, differentialacceleration of the phases caused by theshear forces between the different fluidphases can lead to Kelvin–Helmholtzinstabilities; these almost causebreakdown in stratification. Under theseconditions, production-logging sensors

All the angles

that yield average answers areunsuitable for understanding flowstructure. Local measurements madeacross the borehole’s diameter areneeded to clarify the velocity andholdup profiles.

Near-horizontal wellsFor horizontal and near-horizontalwells (deviations between 85 and 95°),the flow structure is completelystratified, with the water flowing at thebottom and the oil or gas phase at thetop with little or no mixing (Fig. 6C). Atlow flow rates, well deviation has astrong influence on flow behavior. Theslightest deviation from 90° causes themonophasic oil and water streams toflow at different velocities.

Figure 6: Three main types of flow structure can occur in a two-phase (water-oil) system.

One of the key factors influencingflow structure is well deviation. This is the angle to vertical at which the well has been drilled.

Velocity Holdup1

0Top BottomTop Bottom

Holdup1

0Top Bottom

n Oil and water mixed across the section of the pipe

n Smooth velocity profiles

n Almost linear holdup profiles

(A) Near-Vertical Well

n Very complex flow structures

n Monophasic water phase at the bottom of the pipe

n Dispersed oil phase in the uppermost level of the pipe

n Large velocity and holdup gradients

n Almost stratified flow structures

n Monophasic oil at the top and monophasic water at the bottom

n Narrow mixing layer

n Oil and water streams flow atdifferent velocities

(B) Deviated Well (C) Near-Horizontal Well

Velocity

0

Top Bottom

Velocity Holdup1


Velocity Holdup1


Holdup1

0Top Bottom














Velocity

0

Top Bottom

Velocity Holdup1


Velocity Holdup1


Holdup1

0Top Bottom














Velocity

0

Top Bottom

Velocity Holdup1


Number 7, 2006 13Middle East & Asia Reservoir Review

Boosting production in mature fieldsThe application of modern production-logging methods hashelped some operators to make dramatic production gains.Conventional production-logging tools often have difficultyin defining complicated flow regimes and identifying theareas for the water shutoff needed to maximize oil recoveryas fields approach their economic limit.

The Flow Scanner tool was first used in mature reservoirs inthe Gulf of Suez, where viscous oils are produced at highwater cuts through deviated to horizontal completions. Onewell with an inclination of 37° was producing with gas liftthrough six open intervals. The oil production rate was327 m3/d with a 97% water cut. A conventional production-logging survey could not evaluate the individual intervalcontributions or identify the sources of water production, sothe operators decided to try the Flow Scanner tool, whichwas deployed on wireline.

Figure 8: When deployed, the Flow Scanner tool is 5 m long, compared to 25mminimum required for the conventional PL Flagship* toolstring that would berequired to obtain the same measurements. This saving in logging string lengthis a significant benefit for those who rig up and deploy the tool at the wellsite.

12 Number 7, 2006 Middle East & Asia Reservoir Review

The spinners are located in a depth range that means thatthe velocities will be measured at practically the same pointsin depth and time. This is particularly valuable in wells where,during logging, the fluid dynamic properties change overshort intervals. In a 6-in borehole, the top spinner and pair ofprobes are located very close to the inner wall. This enablesthe tool to measure the velocity of any gas that would beflowing along the top of the borehole in a gas-liquid mixture(Fig. 7). Conventional tools can only measure gas velocity ifthe fullbore spinner blades are fully within the gas phase. Theminimum gas holdup required to make measurements withthe top microspinner and probes is only 5%.

The six pairs of electrical and optical probes on the FlowScanner tool are mounted on the rear arm behind thespinners (Fig. 8). In mixed and segregated flow regimes, theelectrical and optical probes measure the localized water andgas holdups, respectively. The electrical probes measure fluidresistance (impedance), which facilitates calculation of thewater holdup, while the optical probes use a reflectancemethod to evaluate the gas holdup.

Figure 7: When the Flow Scanner tool is in the 'open' configuration, its spinners can measure flow rateacross the entire borehole.

The tool arm can deploy both the spinners and the sensorsalong the vertical axis of a nonvertical wellbore to obtain thevelocity and holdup measurements. Additionally, a fifthminiature spinner and the sixth pair of electrical and opticalprobes positioned on the tool body measure the flowproperties on the low side of the well.

The spatial location of the different sensors is accuratelyidentified using an integrated, relative-bearing sensor andcaliper measurements. The direct measurement of the velocityand fluid-holdup profiles helps the analyst to determine thedownhole phase split and reduces the uncertaintiesassociated with multiphase flow interpretation.

The tool arm is motorized with a 1.5-m-long hydraulicmodule, which is controlled from the surface. At any point inthe wellbore, the arm can be made to scan the wellboreslowly during a stationary measurement to pinpoint theposition of the fluid interface or interfaces. In addition, theFlow Scanner tool is 5 m long as compared with the 25 mminimum of the best conventional toolstring required toobtain similar measurements, but of lower quality. Thisshorter logging string saves time and effort at the wellsite.

Conventional Spinner Flow Scanner Spinners

In a 6-in borehole, the top spinnerand pair of probes are locatedvery close to the inner wall. Thisenables the tool to measure thevelocity of any gas that would be flowing along the top of theborehole in a gas-liquid mixture.


caliper. This arrangement provides the area measurementsneeded to calculate flow rates. The tool has an outsidediameter of 111⁄16 in, and it can be run in holes ranging from27⁄8- to 9-in diameter using coiled tubing (CT), wireline, orthe MaxTRAC* downhole well tractor system (Fig. 11).

The Flow Scanner tool’s low-frequency resistivity probesmeasure fluid electrical resistance to detect water. Waterconducts electrical current, whereas oil and gas do not. Athreshold is set that enables the tool to distinguish betweenhydrocarbons and water. Each probe generates a binary signalwhen oil or gas bubbles in a continuous water phase or dropletsof water in a continuous hydrocarbon phase touch its tip.

The water holdup is determined by the amount of timethat the tip is conducting current; thus the water holdupprofile accurately represents the flow regime in the wellbore.This methodology enables a local water holdup measurement,which is independent of fluid properties, to be determinedwithout calibration. Conventional holdup tools, however,require accurate calibration in oil and water.

120

80

40

01 1.1 1.2

Refractive index, n

Refle

cted

light

,%

1.3 1.4 1.5 1.6

Air Gas (n =1.1) Water (n =1.3) Condensate (n =1.4) Crude (n =1.5)

Figure 10: The principle on which the GHOSTprobes operate.

Figure 11: The MaxTRAC unit.


In comparison with the conventional production-loggingsurvey, the Flow Scanner profile showed that approximately25% of the oil and 85% of the water were being produced fromperforations below X,121 m (Fig. 9). The remainder of the waterand some oil were being produced from perforations at X,118 m.

The perforations above X,118 m were producing clean oil,and more than half of the oil was flowing into the topperforation. Conventional production-logging sensors couldnot detect oil entering the top perforations because thespinner was affected by water recirculation, and theresolution of the Gradiomanometer* specific gravity profiletool was too low for it to resolve the oil contributions. As aresult, the conventional survey had erroneously attributed90% of the oil production to the lower perforations.

A workover operation was planned for optimizingproduction on the basis of the Flow Scanner results. Aftercross-referencing the log results with the geologicalinformation on the location of a sealing shale layer, the fieldoperator set a plug at X,120 m to isolate most of the high-water-cut zones in the bottom of the well. The resulting

Figure 9: Gulf of Suez log: When conventional production-logging efforts failed to produce useable results, the Flow Scannersystem identified and measured zonal oil production in the well. A subsequent workover increased oil production by 900%.

40

Water flow

Oil flow

Water flow

Oil flow

Fullbore spinnerVelocity

ConventionalProduction Logging

Spinner stationsrps ft/min0 3 -40 0.92 1.0

Flow Scanner

Gradiomanometerfluid density

Flow Scanner

Flow profile

Flow Scanner

WellSketch

Depth,m

Flow profile

X,105

X,120

Velocity

Velocity imageWater-holdup

imageft/min0 40

Density stationsg/cm30.9 1.2

Fluid densityg/cm30.9 1.2



production (88 m3/d of oil and 403 m3/d of water)represented a nine-fold increase in oil production: paybackfor the operation was achieved in less than a week.

Fluid discriminationThe Flow Scanner tool is engineered specifically to providereal-time holdup and velocity profiles along a vertical axis ofthe borehole cross section. The holdup sensors used are sixGHOST* Gas Holdup Optical Sensor Tool probes and sixFloView* electrical probes. The optical probes distinguishbetween gas and liquid using optical refractive indexmeasurements (Fig. 10). The electrical probes discriminatebetween water and hydrocarbons using fluid electricalresistance measurements. The velocity sensors are fivemicrospinners. Several years of engineering effort haveproduced small diameter spinners with velocity thresholdscomparable to larger fullbore spinners.

To maintain its orientation in the wellbore, the tool’shydraulically operated arm is extended to a length equal tothe diameter of the production tubing so that it serves as a

The Flow Scanner tool software optimizes and displays thedata acquired from the spinners and probes at the wellsite.Two views are constantly updated with real-time acquisitiondata. One of these views shows the relative fluid velocitiesmeasured by the microspinner array, while the other showsthe phase distribution across the wellbore section (Fig. 12). Inboth views, the wellbore is sliced horizontally into the fivelayers associated with the different combinations of spinner,electrical-probe, and optical-probe measurements.

In the spinner view, five rectangles are plotted with lengthsproportional to the rotational velocities of the correspondingspinners. Each rectangle is divided into color-coded sectionswith widths proportional to the three-phase holdups seen bythe electrical and optical probes.

In the cross-sectional view, each layer is color coded torepresent the phase with the highest holdup seen by theprobes. The holdup values of the two remaining phases arerepresented by proportionate numbers and bubble sizes. Therelative positions of the sensors are also shown, with circlesfor the spinners and dots for the probes.

Middle East & Asia Reservoir Review Number 7, 2006 1716 Middle East & Asia Reservoir ReviewNumber 7, 2006

Water recirculation revealedIn the Middle East, the Flow Scanner tool has also helped toidentify water recirculation along a wellbore completion. This wasthe first field test for the tool.

The well under investigation was a 7-in cased holeproducer with a production rate of 500 m3/d of oil at surfacewith zero water cut. The wellbore deviation was 47° acrossthe logging interval. The advanced PS Platform* tool hadalready been run in the well, which meant a directcomparison of its data could be made with data from theFlow Scanner tool. The average value for water holdup abovethe perforations was approximately 25%.

The fullbore spinner on the PS Platform tool had measureda net, positive (upward) velocity. Because the water holdupwas not zero, a conventional interpretation was bound toestimate a net positive water flow rate. When using theconventional toolstring, the zero water cut at surface was theonly indication that water must be recirculating downhole.However, the Flow Scanner tool was able to identify andcharacterize the water recirculation (Fig. 13).

Figure 14 shows the holdup distribution along a verticalaxis of the casing; the bottom probe measured water holdupat about 92% and the top one at about 2%. Note that thebottom two spinners measured a net negative fluid velocity,which was mainly that of the water. The water was beingdragged up with the oil on the topside of the wellbore onlyto fall back down on the low side of the casing. The recordingmade while coming out of hole showed the water columnextending to a few hundred meters from surface, but nowater was reaching the surface (Fig. 15).

This type of information is a major breakthrough forproduction logging. Engineers can now visualize and measureheavy-phase recirculation downhole. The image in Figure 15was taken from a processing application called the FlowScanner tool Inflow Profiler, which uses predetermined spinnerpitches to provide a single-pass interpretation in real time.

The presence of a quasi-stationary water column inside thewellbore was exerting backpressure on the sandface andchoking oil production. The operator has conducted aworkover operation that involved pulling out the completion,cleaning the water from the wellbore, and recompleting thewell as a dual producer.

Figure 12: Real-time flow rate and phase distributiondata are continuously optimized and displayed by theFlow Scanner system.

90°

92°

88°

45°

Surface

Surface

Surface

Surface

In its first field test, the FlowScanner tool identified watercirculation along a completionto around 30 m from thesurface in one Middle East well.

Challenging conditionsAs production-logging technology advances, more accurateand reliable results are being achieved for multiphase flowconditions in horizontal wells. The most significant test of anynew technology is in wells where the operational conditionsare challenging.

Both of the following examples are from a giant carbonatereservoir in which reservoir thickness varies between 46 and55 m, porosity varies between 15 and 20%, permeabilityvaries from 50 to 500 mD, and oil gravity varies between 32 to 36 dAPI.

Determining water entry intervalsand flow profileWell 1 was drilled and completed as a slanted 61⁄8-inopenhole horizontal producer. The well was a barefootcompletion below the 7-in casing with 41⁄2-in tubing and a31⁄2-in tail wellbore extended into the open hole. It was620 m long and produced oil with 22% water cut at surface.The produced water had a total dissolved solids contentreported to be 70,000 ppm, i.e., fresher than the formationwater, which suggested the presence of injection water.

Figure 14: Holdup and velocity profiles.

GR0 60gAPI

SPIN.SD4

-10 15counts/s

SPI1.SD4

-15 15counts/s

WTEP.SD4

218 221deg F

WPRE.SD4

2,350 2,450psi

SCVL.SD4

-7,000 7, 000ft/h

DFHM.SD4

0 1

WFDE.SD4

0.7 1.2g/cm3

XX,000

XX,050

XX,100

Perfo

ratio

ns

XX,150

In-li

nesp

inne

rs

Dens

ity

Tem

pera

ture

Pres

sure

Hold

up

Fullborespinners

Figure 13: Flow Scanner image showing the water recirculation.

The production-logging objectives for this well includeddetermining the water entry interval(s) and the flow profile.The integrated production toolstring used was 28-m long andincluded a gamma ray sensor at the top and a deploymentbar in the middle for two-stage deployment with CT.

The total flow rate was determined in the 41⁄2-in tubing

(the deviated section) above the perforated pup joints

because of the tail wellbore extension into the openhole

section. The agreement between the production-logging tool

data and the test trap data was very good (similar amounts

of oil with a 26% water cut). The water flow velocity

(137 m/min) and the oil-phase flow velocity (142 m/min) were

in excellent agreement with the expected slip velocity in this

38° deviated wellbore section.

The oil-phase flow velocity measurement at this deviation

proved to be valid, independent of deviation, as long as the

oil phase was continuous. Oil and water velocity stations

were continued in the openhole section for flow profile

determination. To increase confidence in the results, a

multiphase holdup pass using pulsed-neutron measurements

(Roscoe and Lenn, 1996) was recorded and holdup

measurements were made using electrical probes. Both

measurements showed very close agreement, see Fig. 15,

tracks 2 and 4.

Number 7, 2006 19Middle East & Asia Reservoir Review

The fluid holdup distribution along the wellbore indicatedthat there was no oil entry below X,260 m; only water wasseen in the wellbore. The first water entry was detected in thetoe section, the second in the middle section where theborehole salinity decreased significantly, which indicated theentry of injection water (see track 5, Fig. 16).

In the presence of water and oil, the amount of oil holdup iscompensated for to determine the salinity of the water. Thesudden increase in oil holdup 60 m above the slanted section ofthe wellbore gave a clear indication of significant oil entry. Infact, the oil-phase flow velocity measurements detected theentry; this translated, using holdup and caliper data, into 40%of the total oil production. An increase in water flow at stationsacross the same interval translated into a 60% water entry.

The spinner data also indicated a large increase in flowvelocity, which supported both the oil- and the water-phasemeasurements. This interval was identified as a superpermeablezone that had not previously been identified in logs.Productivity index information was obtained from themeasured total flow rate and the pressure drawdown data.

Holdup

Oil

Water

Oil

Water

Oil

Water

Oil

Oil

Water

Holdup Holup

Well Sketch

MD

PFC1-8 8in

-8 8inPFC2

Flowing(probes) Shut-in Flowing

(pulsed neutron)

Moved hydrocarbon

Water

Dolomite

Calcite

Anhydrite

No flow

ElanPlus volumes

Water flowstations

TVD TVD TVD

Flow Rate

Flowing

Ratebbl/d

BSALppk0 0

0

250

X,100

X,200

X,300

X,400

X,500

X,600

X,700

X,800

X,900

X,000

X,100

X,200

X,300

X,400

X,500

X,600

X,700

X,800

X,900

X,000

lbg 3½-in

Figure 16: Results of integrated production logging in Well 1.

Quick and accurate resultsWell 2 was drilled and completed as a 61⁄8-in open hole andwas initially producing dry oil. The test trap showed 40%water cut after six years’ production. Before logging, the wellshowed a 51% water cut with an 80⁄172 choke size. Duringlogging with CT, the well was flowing with an 80/172 chokesize and a flowing wellhead gauge pressure of 4,620 kPa. Thelogging operations aimed to determine the water-entryinterval(s) and the flow profile.

The compact, integrated Flow Scanner production-loggingtoolstring was used to provide fast rig-up withoutdeployment. The flowing passes were planned and completedwithin 15 h from rig-up to yield real-time answers.

The job was planned to include one downward and oneupward pass, including stations, with a repeat pass if requiredto achieve the objectives on the basis of the real-time results.Image logs were available during logging and were integratedwith the openhole logs. The total flow rate determination wasperformed above the perforated pup joint to detect any


Figure 15: Middle East well holdup measurements.

5

Calibratedcaliper

Cablevelocity

memorized

-100

PSPdeviation

40 °

°

ft/min

FSIT RB

-20

7

100

60

20 Total holdup

–5.0000 –2.0000–1.0000

–0.5000 –0.4000 –0.3000 –0.2000 –0.1500 –0.1000 –0.0500 –0.0100

0.01000.05000.10000.15000.20000.30000.40000.50001.00002.00005.0000

Mixture velocity image (full range) m/s

–5,000.0000

–1.0

000

1.00

00

0.00

00

–5,0

00.0

000

–21.0000

Waterflow rate Oil flow rate

Wellpressure

0 5,000

Welltemperature

degF

psi

250 2750 100-1 4 0 5

X,100

X,000

x103bbl/d

in

Gamma rayx103bbl/d

Oil

Neutron generator

Water

1. Near Count Rate 2. Far Count Rate 3. Gamma Ray Count Rate

Neutron burst 1 2 3

Figure 17: The WFL* Water Flow Log measurement principle. Thewater velocity is computed from the time of flight of the activatedoxygen between the neutron generator and the detectors. The“vertical” resolution of the measurement is equal to the distancebetween the minitron and the corresponding detector.

Figure 18: The PVL* Phase Velocity Log measurement principle.The oil velocity is computed from the time of flight of themiscible marker between the ejection nozzle and the RST*Reservoir Saturation Tool. The vertical resolution of themeasurement is equal to the flight distance, which is usuallyabout 7.3 m.

Oil

Oil miscible marker

PVL RST

Water

L (usually 7.3m)Phase velocity = L ⁄T

1

2

3

4

5 6

78

Figure 19: The distribution of sensors inconventional logging tools. Probes 1–4belong to one tool and probes 5–8 belongto the other probe tool.

Improved depth resolution and wellbore coverage

The downhole flow rate, Q, is estimatedat every depth point from the formula:

Q = VAYwhere V is the velocity of the phase

in question, Y is its holdup or thefraction that it occupies in a unitvolume, and A is the surface area thatis available to the flow.

When using conventional methods, theoil and water velocities were measuredduring stationary acquisition. Thevertical resolutions of the measurementsare about 0.5 and 7 m for water and oilrespectively (see figures 17 and 18).

Because the oil and water velocitiesare not measured at the same instant,inconsistencies can be introduced intothe computations. In addition, thestationary nature of the measurementhas a detrimental effect on theresolution of the velocities calculated;

surveying a 300-m interval with 15 mbetween stations would require about5 h for each velocity measurement.Therefore, a distance between stationsof less than 15 m is usually avoidedbecause of the time constraints.Consequently, the final flow profile willusually have a vertical resolution of onlyabout 15 m using the PS Platform tool.

For making holdup measurements, four or eight probes are deployedcircumferentially in the wellbore. In highly deviated and horizontal wells,this distribution is not optimum for full holdup coverage and accuratedetermination of the fluid interfaces. Toolrotation can lead to a symmetrical probedistribution where two probes are at thesame level and therefore measuring thesame flow component (Fig. 19).


The futureEfficient integrated production logging improves

understanding of well behavior and reservoir

characterization under challenging conditions. The Flow

Scanner tool offers major improvements over conventional

production-logging technology. Although it uses

established principles of measurement, the miniaturization

of the spinners and the mounting of the sensors across the

diameter of the wellbore offer breakthroughs in the quality

of the data and their interpretation. The Flow Scanner

tool’s ability to measure the continuous velocity of three

phases and its relatively short length in comparison with a

conventional toolstring are added to the advantages of

this new technology.

No fluid contributions were observed from some features thathad been described as open or conductive fractures. The imagelog of the first entry interval showed only a few fractures, yet, itcontributed 42% of the water. Across the second entry interval,one fracture was evident; this interval was responsible for 58%of the water entering the well. Some of the imaged conductivefractures located above the water-entry interval were notassociated with the detected fluid entry, which suggested thatconductivity determination could be directly obtained fromdynamic data such as production logging.

Careful planningPrejob planning and integration of all the available well dataand logs to achieve the logging objectives and maximize thereservoir characterization information are essential for efficientlogging data acquisition. Recent successes have demonstratedthat, by using advanced tools and techniques, integratedproduction-logging acquisition, with either CT or tractorconveyance, can be designed to successfully achievechallenging production-logging objectives in open holes,including boreholes with highly deviated or horizontal sections.

Production logging can include the identification ofsuperpermeable zones or conductive fractures and the directassessment of their flow contributions; the description ofwater salinity variations to define injection water entries

20 Middle East & Asia Reservoir ReviewNumber 7, 2006

contribution from behind the tail wellbore. During downwardlogging, approximately 50% holdup was observedimmediately below the tail wellbore, as was expected at thisdeviation. The spinner at the top was reading much fasterflow rates than the middle spinner—clearly representing theoil and water velocities respectively.

After 120 m of logging, the holdup measurements showedthat the wellbore contained only water, which indicated thatthere was no oil entry beyond that point. Track 3 in Fig. 20shows the holdup distribution, and track 5 shows the oil andwater flow profiles. Two water entries were pinpointed nearthe toe section, where both spinners gave the same values inthe downward and upward passes.

The upper 150-m interval, in which all the oil entries werefound, was logged with another pass in 10 min using a cablevelocity of 18 m/min. The oil and water profiles obtained andthe cross sections are shown in tracks 4 and 5 of Fig. 20,together with the openhole results.

The cross section of the wellbore is shown in Fig. 21 withthe spinner locations and the holdup profile indicated. Thewell’s productivity index was excellent. Although tool designallowed no more than 10° rotation because of the holeconditions, rotations of up to 30° were observed over the 60-m interval where oil entry was indicated during thedownward pass.

Figure 21: Well cross section and sensor measurements in real time in Well 2.

along the wellbore; and the evaluation of productionpressure losses. The compact, integrated Flow Scanner toolprovides fast, efficient rig-up and rig-down; promotes saferoperations; and delivers real-time data analysis in support ofchallenging objectives.

Oil

Water

Oil

Water

Oil

Water

Moved hydrocarbon

Volumetric analysis0 1

Holdup Holdup

Shut-in Flowing

TVD TVD

Oil

Water

Flowing

Flow rate0 B/D

Anhydrite

Dolomite

Calcite

Well Sketch

FSI caliper3 8in

Figure 20: Results of new compact integrated productionlogging in Well 2.

Reference

Roscoe, B. and Lenn, C.: “Oil and Water Flow RateLogging in Horizontal Wells Using Chemical Markersand a Pulsed-Neutron Tool,” paper SPE 36230presented at the 7th Abu Dhabi InternationalPetroleum Exhibition and Conference, Abu Dhabi,UAE (October 13–16, 1996).

Holdup profile

0 1

X,328m20rps

Surface

Documents

A NEW ERA IN PRODUCTION LOGGING: DEFINING .../media/Files/resources/mearr/num7/...A NEW ERA IN PRODUCTION LOGGING: DEFINING DOWNHOLE FLOW PROFILES For decades, production and reservoir