in nonvertical wells regard-less of phase mixing or recirculation
� More accurate flow measure-ments than possible with con-ventional logging tools in highlydeviated and horizontal wells
� Three-phase flow rates com-puted in real time using dedi-cated algorithms
Features� All sensor measurements
simultaneous and at the same depth
� Combinable with PS Platform*and other cased hole loggingtools
� Short length for running inwells with high dogleg severity
� Direct, localized measure-ments of phase velocities andcalculation of a multiphasevelocity profile
� Full three-phase holdupanswer from the same depth
� Scanning sensors across thevertical axis for more accuratedetection of phase interfaces
� Measurement of mixed andsegregated flow regimes
� Independent measurement of gas velocity in multiphasehorizontal wells
� Detection of heavy phaserecirculation downhole
� Software optimization andreal-time display of data fromall 19 sensors
� Caliper and relative-bearingmeasurements for continuoussensor location
Multiphase fluid dynamicsIn vertical wells and wells with devi-ation less than 20°, oil and water aremixed across the entire wellbore, withoil, the lighter phase, increasing on theupper side of the well. The velocity pro-file is smooth, and the water holdupprofile varies gradually across the pipe.Averaged measurements across thewellbore are adequate to determine thevelocity and holdup with this type offlow structure.
Once deviation exceeds 20°, however,the center measurements of conven-tional production logging tools are usu-ally inadequate for multiphase flowprofiling.
For wells with deviation between 20°and 85°, some portions of the wellborehave monophasic flow, but the overallflow structure is complex. Water, theheaviest phase, segregates to the bottomof the pipe, and the mixing layer is onthe upper side of the hole with dispersedbubbles of oil.
Water is frequently recirculated at lowflow rates, and the water velocity on thelower side of the hole can be negative insome areas. At high flow rates, differen-tial acceleration of phases caused bythe shear forces between the differentfluids can lead to instabilities in theflow structure. This flow structure haslarge gradients in the velocity andholdup profiles.
Oil and water flows in wells withdeviations between 85° and 95° are pre-dominantly stratified. Water flows atthe bottom with oil on the top. Evenfor flow rates as high as 20,000 B/D in a5-in. [127-mm] liner, there is little mixing.At low flow rates, the flow has a strongdependence on well deviation.
When gas is also present, dependingon the well deviation, as many as sixmajor flow regimes can be encountered.For a constant flow rate, the holdupand velocity profile of each phase varywith the well deviation.
Biphasic experiments carried out in a controlled flow loop with equal flowrates for oil and water show the dra-matic effects of borehole deviation on flow behavior.
Top
Water Oil
1
0Bottom
Holdup
Velocity
Top Bottom
Velocity
Top Bottom Top
1
00
Bottom
Holdup
Water Oil
Velocity
Top Bottom Top
1
0Bottom
Holdup
Water Oil
Flow regime in near-horizontal well.
Flow regime in near-vertical well.
Flow regime in deviated well.
At 90° the velocities and holdups ofoil and water are nearly equal. Becauseoil is more viscous than water, it has aslightly lower velocity. The oil holdup isslightly higher than the water holdup.
As soon as the borehole deviatesslightly from 90°, the oil and water flowat different velocities. At high flow ratesthe dependence on borehole deviationis smaller because the increasing shearfrictional forces against the wall andinterface dominate.
At deviation lower than 90° (uphill),water, the heavier phase, slows down,and oil velocity increases. The waterholdup increases while the oil holdupdecreases. Any gas present would startto slug.
At well deviation above 90° (down-hill), flow is still predominantly strati-fied. The water flows much faster than
the oil because of its higher fluid density.The water holdup now decreases whilethe oil holdup increases.
Why conventional production logging tech-nology is inadequate in nonvertical wellsUsing production logging to accuratelydetermine the inflow of oil, gas, andwater phases is fundamental to devel-oping optimum production strategiesand designing remedial workovers. But in highly deviated wells conven-tional production logging tools deliverless-than-optimal results because theywere developed for vertical or near-vertical wells.
Downhole flow regimes in deviatedboreholes can be complex and caninclude stratification, misting, and recir-culation. Segregation, small changes inwell inclination, and the flow regime
influence the flow profile. Logging prob-lems typically occur when conventionaltools run in deviated wells encountertop-side bubbly flow, heavy phase recir-culation, or stratified layers traveling atdifferent speeds.
Flow loop studies have also revealedthe ineffectiveness of conventional log-ging tools in multiphase flows. Centermeasurements made by such tools areinadequate for describing complex flowbecause the most important informationis located along the vertical diameter ofthe wellbore. Conventional tools havesensors spread out over long distancesin the wellbore, making measurementof complex flow regimes even moredifficult.
Flow loop experiment with equal flow rates for oil and water.
89° 90° 91°
Deviation from vertical
6,000
1,500
600
Total flow rate
(B/D)
Oil
Relative speed
Water
Oil
Water
Oil
Water
The solution: Flow Scanner systemThe Flow Scanner* horizontal and deviated well production logging systemwas developed especially for highlydeviated and horizontal to near-horizontal wells.
On one side of the tool’s retract-able arm are four miniature spinnersdesigned to measure the well fluid-velocity profile. On the other side arearrays of five electrical and five opticalprobes for measuring localized waterand gas holdups, respectively. Addition-ally, a fifth miniature spinner and asixth pair of electrical and opticalprobes on the tool body measure flowproperties on the low side of the well.All sensor measurements are made atthe same depth simultaneously.
The Flow Scanner system is runeccentered, lying on the low side of thewell with its arm deployed across thevertical diameter of the wellbore. Thearm is extended to a length equal tothe diameter of the production tubu-lars, so it serves as a caliper, providingthe area measurements needed to calculate flow rates.
The tool has a small outside diameter(OD) of 111⁄16 in.[42.9 mm], and it can berun in holes ranging from 27⁄8 in. to 9 in.[73.0 to 228.6 mm] using coiled tubing,wireline, or the MaxTRAC* well tractorsystem. Its short 16-ft [4.9-m] lengthmakes it ideal for wells with high dog-leg severity. When an even shorter tool-string is desired, the 4-ft [1.2-m]hydraulic section used for scanningand closing the tool can be removed.The system operates in temperatures to 302°F [150°C] and at pressures to 15,000 psi [103,425 kPa].
The Flow Scanner system is com-binable with the PS Platform systemand other cased hole logging tools.
Multiphase velocity profilingBecause the Flow Scanner tool meas-ures the velocity profile along the verticaldiameter of the wellbore, it can meas-ure velocity variations that cannot bedetected using a single, centered spinner.It provides measurements of mixed andsegregated flow regimes, includingdirect independent measurement of gasvelocity in a multiphase horizontalwell. The Flow Scanner tool evendetects water recirculation downhole.
The Flow Scanner tool uses a maneuverable arm to deploy sensors along the vertical axis of nonverticalwells to obtain velocity and holdup measurements in mixed and segregated flow regimes.
A conventional spinner measures flow in the center of the wellbore, regardless of the flow profile,whereas the Flow Scanner spinners measure velocities at five different points across the vertical axis of the wellbore. The average velocity measurement of the conventional spinner would not accountfor the negative velocity measured here by the bottom spinner of the Flow Scanner tool.
Each of the five miniature spinnersmakes a direct, localized measurementof the velocity of the fluid passingthrough it, enabling calculation of amultiphase velocity profile.
Distinguishing hydrocarbons from waterThe Flow Scanner system detectswater by using six low-frequency probesthat measure fluid impedance. Becausewater conducts electric current, whereasoil and gas do not, a threshold is setthat allows the tool to distinguish oiland gas from water.
Each probe generates a binary signalwhen oil or gas bubbles in a water-continuous phase, or droplets of waterin a hydrocarbon-continuous phase,touch the probe’s tip. Water holdup isdetermined by the fraction of time aprobe’s tip is conducting, and the waterholdup profile accurately representsthe flow regime in the wellbore.
This methodology enables a localwater holdup measurement, independentof fluid properties, without any need forcalibrations. Conventional tools, on theother hand, require accurate calibrationin oil and water. Furthermore the bubblecount measurement—the log that rep-resents the number of nonconductingevents detected during a monitoringinterval—can be used to locate fluidentries. Conventional tools also lackthe accuracy to do this.
Distinguishing gas from liquidsConventional low-frequency probes can only distinguish water from hydro-carbons, but the Flow Scanner systemis also equipped with optical probes for gas detection.
Its six GHOST* Gas Holdup OpticalSensor Tools are sensitive to the fluidoptical refractive index. Typically gashas an index near 1, water near 1.35,and crude oil near 1.5. Because oil andwater have very similar fluid indices,the optical probes are used to distin-guish gas from liquid.
The gas bubble count can also beobtained from the raw data and used tolocate first gas entries. Optical probesallow a local gas holdup measurementwithout requiring calibration becausetheir signals are binary.
Together, the optical and electricalprobes deliver a full three-phase holdupanswer from the same depth interval.
Flow Scanner monitor boxFlow Scanner software optimizes anddisplays the data sent uphole from thespinners and probes. Two views areconstantly updated with real-timeacquisition data.
One view shows relative fluid veloci-ties measured by the spinner array, whilethe other shows phase distribution acrossthe pipe section. For both views, thepipe is sliced horizontally into the fivelayers associated with the differentcombinations of spinner, electrical-probe,and optical-probe measurements.
In the spinner view, five rectanglesare plotted with lengths proportional to the rotational velocities of the corre-sponding spinners. Each rectangle isdivided into color-coded sections withwidths proportional to the three phaseholdups seen by the electrical and opti-cal probes.
In the cross-sectional view, eachlayer is color coded to represent thephase with the highest holdup seen bythe probes. The holdup values of thetwo remaining phases are representedby proportionate numbers and sizes ofbubbles. The relative positions of thesensors are also shown, with circles forthe spinners and dots for the probes.
On the basis of the fluid optical refractive index, GHOST probes make a binary distinction between gasand liquids.
Surface
90° 88°
92° 45°
SurfaceSurface
Surface
Real-time flow rate and phase distribution data are continuously optimized and displayed on the Flow Scanner system monitor.
Case study: Gulf of SuezAging reservoirs in the Gulf of Suezproduce viscous oils at high water cutsthrough deviated to horizontal comple-tions. Conventional production loggingtools often have difficulty defining thecomplicated flow regimes and identify-ing areas for water shutoff to maximizeoil recovery as a field nears its eco-nomic limit.
One well with an inclination of 37° wasproducing with gas lift through six openintervals. Production was 2,058 B/D with97% water cut. When a conventionalproduction logging survey was unableto evaluate individual interval contribu-tions or identify sources of water pro-duction, the Flow Scanner tool wasdeployed on wireline.
The figure compares logs from theFlow Scanner and conventional pro-duction logging surveys. The FlowScanner flow profile shows that approx-imately 25% of the oil and 85% of thewater were being produced from perfo-rations below X400 ft. The remainder
of the water and some oil were producedfrom perforations at X390 ft. The twoperforations above X390 ft were produc-ing clean oil, and more than half of theoil was flowing into the top perforation.
Conventional production logging sen-sors could not detect oil entering the topperforations because the spinner wasaffected by water recirculation, and theresolution of the gradiomanometer wastoo low for it resolve oil contributions.The conventional survey erroneouslyattributed 90% of the oil production to the lower perforations.
On the basis of the Flow Scannerresults, a workover operation wasplanned to optimize the oil production.After cross-referencing the log resultswith geologic information on the loca-tion of a sealing layer of shale, theoperator set a plug at X400 ft to isolatethe majority of the high water-cut zones in the bottom of the well.
The resulting production of 556 BOPDand 2,532 BWPD represented an 800%increase in oil production, and paybackwas accomplished in less than a week.
Case study: North SeaThe Flow Scanner system was run in a North Sea well on coiled tubing. Thewell was producing 9,800 BOPD, with20% water cut and no gas, through a 41⁄2-in. [114-mm] liner. Maximum devia-tion over the 2,300-ft [700-m] interval is 93°.
In the flow profile shown in Track 1both oil and water were produced fromthe lowest perforations in the well, butthe major inflow of oil was at X680 m.Production increased significantlycloser to the heel of the well.
The holdup profile in Track 2 showsthe effect deviation has in horizontalwells. Holdup varies greatly when flowrates are low, and it lessens as flowrate increases, eventually reaching apoint at which deviation has almost noeffect. This proves the flow-loop testsare representative of actual conditionsdownhole.
40
Water Flow
Oil Flow
Water Flow
Oil Flow
Fullbore SpinnerVelocity
Conventional PL
Spinner Stationsrps ft/min0 3 –40 0.92 1.0
GradiomanometerFluid Density
Conventional PL
Flow Profile WellSketch
Depth,ft
Flow Profile
Conventional PL
X350
X400
Velocity
Velocity Image Water-Holdup Imageft/min0 40
Density Stationsg/cm30.9 1.2
Fluid Densityg/cm30.9 1.2
Flow Scanner Flow Scanner Flow Scanner
The Flow Scanner system identified and quantified zonal oil and water production in this well in the Gulf of Suez after conventionalproduction logging had failed. A workover operation led to an 800% increase in oil production.
Case study: Middle EastA client in the Middle East wanted totest the Flow Scanner system in a wellconsidered to be single phase. The 52°deviated well was producing 3,300 BOPD,with no water. The Flow Scanner sys-tem was run on wireline and recordedthe field log shown in the figure.
The relative bearing measurement(purple) in Track 1 shows that the toolkept its sensors deployed across the ver-tical axis with only slight movement andremained within 10° throughout the pass.
Track 2 shows the holdup of eachphase in the well. It clearly showswater to 100 ft below the surface.
Track 3 is a velocity image. Negativevelocity (recirculation) is shown in yellow, then orange, and red as itincreases; increasing positive velocity(production) is shown in blue, then green,and dark green. Oil is being producedin the middle and on the high side ofthe well, while water is recirculating on the low side of the well (left).Recirculation could be seen to 100 ftbelow the surface.
Tracks 4 and 5 represent the waterflow rate (negative) and the oil flowrate (positive) calculated using thedefault pitches for all five spinners.
Tracks 6 and 7 show the gamma ray, pressure, and temperature curvesrecorded with the PS Platform basicmeasurements sonde.
TrueVerticalDepth
(m)
FlowProfile
0
100
(m3/h )
MD1 : 4000
m X300X200X100X000
YZ40
YY60
X800X700X600X500X400Perforation
Oil
Oil
Water
Water
The Flow Scanner system demonstrated in this North Sea well that the effect of deviation on holdupdecreases as flow rates increase.
This Middle East well was producing 3,300 BOPD with 0% water cut. Holdup measurements show waterto 100 ft below the surface, and the velocity image shows that the water is recirculating.
