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Steve BamforthBP Exploration Operating Co. Ltd.Poole, England
Christian BessonKen StephensonColin WhittakerCambridge, England
George BrownBP Exploration Operating Co. Ltd.Sunbury on Thames, England
Grard CatalaGilles RouaultBernard ThronClamart, France
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;Jean-Rmy Olesen, Beijing, China; DeWayne Schnorr,Anchorage, Alaska, USA; Antonio Jorge Torre, TechnicalEditing Services, Houston, Texas, USA; and AmalVittachi, 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) andWFL (Water Flow Log) are marks of Schlumberger.
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.
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For decades, production logs have beenused in new wells to optimize ultimate
recovery 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 each
fluid in the pipecalled the holdupandits 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 density
tend 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 flowratesusually from 200 to 5000 B/D [30 to800 m3/d], depending on the tool used andthe pipe diameterthese 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 horizontal
wells 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 Flow
Fundamentals,page 61).Depending on the borehole deviation, the
velocity and holdup of the different phasescan change dramatically for any given flowrate. In these circumstances, traditional PLmeasurements may become unreliable.3
This 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.
, , , , ,
, , , , ,
, , , , ,
,
, , , , ,
Stagnant gas Failed external
casing p acker
Fault
Form ation
instab ility
O il layer
C utting s Fractures
W ater
G as
, , ,
, ,
, , ,
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 accumulate
on 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 Technology17 (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.
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When to Run Production Logs
Generally, 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 the
integrity of the completionfor 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 Bit
0 10
Openhole Sw
1993
100 p.u. 0
Openhole Porosity
50 p.u. 0
Openhole Porosity
50 p.u. 0
Downhole Flow Rate
0 B/D 10000
RST Oil
1996
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.
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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 tubing
leaks, 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 techniquessuch as thermal-neu-tron decay time or carbon-oxygen measure-mentsrun 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, was
producing 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 wells second highest perforatedzone, the RST monitor logs showed a signif-icant oil-water contact (OWC). The lowest
half 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 Indias 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 Review8, no. 3 (Autumn 1996): 4-17.
5. In dump-flood wells, water is produced from an
aquifer and injected into a producing formation in thesame well.
6. Albertin, I, Darling, H, Mahdavi, M, Plasek R, CedeoI, Hemingway J, Richter P, Markley M, Olesen J-R,Roscoe B and Zeng W: The Many Facets of PulsedNeutron Cased Hole Logging, Oilfield Review8,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.
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With the top set of perforationsZone 1the 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 channeling
behind the casing.Armed with this knowledge, the operator
had two choices for remediationsqueezethe 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 Logging
Once a well substantially deviates fromvertical and multiphase flow becomescomplex, spinner tools often indicate onlyreverse flowespecially 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 wells 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 (seepage 45).
Horizontal and many deviated wells areoften completed either open hole, withuncemented slotted liners or withprepacked screens.8 Such completions
introduce other special fluid-flow and pro-duction problems that usually are notencountered in vertical, cased wellssuchas flow restrictions due to the logging tool inthe pipe forcing fluids to channel throughthe liner-formation annulus. Furthermore, a
0 12 24 36 48 60
0
300
600
900
1200
C
ount
ra
te,cp
s
C
oun
tra
te,cps
1500
0 12 24 36 48 60
0
10
20
30
40
50
G R
AP I
M easured Fluid
Velocity ft/m in
1:200
0 60
0 125
X390
5
4
3
2
1
X380
X370
M easured Fluid
D ensity gm /cm 3
0 125
M easured
Tem perature
F
W FL
W ater Flow Rate
B W P D
243 245
R econstructed
Fluid Velocity
ft/m in
0 125
Reconstructed
Fluid D ensity
gm /cm 3
0 125
D ow nhole
Flow Rate
B/D
G as
O il
W ater
0.0 6000.0
0.0 6000.0
200
160
120
80
40
0
0 12 24 36 48 60
0 12 24 36 48 600
100
200
300
400
500
Tim e, sec
0 12 24 36 48 600
40
80
120
160
200
0 12 24 36 48 600
40
80
120
160
Tim e, sec
200 G R
Far
N ear
G R
Far
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).
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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 downward
and 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 Wells
Success 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 X050a very confusing picture.
The spinner measurement was presumedunreliable in this zone, as it had insufficient
resolution 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
, , , ,
, , , ,
, , , ,
, , , ,
, , , ,
W ater flow
G as flow
Backflow as drain-hole moves towardsvertical. In highlydeviated or horizon-tal wells and at lowfluid velocities,buoyancy forcestend to segregatefluids. The lighter
phase flows in theupper part of the
pipe draggingalong with it someof the heavier
phase. Sometimespart of the heavierphase moves down-wards due to grav-ity, causing a circu-lation within the
pipe. 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 85from 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.
C
oun
tra
te,cps
Flow Outside Pipe
Flow Inside Pipe
C
oun
tra
te,cps
400
320
240
160
80
012 24 36 48 60
2200
880
440
0
1760
1320
Tim e, sec
12 24 36 48 60
Tim e, 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-sectional
pipe 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)
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Several years ago, the WFL Water Flow Log tech-
nique was i ntroduced using the TDT-P ThermalDecay Time tool to provide water-velocity data,
first in vertical well s, then later in deviated and
horizontal wells.1 Today, the RST Rese rvoir 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 timeafter 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 wa ter cloud
will be a time-of-flight for the water flow in the
pipe, and is used to compute water velocity. The
half-li fe 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/mi n]. 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 me asure
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
Casing
Minitron
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.
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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 procureme nt and safety i ssues.
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 largethermal 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 a nd 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).
130
132
134
136
138
140
142
144
490ft/min
12 ft/min
Tim e, sec
B
ore
ho
le
sigm
a
indica
tor
300ft/min 200
ft/min100
ft/min50
ft/min
0 5 10 15 20 25 60 80 100 120
Raw Data
Filtered Data
Typical marker slug time-of-flight distributions for a variety of fluid-flow velocities.
500
A ctual w ater velocity, ft/m in
0
400
300
200
100
0100 200 300 400 500
PVL
m
easurem
en
ts,
ft/m
in
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
100
0
200
100
0
200
100
0
200
100
0
200
100
0
Ve
loc
ity,
ft/m
in
OilWater
2300 BOPD
3000 BOPD
3800 BOPD
D eviation, deg ree
85 87 89 91 93
750 BOPD
1500 BOPD
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 measured
for 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.
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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, from
below 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-mentseliminating 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 lowest
zone 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 a
small hydrocarbon entry in Zone 2, and alarge entry in Zone 3, as seen in the FloViewholdup map.
Well Sketch
15 in. -15
Downhole Flow Rate
0 B/D 4000
WFL Water Rate
0 B/D 4000
1
X025
2
WFL GR red
-25 ft/min 100
WFL Far blue
-25 ft/min 100
WFL Near green
-25 ft/min 100
Fluid Vel
-25 ft/min 100
Theor.Dens
6.6 1.10
gm/cm3
Theor. Temp
235 240
C
Theor. Pres
1010 1090
psi
Fluid density
0.6 1.10
gm/cm3
Temperature
235 240
C
Pressure
1010 1090
psi
Matrix
Cement
Production
Perforations
Shale
Water
Oil
Gas
WFL Water Rates
3
X050
4
X075
5
Flowoutside
Outsidevelocities
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 45angle of the tadpole tails show an upflow in the well.Downward flow would be indicated by tails pointing 45downward.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, October6-9, 1996.
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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 and
4, there was a reduction in average FloViewbubble velocity. The FloView imagesshowed a narrow band of hydrocarbon inthis section of the welllow 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 FloView
pass had a lower hydrocarbon velocity thanthe downgoing pass. This occurs becausehydrocarbon bubbles, carried by theupward flowing water, were moving alongwith the upward moving toola 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 operator
was 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/cm31.1
Temperature
218 F 223
0.5 v/v 1
FloViewHoldup
FloViewHoldup Map
Downhole Flow
Profile
0 10,000
B/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
0 150
API
X800
X1000
X900
1
2
3
4
Identifying fluid entry. The holdup map in Track 2 and the hydrocarbon velocity mapin Track 4, from an Alaskan well show the first hydrocarbon entry in Zone 3. The centerof 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
Prod uction , B/D
3
2
1
0 20001000 3000 400
Conventional PL Results
4
Prod uction, B /D
Zone
3
2
1
0 2000 400
PL Results with FloView
Gas
Oil
Water
Gas
Oil
Water
1000 3000
Zone
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.
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54 Oilfield Review
The 11116-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 tools 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 9 58-in.
casing. Each probe is sensitive to the local resis-
tivity of the fluid within the pipe and generates abinary 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, a nd 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 ea ch 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 mea surements 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
91908980
0.580.71
Flow rate
1500 B/D
Deviation
from 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.
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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 f requently 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 opposite
perforations. 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 s ignificantly.
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56 Oilfield Review
Horizontal Wells: The Flagship Project
During 1994, British Petroleum ExplorationOperating Co. Ltd. and Schlumberger Oil-field Services established a joint initiativeThe Flagship Projectto 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 wasdevelopedcombining 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 least
ten 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 marker
injector
Spinner
Total flow rate
Gamma raydetector
PVL Phase Velocity Log
Marker injection for oil
and/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.
W ater 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
A verage 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.
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58 Oilfield Review
The data acquisition capability of the toolstring allows most critical parameters to bedetermined by alternative independentmethodsfor example, C/O and imagingholdup data, or WFL and PVL velocity datasupported by spinner measurementsinstilling greater confidence in the results.
The new tool string clearly identified allthe water entry points in the well, confirmedthat the downhole flow was stratified, and
proved 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. The
logs showed that water was being drawn upthrough the fault from the OWC.In the third wella dry-oil producerthe
PVL 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 TogetherInterpretation
Traditional PL interpretation for verticalwells primarily uses density from the gra-diomanometer to compute oil and water
holdup, 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 in
deviated 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 productionparameterssuch as fluid velocities fromspinners, WFL and PVL logging runs, as wellas holdup measurements from imaging toolsand RST logsenable delivery of optimized
solutions 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
S
olver
Flow Model
Tool Model
7800
7600
7700
Spin - rpm
CableSpeed
Bot. Top Slope Intercept
7750 7700 .21 .027800 7750 .22 .03
7800
7600
7700
Flow Veloc ity Temp
Inputs
Data Editing
Depth Matching
Log Inputs Well and FluidCharacteristics
7600
7700
7800
C alibrations
R econstruction
D ep th M atching
R ep ort and W ell 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 Choquette
and 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.
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A new fluid dynamics-based interpretation model
called the Stratflo model has been developed tocompute 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, a nd 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 Palong 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 i nto two parts: the shear stress on the
wall for oil Towand 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 dynami c
parameters such as flow rates and holdup, as
well as static parameters, such as flowing diam-
eter D, deviation angle, , fluid densities o and
w, and viscosities, o and w. For example, interms 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 m odel, readily-measured parameters
such as local holdup and velocity measurements
may be used for two of the necessary input
dynamic parameters. With the mass conservationequations, 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 ma ss-conservation e quations using a root-
finding technique.
The flow m odel 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
Tow
Tww
Vo
Vw
Ti
P in water = P in oil
Pressure DropWall friction (Tw)Interfacial friction (Ti)
Gravity (,devi)P
P
ho
w
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 ), h, and the wall, Tw, and interfacial, Ti,friction components for each of the two fluids.
1.0
W
ater
ho
ldup
D eviation, deg
87
0.8
0.6
0.4
0.2
088 89 90 91 92
Flow model
Flow model
Flow=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
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The Outlook
The ongoing development effort in under-standing three-phase flow is deliveringresultsincluding detailed gas holdup andvelocity measurementsthat are reshapingPL services. However, there is still an impor-tant flow domain not adequately covered bytodays technologyenvironments wherethere is low water holdup and significantdrainhole deviation. Work is under way at
SCR 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 servicessome 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 temperature
and pressuresuch 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 the
process repeats farther up the pipe. Such fluid simulations help scientists test fluid-flow
models under many conditions and design better methods to measure their properties.
Technology Forum
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The Production Logging Web-Forum
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15. Baker A, Gaskell J, Jeffery J, Thomas A, Veneruso T,and Unneland T: Permanent MonitoringLookingat Lifetime Reservoir Dynamics, Oilfield Review7,no. 4 (Winter 1995): 32-46.
60 Oilfield Review