Light Fantastic In other articles in this issue of Middle East & Asia Reservoir Review, we can see that synergy between permanent monitoring sensors, advanced completion technologies, and remote connectivity is the key to real-time reservoir management. Ian Walker and George Brown of Sensa describe how novel fiber- optic sensors are at the heart of a renaissance in temperature logging that offers a reliable and cost- effective source of valuable well data. Conventional quick-look interpretation methods remain valid, while upgraded reservoir models can yield quantitative flow rates from the new distributed temperature measurements. Using these techniques, the value of temperature data far exceeds anything that could have been imagined in 1936 when well-logging pioneer Henri Doll first wrote on the subject.
Transcript
Light Fantastic
In other articles in this issue of Middle East & AsiaReservoir Review, we can see that synergy betweenpermanent monitoring sensors, advanced completiontechnologies, and remote connectivity is the key toreal-time reservoir management. Ian Walker andGeorge Brown of Sensa describe how novel fiber-optic sensors are at the heart of a renaissance intemperature logging that offers a reliable and cost-effective source of valuable well data. Conventionalquick-look interpretation methods remain valid, whileupgraded reservoir models can yield quantitative flow rates from the new distributed temperaturemeasurements. Using these techniques, the value of temperature data far exceeds anything that couldhave been imagined in 1936 when well-loggingpioneer Henri Doll first wrote on the subject.
Middle East & Asia Reservoir Review
Spatial resolution, temperatureaccuracy, and temperature resolutionare interrelated because, as withnuclear logging measurements, theDTS temperature measurement isstatistical. Extending the acquisitiontime or sampling longer sections offiber results in more-accuratetemperature measurements. To reducestatistical uncertainties further, thetemperature of several adjacentelements of fiber can be averaged.Acquisition times are typically about1 hr, but can be as little as 7 sec or aslong as a few hours. With suitableaveraging, the temperature at the endof a 16,000-ft long well can be resolvedto better than 0.1°C.
Measurements can be madecontinuously with fixed surfaceequipment or by mobilizing surfaceequipment to the wellhead tointerrogate a permanently installedsensor. Once computed, thetemperature data can be displayed on site, stored for later analysis, ortransmitted in real time using amodem or a supervisory control and data acquisition system link.
The simplicity of fiber-opticinstallations has many benefits, notleast the high reliability of a systemthat needs no electronics in the well.These installations can be expected tooutlive a well, but, even if the sensorneeds replacing, a new fiber can be run into the control line with no impacton production. Temperature surveysfrom total depth to wellhead can beperformed without intervention, loss of production, or risk to the well attemperatures up to 300°C.
With an increasing number of wellsbeing drilled with long, high-deviationor horizontal intervals, conventionalproduction logging can be difficult. In these wells, a DTS may providecontinuous information on inflowcharacteristics, gas breakout, artificiallift performance, and mechanicalintegrity. Sensa DTS installations areparticularly valuable in Schlumbergerreservoir monitoring and controlsolutions that combine downholesensors and flow control.
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occurred (see page 36, Time to
reflect). The resulting temperaturemeasurement is described as adistributed measurement because it is made at all points along the fiber.
This method of determining thetemperature along an optical fiberwas first demonstrated in 1985 and was commercially developed at the beginning of the 1990s at theOptoelectronics Research Centre atSouthampton University, UK. Thetechnique is the basis for the newsystems that are being deployed inthe oil field and many other industriesranging from civil engineering toaviation safety. The first commercialoilwell installation of a Sensa DTS wasin Canada in 1996 for monitoring asteam-assisted, gravity-drained well.More than 300 wells have beeninstrumented to date.
Illuminating the reservoirDTSs are relatively simple to install inan oil or gas well. Unlike conventionaldownhole gauges, they do not needcostly, special mandrels. Instead theoptical fiber, contained in a protectivemetal tube similar to that of aconventional control line, is run down the well and across the zone ofinterest. The completion geometry andsurvey objectives dictate the depth towhich the control line is run and, inparticular, whether it is run throughthe packer and across the reservoir(see page 48, Running light).
The fiber can be run either singleended, that is in a single strand fromsurface to downhole, or doubleended—running in a loop from thesurface, turning around at the bottomof the well and returning back tosurface. In either case, the fiber canbe preinstalled inside the control linebefore it is run or, more usually, it canbe inserted after the completion is inthe ground (Figure 3.2).
A laser in the surface equipment is used to introduce light pulses intothe fiber. The backscattered light isdirected to a signal conditioner andspectrum analyzer, and spectrarecorded over short time intervals areanalyzed to extract the temperature-dependent information for eachinterval of fiber from top to bottom.
Optical losses that occur in the fiber affect the measurement and
are described by a parameter called thedifferential loss constant (DLC). In asingle-ended system, compensation forthe optical losses that occur in the fiberis estimated by assuming a constantvalue for the DLC, an assumption thatis not necessarily valid. In a double-ended system, the laser is directedalternately into each end of the fiber.Measurements taken from either endare used to compensate accurately forthe differential losses along the fiber.This results in a more accuratemeasurement.
Figure 3.2: A single-ended DTS (left) requiresonly one packer port, but this convenience is atthe expense of measurement accuracy. Double-ended installations (right) offer easy installationor replacement and redundancy if the fiber isdamaged but require two packer ports.
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Space agencies know the value ofremote temperature monitoring.
Since the 1960s, doctors have beenable to observe astronauts’ bodytemperatures, while technicians havemonitored the temperatures ofspacecraft structures using built-insensors. Similarly, if well operatorsare able to monitor the temperaturealong the length of their oil or gaswells they can respond promptly tochanges. A downhole temperaturesensor with no moving parts and nodownhole electronics would deliverunprecedented reliability. And, if thesensor could be installed or replacedat will in a matter of hours andwithout affecting production it wouldbe very cost-effective.
Recent advances in fiber-optic sensortechnology mean that these featuresare now available in Sensa* distributedtemperature sensors (DTS). Thesesystems allow operators to correlateproduction changes immediately withchanges downhole and, under certainconditions, to quantify downhole flowrates. Because such systems arepermanently installed, every well
transient, planned or unplanned, canprovide data to improve understandingof the reservoir. And this monitoring ispossible in wells that are inaccessible toconventional production logging tools.When deployed with downhole flowcontrol valves, this new technologyoffers the real-time monitoring andcontrol that are increasingly beingdemanded by operators to helpmaximize production and recovery.
We may still be a long way fromhaving the astronauts’ advantages of health monitoring from afar, andwe cannot expect our vehicles to be examined as we drive. But oilcompanies can now monitor theconditions in their oil and gas wells in real time.
Shine a light During the past 35 years, the fiber-optic technologies that have beendeveloped for telecommunicationsapplications have enabled a massiveincrease in digital data traffic. Now,inexpensive optical fibers and relatedoptoelectronic devices are being
used for other applications such asinnovative environmental sensors. In some cases, these sensors offercapabilities that do not exist intraditional sensors. In other cases, they are more sensitive and outperformalternative technology, especially inunusual or harsh environments.
One type of temperature sensoranalyzes light that returns as a result of backscattering after a short pulse oflaser light is sent down an optical fiber.Backscattering of photons occurs at themolecular level all along the fiber, butphotons returning at any given timewill all have been backscattered at afixed distance along the fiber. Thisdistance is directly proportional to the time the pulse takes to return.Similarly, backscattered light that isobserved during a short interval of timehas come from a short length of thefiber (Figure 3.1).
Temperature-dependent changes in the light spectrum occur duringbackscattering. By analyzing thesechanges, it is possible to determinethe temperature of the fiber at thepoint where the backscattering
Return pulse
Optical fiber (b)
Spectrometer (d)
Laser (a)Outward pulse (e)
Directional coupler (c)
Figure 3.1: Distributed measurement of temperature in an optical fiber uses optical time domain reflectometry to measure the temperature at all pointsalong the fiber. A Sensa system comprises a pulsed laser (a), several kilometers of optical fiber (b), a directional coupler (c), and a spectrometer (d). Veryshort (10-nsec) pulses of light (e) are sent down the fiber. A few photons backscattered (f) by the molecules of the fiber return to enter the spectrometervia the directional coupler. Backscattered photons coming from the element of fiber at a distance between L and L+ΔL away from the laser are receivedbetween time 2 t and 2( t+Δt) (where L = tcf, ΔL= cfΔt, t is time, and cf is the velocity of light in the fiber). By analyzing the energy spectrum of photonsreceived in the time interval from t to t+Δt, the temperature of the element of fiber can be determined.
Figure 3.4: Attenuation of backscattered light by the fiber increases thestatistical errors inherent in the DTS measurement. By operating the laserlight source at a wavelength of 1.64 µm, the temperature-dependent anti-Stokes signals are produced at 1.53 µm (top). This coincides with the low-loss window for telecommunications-grade fiber, thus decreasing theattenuation at the anti-Stokes-shifted wavelength to around 0.06 dB/1000 ft,facilitating long-range measurements, and increasing the dynamic range of the measurement. However, the low-loss window is very narrow. A1.55-µm-wavelength laser produces an anti-Stokes signal at 1.45 µm withtypical losses as high as 0.3 dB/1000 ft (bottom).
Anti-Stokes bandattenuation
0.2 dB/m
Low-loss window
Wavelength (µm)
Wavelength (µm)
No.
of b
acks
catte
red
phot
ons
dete
cted
No.
of b
acks
catte
red
phot
ons
dete
cted
Anti-Stokes bandattenuation
0.3–1.0 dB/m
1.55 1.65
1.651.45
1.45
1.55
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Figure 3.5: The statistical nature of the interactions between photons and molecules gives rise to variations in the number of photons produced by eachpulse in the anti-Stokes and Stokes bands. Increasing the length of the measuring time interval (i.e., the length of fiber interrogated) or the number ofpulses (i.e., the acquisition time) reduces statistical variations.
Spectrometer
Total number of photons from all pulses
Incident wavelength
LaserPulse 3 Pulse 2 Pulse 1
Pulse 4Pulse 5
Anti-
Stok
es b
and
Stok
es b
and
1–n
1–nNumber Anti-Stokes-band photons
Number Stokes-band photons
Return signal
Calculation of the temperature of the optical fiber at any point isstraightforward once the effects ofattenuation and statistical variationhave been dealt with. Thetemperature is proportional to theratio of the total number of photonssummed in the anti-Stokes and Stokesbands. The constant of proportionalityis found for the Sensa system byacquiring the average ratio from a 50-m length of fiber held at a constanttemperature in a calibration loop atsurface. The measurement is,therefore, self-calibrating.
Time to reflect Intrinsic fiber-optic sensors, which usethe fiber itself as the sensing element,are well suited to measuring a singleparameter continuously along thelength of the fiber. A DTS employsoptical time domain reflectometry(OTDR)—a form of intrinsic sensingthat analyzes backscattered lightsampled in short time intervals. Thephysical processes involved in thistype of OTDR mean that the accuracyand the resolution of a DTS depend onthe length of the fiber, the acquisitiontime, the desired spatial resolution,and whether the measurement is madein a single- or double-ended system.
Density contrasts, compositionalvariations, and molecular and bulkvibrations in the fiber all causecharacteristic changes in thebackscattered light. Thermallyinfluenced molecular vibrations areresponsible for a particular type ofbackscattering—Raman scattering—that shifts the wavelength of thereturning light. Most photonsundergoing Raman scattering do soelastically, that is with no change inenergy. However, a few photons gain or lose energy to the molecules of the optical fiber (Figure 3.3). Somephotons excite the molecules fromtheir ground energy state and lose a
discrete amount of energy in the process. These photons arebackscattered with a longer wavelengththan the incident photons and are saidto fall in the Stokes energy band.
However, at any time, a smallnumber of molecules will already be in an excited state. This populationincreases with temperature. Photonsbackscattered from excited moleculesgain a discrete amount of energy asthe molecules revert to their groundenergy state. This puts them into ahigher energy band, the anti-Stokesband. Although the number of theseshorter wavelength photons is low, itdepends on the number of excitedmolecules encountered by incidentphotons. Therefore, it has a strongrelationship to the fiber’s temperature.
Raman scattering is the result ofrandom encounters between photonsand molecules, which are governed bythe laws of probability. In any sample of backscattered photons there will be some statistical variation in thedistribution of photons in the anti-Stokes and Stokes bands. This reducesas the size of the sample increases.Unfortunately, the number ofbackscattered photons is furtherreduced by attenuation before thephotons reach the end of the fiber forprocessing. This increases the statisticaluncertainty of the measurement.
Attenuation is a function of thewavelength of the light and can beminimized by carefully choosing a lasersource that results in an anti-Stokesband that coincides with the low-losswindow of the fiber (Figure 3.4). Thetypical attenuation achieved in oilfieldapplications is 0.06 dB/1000 ft(equivalent to reducing the signal to one-tenth of its initial size every 30 miles). The temperature of 3-ftintervals can be resolved in fibers as long as 37,000 ft, and DTSmeasurements are limited byattenuation to fibers of up to about100,000-ft long.
Statistical variations and signalattenuation mean that manyinteractions must be summed before the received population ofbackscattered photons reliably reflectsthe temperature of the fiber. To achievethis, a single measurement involvessending many pulses of laser light. Thenumber of photons returning in theanti-Stokes and Stokes bands for eachpulse is summed to reduce statisticalerrors, and the totals are used tocompute the temperature (Figure 3.5).The resulting data are averaged overthe acquisition time and the length offiber. The statistical variations may, inpractice, be further reduced at theexpense of spatial resolution byaveraging over several adjacent fibers.
A B C D E F G
Elastic Inelastic
Ground state
Anti-Stokes band
Stokes bandIncident energy
Ener
gy o
fba
cksc
atte
red
phot
on
Excited state
Ener
gy o
f mol
ecul
e
G
D
B
EF
CA
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Figure 3.3: The energy of molecules involved in Raman scattering is shown (top left). Most are initially in a ground vibrational energy state (A–F)before backscattering occurs. During elastic backscattering, molecules return all the incident energy of the photon, ending up at their original energylevel (A–C and E–F). However, a few (approximately 1 in 10 million) change their energy during inelastic backscattering. This can result in energybeing lost by the photon as the molecule is excited (D). In a very few cases, a photon will interact with a molecule that is already thermally excitedand gain energy as the molecule returns to the ground state (G).
the most water during injection willhave cooled to a much greater radialdistance from the wellbore and willwarm more slowly. The magnitude of the effect depends on the injectionrate, the interval permeability, theinjection time, and the thermalproperties of the fluid and the rock.
Sensa systems are particularly suitedto monitoring a slow warm back, whichmay take several days after evenrelatively short injection periods of aday or two. After extended injectionperiods, the warm back will becorrespondingly slow, as heat flowsfrom distant parts of the reservoir toraise the temperature at the wellbore.Indeed, the time needed to resolvepermeability contrasts in the reservoirfrom the warm-back temperatureprofile is a significant portion of theinjection time (Figure 3.6).
Occidental Petroleum in Oman uses line-drive water injection fromhorizontal wells in its Safah field toenhance recovery from the Shuaibareservoir. Wells in the field arecompleted with up to 5000 ft of openhole. Fiber-optic DTSs were installedin two horizontal injectors (Wells Aand B) and several horizontal oilproducers during 2002 (Wells C to F).One of the main objectives of the fiber-optic installation was to determinewhether or not long laterals wouldadequately flood the reservoir. Theoptical fibers were conveyed through31/2-in. tubing into the open hole on a 27/8-in. stinger equipped with anexternal double-ended control line.
Having a fiber in the well from thestart of injection meant that thewarm-back process could be observedafter a relatively short injectionperiod. The first well to benefit from aSensa system was the water injector,Well A. On January 1, 2002, after 39hr of injection at 4500 BWPD, Well Awas shut in and warm back observedover 24 hr. Figure 3.7 shows that theinterval 7000–8000 ft had very slowwarm back, which indicated that thiszone had been taking a relatively largevolume of the injection water. Warmback was quicker between 8,000 and10,000 ft, which showed that thisinterval had taken less injectionwater. Below 10,000 ft, cooling hadnot occurred, thus indicating that noinjection water flow beyond this point
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90–10080–9070-8060–7050–6040–50
2420
16 Hours since shut-in128
40
6,000
Temperature (°C)
8,000 10,000 12,000
Figure 3.7: Incomplete injection in Safah Well A was revealed by the warm-back technique. After39 hr of injection at 4500 BWPD, the well was shut in and the warm back was observed using thepermanently installed fiber-optic DTS. The well exhibited very slow warm back between 7000 and8000 ft over the 24 hr following shut-in. Below 10,000 ft, no cooling by the injection water wasevident, which indicated that there had been no flow into this region.
Figure 3.8: Detailed analysis of the data from the Safah Well A warm-back tests in January, March,and November 2002 was performed using thermal modeling software. The reservoir was divided intozones by permeability, and the total injected flow was allocated according to the permeability and thepressure drop between zones. The temperature profile during injection and the warm-back response to modeled injection rates were computed for several permeabilities until a satisfactory match to the warm back recorded by the Sensa system was achieved. Injection profiles consistent with theobserved warm-back response clearly show that the reservoir interval taking injection expands towardthe toe of the well over time.
in the formation (Figure 3.7). Two further shut-ins with warm
backs were performed in March 2002and November 2002. The dataindicated that, as time passed, waterwas being taken by the reservoirfurther along the open hole. ByNovember 2002, water was floodingalmost the entire horizontal interval(Figure 3.8).
The results confirmed that long
laterals were effective. However, thetemperature data could not indicatethe mechanism causing the interval to take increasing amounts of waterwith time. The data vindicatedOccidental’s decision to drill long,horizontal injectors, and showed that,with sufficient injection time, thewhole reservoir interval could beflooded. This was an important finding,as it is more economical to drill fewer
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Interpreting a new dimension
Since the early days of well logging,temperature profiles have helpedengineers understand downholeconditions and many applications for these logs have been found. For example, observing elevatedtemperatures in the wellbore was oncethe only way of detecting the presenceof setting cement behind casing.However, the humble temperaturemeasurement has often been pushedinto a secondary role by the advanceof technology. Cement can now bemapped in great detail using sonic and ultrasonic imaging tools.
Oil or gas inflows change thetemperature of the flow downstream of the entry point, and zones takingwater during injection are cooled.Temperature logs indicate these flowchanges, but, in the past, interpretationtechniques typically yielded no morethan a qualitative analysis of flowcontribution. Apart from beinginvaluable as an indicator of free gasentry (seen as a drop in temperaturethat is due to the cooling effect ofexpanding gas), temperature logs can confirm water injection profiles,crossflow between zones, and flowoutside the casing. In contrast, modern production-logging sensorsbring a detailed and quantitativeunderstanding of complex flows,including the analysis of three-phaseproduction—they can even countbubbles of oil and gas in the stream.
However, when productionanomalies need explaining, it may besome time before wireline production-logging equipment can be mobilized,which delays analysis and remedialwork. In high-angle or horizontalwells, production logging may requiredownhole tractors or coiled-tubingdeployment. In other wells, includingmany subsea completions, productionlogging may simply be impossible.Even though temperature is only oneof the many parameters that describefluid flow, a Sensa system can be ofgreat value in these cases.
Monitoring temperature profilesadds a new dimension to temperaturelogging. Continuously revealingchanges in temperature over timeoffers a much greater scope forinterpretation than a single snapshot
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recorded during conventionalproduction logging. The evolution oftemperature profiles reveals changesin production, and, by using moderncomputer modeling techniques, it ispossible to extract quantitative resultswith some accuracy and confidence.
A permanently installed DTS hasthe added attraction of instantlyrevealing changes in the downholeflow. It allows prompt action to betaken at any time throughout the lifeof the well by pinpointing anomaliesalong the wellbore, and enablesplanned or unplanned transients tobe analyzed with no additional data-acquisition costs.
Disturbing the equilibrium Wellbore temperature profilesrecorded using DTS measurements arevaluable not because the temperatureof the well itself is of direct interest,but because of what can be inferredabout the flow. One way of studyingflow is to observe the temperaturechanges that occur naturally as a resultof the physical processes involved in
production or injection. For example,temperature changes in formationscooled by injection water can bemonitored, or temperature anomaliesin flowing fluid can be tracked as theymove along the well.
Warming upThe water injected from surface intoreservoirs in order to supplementdrive is colder than the reservoir.During injection, heat from thereservoir flows into the wellbore andwarms the injection water slightly.However, injection rates are usuallyhigh enough for the near-wellboretemperatures to remain close to thetemperature of the injection water. In this case, DTS data will show coolinjection water in the wellbore as fardown as the lowest interval that istaking water, but will not differentiatebetween those zones that are takingwater and others that are not.
Once injection stops, the wellboreheats up by conduction from thedistant reservoir (warm back).Reservoir intervals that have taken
Figure 3.6: A computer model of the temperature in a wellbore following 10 days’ injection into alayered reservoir illustrates the value and limitations of the warm-back analysis technique. Duringinjection, the temperature of the wellbore (and sensor) remains close to that of the water injected atsurface (1). After injection stops, heat from deep in the formation warms the regions of the well andthe formation that were cooled by injection. Where no injection water has entered the formation(above 4400 ft), the relatively small volume of cool water in the wellbore heats up significantly in thefirst 24 hr (2). However, the larger volumes of injection water in the formation (4400 to 5000 ft) takemuch longer to warm back toward the geothermal gradient. After a day, there is a noticeabletemperature increase in the 10-mD layers but the 100-mD layer has taken up so much water that notemperature increase can be seen in this layer for several days (3).
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surface. Some distance above thepoint of entry, the temperaturedifference between the fluid and thegeothermal gradient will approach aconstant value. In other words, thetemperature profile is asymptotic to a line parallel to the geothermalgradient. The size of the temperaturedifference depends on the heatcarried by the fluid, itself a functionof the mass flow rate. Duringproduction, any change in the flowrate will shift the asymptote. Anyadditional producing zones will add fluid to the wellbore at thegeothermal temperature of the zone.If the geothermal gradient is known,the relative contribution from two ormore stacked flowing reservoirs canthus be estimated from the measuredtemperature profile (Figure 3.10).Crossflows within a well also havecharacteristic temperature profiles on temperature logs and can beinterpreted with similar techniques(Figure 3.11).
Lower flowTotal flow
Tt - Tg
TI - Tg=
100
Geothermal gradient
c Upper flow only
b Lower flow only
a
TtTg TlTemperature (°F)
50
Dept
h (ft
)
0
1000
2000
3000
4000
5000
Upper reservoir
Lower reservoir
d Total flow
Figure 3.10: Fluid produced into a well is at the local geothermal temperature (a). Fluid flowing up a vertical (or deviated) well in the presence of a temperature gradient will be warmer than thesurrounding formation and will lose heat to the formation. The temperature difference is a function ofmass flow rate, and formation and fluid properties. Very slow warming of the formation results;however, at any time, the temperature above a single, steady fluid entry tends toward a constantvalue above the prevailing temperature gradient (b). Similarly, production from a higher interval willbe at the local formation temperature and lower than the temperature of the stream from below (c).A decrease in the temperature of the commingled stream is a clear indication of an additional fluidentry (d). Assuming the fluid and formation properties are constant, the ratio of the flow rates can be computed from the DTS measurements of the geothermal temperature ( Tg) and temperature of thestream just above (Tt) and below (Tl) the point of entry.
Downwardcrossflow
Temperatureprofile
Lower reservoir
Upper reservoir
Temperature Temperature
a b
Figure 3.11: Temperature profiles can show crossflows during well shut-ins. A permanently installed system provides continuous measurements oftemperature and the chance to observe flow anomalies that may not be apparent from surface. For example, downward crossflows produce a localdecrease in temperature below the geothermal gradient (a), while upward crossflows locally warm the wellbore (b). The system responds to flow in or outside casing, so crossflow behind casing that is due to poor zone isolation or is outside a slotted liner can be identified.
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long wells than more short wells.Occidental benefited from monitoring
injection in its new well, but, inpractice, the long shut-in needed toobserve warm back in establishedinjectors may rule out the technique inmany cases. Occasionally, a long shut-inmay be required for operationalreasons. In these cases, a permanentlyinstalled system may allow warm backto be observed over a sufficiently longperiod for it to be interpreted.However, this is the exception, so anew technique was developed toovercome this limitation in the warm-back technique.
Hot spotsInjection rates can be measured bydeliberately creating a temperatureanomaly, a hot slug, in the injectionwater. The hot slug is created in the tubing by warm back during arelatively short shut-in period andis pumped down the reservoir wheninjection recommences. The positionof the slug can then be trackeddirectly from temperature data, andthe flow rate of the injected water canbe determined as it travels along thewell before entering the formation. Ininjectors, this approach is preferable
to the warm-back technique and isessential after long periods of injectionwhen the warm back is slow.
During the sequence of shut-ins andwarm backs in Safah Well A, it wasobserved that the water in the tubingand the casing immediately above thereservoir warmed quickly after shut-inbecause of heat conduction from thesurrounding formation. In early 2003,this effect was used to monitor theinjection velocity in the Safah Well Binjector. After shutting in to create aslug of hot water, injection was startedand the position of the slug wassuccessfully tracked using a Sensasystem (Figure 3.9).
The significant difference betweenwarm-back analysis and hot-slugtracking is that warm-back analysisrequires increasingly long warm-backperiods over the life of a well. Thehot-slug injection technique onlyrequires a short warm-back period toheat up the slug—irrespective of thelength of time of injection. When thecooled thermal front has extended farbeyond the wellbore—and warm-backanalysis is no longer possible—thistechnique offers a way of monitoringinjection profiles indefinitely.
Exploiting the gradient In producing wells, flow rates can be deduced from temperature data bytaking advantage of the fact that thegeothermal gradient means that flowfrom a higher zone is cooler than flowfrom greater depths. Produced fluidschange the temperature profile inwells that have a marked geothermalgradient along their length.
Tried-and-tested quick-lookmethods have been used for manyyears for interpreting temperaturechanges in production logs. Thesemethods are equally applicable to DTS measurements and can yieldquantitative flow rates in single-phase,low gas/oil ratio (GOR) producingwells or low-flow-rate gas wells.
The temperature in a well isgoverned by thermodynamic effectsthat include conduction of heat andtransport of heat by the fluids movingbetween regions at differenttemperatures.
Oil entering a wellbore at thegeothermal temperature will stay at a higher temperature than thesurrounding formation while losingheat by conduction to the coolerformation as it flows toward the
Figure 3.9: Warm-back analysis requiresincreasingly long warm-back periods over the life of an injection well. An alternativetechnique was used in Safah Well B. Waterimmediately above the reservoir where noinjection had occurred warmed back quicklyafter shut-in. Once this warm slug had formed(at time = 20:18), injection was restarted andthe DTS was used to monitor the slug’smovement along the openhole. The slug’svelocity at any depth in the well can becomputed from the distance traveled in agiven time interval, for example, from 20:54 to21:09 the slug travels 500 ft at 34 ft/min from8000 to 8500 ft.
Tem
pera
ture
(°C)
90008000
7000
40
60
80
100 Depth (ft)
Hot slug formsduring shut-in
20:1820:3920:5421:0921:33
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may be identified. But quick-looktechniques are unable to account for the complex thermodynamicprocesses of multiphase flows. Forexample, the liberation of gas notonly results in Joule–Thomsoncooling but also in changes in thedensity and specific heat capacity of the fluid. All this means that analternative method is needed to wringquantitative results out of DTS datain more complex situations.
Model solutionsReservoir engineers commonly usemathematical models for predictingproduction. With enhancements, thesame tools can be harnessed forinterpreting temperature data from aSensa system, but a detailed nodal-analysis thermal model is needed tomatch an observed temperature profile.
As with conventional reservoirmodeling, the objective is to constrainthe model using known reservoir dataand fluid properties, and then toperform multiple sensitivity runs whilevarying one or more unknownparameters, for example, zonal flowrate. The model must describe notonly pressures and mass flow rates,but also the temperature and the heatflows in and out of each element. Itmust also account for both geothermaland Joule–Thomson effects onproduced fluids as they flow throughthe reservoir and up the completion. Itis not necessary to know the completehistory of temperature and productionto run the simulator. However, astemperature is a slowly changingparameter, often taking several daysor weeks to stabilize after a significantflow change, it is useful to know howlong the well has been flowing sincethe last shut-in.
Thermal response can be modeledwith various commercial andproprietary applications. For example,PIPESIM* production system analysissoftware calculates the Joule–Thomsoneffect caused by flow through zones of varying permeability. However, this is a steady-state model that does notattempt to account for the transientthermal effects resulting from fluid flow.
Schlumberger has developed a suiteof software for thermal responseanalysis that includes a near-wellboretransient thermal model. This takes
Tem
pera
ture
(°C)
110
108
106
104
102
1006,000 7,000 8,000 9,000 10,000 11,000 12,000
Depth (ft)
b Geothermal gradient
a Before production
c 08/19/2002d 10/28/2002
Figure 3.13: The magnitude of Joule–Thomson cooling may be sufficient to reveal production in ahorizontal well. A Sensa system was installed in Safah Well C, a newly drilled horizontal well. Datarecorded in June 2002 before the well was put on production showed that the well had been cooledby drilling (a) and had not yet warmed back to the geothermal gradient (b). Production commenced inJuly, and by August, significant Joule–Thomson cooling was evident from the heel to 9000ft (c).Below this depth, the well had warmed up but not yet returned to the undisturbed geothermalgradient. By October, significant cooling was also occurring from 9,000 to 11,000ft, indicating that thewell was progressively cleaning up toward the toe (d).
On the level
In horizontal well sections there is often no temperature differencebetween zones that is due to thegeothermal gradient because thewell trajectory is at a constantdepth. In this situation, any flow-dependent thermal response isgenerated entirely by theJoule–Thomson effect as the fluidpressure changes along the well.
Heating or cooling of the producedfluid is a function of the drawdownpressure, which is often low inhorizontal completions. However, inlow-permeability reservoirs producinghigh GOR oil, the pressure drawdownin the near wellbore region may besufficient to generate measurableJoule–Thomson cooling in theformation.
Data from Safah Well C, a horizontalproducer completed in July 2002,illustrate how the cooling of high GORoil can indicate where flow is occurring.Qualitative analysis showed the wellcleaning up toward the toe with time(Figure 3.13). Comparison of thetemperature distribution with a thermalmodel enabled the relative contributionof the producing intervals to beestimated. In this case, Occidentallearned that production from below9000 ft doubled between August and
October 2002, despite a fall in the totalproduction. This was taken as evidencethat the well was cleaning up over time.Stimulation procedures were modifiedon subsequent wells to improve theclean-up rate further on the basis of theDTS data from Safah Well C.
In Safah Well D, the same approachwas used to show that the initialproduction was coming from the entireopenhole interval. This indicated thatthe application of a mud-enzymetreatment just before flowing the wellhad successfully broken down the mudfiltercake all along the well.
Safah well conditions wereconducive to DTS measurements.However, in low-flow-rate horizontalwells with large casing diameters, theJoule–Thomson effect is negligibleand is unlikely to be detected by sucha system.
Quick and easyWe have seen that a quick-lookinterpretation can be very useful.Flow profiles can be established withsome confidence. Flow contributionsand changes in flow rate can beestimated in vertical or deviatedproducers. Zones taking fluid andeven relative formation permeabilitiescan be found in injectors. And, inhorizontal wells, producing intervals
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Cool it
These quick-look techniques assumethat fluids enter the well at thegeothermal temperature and thengain or lose heat by conduction. Infact, fluids heat up or cool down astheir pressure changes, a processdescribed as the Joule–Thomsoneffect. The magnitude of the effectdepends on the reservoir pressuretemperature, and fluid properties.
The magnitude of the Joule–Thomson effect is large for gas, and in the near-wellbore region, where thepressure changes rapidly, significanttemperature drops occur where gas enters a well. Gas flowing at10 MMscf/D through a 100-ft zonewith a permeability of 10 mD willtypically drop 200 psi and cool by 5°C.Gas entries can be easily seen fromtemperature logs, and this applicationhas long been a standard example inproduction-log interpretation texts.Continuous monitoring with a DTSallows the source of a gas entry to bepinpointed at the earliest opportunity,for example, to determine the causeof an increase in gas productionobserved at surface.
Oil with a significant proportion of dissolved gas also exhibits Joule–Thomson cooling and can causetemperature drops of a few degrees inthe near-wellbore region. Conversely,low GOR oil actually warms upslightly when its pressure drops. A1°C temperature rise is typical for500 B/D of low GOR oil flowingthrough a 100-ft zone with apermeability of 1000 mD. This effect is often insignificant, but it must betaken into account to ensure thehighest possible accuracy incalculations of flow contributionbased on DTS data.
A DTS records the temperature allthe way to surface. This enables theJoule–Thomson cooling of gas passingthrough gas lift valves (GLV) to be usedto monitor the valve’s performance. In 2002, Occidental was able totroubleshoot GLVs in its Safah Well Dwith a DTS originally installed tomonitor production in the longopenhole interval. A faulty GLV wasreplaced promptly, and the correctfunctioning of the new device wasconfirmed (Figure 3.12).
Figure 3.12: Safah productionWell D was completed with GLVand a Sensa system. Coolingcaused by the pressure dropthrough the operating mandrelwas clearly seen (a). However, thisgas was entering at 3600 ft, higherthan intended because of a fault inthe GLV. DTS data enabled thefault to be identified immediately.Prompt replacement of the valverestored gas entry to the correctvalve at 6200 ft (b). Without a DTS,additional time would have beentaken pulling each of the mandrelsin order to identify the problemand solve it.
Tem
pera
ture
(°C)
100
80
60
400 2,000 4,000 6,000 8,000 10,000
Geothermal before flow
Well flowing
Depth (ft)
a GLV at 3600ft operating
b GLV at 6200ft operating
A Schlumberger Sensa crew prepares a DTS control line wet connect assembly in suitable weather.
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Figure 3.15: As the pressure in each zone of a reservoir changes with time so does its flowcontribution. This example shows DTS datafrom the well seen in Figure 3.10. The zone at1475 m was initially a major contributor, butafter eight months of production the thermalprofile showed that it had stoppedcontributing. On shut-in, the temperatureprofile did not return to the geothermalgradient, but showed flow from above andbelow entering the same zone. This confirmedthat the zone had a lower pressure andexplained why it had ceased to produce underflowing conditions. The thermal profile aftereight months’ production also indicated thatflow has ceased below 1600 m.
Figure 3.16: Horizontal wells are not influenced by the geothermal gradient. However, smalltemperature variations occur because of the Joule–Thomson effect. Shell Brunei completed Well SWA 293 with a double-ended optical fiber run within a dual 1⁄4-in. control line on a 23⁄8-in. preperforated stinger (top). Thermal simulation showed that inflow from the threesands would produce temperature changes that could be measured by a Sensa system andthen interpreted to allocate production (bottom).
Initial flow profile
Crossflow
GeothermalEight months’ productionShut-in after eight months
Temperature (°C)
50 52 54 56 58 60 62 64 66
X300
X400
X500
X600
Dept
h (m
)
observed data at two recorded flowrates. Oil production from 15 zones in the reservoir was clearly identified.With a temperature difference ofaround 5°C across the zone whileflowing, and a temperature resolution of approximately 0.1°C, changes ininflow of about 3% were resolved in the model (Figure 3.14).
The value of continuous real-timetemperature data was furtherdemonstrated by analysis of thetemperature profile as it developedover time. The initial data confirmedthat the well cleaned up afterproduction commenced. However, twozones changed their flow contributionover the first eight months. One of thezones ceased flowing. Its shut-intemperature profile showed crossflowsinto the depleted zone, thusconfirming that the zone had beendepleted to a lower pressure than thesurrounding intervals. The flow frombelow 1600 m also ceased in the sameperiod; this was attributed to sand fill(Figure 3.15).
In this application a Sensa systemprovided a low-cost solution withclear cost benefits shown for futurereservoir monitoring—smaller casingsizes can be run, as productionlogging will not be required and theneed for Y-tools can be eliminated.
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account of the reservoir and thecompletion hardware, performs anodal analysis to calculate theproduced fluid properties up thewellbore, and can calculate near-wellbore Joule–Thomson effects as afunction of reservoir properties suchas permeability, reservoir pressure,skin factor, drainage radius, and zonethickness. Temperature profiles at anytime can be computed from the initialgeothermal temperature and themodeled flow.
The applications also import the raw temperature data and perform the statistical averaging necessary toachieve the temperature and spatialresolution required for analysis beforecomparing the results with thethermal model developed by theanalyst. The software includes aniterative program that takes DTS dataand modifies chosen parameters in themodel to best fit the observed andmodeled temperature profiles.
It is worth noting that, while themodeled solutions for flow rate areunique, the computed value can resultfrom different combinations ofpermeability, reservoir pressure, skinfactor, or other parameters defined inthe model. Consequently, although it ispossible to achieve a good match to thetemperature data and to compute theflow rate, it is not possible to be certainthat all the reservoir parameters arecorrect. Indeed, it is likely thatdifferent combinations of reservoir
parameters will result in the same flowrate. To resolve any ambiguities, theanalyst selects values for the mostreliable reservoir parameters (forexample, permeability) and varies theleast understood parameter (forexample, reservoir pressure) to obtaina fit to the temperature data.
Sand-screen insightFlow rates derived from DTSmeasurements are less affected by theflow regime, or whether the flow is in-or outside the casing, than spinner logs.In highly deviated wells or wells withsand screens or slotted linercompletions, thermal modeling andDTS data offer practical alternatives to conventional flowmeter logs.
A Sensa system can be installed on a stinger run inside the screens.Alternatively, a control line can be run in two parts, one on the lowercompletion, which runs outside thesand screens and through the packer,and the other on the upper completion,which is run after gravel packing hasbeen completed. A wet mate assemblyaligns and connects the two sections of the control lines as the uppercompletion is stabbed into the packer,allowing the fiber to be pumped acrossthe sand screens. A DTS can also behung on a stinger from a Y-block tomonitor the temperature acrossscreens below an electric submersiblepump (see page 48, Running light).
Sensa recently installed a DTS forPhillips China Inc. in a deviated oilwell producing from a complexmultizone reservoir to continuouslymonitor the reservoir and, byimproving understanding of reservoirperformance and connectivity, help tooptimize the location of future wells.†
The well was drilled to 4652 ft(1418 m) true vertical depth from anoffshore platform, and the reservoirinterval was completed with anexpandable sand screen. The DTScontrol line was run across thereservoir on a 23/8-in. tubing stingerhung below the electrical submersiblepump. The installation reduced therisks associated with acquiringproduction and shut-in data byeliminating production-loggingintervention below the pump.
The well has been continuouslymonitored from the time ofcompletion. Initially the shut-ingeothermal gradient from the top tothe bottom of the sand screens wasabout 10°C. Major inflows wereclearly seen as temperature steps in the temperature profile thatcorrelated with the major sands.These qualitatively confirmed thatthe well had cleaned up afterproduction commenced.
A Schlumberger thermal model was used to quantify the inflow.Permeability values in the model were adjusted so that the resultingtemperature profile matched the
Figure 3.14: Inflow can be quantified fromchanges to the geothermal temperaturegradient. Temperature profiles were recordedat two flow rates in a deviated oil producerequipped with a Sensa system. At thisdeviation, a significant change in temperaturedue to the geothermal gradient was evidentacross the reservoir. A computer model wasdeveloped to predict production and thethermal response of the reservoir. Thepermeability was adjusted to match themodeled temperature to the DTS data at both flow rates. In this well, the resolutionenabled incremental inflow contributions assmall as 3% to be modeled.
†Sensa would like to thank Phillips China Inc.
for allowing the use of its data.
GeothermalInitial flow profile(flow rate 1)Initial flow profile(flow rate 2)Thermal model
DTS shut-ingeothermal gradient Modeled flow
contribution
DTS temperature
Temperature (°C)
50 52 54 56 58 60 62 64 66
X300
X400
X500
X600
Dept
h (m
)
Flow (%)
0 20 40 60 80 100
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permeability was known. Severalparameters could have been varied in an attempt to match the modeledthermal response with the observeddata. However, concerns about themud design and the effectiveness of the flowback led to the belief thatvariations in skin effect or drawdownalong the openhole were likely causesof the thermal response. The skineffect and drawdown were varied in multiple runs of the model until a satisfactory match was achieved.
Shell Brunei acknowledged thevalue of temperature data forunderstanding inflow performanceand concluded that only a portion ofthe open hole was producing and thatthe toe of the well was unlikely toproduce in the future.
Lighting the futureFiber-optic temperature monitoringinstallations are being rapidly adoptedin the oil field. They offer a reliableand cost-effective measurementsolution with the advantage thattemperature data respond to flowsboth in- and outside the casing.
Petroleum Development Oman(PDO) has been using Sensa systemslonger than most operators—it wasthe first company in the world toinstall a system in a horizontalinjector. Joe Straccia, PDO technologymanager, has noted that the mainadvantage of the system is that itworks in real time. Although PDO has been able to take temperaturereadings along the wellbore before, it was only possible by logging thewell. And that meant shutting off thewell, thereby forgoing valuable oilproduction. Real-time temperature
data will enable PDO to makeintelligent decisions for optimizingwell performance. The companyestimates that the informationprovided by a Sensa system couldenable the productivity of some wellsto be increased by 10 to 20%.
Like PDO, companies all across the Schlumberger Middle East andAsia GeoMarket are seeing thepotential of Sensa installations. Forthose with plans to use reservoirmonitoring and control solutions foradvanced completions, Schlumbergersystems have a particularly importantrole to play. These monitoringsystems are able to provide databelow the packer over the entireproducing interval.
From medical applications tomonitoring nuclear reactors and fromrobots to oil wells, fiber-optic sensorsare finding new applications. In the oil industry, the skills of temperature-logging pioneers like Henry Doll arebeing relearned and are bringing thebenefits of fiber-optic temperaturemonitoring systems to bear on themost contemporary of reservoiroptimization challenges.
Optical fiber ready for deployment.
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Statistical techniques were used toimprove the data quality. The initialstatic surveys were recorded overintervals of 11⁄2hr to improve theresolution of the temperature data.Statistical variations were reducedfurther, at the expense of spatialresolution, by averaging data fromseveral adjacent intervals.
The well was drilled and completedin late 2001 with 51⁄2-in. wire-wrappedscreens. Laboratory tests suggestedthat the producing drawdown wouldeasily result in the filtercake beinglifted off and flowed back throughthese screens. With rig activitiescompleted, the fiber was run intoplace, and a baseline temperaturesurvey acquired. The well was theninitially flowed at a low rate. Thetemperature profiles indicated thatthe well was flowing from an interval
Behind the screens in BruneiWhen Brunei Shell planned to developits Southwest Ampa field block 12, it expected that long (more than3000 ft) near-horizontal, openholecompletions would effectively drainall the penetrated reservoir sections.These wells would require downholesand control, as failure of the shallowsands was predicted because ofdepletion over the life of the wells.Installation of a fiber-optic DTS wouldallow engineers to infer the inflowproduction profile and verify thatdrainage was as expected.
Temperature logging offered thepossibility of monitoring inflow withinand behind the screens in the longsections without production-loggingintervention. If successful, thetemperature data would be used for future well design, location ofdrainage penetration, and calculationof the required length of thehorizontal sections. Confidence wasneeded in the reliability of the fiber-optic technology, as the restrictedinternal diameter of the completionwould limit future intervention withproduction-logging tools.
The first well to benefit from Sensatechnology was Southwest Ampa(SWA) 293—an early well in thedevelopment that targeted threemain sands. Initial production fromthe high porosity (25 to 29%)sandstone was expected to be35,000 ft3/D oil, with high GOR(560 scf/bbl) and no water from morethan 3000 ft of openhole section.
This DTS application wasparticularly challenging because WellSWA 293 was horizontal and thermalsimulations showed the temperaturedata were expected to fall within a2°C temperature range (Figure 3.16).However, this was expected to beadequate to show whether productionwas from the heel, the toe, ordistributed along the well and also tolocate gas or water breakthrough ifthey occurred.
Calculated inflow distribution tomatch the flowing temperature profile
Sidetrack cement
Flow
rate
(m3 /d
)
1500
1000
500
0
Temperature profiles
Figure 3.17: Well SWA 293 was a sidetrack from an existing well slot; however, the first hole waslost and plugged back with cement before a second successful sidetrack was drilled. Heat from thecuring cement plug had not dissipated when the initial static temperature profile was recorded, andthe location of the sidetrack was clear from an increase in temperature. After flowing for six months,the DTS thermal profile showed Joule–Thomson cooling of approximately 0.5°C, which indicated thatthe well was flowing from the heel section of the reservoir interval. The model for Well SWA 293showed that a skin value of 8 would produce the Joule–Thomson cooling observed in most of theproducing interval. However, this effect was insufficient to account for increased cooling at the heelof the well. An additional 12-bar drawdown at the heel was artificially introduced into the model bylocally increasing the reservoir pressure. Once a combination of skin effect and increased drawdownhad been identified as the likely cause of the observed thermal response, the model was used tooutput the flow-associated flow distribution.
below the casing shoe at the heel ofthe well but not all the way to the toeas expected. After six months ofsustained production at rates of35,000 ft3/D of oil, this flow profilewas unchanged (Figure 3.17).
Three months later, a multiratewell test was conducted thatindicated crossflow within the flowingsection. During the nine monthsduring which temperature data wereacquired, the well cooled throughJoule–Thomson cooling of the highGOR oil when its pressure dropped in the near-wellbore region.
A detailed thermal model of the well was constructed to helpunderstand the thermal response andthe observed effects of temperaturechanges. Oil properties, including theGOR, were available from surfacesampling, and the reservoir
Supply from pump (water)
Air
Direction of flow(water)
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Figure 3.20: The lower completion (a) is run inhole on a service tool. Double-ended control linesrun from the turnaround sub at the bottomoutside the screens, through the packer and up tomale control line wet-mate stems. After gravelpacking, the service tool is pulled out (b) and theupper part of the completion, with control linesto surface, is run into the well (c). The designensures that the control lines are aligned andsecurely mated as the seals stab into the packer(d).
stabs into the packer seal bore. Thecontrol line can then be pressuretested and flushed before the fiber is subsequently run into place.
In sand-screen completions, anoptical fiber can be run in- or outsidethe screens. A well that has alreadybeen gravel packed can have the fiberinstalled on a stinger run inside thescreens. This is a simple solution;however, production logging may notbe possible through the small-diametertubing of the stinger. Alternatively, thecompletion can be run in two partswith the control lines outside thescreens using a disconnect unit(Figure 3.20). The flexibility of theSensa system ensures that many othercompletion designs are possible(Figure 3.21).
Figure 3.21 Simple installations for monitoringtemperature above the packer, such as formonitoring gas lift valve performance (a),involve running the control line outside theconventional completion components. Tomonitor production from an extended-reachinterval (b) the control line can be conveyed ona stinger, a technique that can also be usedinside sand screens. Control lines can be hungfrom tubing on one side of a Y-block to monitoran interval produced or flooded by an electricsubmersible pump on the other side (c). Asimilar Y-block deployment on coiled tubing iscurrently being evaluated.
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Running light At only 0.01-in. diameter, the optical fibers used in oilwell DTSinstallations are fragile and must beprotected within a metal tube. This is usually a 1⁄4-in.-diameter stainlesssteel control line. In shallow, verticalwells, the fiber is strapped to theoutside of the completion tubulars.Where the system is more exposed todamage, for example, on the outsideof horizontal sand screens, speciallyengineered clamps protect thecontrol line. A modified wellhead andtubing hanger provide the pressurebarrier where the control lines exitthe well at surface (Figure 3.18). To convey optical fiber across thereservoir it is hung below a specialpacker on plain or preperforatedtubing. Ports in the packer allow oneor two system control lines to passthrough from top to bottom whilemaintaining pressure integrity.
Single-ended DTS installations use asingle fiber-optic strand across the zoneof interest, with one end connected tothe laser light source at surface. Incontrast, a double-ended Sensainstallation has a control line and afiber that start at surface, double back
in a turnaround sub at the bottom ofthe well and return to surface. Bothends of the fiber are then connected to the acquisition system.
Optical fiber can be preinstalledinside the control line before being run with the completion. Alternatively,a control line can be run empty and the fiber installed later using ahydraulic installation technique that isexclusively licensed to Schlumberger.The fiber is carried along the controlline in a stream of water pumped fromsurface (Figure 3.19). Deploymentstarts after the correct flow conditionshave been established, and the fibertypically travels at 100 ft/min. Afterfiber installation, hydrogen releasedfrom the water will cause the opticalproperties of the fiber to deteriorateover time through an effect known as hydrogen darkening, especially at elevated temperatures. Therefore,water in the control line is displacedby a protective fluid immediately afterinstallation to prevent damage.
Completions with a Sensa systemcan be run in more than one tripusing a Schlumberger on–offdisconnect unit. The lower part of thecompletion has double-ended controllines terminating in a connector
Figure 3.18: A Sensa system is shown during astack-up trial. The control line is seen emergingfrom the body of the wellhead just below thethreaded section.
Figure 3.19: During optical fiber installation, a T-piece is connected to the control line installed in the well (far right). Optical fiber is fed from a reelthrough a close-fitting, fine-bore tube connected to the side opposite to the control line, and water is pumped into the T-piece. Water flows through thecontrol line and returns to surface in a double-ended installation or out of the control line through a check valve in single-ended installation. The fiber iscarried along by fluid drag and can negotiate relatively tight corners, including the turnaround sub that loops the control line around the tubing.
assembly above the packer and is run in hole on a service tool. After thepacker has been set, the service toolis pulled out and the upper part of thecompletion is run with control lines tosurface. , The design ensures that thecontrol lines are aligned and securelymated when the connector assembly
