GB2397648A

GB2397648A - Fibre optic flow sensing in deviated wellbores and pipelines

Info

Publication number: GB2397648A
Application number: GB0328443A
Authority: GB
Inventors: Glynn R Williams; George Albert Brown; Arthur Hartog; Kevin J Forbes; Christian Koeniger
Original assignee: Sensor Highway Ltd
Current assignee: Sensor Highway Ltd
Priority date: 2002-12-17
Filing date: 2003-12-09
Publication date: 2004-07-28
Anticipated expiration: 2023-12-09
Also published as: GB0328443D0; US20060065393A1; US7240730B2; GB2397648B; US20040112596A1; US6997256B2

Abstract

A wellbore 12 comprising a deviated section 18 is provided with at least one distributed fibre optic temperature sensor 38. The fibre optic temperature sensor 38 measures the temperature profile along at least two levels of a vertical axis 90 of the deviated section 18 using optical time domain reflectometry (OTDR). The temperature profiles at different positions along the vertical axis 90 are analysed to determine the cross-sectional distribution of fluids, the velocity and the flow rate of each fluid in the deviated section 18. Measurements may also be made to determine the flow rate of fluids in a subsea pipeline.

Description

I]SE OF FIBER OPT1(N IN DEVIATED FLOWS B ACK(:iROI JND The present

invention generally relates to the use of fiber optics in wellbores. More particularly, this invention relates to the use ol fiber optics in deviated wells, including horizontal wells. The present invention may also be used h1 conjunction with pipelines, such as but not limited to subsea pipelines.

Flow of fluids into and along a deviated well is highly dynamic and is difficult to analyze. Among other flow regirnes7 fluid BoNN along a deviated well can be stratified, wherein different fluids stratify based on their density and flow along the well within their stratum.

Typically, fluids stratify so that hydrocarbon gas is located on top, hydrocarbon liquid underneath the hydrocarbon gas, and water, if ally, below the hydrocarbon liquid. Another flow regime that may be present in a deviated well is ''slug flow," wherein slugs of gas and liquid alternately flow along the well.

In any case, not only is the identity of the fluids (hydrocarbon gas, hydrocarbon liquid, water, or a mixture thereof) along the length and vertical axis of the deviated well difficult to determine, but the location of any hydrocarbon gas / hydrocarbon liquid / water interface(s) (if such is present) is also difficult to establish. 'I'his information would be useful to an operator in order to understand the content and fluid contributions of the relevant formation and wellbore.

With such information, an operator could diagnose inflow characteristics and non-conformances, with a view to optimizing production conditions or planning interventions for remediations.

Similarly, many pipelines, such as subsea pipelines, also include stratified flow. In these pipelines. it would also be useful to identify the fluids flowing therethrougl1 and the presence and location of any stratification.

I bus, there exists a continuing need for an arrangement and/or technique that addresses one or more of the problems that are stated above.

SUMMARY

A system to determine the mixture of fluids in the deviated section of a wellbore comprising at least one distributed temperature sensor adapted to measure the temperature profile along at least two levels of a vertical axis of the deviated section. Each distributed temperature sensor can be a fiber optic line functionally connected to a light source that may utilize optical time domain reflectometry to measure the temperature profile along the length of the fiber line.

l he temperature profiles at different positions along the vertical axis of the deviated wellbore enables the determination of the cross-sectional distribution ol fluids flowing along the deviated section. Together with the fluid velocity of each of the fluids Solving along the deviated section, the cross-sectional fluid distribution enables the calculation of the flow rates of each of the tivids. 1 he system may also be used in conjunction with a pipeline, such as a subsea pipeline, to determine the flow rates of fluids flowing therethrough.

BRIEF DESCRIPTION OF THE DRAWING

1 ig. 1 is a schematic of one embodiment of the system that is the subject of the present invention disposed in a deviated wellbore.

Fig. 2 is a schcnatic of one embodiment for the attachment of a conduit with fiber line therein to a conveyance device.

Fig. 3 is a schcnatic of another embodiment of the system, wherein the distributed temperature sensor is \>rapled in a coil around a conveyance device.

Fig. 4 is a schcuatic of another embodiment of the system, in which a plurality of fiber lines are disposed bet\\ con the top area and the bottom area of the deviated section ol'a wellbore.

Fig. 5 is a schematic of the system deployed on a coiled tubing.

Fig. 6 is a scllenatic of another embodiment of the system, wherein the system includes at least one low resolution section and at least one high resolution section.

Fig. 7 is a schematic of a high resolution section of Figure 6.

Fig. 8 is a schematic of a heating tool being deployed within a conveyance device with the distributed temperature sensor wrapped in a coil around the conveyance device.

Fig. 9 is a schematic of a deviated wellbore with a hold up.

Fig. 10 is a schematic ot'a deviated wellbore including an undulation with a hold up.

] 5 Fig. ] I is a sclcmatic of a subsea pipeline including the system.

DETAILED DESCRIPTION

1 igure I i]lrstrates the system 10 of the present invention. A wellbore 12, which may be cased, extends front talc surl'acc]4 and may include a vertical section 16 and a deviated section 18. Deviated section 18 is angled from the vertical section]6 and can extend in the horizontal direction. "Deviated section" shall mean a wel] bore section having any angular deviation from a completely vertical section. Wel]bore] 2 normally intersects at least one formation 20 containing hydrocarbon fluids.

A tubing 22, which may be production tubing or coiled tubing among others, may be disposed within the wellbore 12. In one embodiment, the tubing 22 extends into the deviated section 18 past the heel 24 of the wel lbore 12 arid proximate the toe 26 of the wellbore 12. As shown in Figure 6, tubing 22 may also include a stinger assembly 76 that extends past the bottom hole packer 79 into the deviated section I X. (generally fluids flow from talc Correlation 20 into the annulus 28 of the wellbore 12, into the tubing 22 (or stinger assembly 7(, ), and to the surface 14 of the wellbore 12 through the tubing 22. In some embodiments all artificial lift device, such as a pump, may be used to aid fluid flow to the surface 14. I he fluids are then transmitted via a pipeline 30 to a remote location. The fluids may be separated Irom each other (hydrocarbon gas / hydrocarbon liquid / water) within the wellbore or at the surface by use of separator devices, as known in the prior art.

As previously described, fluids flowing from the formation 20 may comprise hydrocarbon liquids, hydrocarbon gases water. or a combination thereof. It is beneficial and useful to identify the fluids (whether they are hydrocarbon liquids, hydrocarbon gases, water, or a combination thereof) flowing from formation 20 and along the deviated section 18. In deviated sections 18 of wellbores 12, the mixture of fluids tends to be very dynamic and may stratify, wherein the fluids differ at least beta een the kelp area 32 and the bottom area 34 of the deviated section 18. For instance, in the case where no \vater is present, the mixture of fluids proximate the top area 32 tends to be mostly by drocarbon gas, if not all hydrocarbon gas, and the mixture of fluids proximate the bottom area 34 fends to be hydrocarbon liquid, if not all hydrocarbon liquid.

If water is present in the formation and is flowing into the deviated section 18, the water typically stratifies below the hydrocar bore liquid adding yet another layer. It is beneficial to know the type of mixture along the \!crtical axis 90 of the deviated section 18 and when and \vher c the fluid strata form because, among other things. this information allows the calculation ol'tlc flow rate o-l' each fluid along the pipe.

In order to determine the hydrocarbon gas, hydrocarbon liquid, and water flow rates in the deviated section 18 of a welihore, one must first determine la] the cros.sectional distribution of to dil't'erent fluids and [b] the velocity of each of the fluids. When the flow regime is slug florid as previously described, instead of determining the velocity of each of tile fluids, one can use the average of the fluid velocity in the core of the slug flow. This invention provides a tecliniquc to determine the cross-sectional distribution ol' the different fluid strata.

System 10 enables the determination of the cros.+sectional distribution of the different fluids flowing along the vertical axis 90 of the deviated section 18, including at the bottom area 34 and the top area 32. In one embodiment, system 10 comprises at least one distributed temlcrature sensor 36 that measures the temperature profile along at least two levels ofthe vertical axis 90 of the deviated section 18. In one embodiment, two distributed temperature sensors 36 are deployed, one proximate the top area 32 ol' the deviated section 18 and another proximate the bottom area 34 of the deviated section 18. Each distributed temperature sensor 36 may comprise a fiber optic line 38 that is adapted to sense temperature along its length.

In one embodiment, fiber optic line 38 is part of an optical time domain reflectometry (O'i'L)R) system 40 whicl1 also includes a surface system 42 with a light source and a computer or logic device. OTDR systems are known in the prior art, such as those described in U.S. Pat. Nos. 4,823,166 and 5,592, 282 issued to Hartog, both of which are incorporated herein by rcl'crence. In OTDR, a pulse of optical energy is launched into an optical fiber and the baclscattered optical energy returning from the fiber is observed as a function of time, which is proportional to distance along the fiber from which the l ackscattered light is received. This s backscattered light includes the Rayleigh, Brillouin, and Raman spectrums. The Raman spectrum is the moist temperature sensitive with the intensity of the spectrum varying with temperature, although 13rillouin scattering and in certain cases llayleigl1 scattering arc temperature sensitive.

Generally, in one embodiment, pulses of light at a fixed wavelength are transmitted from the light source ilk surt'ace equipment 42 down the fiber optic line 38. At every measurement point in the Idle A. Ii,ht is back-scattered and returns to the surface equipment 32. Knowing the speed of light and the moment of arrival of the return signal enables its point. of origin along the fiber line 38 to be determined. 'I'emperature stimulates the energy levels of molecules of the silica and of other index-modiiying additives - such as germania - present h1 the fiber line 38.

The back-scattered light contains upshifted and downshifted wavebands (such as the Stokes Raman and Anti-Stoles Raman portions of the backscattered spectrum) which can be analyzed to determine the temperature at origin. In this way the temperature of each ol' tile responding measurement points h1 the fiber line 38 can be calculated by the equipment 42, providing a complete temperature profile along the length of the fiber line 38.

Thus, the tempcraturc profile along the length of each of the fiber optic lines 38 can be known. As will be discussed, by using different embodiments of system 10, the temperature profile along man! levels of the vertical axis 90 of the deviated section 18 can also be known.

Knowing the teml!crature profile along the vertical axis 90 of the deviated section 18, the cross sectional distribution ol'the fluids flowing therethrough can be determined not only in the vertical direction 1 om the top area to the bottom area but also along the length oi'thc deviated section 1 8.

One can identify the fluids from the temperature profiles because the hydrocarbon gases and the hydrocarbon liquids normally have different temperatures within the same wellbore.

Theretorc, a difference h1 temperature along the vertical axis 90 typica]] y signifies the presence of dificrent fluids. For instance, gas is typically cooler than the hydrocarbon liquids (and any water), since it cools as it enters the \vellhore (the.lou]e-Thompson effect). The presence of water may also be identified in some instances, when the water entering the wellbore is at a different temperature than the hydrocarbon liquids. Knowing these norma] temperature differences between fluids and the typical stratification of fluids as previously disclosed (hydrocarbon gas / hydrocarbon liquid / water) allows the identification of fluids in any cross section oi the deviated section 18.

For deployment within wellbore 12, each fiber line 38 is disposed on a conveyance device 467 which can be permanently or temporarily deployed in wellbore 12. Conveyance device 46 may comprise, among others, production tubing 22, as shown in Figure 1, coiled tubing 50, as shown in Figure 5, or even a stager assembly 76, as shown in Figure 6.

In one embodiment, one fiber idle 38 is located proximate the top area 32 and another fiber line 38 is located proximate the bottom area 34. In order to ensure that one fiber dine 38 is at least located proxhllate the top area 32 and that one fiber line 38 is at least located proximate the bottom area 34, system 10 may h1 one embodiment include an orienting device 62 that may be attached to conveyance device 46. In one embodiment, orienting device 62 orients system 10 so that the fiber line 38 h1 the top area 32 is approximately at the topmost position and the fiber dine 38 in the bottom area 34 is approximately at the bottommost position (in this embodiment' the fiber lines 38 are 180 degrees apart). Orienting device 62 may comprise, among others, a gyro tool or a mechanical orienting mechanism such as a muleshoe. In general, orienting device (2 may comprise a unilaterally / azimutllally weighted conveyance device 46 with at least one swivel that provides gravitational alignment and orientation.

In one embodiment, each fiber line 38 is disposed in a conduit 44, such as a tube.

AItllougla the material, construction and size of conduit 44 may vary depending on the application, an exemplary conduit 44 is a stainless steel tube. I he exemplary tube has a diameter less than approximately one half inch and often is approximately one-quarter inch. Conduit 44 nay be attached to conveyance device 46. As shown in Figure 2, each conduit 44 (for instance at top area 32 and bottom area 34) can be attached to conveyance device 46 (in this case production tubing 22) by way ol clamps 48 or other mechanical attachments, as kncrvvn in the

prior art.

In one embodiment as shown in Figure 1, one fiber line 38 is arranged to measure the temperature profile of both the top and bottom areas 32, 34. In this embodiment, the fiber line 38 has a U-shape as does the relevant conduit 44. Thus, this ITshaped fiber optic line 38 (and conduit 44) includes a leg that extends away from the surface 14 and a leg that extends towards the surface 14.

T he fiber line 38 may be deployed within conduit 44 by being pumped through conduit 44, before or after conduit 44 is deployed in wellbore 12. This technique is described in United States Reissue Patent 37,283. Essentially, the fiber optic line 38 is dragged along the conduit 44 by the injection of a fluid at the surface. The fluid and induced injection pressure work to drag the fiber optic line 38 along the conduit 44. This pumphlg technique may be used in configurations where the conduit 44 and the fiber line 38 have a I)-shape, as previously clisc.ssed, or in configurations where the conduit 44 and the fiber line 38 terminate in the wellbore This fluid drag pumping technique may also be used to remove a fiber line 38 from a conduit 44 (such as if Char line 38 fails) and then to replace it with a new, properly-functioning fiber line 38.

Figure 3 illustrates an embodiTlleTlt of system 10 whereh1 a fiber line 3X (and relevant conduit 44) is arranged in a coil 52 around conveyance device 46 (production t..'bing 22) in the deviated section l 8 ol'\cllhore 12. Since conduit 44 iT1 this embodiment wraps around tlr conveyance device 4(. tile use of coil 52 enables the determination of temperature profiles at dit'i-'erent levels agog the vertical axis 90 tlereoJ', including the top and bottom areas 32, 34.

Thus, coil 52 can also be used to deterTniTle the cross-sectional distribution of fluids along the vertical axis 90 o-l'llic deviated section 18, as previously disclosed. Coi] 52 may also be used in tile embodiTlleTlt its which fiber optic lisle 38 and conduit 44 have a Ushape. Multiple coils 52 may also be placed alone, the deviated section 18 so as to provide the relevant measurement at more than one location of the deviated section l 8.

IT1 another embodiment, a plurality of fiber lines 38 (and conduits 44) may be disposed around the circumi'crence of conveyance device 46. Figure 4 illustrates a system 10 having a fiber line 38A closer to the top of top area 32 and a fiber line 38B closer to the bottom of bottom area 34. In addition, this system 10 includes fiber lines 38C located at various levels between top fiber line 38A and bottom fiber line 38B. The use of these additional lines 38 provides temperature measurc'ents at different levels between the top and bohom areas 32, 34, which allows the determination ol'tile cross-sectional fluid distribution in the deviated section 18.

For instance, in l:i,=ure 4, line 53 represents the hydrocarbon gas / hydrocarbon liquid interface, wherein the hydrocarbon liquid is located below the line 53 and the hydrocarbon gas is located above the I jT1C 53. Similarly, assuming water is present, line 54 represents the hydrocarbon liquid / water interface, wherein the hydrocarbon liquid is located above the line 54 and the water is located below the line 54. In this case, the fiber lines 38 located above line 53 (fiber lines 38A, C, D) and the fiber lines.8 located between line 53 and line 54 (fiber lines 38 (,, H) will measure dil7'erent tempcratrrcs. If water is present and it is at a temperature dif'l'erent than the hydrocarbon liquids, the fiber Ihies 3X located below line 54 (fiber lines B. E7 F) will also measure dif't'erent temperatures. An operator would thus be able to determine that hydrocarbon gas is present above Ihic 53, hydrocarbon liquid is present between lines 53 and 54, and water is present below line 54. A change he the location of lines 53 or 54 will become known by a change in the temperature reading of the relevant fiber lines 38. It is noted that in the embodiment where water is not present only line 53 would be identifiable. It is also noted that use ofthe coil 52 of Figure 3 also enables the determination ol'the interface locations since it includes measurements at different levels between the top and bottom areas 32, 34. The determination of the interfaces and the movement of the interfaces in time provides valuable information to an operator regarding tle formation 20 and its production, as previously disclosed.

Figure 4 also illustrates tile use of extensions 56 attached to and extending from conveyance device 46. Conduits 44 and fiber lines 38 are disposed at the distal ends of extensions 56 so as to be proximate the wellbore wall 58. The use of extensions 56 enables tle use of a larger range along the vertical axis 90 between the top area 32 and the bottom area 34.

This h1 turn provides a more accurate measurement of the fluid as it flows from the formation 2() into the wellbore 12 and also provides a larger range for the determination of the interface locations. The use of extensions 56 also functions to centralize the conveyance device 46 within the wellbore 12.

1 igure 5 illustrates the use of a coiled tubing 50 as conveyance device 46. In this cmbodinent, conduit 44 (and fiber line 38) is located within coiled tubing 50 until it reaches bottom hole assembly 60, wherein the conduit 44 emerges Groin the interior of the coiled tubing 5(). 'lilac conduit 44 is attached and located on the exterior of lotlom hole assembly 60.

l ig,ure 6 illustrates another embodiment of the system I (). In this embodiments the system l () comprises at least one low resolution section 70 arid at least one high resolution section 72. In each high resolution section 72, the fiber optic lilac 38 is configured so that it traverses the length of higl1 resolution section 72 at least twice. One possible configuration of fiber optic line 38, as shown in l igure 7, is for it to be looped 71 axially on the exterior of high resolution section 72 a number of times and in one embodiment around the circumference of the section 72 Tile object is for the fiber optic line 38 (corresponding to high resolution section72) to be co,f'igured so that it can provide temperature prof les at different points along the vertical axis 90. Thus, a configuration, such as coil 52, is also an alternative. In a preferred embodiment, fiber optic line 38 exits high resolution section72 so that it call pass through another high rcsoluti'n section 72 or through a low resolution section 70.

In one embodiment, each low resolution section '70 includes a fiber optic line 38 proximate the top area 32 and a fiber optic line 38 proximate Tic bottom area 34 and is thus similar to the system described in relation to Figure 1. In another embodiment (not shown), each low resolution section 70 includes only one fiber optic Ihie 3X: thus, in this embodiment, an operator would not be concerned with measuring the temperature profile along different levels of the vertical axis of the low resolution section 70.

Multiple high resolution sections 72 can be located along the length of a tubing 22 and stinger assembly 76. High resolution sections 72 may he interspersed among low resolution sections 70 and ma! he positioned so that they are located at particular locations along the deviated sections I 8 (sue h as across formations or along bends) once the tubing 22 and stinger assembly 76 is del:'loyed within the wellbore 12. In the embodiment h1 which fiber optic line 38 is u-shaped, the boltom ol stinger assembly 76 also includes a turn-around.suh 78 (as in Figure] ) to provide the <,verall l}-shape to the fiber optic line 38 and relevant conduit 44.

In one cmh<>climent,1ligl1 resolution sections 72 and low resolution sections 70 are modular SO that an! SCCtiOr17(), 72 can be attached to ally other section 70 72 thereby allowing the greatest 11CN;b;I Sty in deployment. In one embodiment, each high resolution section 72 includes a conduit 44 to house fiber optic line 38 (as previously disclosed) as well as a retune line conduit 84. Thc cc]duit 44 within higl1 resolution section 72 (and therefore the fiber optic line 38) is configured as previously described, and includes one entry 80 and one exit 82 (at either end of the section 72). In one embodiment, each low resolution section 70 includes two conduits 44, one housing the liter optic line 38 extending away from surface 14 and the other housing the fiber optic line 38 extending to the surface 14.

In another embodiment, neither the high resolution section 72 nor the low resolution section 70 include Hi return line conduit 84 so that only one fiber optic line 38 is used.

In the close when two low resolution sections 70 are attached to each other, each of the conduits 44 of fine section 70 is attached to its counterpart in the corresponding section 70. To tile case when two Leigh resolution sections 72 are attached to each other, the exit 82 of one section 72 is attached to the entry 80 of the other section 72, and the return line conduits 84 of the two sections 72 are attached to each other. In the case when a low resolution section 70 is attached to a hi,l1 resolution section 72, one conduit 44 of the low resolution section 70 is attached to either talc entry 80 or exit 82 (as the case may be) of the conduit 44 of the high resolution section 72 and the other conduit 44 of the low resolution section 70 is attached to the return line conduit 84 ofthc high rcsohtion conduit 72.

As previously described, in order to determine the hydrocarbon gas, hydrocarbon liquid, and water flow rates hi the deviated section I X of a wellbore, one must first determine [a] the cross-sectio1al distribution of the discreet fluids and [b] the velocity of each of the fluids.

When the flow regime is slug flow as previously described, instead of determining the velocity of each of the fluids, one can use the average of the fluid velocity in the core of the slug flow.

As discussed' this invention provides a technique to determine the crosssectional distribution of the different Muid.

Several techniques may be used to determine the velocity of each of the fluids in a deviated section 18 of a wellbore. I:or instance, flow sensors, as known in the art, may be deployed to provide the velocity of cock ol the fluids. In another embodiment, if the flow regime is slug flow., the fiber optic lines 38 and their derived temperature profiles may be used to track tile gas and liquid slugs as they move along the wellbore. Thus, in this embodiment, the fiber optic dines 38 would also enable the calculation of the average of the fluid velocity in the core of the slug flow. In another embodiment, the fiber optic lines 38 may be used to track naturally occurring thermal events/spots (either cool slots or hot spots) as they occur and travel along the wellbore thereby enabling the calculation ol the velocity of the fluid in which such thermal spots travel. In yet another embodiment thermal events may be artificially introduced into the wellbore (such as by injecting nitrogen gas or steam), which thermal events are then tracked as they travel along the wellbore.

Thus by knowing the cross-sectional distribution of the different fluid and the fluid velocity of each of the Buids, the flow rates of each ol the fluids can be determined by an operator.

In another embodiment, instead of using orienting device 62 as shown in Figure 1, a di llc rent orienting mctl1od may be used to ensure that the operator knows the orientation of each iiLcr line 38 or each section of the fiber lines 38. In this embodh1lent as shown in Figure 8, a heating tool 100 including an orienter 102 (such as a gyro) and at least one heating element 104 may be introduced into the conveyance device 46. The heath1g tool 10() is configured so that the oi ienter 102 orients the heating element 104 to be on a specific position/orientation within the co'1vcyance device 46. For instance, the heating tool 100 may be configured so that the orienter 1()2 or ients the heating element 104 to be on the top-most or bottom- most position/orientation \ithh the conveyance device 46. Once properly oriented, the heating element 104 is activated allowing the operator to identify which fiber optic line 38 or which sections of the fiber optic line 38 (socially in the case of coil 52 or high resolution section 72) are adjacent the heating element 1()4 acid are thus in the same or approximately the same orientation/position as the heating element 104. The heating tool 100 orienting method is S]lOWn in Figure 8 used with coil 52, however, it may also be used with the embodiments including low and high resolution sections 7(), 7 and multiple conduits 44 at different positions along the vertical axis 90 or deviated wellbore 18.

2() System 10 may also be used to identify the location and extent of"hold up" in a deviated \sell 18. Figures 9 and 10 show different types of hold up. Figure 9 shows a typical wellbore 12 with deviated section 18 wherein fluid having a higher density is "held up" within the deviated section 18 at line 1 10 and an operator is attempting to produce fluid having a lower density. The ]4 higher density "hold up'. prevents or inhibits the production ofthe lower density fluid because the lower densit! fluid struggles to flow tlrougl1 and past the higher density ' hold up." Similarly, I;igure 1(') sows a deviated section 18 including an undulation 1 12. Hold up, such as shown at line I 1(), can occur across the undulation 112, preventing or inhibiting the flow of lower density fluid tlroc.gl1 or past the held up higher density fluid. By disc ol"the techniques previously disclosed. the system 1 () within such a wellbore enables the determination of the location and extents ol'tle hold up and line 1 10. In either cases the "held up" higher density fluid may be water and tilde lower density fluid may be liquid hydrocarbons or gas. Or, the "held up" higher density fl.id may be liquid hydrocarbons and the lower density fluid may be gas. In one embodiment, only one fiber line 38 and conduit 44 is necessary to determine the location and extent of hold up.

System 10 ma) also be used in conjunction with pipelines, particularly those that extend in a non-vertical di-eclion (such as but not limited to the horizontal direction). Although it can; be used with any pipeline,system 10 is shown in Figure] 1 being used in con junction with a subsea pipeline 15(). Siubsea pipeline 150 carries the fluids produced from wellbore 12. Each embodiment previousiv described in relation to wellbore 12 (including the coil 52, high I resolution section 72. sing or double conduit 44, multiple fiber optic line 38A, and hold up measurement) may lee used with subsca pipeline 150 in order to identify the temperature profile at different Icvels along the vertical axis 152 of the subsea pipeline 150. For use with pipelines, tile relevant fiber lines 38 and/or conduits 44 may be placed inside or outside the relevant pipeline 150 or they may be built into the pipeline cladding or structure. As previously described, the tcnpcrat:'re profiles enable the determination of the cross-sectional distribution of 1 the different fluids flowing in the pipeline 150 and the fluid velocity of each of the fluids. With this information, the flow rates ol'each ol'the fluids can be determined by an operator.

The inclusion ol'a distributed tcml:'crature sensor 36 such as the described fiber optic]hlC 38 will also enable an operator to determine changes in state of the wellbore. For instance, the distributed temperature sensor 36 may be used to measure and locate the inflow of fluids into the wellbore, if the inflow fluids are at a temperature dit'f'erent than the fluids already in the wellhore.

Thus, an operator may be able to tell at what points fluids are flowing into the wellbore. ''I'he distributed temperature sensor 36 may also be used to determine the existence of any flow behind the casing by measuring temperature differences caused by Ellis flow. The distributed temperature sensor 36 may also be used to identify the presence and location of leaks from the tubing or casing also based on measured temperature difference.

The system 10 may also he used to identify the location around the circumference of the wellbore of' any thermal event, such as inflows, leaks, or temperature differences of the fluids; flowing in the wellbore. Once the azinthal location of each distributed temperature sensor:6 is known (such as by the gyro or heating element methods described above), an operator will he able to determine the azimuthal location within the wellbore of any thermal event by determhling I which distributed temperature sensor 36 is closest and is most reactive to the thermal event. Tile azimuthal temperature measurement also helps to determine the stratification of fluids, as previously discussed all the way to tile surt'ace through any deviated or vertical sections. With the OTDR measurement which enables the location of the depth of the thermal event, a total picture ofthe thermal events within a wellbore may be obtained by an operator. This information would be useful to an operator in order to visualize the fluids as they progress up the wellbore. These measurement can he performed using one or more distributed temperature sensors 36 (fiecr optic lines 38) as per the embodiments previously disclosed.

While the invention has been discksed with respect to a limited number of embodiments those skilled h1 the art, having the benefit of this disclosure will appreciate numerous modifications and variations therefrom. For instance, the conduits 44 and fiber lines 38 may be located in the interior of the conveyance device 46 (synch as tubing 22, coiled tubing 50, and stinger assembly 76). Moreover, the conduits 44 and fiber lines 38 may pass to and from the interior and exterior oLconveyance devices 46 by use of crcss-over tools at specific locations, such as proximate bolkm hole packer 79. In addition although the drawings have shown the use I () of a system 10 h1 a substantially horizontal well, it is r.ndcrstood the system 10 can be used in a deviated section, as that term is defined herein, or even in Hi vertical well. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of the invention. ; 17 1

Claims

What is claimed is: 1. A mctilocl for determining the cross-sectional distribution of fluids along a deviated wellbore, comprising: measuring a temperature profile along at least two levels of a vertical axis of a deviated section of a wellbore using at least one fiber optic line; and comparing the temperature profiles to determine whether different fitids are present in each o1 the levels. ]O

2. The metilod of claim 1, wherein the measuring step comprises measuring a temperature profile proximate a top area oI the deviated section using a first fiber optic line and measuring a temperature profile proximate a bottom area of the deviated section using a second fiber optic I ine.

3. T he method ol claim 2, further comprising measuring at least one temperature profile intermediate the top area and the bottom area by using at least one additional fiber optic line and wherein the comparing, step comprises comparing each of the temperature profiles to determine whether different- fluids are present along a vertical axis of the deviated section.

4. The method of claim 1, wherein each of the measuring steps comprises launching a pulse of optical energy into the at least one I il or optic line and measuring at least one temperature sensitive spectrum of the backscattcrcl light from the at least one fiber optic line.

5. The method ol' claim 2, wherein the at least one fiber optic line has a U-shape and extends Tom a surt'ace towards the deviated section and at least partially back towards the surface.

6. The method of claim], further comprising coiling at least a portion of the at least one ] 0 fiber optic Ihle around a conveyance device used for deployment into the wellbore.

7. Tile method of claim 1, t;rther comprising providing at least one conduit to house the at least one fiber optic line.

8. The method of claim 77 furtller comprising pumping the at least one fiber optic line into the at least one conduit by use of fluid drag.

9. The method ol'claim 7, further comprising attaching the at least one conduit to a conveyance device used for deployment.

10. Tlle method of claim 27 further comprising: deploying the first and second fiber optic lines on a conveyance devices and orienting the conveyance device so that the first fiher optic line is proximate the top area and the second fiber optic line is proximate the bottom area.

1 1. The method oi claim I, further comprising: deploying a heating element along the at least our fiber optic line; and identifying the orientation of the at least one fiber optic line by activating the heating element.

12. The method oEclaim 1, further comprising deploying the at least one fiber optic line on a conveyance devices wherein the conveyance device is one of a production tubing or a coiled tubhlg.

13. The method of claim 1, further comprising deternhling the presence of hold up based on the comparing step.

IS

14. A method for detennining the flow rate of a fluid flowing along a deviated wellbore, comprising: determining the cross-sectional distribution ol fluids flowing along a deviated wellbore by measuring the temperature profile at different positions along a vertical axis of the deviated wellbore; and determining the Quid velocity of each fluid flowing along a deviated wellbore.

15. The metilQd of claim 14 wherein the temperature profiles are measured by use of at least one fiber optic lisle.

16. The method of claim 14, wherein the temperature profile is measured by launching a pulse of optical cncrt,7y into the at least one fiber optic line and measuring at least one temperature sensitive spectrum of the backscattered light from the fiber optic lines.

17. The mctlod oi claim 14, wherein the determining the cross-sectional distribution step comprises comparing the temperature profiles *om the different positions to determine whether different fluids are present in each ofthe positions.

18. The netilod ol claim 147 wherein the determining the fluid velocity step comprises deploying at Icast one flow sensor in the wellbore to measure the fluid velocity.

19. The method of claim 14, wherein the determining the fluid velocity step comprises tracking at least one thermal event flowing in at least one fluid by use of the temperature profiles.

20. The method of claim 19, wherein the thermal event is artificially induced.

21. Tile method ol claim 2O7 wherein the thermal event is naturallyoccurring.

22. A system for determining the cross-sectional distribution of fluids along a deviated welihore, comprising at least one fUcr optic line adapted to measure a temperature prosaic along at least two levels ova vertical axis ova deviated section ot'a wellbore.

23. The system of claim 22, comprise: a first fiber optic line proximate a top area of a deviated section of a wellbore adapted to measure a temperature profile; and a second fiber optic line proximate a bottom area of a deviated section of a wellbore adapted to measure a temperature profile.

24. The system of clahn 23. further comprising at least one additional fiber optic line intermediate the top area and the bottom area and adapted to measure a temperature profile.

25. The system of claim 22, wherein the temperature profile is derived by launching a pulse ] 5 of optical energy into the at least ogle fiber optic line and measuring at least one temperature sensitive spectrum of the backscattered light from the at least one fiber optic line.

26. The system of claim 22, wherein the at least one fiber optic line has a U-shape and extends from a surface towards the deviated section and at least partially back towards the surface.

27. the system of claim 22, wherein at least a portion of the at least one fiber optic line is coiled around a conveyance device used for deployment into the wellbore.

28. The system of claim 22, further comprising at least one conduit housing the least one liLcr optic line.

29. The system ol claim 28, wherein the at least one conduit is attached to a conveyance device used for deployment into the wellbore.

30. The system of claim 29, farther comprising: a plurality of additional fiber optic lines intermediate the top area and the bottom area and 1 () adapted to measure a temperature profile; and each of the additional fiber optic lines being housed in at least one conduit ahached to the conveyance device.

31 The system of claim 29, wherein the at least one conduit is proximate a wellbore wall widen deployed within the wellbore.

32. l he system of claim 227 wherein the at least one fiber optic line is pumped by fluid drag through the at least one conduit.

2(:) 33. The system of claim 23, further comprising: a conveyance device connected to the first and second fiber optic lines; and an orienting device adapted to orient the fiber optic lines so that the first fiber optic line is proximate the top area and the second fiber optic line is proximate the bottom area.

34. The system of clahn 22, further comprising: a conveyance device associated with the at least one fiber optic line; the conveyance device including at least. one high resolution section; and the tat least OnL high resolution section including the at least one fiber optic line in a configurations tidal provides a temperature profile in the at least two levels of the vertical axis.

35. The system ol claim 34, wherein the at least one fiber optic line is coiled around the conveyance device.

36. The systc' o-l claim 34, wherein the at least one fiber optic lisle is axially looped at least twice along the length of the at least one high resolution section.

37. I he systcin ol claim 36, wherein the axial loops extend around the circumference of the conveyance device.

38. The system ol claim 34, further comprising at least one low resolution section including the at least one i iber optic line in a configuration that provides a lesser number of temperature profiles thank the at least one high resolution section.

39. The system ol claim 38, wherein the at least one low resolution section and the at least one higl1 resolution section are modular.

40. The system of claim 38 wherein the at least one low resolution section and the at least one high resolution section can lee removably attached to a low resolution section ore high resolution section.

41. Tlic system of claim 22. t;rtler comprising a heating element adapted to be deployed into flee deviated section wherein talc activation of the heating element enables the identification of the orientation oftilc at least one fiber optic line.

42. The system of claim 22. farther comprising a conveyance device connected to the at least ]0 one fiber optic line.

43. The system of claim 42. wherein the conveyance device comprises one of a production tubing or a coiled tubing.

44. The system of claim 22. wherein the at least one fiber optic line is deployed across a hold up in the deviated section.

45. A method for identifying the presence of a hold up in a deviated section of a welll:>orc, comprising: measuring a temperature profile along a deviated section of a wellbore using at least one fiber optic line; and analyzing the temperature profile to determine whether hold up is present in the deviated section.

4. The method of claim 45, wherein: the measuring step comprises measuring a tcmperaure profile along at least two levels of a vertical axis of tile deviated section; and the analyzing step comprises analyzing the temperature profiles to determine whether hold up is present in the deviated section.

47. l he method of claim 45, further comprising deters ining the location of the hold up by analyzing the temperature profile.

48. A method for determining the cross-sectional distribution of fluids along a pipeline, comprising: measuring a temperature profile along at least two levels of a vertical axis of a pipeline using at least one fiber optic line; and compar-irig the temperature profiles to determine sA nether different fluids are present in cacl1 of the levels.

4'). I he method of claim 48, wherein the measuring, slop comprises measuring a temperature profile proximate a top area of the pipeline using a first loller optic line and measuring a temperature profile proximate a bottom area of the pipeline using a second fiber optic line.

5(). The method of claim 49, further comprising measuring at least one temperature profile intermediate the top area and the bottom area by using at least one additional fiber optic line and wherein else comparing step comprises comparing each of the temperature profiles to determine whether dif'ferct fluids are present along a vertical axis of the de\ iated section.

51. 'I lie method of claim 48, further comprising coiling at least a portions of the at least one fiber optic lisle w ithin the pipeline.

52. 'me reflood of claw 48, i'urtiler comprising providing at Icast one conduit to house the at least one fiber optic line.

53. 'I'le method of claim 48, further comprising placing the pipeline in the subsea environment.

54. system for determining the eross-seetional distribution ol'tiuids along a pipeline, comprising at least one fiber optic line adapted to measure a temperature pr <file along at least two levels of'a vertical axis of a pipeline.

55. Tle system of claim 54, comprising: a I first fiber optic line proximate a top area of the pipeline adapted to measure a temperature profile; and a second fiber optic line proximate a bottom area of the pipeline adapted to measure a temperature profile.

56. The system ol claim 55 fcrthcr comprising at least one additional fiber optic line intermediate the top area and 11le bottom area and adapted to measure a temperature profile.

57. Tile system of claim 54 wherein at least a portion of the at least one fiber optic l ine is coiled within the pipeline.

58. The system of claim 54 l;rtlcr comprising at least one conduit housing the least one fiber optic dine.

59. The system of claim 54 \vUerein the at least one fiber optic line is axially looped at Icast twice along a length of tile pipeline.

60. The system of claim 54 \vilerein the pipeline comprises a subsea pipeline.

61. A method for identifying the azhnuthal location of a thermal event in a subterranean wellbore comprising: measuring a temperature profile along a portion of a wellbore using at least one fiber optic line; and determining an azhnutilal location of a thermal event by analyzing the temperature profile.

62. The method of claim 61 I;rrtler comprising establishing the azimuthal location of the at least one fiber optic line.

63. The method of claim 62, wherein the estahlishin!a step comprises deploying a hcathig element along the al least one fiber optic line; and identi fyLlg the orientation of the at least one Her optic line by activating the heating element.

64. Tile method ot claim 61, wherehl: the measurhig step comprises mcasurhg a. temperature profile along at least two positions of a crosssection of the wellbore; and 1 () the determining step comprises detenninbig the azimuthal location of the thermal event by comparing the temperature profiles.

65. The method of claim 64, further comprising deploying at least two fiber optic lines, each fiber optic line associated with one of the temperature profiles.

66. The method of claim 61, wherein the thermal event comprises an inflow into the wellbore.

fi7. The method ol claim 61, wherein the therm. evens comprises a leak out ofthe wellbore. 2()

68. Tile method of claim 61, wherein the thermal event comprises a temperature difference in fluids flowing in the wellbore.

69. A mLtllod to visualize the flow regime of a subterranean wellbore' comprising: neasrrilg a temperature profile along a portion of a wellborc using at least one fiber I optic lisle; anal determining a location of at least 021C thermal event by analyzing the temperature profile, wherein talc determining step comprises determining an azimuthal location of the at least me thermal evenly.

70. 'I'le netilod exclaim 69, wherein the determining step comprises determining a depth location ol'tlc at least one thermal event.

71. 'I''he method of claim 69, wherein: the 'casuring step comprises measuring a temperature profile along at least two positions of a C205SSCCtiO21 of the wellbore; and the dcterminhig step comprises determining the azimuthal location of the at least one thermal event by comparing the temperature profiles.

73. The 'method of claim 72, further comprising deploying at least two fiber optic lines, each fiber optic I ine associated with 02le of the temperature profiles.