WO2019224567A1

WO2019224567A1 - Apparatus for measuring fluid flow in a well, related installation and process

Info

Publication number: WO2019224567A1
Application number: PCT/IB2018/000776
Authority: WO
Inventors: James LOWDEN; Jacques DANQUIGNY; Hugues Noël Michel GREDER; Salim BOUZIDA
Original assignee: Total Sa
Priority date: 2018-05-22
Filing date: 2018-05-22
Publication date: 2019-11-28

Abstract

The apparatus (20) comprises: - at least a linear longitudinal sensor (50) able to detect an acoustic noise occurring in the well (16) at least at several locations along the linear longitudinal sensor (50) and to generate a corresponding output; - an analyzer (54), able to analyze the output obtained from the linear longitudinal sensor (50); - at least a mobile or permanent noise source (52), able to generate, in the well (16) along the linear longitudinal sensor (50), an artificial predetermined acoustic noise, distinct from an ambient acoustic noise generated by the fluid flow, the analyzer (54) being able to identify a contribution of the artificial predetermined acoustic noise in the output generated by the linear longitudinal sensor (50) and to determine the at least one fluid flow feature based on the artificial predetermined acoustic noise contribution in the output generated by the linear longitudinal sensor (50).

Description

Apparatus for measuring fluid flow in a well, related installation and process

The present invention concerns an apparatus for measuring fluid flow in a well, comprising:

- at least a linear longitudinal sensor able to detect an acoustic noise occurring in the well at least at several locations along the linear longitudinal sensor and to generate a corresponding output;

- an analyzer, able to analyze the output obtained from the linear longitudinal sensor.

Such an apparatus is intended to be used in a well in which a flow of fluid circulates, to determine at least a feature of the fluid flow, such as a fluid velocity and/or a fluid flow rate at various locations in the well.

The apparatus can be used for example in an injector well, in which a fluid is pumped from the surface to a reservoir at the bottom of the well to be injected in the reservoir. The apparatus can also be used in a producer well, in which a fluid from a reservoir is collected in the well, and is conveyed to the surface. The apparatus is used in particular to collect relevant production logging data.

The acquisition of production logging data remains a decisive step to characterize reservoir behavior and well productivity. This is especially the case along drains which are long and which have large deviation, above 60° (which is the usual limit for gravity driven wireline logging acquisition) up to 90°, such as in horizontal drains.

In particular, in production wells, it is crucial to determine the producing length of the drain to enable a quantitative deterministic interpretation of pressure transient test or to allocate a part of production produced by each layer or reservoir drilled through a horizontal or highly deviated drain.

In injector wells, the logging allows the determination of the quantity of fluid injected in the well, at various locations along the length of the well. This is a very important information in order to properly model the flooding of hydrocarbons within the reservoir by the injected fluid (typically water, or polymer or gas, or alternatively water and gas).

In practice, production logging measurements are implemented quite rarely. Indeed, the measurements require stopping the well production and running in hole a logging tool in the well. The intervention is often carried out with a tractor or coiled tubing. There is a strong risk that the equipment inserted downhole damages the well, or remains stuck at the bottom of a well, requiring expensive maintenance and even in some cases well shutdown. In order to avoid deploying logging tools, linear sensors such as fiber optics have been deployed in a well, e.g. along a stinger (i.e. a permanent piece of small tubing along which the fiber optic is clamped), to sense data such as temperature along the well.

Nevertheless, the related PLT (“Production Logging Tool”) acquisition techniques, such as“Warm-Back” or“Hot or Cold Slug” are usually difficult to analyze and are hardly quantitative. Difficulties occur especially in nearly horizontal drain where geothermal gradient is useless to infer the production influx along the drain. Such techniques also involve long shutdowns of production or injection, and hence, great loss of production.

In order to overcome these drawbacks, WO 2009/056855 discloses an apparatus in which an optical fiber is used to sense a natural acoustic noise generated by the fluid flow, using Distributed Acoustic Sensors or“DAS”.

The natural noise of the flow is however quite hard to detect and analyze. Specific arrangements such as corrugations provided along the tubing are used to enhance the natural noise generated by the flow and hence, to improve signal analysis.

Nevertheless, the natural noise may not carry enough information to provide accurate detection of the fluid flow features, especially in monophasic flow. On the other hand, multiphasic flow requires much more information than just a“speed of natural noise displacement” to assess quantitatively the flow of each fluid phase.

One aim of the invention is therefore to provide an apparatus which can easily be put in place in particular permanently in a well, with minimal disruption of production, and which can be used to very accurately monitor at least a fluid flow feature of the well such as fluid velocity.

To this aim, the subject-matter of the invention is an apparatus of the above- mentioned type, characterized by:

- at least a mobile or permanent noise source, able to generate, in the well along the linear longitudinal sensor, an artificial predetermined acoustic noise, distinct from an ambient acoustic noise generated by the fluid flow, the analyzer being able to identify a contribution of the artificial predetermined acoustic noise in the output generated by the linear longitudinal sensor and to determine the at least one fluid flow feature based on the artificial predetermined acoustic noise contribution in the output generated by the linear longitudinal sensor.

The apparatus according to the invention may comprise one or more of the following features, taken solely, or according to any feasible technical combination:

- the or each noise source comprises an active artificial noise generator able to generate the artificial predetermined acoustic noise; - the or each noise source comprises at least an additional sensor, able to collect an additional output representative of the fluid flow;

- the or each noise source is able to freely move longitudinally in the fluid flow along the linear longitudinal sensor;

- said apparatus of the above mentioned type comprises a retainer, operable between a retaining position, in which the noise source is longitudinally retained with regard to the linear longitudinal sensor and a release position, in which the noise source is free to move longitudinally in the fluid flow along the linear longitudinal sensor;

- the noise source comprises a main body having a spherical shape;

- the noise source comprises a stabilizer connected to the main body;

- the noise source is permanently fixed longitudinally in the fluid flow along the linear longitudinal sensor;

- the noise source is radially deployable from a retracted position to an extended position in the flow;

- the fluid flow feature is a fluid flow rate and/or a fluid velocity and/or fluid density;

- the longitudinal linear sensor is an optical fiber.

The invention also relates to a fluid production installation comprising:

- at least a well in which a fluid is able to flow;

- at least an apparatus according to the above mentioned type, the linear longitudinal sensor and the or each noise source being located in the well.

The installation according to the invention may comprise one or more of the following features, taken solely, or according to any feasible technical combination:

- the well is a fluid injector well, the fluid flowing from a surface to a reservoir at a bottom of the well or the well is a producer well, the fluid flowing from a reservoir at the bottom of the well to the surface;

- the well comprises at least a stinger, the longitudinal linear longitudinal sensor being connected along the length of the stinger.

The invention also concerns a process for measuring fluid flow in a well, comprising:

- providing an apparatus of the above mentioned type;

- generating, in the well along the linear longitudinal sensor, an artificial predetermined acoustic noise, distinct from an ambient acoustic noise generated by the fluid flow, with at least a noise source;

- generating, with the linear longitudinal sensor, an output representative of an acoustic noise occurring in the well at least at several locations along the linear longitudinal sensor; - identifying with the analyzer, a contribution of the artificial predetermined acoustic noise in the output collected by the linear longitudinal sensor and determining the at least one fluid flow feature, based on the artificial predetermined noise contribution in the output generated by the linear longitudinal sensor.

The process according to the invention may comprise one or more of the following features, taken solely or according to any technical feasible combination:

- said process comprises freely circulating the noise source in the fluid flow along the linear longitudinal sensor, the noise source generating an artificial predetermined acoustic noise distinct form an ambient noise generated by the fluid flow, the determination of the fluid flow feature comprising determining a velocity of the noise source along the linear longitudinal sensor in the fluid flow, based on the artificial predetermined noise contribution in the output generated by the linear longitudinal sensor;

- the noise source is permanently fixed longitudinally in the fluid flow, the noise source comprising a movable part, able to move in the fluid flow as a function of the flow rate, the movement of the noise source generating an artificial predetermined acoustic noise.

The invention will be better understood, based on the following description, given solely as an example, and made in reference to the appended drawings, in which:

- figure 1 is a schematic section view of a first fluid production installation comprising an apparatus including a Distributed Acoustic Sensor (noted DAS) fiber optic, also referred as a linear longitudinal sensor which is used to monitor at least a noise source for measuring a fluid flow feature according to the invention;

- figure 2 is a side view of a mobile noise source able to actively generate an artificial predetermined acoustic noise signal in the fluid flow;

- figure 3 is a view of a releaser, able to hold the mobile noise source in the well and to release the mobile noise source when a measurement has to be carried out;

- figure 4 is a schematic view of a measurement interpretation principle carried out using a noise source according to figure 2 and of subsequent calculations to determine the fluid flow features like fluid velocity and fluid rate along the wellbore ;

- figure 5 is a typical sectional view of the end section of a well in a second installation according to the invention;

- figure 6 is a view similar to figure 2 of a noise source adapted for the well of figure 5, the design of the noise source being done to avoid its trapping within the well completion while flowing upward at the same speed as the produced fluid ;

- figure 7 is a view similar to figure 5, in which sources as shown in figure 2 or figure 6 are used; - figure 8 is a view of a variant of apparatus according to the invention comprising a plurality of longitudinally fixed noise sources ;

- figure 9 is a view similar to figure 8 of a variant of apparatus according to the invention.

A first fluid production installation 10 according to the invention is shown in figure 1. The fluid production installation 10 is intended for injecting or producing a fluid from a reservoir 12 located in a subsoil 14 whose surface 18 is located above the ground, or underwater.

The fluid produced in the installation 10 from the reservoir 12 is in particular oil and gas, containing hydrocarbons. The fluid injected in the installation 10 is in particular water or/and gas or/and polymer.

The installation 10 comprises at least a well 16 connecting the reservoir 12 in the subsoil 14 to the surface 18 of the subsoil 14 and a fluid production and/or injection installation 19 connected to the well 16 at the surface 18 of the subsoil 14.

The well 16 is for example of producer well configured to carry a produced fluid from the reservoir 12 to the surface 18 of the subsoil 14. In the example shown in figure 1 , the well 16 is an injector well configured to carry an injected fluid from the surface 18 to the reservoir 12 to boost the production at another producer well.

The fluid production installation 10 further comprises at least a measuring apparatus 20 according to the invention, for measuring a fluid flow feature of the fluid circulating in the well 16.

The well 16 has a borehole 22 extending through formations of the subsoil 14 to the reservoir 12.

The well 16 further comprises at least a wellhead 24 closing the borehole 22, at least a casing 26 inserted in the borehole 22, and at least an inner tubing 28 inserted in the casing 26, and a tubing referred to as stinger 30 (which may be coiled tubing or small tubing).

In the example of figure 1 , the well 16 further comprises at least a packer 32 surrounding the inner tubing 28, and a liner 34, connected to the inner tubing 28, downhole of the packer 32.

In the example of figure 1 , the borehole 22 has an upper vertical section 36, and at least a lower inclined 38 and/or horizontal section 40, in particular located in the reservoir 12.

As shown in figure 1 , an outer casing 26 is placed against the formations of the subsoil 14 to line the borehole 22. The inner tubing 28 is installed in the outer casing 26. The outer casing 26 extends in this example up to the reservoir 12. In the reservoir 12, a section of the borehole is advantageously open, without casing 26.

The stinger 30 extends in the tubing 28 and casing 26. It projects out of the tubing 28 and the casing 26 in the lower inclined and/or horizontal sections 38 and 40.

The packer 32 is placed at the bottom end of the inner tubing 28 to close the annular space defined between the inner tubing 28 and the outer casing 26.

The liner 34 extends longitudinally in the open section 40 of the borehole 22. In this example, the liner 34 is closed at its lower end.

The liner 34 further delimits a plurality of slots 42 which define a screen 44 between the outer peripheral surface of the liner 34 and the inner peripheral surface of the liner 34.

The fluid injection and/or production installation 19 is located at the surface 18 of the subsoil. In the example of an injector well such as shown in figure 1 , the installation 19 is connected to the annulus 46 defined between the stinger 30 and the tubing 28. It is able to inject an injection fluid, such as water advantageously containing polymers, in the annulus 46, so that the injection fluid is able to flow to the liner 34, pass through the screen 44, and enter the reservoir 12.

The apparatus 20 for measuring a fluid flow feature in the well 16 comprises at least a linear longitudinal sensor 50, here a DAS optical fiber, able to detect an acoustic noise representative of a flow feature (such as fluid velocity or density) occurring in the well 16 at several locations along the sensor 50, and to generate an output representative of the detected acoustic noise.

The apparatus also preferentially comprises at least a mobile noise source 52 able to generate, along the linear longitudinal sensor 50, an artificial predetermined acoustic noise, distinct from natural noise generated by the fluid flow.

The apparatus 20 further comprises an analyzer 54, able to analyze the output obtained from the linear longitudinal sensor 50 to identify the contribution of the artificial predetermined acoustic noise in the output generated by the sensor 50 and to determine the at least one fluid flow feature based on the artificial predetermined noise contribution in the output generated by the sensor 50.

The linear longitudinal sensor 50 extends in the well 16, in the region in which the measurement of the fluid flow feature is to be carried out.

In the example of figure 1 , the linear longitudinal sensor 50 extends in the annulus 46 between the Stinger 30 and the inner casing 26 in the lower inclined and horizontal sections 38 and 40, and in the upper vertical section 36. In a variant, the linear longitudinal sensor 50 extends only along part of the well 16 if the stinger 30 cannot be run down to the bottom of the well 16.

Preferably, the linear longitudinal sensor 50 is fixed to the stinger 30 along a generatrix of the stinger 30.

Advantageously, the linear longitudinal sensor 50 comprises an optical fiber, an optical source, able to inject light in the optical fiber, and an optical detector, able to produce an output from the light reflected at various locations in the optical fiber.

Preferentially, the linear longitudinal sensor 50 is a Distributed Acoustic Sensor or DAS. The light source is a coherent source which creates pulses injected in the optical fiber. The detector is connected to the optical fiber through a beam splitter which receives the light scattered from the optical fiber. An example of Distributed Acoustic Sensor is disclosed in WO 2009/056855.

The apparatus 20 preferentially comprises at least one noise source 52, preferentially a plurality of noise sources 52.

In the example of an injector well, the noise source 52 is able to be dropped directly in the well 16 from the wellhead 24. In a producer well or in an injector well, the noise source 52 can also be retained in the well 16 by a retainer 60, an example of which is shown in figure 3.

In the example of figure 2, the noise source 52 is a mobile noise source, able to freely move in the fluid flow along the longitudinal sensor 50. It is designed to flow at a velocity as close as possible as the injected fluid velocity.

For example, the overall density of the noise source 52 is designed to be as close as possible as the fluid density.

In an injector well, the noise source 52 is advantageously composed at least partly and preferably as much as possible of degradable materials in downhole condition, so that after the acquisition of the PLT data acquired thanks to the launching of the noise source 52, the noise source degrade at least partly and preferably as much as possible. This limits the impact of the remaining components of the noise source 52 in case of a future well intervention (like the abandonment of the well at late well’s life).

As shown in figure 2, the noise source 52 comprises a main body 62, at least an active artificial noise generator 64 located in the main body 62, and advantageously, a stabilizer 66 able to guide the movement of the main body 52 in the fluid flow.

The main body 62 advantageously contains additional sensors 68 to provide additional logging data.

In the example of figure 2, the main body 62 has a spherical ball shape. The main body 62 for example has two half shelves sealingly connected to another. The main body 62 defines an inner volume containing the active artificial noise generator 64 and if applicable, the additional sensors 68.

The active artificial noise generator 64 is able to generate a predetermined acoustic noise at a given predetermined frequency or in a given predetermined frequency range. The predetermined frequency and/or the predetermined frequency range are distinct from the range of frequencies of the natural noise generated in the well 16 in particular by the fluid flow.

The difference in between the natural noise generated in the well 16 and the active artificial noise generated by the active artificial noise generator 64 is designed, for example in terms of mean frequency or spectrum (narrow band or broad band) or sequence of generated artificial noise. The difference is predetermined, for example with a sine or slot shape having a predetermined frequency, so that the DAS fiber optic 50 can locate the precise position of each noise source 52 placed or injected into the wellbore.

The additional sensors 68 advantageously contained in the main body 62 are preferably chosen among an acceleration sensor, able to measure an acceleration of the noise source 52, a pressure sensor, able to measure the pressure of the fluid located around the noise source 52, a temperature sensor, able to measure the temperature of the fluid located round the noise source 52, a casing collar locator (CCL), able to measure the successive connections of successive casing collars of the casing 26, 28, a clock, able to type stamp data collected by each sensor, and a memory, able to collect type stamped data. This is particularly useful in the case of a producer well, in which the noise source 52 and the enclosed measured data could be collected at surface.

The stabilizer 66 is configured for directing the noise source 52 along the fluid flow axis, and preferably, to let it flow at the same velocity as the fluid flow velocity. The choice of the material of the main body 62 and its density can also help the noise source 52 flowing at the same fluid velocity.

In the example of figure 2, the stabilizer 66 comprises a cylindrical tubular wall 70, open at its longitudinal ends, and centered with an axis of the main body 62. The tubular wall 70 is longitudinally apart from the main body 62, and is connected to the main body 62 by at least one longitudinal arm 72.

In the example of figure 2, the longitudinal edge of the tubular wall 70 closest to the main body 62 and the main body 62 define between them an annular passage 74 for the fluid flow.

Preferentially, the transverse extent of the tubular wall 70, taken perpendicularly to the axis of the tubular wall 70, is smaller than the transverse extent of the main body 62, taken perpendicularly to the same axis. Moreover, the length of the tubular wall 70, taken along the axis of the tubular wall 70, is smaller than the length of the main body 62, taken along the same axis. The distance separating the main body 62 from the tubular wall 70, along the axis of the tubular wall 70 is smaller than the length of the tubular wall 70.

The stabilizer 66 here comprises several parallel longitudinal arms 72. Each longitudinal arm 72 connects an outer surface of the main body 62 to the tubular wall 70, preferentially to the edge of the tubular wall 70. The longitudinal arm 72 is here parallel to the axis of the tubular wall 70.

A variant of noise source stabilizer 66 is shown in figure 6. As shown in figure 6, the stabilizer 66 comprises a single central longitudinal arm 72, protruding from the back of the main body 62 along the axis of the tubular wall 70, and several connecting fingers 76 connecting a free end of the longitudinal arm 72 to the tubular wall, preferentially to a longitudinal edge of the tubular wall. In this example, the distance between the main body 62 and the tubular wall 70 is greater, preferentially at least twice greater, than the length of the tubular wall 70.

The stabilizer 66 of figure 6 not only allows a stabilization of the noise source 52 in the flow but also an alignment of the noise source 52 in the axis of the tubing 30 at the center of the flow. This kind of design is aimed at preventing the noise source 52 to be trapped in dead head locations as shown in figure 7 just below the packer 32, while flowing upward in case of a producer well.

As shown in figure 3, the retainer 60 protrudes in the fluid flow. In the example of figure 3, the retainer 60 protrudes transversely from the stinger 30, on a side of the stinger 30.

The retainer 60 defines a housing 80 receiving at least a noise source 52, to axially retain the noise source 52, and an expeller 82, able to push the noise source 52 out of the housing 80 to launch it the fluid flow.

Thus, the retainer 60 is operable between a retaining position, in which the noise source 52 is longitudinally retained with regard to the linear longitudinal sensor 50, and a released position, in which the expeller 82 has been activated to launch the noise source 52 away from the housing 80, and in which the noise source 52 is free to move longitudinally in the fluid flow along the linear longitudinal sensor 50, independently of the linear longitudinal sensor 50.

The expeller 82 is able to be controlled and/or triggered at a particular time. It advantageously comprises a clock and/or timer system.

As shown in figure 1 , the analyzer 54 is located at the surface. It comprises a computer having a processor 84 and at least a memory 86 containing software modules able to be executed by the processor 84. Among the modules contained in the memory 86, the analyzer 54 comprises a module 88 for acquiring an output of the sensor 50 representative of an acoustic noise occurring in the well 16, at different locations along the linear longitudinal sensor 50, a module 90 for identifying the contribution, at each location, of the artificial predetermined noise in the output collected by the linear longitudinal sensor 50, and advantageously a module 92 for tracking and interpreting in terms of fluid velocity and rates (either single phase or multiphase) the specific contribution of the noise sources 52.

The acquiring module 88 is connected to the detector of the linear longitudinal sensor 50, to acquire the optical output backscattered from the optical fiber at various locations along the optical fiber. This optical output is representative of the acoustic noise sensed at each location of the linear longitudinal sensor 50. The acquiring module 88 is also able to time stamp the data collected from the optical sensor, so that an output is measured as a function of time at each location along the linear longitudinal sensor 50.

The output acquired by the module 88 at each location comprises the natural noise contribution generated by the fluid flow circulating in the well 16 and the active artificial noise contribution generated by the generator 64 of the noise source 52, when the noise source 52 passes in register with the location.

The identifying module 90 is able to carry out a frequency and/or signal analysis to sort out in the output, the particular contribution of the artificial predetermined noise. This contribution can range from a zero contribution, when no artificial noise is detected at the particular location, to a maximal contribution, when the noise source 52 passes in register with the particular location. From the active artificial noise detected at each location as a function of time, the position of the mobile noise source 52 as a function of time is determined along the linear longitudinal sensor 50.

For the case of a single phase injector well, the determining module 92 comprises an application for calculating the velocity of the noise source 52 by deriving the position of the noise source detected by the identifying module 90 as a function of time, as shown in graph (a) of figure 4. It further comprises an application for calculating the surface area of the flow at each location and to multiply it with the velocity of the fluid at the location, inferred from the velocity of the noise source 52, to obtain the fluid flow rate as a function of location along the linear longitudinal sensor 50, as shown in graph (b) of figure 4.

Advantageously, since the noise propagation in a fluid depends on fluid nature, temperature, density and compressibility, other fluid flow features such as relative compositions in oil and water can be inferred from the measured signal.

A process for measuring features of a fluid flow in a well 16, using the apparatus 20 according to the invention will now be described, in the example of an injector well. Initially, a linear longitudinal sensor 50 is deployed in the well 16, at least in the lower inclined 38 and/or horizontal section 40, and preferentially also in the upper vertical section 36. Then, a noise source 52 is dropped in the fluid flow. The noise source 52 is for example inserted at the wellhead 24 and/or is released from a retainer 60 located in the well but upstream the zone where the inflow profile acquisition is targeted.

When the noise source 52 is launched in the fluid flow, the active artificial noise generator 64 is triggered to generate an artificial acoustic noise distinct from the natural noise of the flow. The artificial noise for example has a frequency and/or shape which is predetermined and which is distinct from the frequency of the natural noise. Advantageously, the additional sensors 68 are also activated to measure data along the well 16.

Simultaneously, the detection using the linear longitudinal sensor 50 is also activated. The artificial noise generated by the generator 64 is sensed at various locations of the linear longitudinal sensor 50 by continuous analysis of the optical output of the sensor 50 which is backscattered in the optical fiber at the different locations.

The acquiring module 88 of the analyzer continuously acquires the noise data at various locations, the noise data including the natural acoustic noise generated in the well 16 by the fluid flow and the active artificial noise generated by the noise source 52 when the noise source 52 passes in register with the particular location.

The identifying module 90 is able to extract the contribution of the artificial acoustic noise generated by the noise source 52 from the output of the sensor 50 measured at various locations. The position of the noise source 52 in the well 16 as a function of time is then determined from the contribution of the artificial noise detected at each location as a function of time.

In addition, the noise data acquired simultaneously at various locations by the linear longitudinal sensor 50 can be used to improve the calculation of the noise source 52 position in the well.

Then, the determining module 92 calculates the derivative of the position of the noise source 52 as a function of time to obtain the velocity of the noise source 52 as a function of time.

The fluid velocity is then inferred from the velocity of the noise source 52, preferentially by being equal to the velocity of the noise source 52. This is the case in particular, when the noise source 52 comprises a stabilizer 66 which directs the noise source 52 along the fluid flow, at the same velocity as the fluid flow. Then, the fluid flow area is calculated at each location, and is multiplied by the velocity of the fluid flow to obtain the fluid flow rate as a function of the location in the well 16.

The measurement using the apparatus 20 according to the invention is very accurate, thanks to the easy identification of the artificial noise generated by each noise source 52 in comparison with the natural noise which is quite erratic. The fluid flow feature is then measured with great accuracy, without trouble for the operator of the well 16 and advantageously without shutdown of the well.

In the case of a well 16 being a producer well as shown in figure 5, several retainers 60 are usually positioned downhole in the potentially producing zone of the well 16, for example along the interval where successive perforations have been carried out as showed in figure 5. The expellers 82 are triggered sequentially or simultaneously to carry out measurements of the produced flow at various times and / or locations.

The advantage of placing several retainers at various locations along the potential producing length of the well is that the deepest zone with actual production coming into the wellbore is not known a priori.

Therefore, at least some of the released noise sources 52 will be located in front of zones with production and they will be entrained dragged by the producing flow and thus deliver the inflow profile starting from their respective retainer 60. In a well, the deepest perforated or stimulated zones often do not finally produce. Hence, by placing a single noise source 52 upstream this deepest zone, the noise source may not be entrained. In this case, the inflow profile would not be acquired, as showed in figure 5 with the deepest noise sensor 52.

The noise source 52 travels upwards in the well 16 and is advantageously recovered at the surface of the well 16. The data measured by the additional sensors 68 can be acquired by the analyzer 54 or by another specific analyzer, in addition to the output obtained from the linear longitudinal sensor 50. More production data can be obtained.

In a variant shown in figure 8 (referred to as a "velocity cross section profiler”), the noise source 52 is permanently longitudinally retained with regard to the linear longitudinal sensor 50. The retainer 60 of the apparatus 20 comprises at least a deployable member 100, able to be deployed in the fluid flow from a retracted position to an expanded position shown in figure 8. In this example, the deployable member 100 is a flexible blade, radially deployable from the retracted position to the expanded position. Each noise source 52 is permanently attached to the deployable member 100. The noise source 52 is here a noise spinner. The main body 62 is fixed to the deployable member 100.

The noise source 52 further comprises a propeller 52, mounted in the main body 62. The propeller 102 is able to be rotated by the fluid flow, at a speed which depends on the velocity of the fluid flow. The movement of the propeller 52 is able to generate an artificial noise, whose frequency depends on the speed of rotation.

For example, the propeller 102 comprises at least a mechanical member such as a stop which rotates jointly with the propeller 102 to periodically contact a fixed mechanical member in the main body 62 to generate acoustic noise.

In a variant, the rotation of the propeller 102 generates an electric current, whose intensity and/or frequency is dependent on the speed of rotation, and which is transmitted to an active artificial noise generator to generate an artificial noise whose frequency is dependent on the speed of rotation.

In the example of figure 8, the apparatus 20 comprises several noise sources 52 which are spread radially apart from the flow axis. Each noise source 52 is able to measure the velocity of the fluid at a particular radial location in the flow.

As described above, the linear longitudinal sensor 50 positioned in register with each noise source 52 is able to detect the acoustic noise generated by each noise source 52 at the particular location as a function of time.

In operation, the fluid flow rotates each propeller 102 at a rotational speed which depends on the flow velocity. The rotation of the propeller 102 generates an artificial noise whose frequency and/or intensity is dependent on the speed of rotation, and hence on the fluid velocity.

The artificial noise generated by the noise source 52 is sensed by the linear longitudinal sensor 50 and is transmitted to the analyzer 54. The analyzer 54 is able to determine the frequency and/or intensity of the artificial noise from the contribution of the artificial noise in the output detected by the sensor 50, and to calculate the fluid velocity at the particular location based on the artificial noise contribution. These multiple noise sources 52 provide very valuable flow velocity profiles across the well flowing area, which is useful and necessary to acquire in case of a multiphase flow.

In a variant shown in figure 9 (referred to as“density cross section profiler”), each noise source 52 is a Coriolis sensor. The Coriolis sensor comprises at least two parallel deviated tubes able to move in relation to another depending on the fluid flow rate.

The relative movement of the two tubes is used to create an artificial noise, for example by mechanical cooperation between mechanical members on each of the tubes, and/or by generation of an electrical signal whose frequency is dependent on the mechanical movement between the tubes. In the latter case, the electrical signal is transmitted to an artificial noise generator, to generate an artificial noise at a particular frequency corresponding to the measured output.

The generated acoustic noise is sensed by the linear longitudinal sensor 50, as described above.

The operation of the apparatus 20 shown in figure 9 is similar to the operation of the apparatus shown in figure 8. This multiple Coriolis sensor noise sources 52 provide a fluid density profile across the well flowing area which is necessary to acquire in case of multiphase flow.

A velocity cross section profiler (like in figure 8) and density cross section profiler (like in figure 9) should be located at a neighboring depth. The combination of their data enables to infer a multiphase flow profile across the well flowing section at the average depth.

Placing several duets of velocity and density cross section profilers along the wellbore enables a permanent acquisition of multiphase flow data at these specific locations. This can be extremely valuable to measure the production rate from various reservoirs or layers which are simultaneously produced through a same well.

In all embodiments, the artificial predetermined acoustic noise generated by the or each mobile or permanent noise source 52 is distinct from any natural acoustic noise of the fluid flow when it flows in the well, in particular distinct form a natural noise of the fluid flow flowing along any pattern defined in the well such as a corrugated surface of a tube.

Claims

1.- Apparatus (20) for measuring fluid flow in a well (16), comprising:

- at least a linear longitudinal sensor (50) able to detect an acoustic noise occurring in the well (16) at least at several locations along the linear longitudinal sensor (50) and to generate a corresponding output;

- an analyzer (54), able to analyze the output obtained from the linear longitudinal sensor (50), characterized by:

- at least a mobile or permanent noise source (52), able to generate, in the well (16) along the linear longitudinal sensor (50), an artificial predetermined acoustic noise, distinct from an ambient acoustic noise generated by the fluid flow, the analyzer (54) being able to identify a contribution of the artificial predetermined acoustic noise in the output generated by the linear longitudinal sensor (50) and to determine the at least one fluid flow feature based on the artificial predetermined acoustic noise contribution in the output generated by the linear longitudinal sensor (50).

2.- Apparatus (20) according to claim 1 , wherein the or each noise source (52) comprises an active artificial noise generator (64) able to generate the artificial predetermined acoustic noise.

3.- Apparatus (20) according to any one of the preceding claims, wherein the or each noise source (52) comprises at least an additional sensor (68), able to collect an additional output representative of the fluid flow.

4.- Apparatus (20) according to any one of the preceding claims, wherein the or each noise source (52) is able to freely move longitudinally in the fluid flow along the linear longitudinal sensor (50).

5.- Apparatus (20) according to claim 4, comprising a retainer (60), operable between a retaining position, in which the noise source (52) is longitudinally retained with regard to the linear longitudinal sensor (50) and a release position, in which the noise source (52) is free to move longitudinally in the fluid flow along the linear longitudinal sensor (50).

6.- Apparatus (20) according to any one claims 4 and 5, wherein the noise source (52) comprises a main body (62) having a spherical shape.

7.- Apparatus (20) according to claim 6, wherein the noise source (52) comprises a stabilizer (66) connected to the main body (62).

8.- Apparatus (20) according to any one of claims 1 to 3, wherein the noise source (52) is permanently fixed longitudinally in the fluid flow along the linear longitudinal sensor (50).

9.- Apparatus (20) according to claim 8, wherein the noise source (52) comprises at least a movable part, in particular a rotatable part, able to move in the fluid flow as a function of a flow rate of the fluid flow, the artificial acoustic noise being generated by the movement of the movable part.

10.- Fluid production installation (10) comprising:

- at least a well (16) in which a fluid is able to flow;

- at least an apparatus (20) according to any one of the preceding claims, the linear longitudinal sensor (50) and the or each noise source (52) being located in the well (16).

11.- Installation (10) according to claim 10, wherein the well (16) is a fluid injector well (16), the fluid flowing from a surface (18) to a reservoir (12) at a bottom of the well (16) or a producer well (16), the fluid flowing from a reservoir (12) at the bottom of the well (16) to the surface (18).

12.- Installation (10) according to any one of claims 10 or 1 1 , wherein the well (16) comprises at least a stinger (30), the longitudinal linear longitudinal sensor (50) being connected along the length of the stinger (30).

13.- Process for measuring fluid flow in a well (16), comprising:

- providing an apparatus (20) according to any one of claims 1 to 9;

- generating, in the well (16) along the linear longitudinal sensor (50), an artificial predetermined acoustic noise, distinct from an ambient acoustic noise generated by the fluid flow, with at least a noise source (52);

- generating, with the linear longitudinal sensor (50), an output representative of an acoustic noise occurring in the well (16) at least at several locations along the linear longitudinal sensor (50); - identifying with the analyzer (54), a contribution of the artificial predetermined acoustic noise in the output collected by the linear longitudinal sensor (50) and determining the at least one fluid flow feature, based on the artificial predetermined noise contribution in the output generated by the linear longitudinal sensor (50).

14.- Process according to claim 13, comprising freely circulating the noise source (52) in the fluid flow along the linear longitudinal sensor (50), the noise source (52) generating an artificial predetermined acoustic noise distinct form an ambient noise generated by the fluid flow, the determination of the fluid flow feature comprising determining a velocity of the noise source (52) along the linear longitudinal sensor (50) in the fluid flow, based on the artificial predetermined noise contribution in the output generated by the linear longitudinal sensor (50).

15.- Process according to claim 13, wherein the noise source (52) is permanently fixed longitudinally in the fluid flow, the noise source (52) comprising a movable part, able to move in the fluid flow as a function of the flow rate, the movement of the noise source (52) generating an artificial predetermined acoustic noise.