GB2522266A

GB2522266A - Sensor system

Info

Publication number: GB2522266A
Application number: GB1400970.8A
Authority: GB
Inventors: Garth Naldrett
Original assignee: Tendeka AS
Current assignee: Tendeka AS
Priority date: 2014-01-21
Filing date: 2014-01-21
Publication date: 2015-07-22
Anticipated expiration: 2034-01-21
Also published as: GB201400970D0; GB2522266B

Abstract

A sensor system 5 for determining at least one property of a fluid in a wellbore 10, pipeline or conduit includes at least one acoustic generator 40a, 40b, 40c, the acoustic generator being operable to transmit an acoustic beam or signal through the fluid, in use; and at least one distributed acoustic sensor 20 (DAS), the DAS being configured to detect and/or measure the acoustic beams or signals passing through at least a portion of the fluid at a plurality of measurement locations. The sensor system is configured to determine the at least one property of the fluid from the acoustic beams or signals detected or measured at the plurality of measurement locations. The acoustic generator maybe remotely operable and the sensor may comprise at least one optical fibre.

Description

Sensor System

Field of Invention

The present invention relates to a sensor system, particularly a sensor system for use in a conduit or wellbore to determine properties of fluids within the wellbore or conduit.

The sensor system is preferably configured to determine density and/or flow rate of the fluid.

Background of the Invention

Knowledge of the properties of fluids flowing in pipes and other conduits is of great importance in many applications, particularly in downhole oil and gas applications. A variety of sensor systems are known, examples of which include electrical sensors having quartz or strain transducers, or optical fibre sensors having Fabry-Perot etalons or Bragg gratings and examples of measurements include temperature, pressure and flow.

One particular technique upon which sensors can be based is distributed acoustic sensing (DAS), which involves measuring light from an optical signal that is scattered as it passes along an optical fibre in order to determine the acoustic field at various locations along the optical fibre.

Summary of Invention

Various aspects of the present invention are defined in the independent claims. Some preferred features are defined in the dependent claims.

According to a first aspect of the present invention is a sensor system for determining at least one property of a fluid in a wellbore, pipeline or conduit. The at least one property may comprise at least one of speed of sound in the fluid, density of the fluid and/or flow rate of the fluid.

The sensor system may comprise at least one acoustic source, such as an acoustic generator. The acoustic source may be operable to transmit an acoustic beam or signal through the fluid, in use. The sensor system may comprise an array of acoustic sources.

The sensor system may comprise at least one sensor, such as an acoustic sensor, which may comprise a distributed acoustic sensor. The sensor may be configured to detect and/or measure the acoustic beams or signals passing through at least a portion of the fluid at a plurality of measurement locations.

The sensor system may be configured to determine the at least one property of the fluid from the acoustic beams or signals detected or measured by the at least one sensor at the plurality of measurement locations.

The sensor system may comprise a plurality of acoustic sources, which may be distributable along at least part of the wellbore, pipeline or conduit, e.g. in a lengthwise direction of the wellbore, pipeline or conduit. The acoustic sources may be permanently installed in the wellbore, pipeline or conduit, or may be inserted on a temporary basis, which may allow the location of the acoustic sources to be changed over time. The acoustic sources may also be configured or allowed to move along the wellbore, pipeline or conduit, for example using a suitable tractor or cable mechanism.

The sensor system may be adapted to be retrofifted into the wellbore, pipeline or conduit, e.g. without requiring a workover. The sensor system may be adapted to run in and/or out of the wellbore, pipeline or conduit, e.g. using slickline or wireline.

The acoustic sources may be selectively operable, controllable and/or programmable in order to control at least one of the timing, phase, frequency and/or amplitude of the acoustic beams or signals emitted/transmitted by the acoustic sources. The acoustic sources may be wirelessly operable, controllable and/or programmable. The acoustic sources may be remotely operable, controllable and/or programmable, e.g. using acoustic control signals or pressure pulses sent to and/or from a remote control system. The acoustic control signals may encode operational commands for controlling or operating the acoustic sources.

The at least one sensor may be provided or providable on and/or within the wellbore, pipeline or conduit.

The at least one sensor may comprise at least one optical fibre. At least one property of the at least one optical fibre may be variable responsive to variations in the acoustic field or acoustic environment experienced by the optical fibre, e.g. due to acoustic beams or signals. The at least one sensor may be configured to determine variations in light scattered, reflected or propagating in the at least one optical fibre, in order to detect and/or measure the acoustic beams or signals passing through at least a portion of the fluid. For example, the variations in the light scattered, reflected or propagating in the at least one optical fibre may be due to variations in the at least one property of the at least one optical fibre, which may comprise variation in the at least one property of the at least one optical fibre at the plurality of measurement locations.

The at least one property of the at least one optical fibre that may be variable responsive to acoustic beams or signals may comprise an optical property of the optical fibre or fibres e.g. a degree of scattering or phase or phase change of light propagating in the optical fibre. The plurality of measurement locations may be distributed along the optical fibre or fibres.

The at least one sensor may be configured to receive or detect the acoustic beam or signal and/or a scattered, backscattered or reflected acoustic beam or signal, such as scatter, backscatter or reflection of the acoustic beam or signal by the fluid. At least one of the optical fibres of the distributed acoustic sensor may extend substantially perpendicularly to a beam direction or axis of the acoustic beam or signal acoustic source.

The at least one sensor may comprise or be configured to receive light from one or more transmitters or light sources. The transmitters or light source(s) may be configured to transmit an optical signal along the optical fibre or fibres. The transmitter or light source may comprise a laser. The optical signal may be a modulated optical signal, such as a pulsed signal.

The at least one sensor may comprise one or more optical detectors. The optical detectors may be configured to detect or measure scattered or reflected light from the optical fibre, such as light scaftered by Brillouin, Rayleigh and/or Raman scattering.

The at least one sensor may comprise or be configured to communicate or couple with a signal processing unit. The signal processing unit may be configured to determine acoustic perturbations or environment experienced by the optical fibre, e.g. at the plurality of measurement locations. The signal processing unit may be configured to determine the properties of the acoustic signals and/or changes in acoustic environment, e.g. from the scattered light detected by the one or more optical detectors, for example from measured differences in amplitude and/or phase of the scattered light and/or optical path length.

The acoustic sources may be provided or providable outside, on and/or within the wellbore, pipeline or conduit. The acoustic sources may comprise piezoelectric or magneto-restrictive acoustic generators, hammer or other actuating and/or striking apparatus, or the like.

In embodiments, the acoustic beams or signals may comprise acoustic pulses. In embodiments, the acoustic beams or signals may comprise a continuous beam or signal.

The acoustic sources may be arranged such that the acoustic beams or signals traverse, partially traverse or are transmitted across the wellbore, pipeline or conduit, e.g. perpendicularly to the longitudinal direction of the wellbore, pipeline or conduit or flow direction. The beams or signals may be divergent.

The sensor system may configured to determine a magnitude, amplitude, frequency spectrum and/or phase of acoustic perturbation or received acoustic beam signal or the scattered or backscattered beam or signal at the plurality of measurement locations, e.g. using the distributed acoustic sensor. The sensor system may be configured to determine an intensity or amplitude profile or distribution of the acoustic beam or signal or scattered or backscattered acoustic beam or signal. The profile may comprise a plurality of acoustic measurements taken at the plurality of measurement locations of the distributed acoustic sensor. The acoustic profile may be generated by the at least one acoustic generator. The sensor system may be configured to determine the acoustic intensity profile along the array. The sensor system may be configured to relate the intensity profile to at least one property of the fluid. The acoustic intensity profile may be measured for a specific period synchronous with the at least one acoustic generator.

The sensor system may be configured to determine speed of sound through the fluid, e.g. using time of flight measurements. The system may be configured to determine time of flight of a signal propagating perpendicularly to a flow direction of the fluid and/or to a longitudinal direction of the wellbore, conduit or pipeline, e.g. to determine the speed of sound through the fluid. The speed of sound in the fluid may be determined from a time of flight of the acoustic signal from one or more of the acoustic sources to one or more of the measurement locations of the distributed acoustic sensor, which may be a measurement location aligned with the acoustic source in a direction that is perpendicular to the direction of flow, e.g. in a widthwise direction of the wellbore, pipeline or conduit.

The sensor system may be configured to determine the density of the fluid from the determination of the speed of sound through the fluid. The sensor system may be configured to characterise the fluid based on the density of, or the speed of sound through, the fluid e.g. by comparison with reference or calibration data or by calculation. The fluid may comprise at least one liquid and/or at least one gas. The characterisation may comprise determining a degree of aeration or gas content in a liquid, distinguishing between a liquid and a gas or between two different liquids, such as oil and water. The at least one property of the fluid determined by the sensor system may comprise at least one property of a liquid and/or at least one property of a gas.

At least one and preferably a plurality of the measurement locations may be upstream of the associated acoustic source. At least one and preferably a plurality of the measurement locations may be downstream of the associated acoustic source. At least one measurement location may be perpendicular to the flow direction from the associated acoustic source, e.g. the measurement location and the associated acoustic source may be aligned in a widthwise direction of the wellbore, pipe or conduit.

The sensor system may be configured to determine a shift or degree of shift, such as a Doppler shift or degree of Doppler shift or a time of flight difference, in the acoustic beam or signal or profile or scattered or backscattered acoustic beam or signal or profile received by the distributed acoustic sensor, e.g. at the plurality of measurement locations.

The sensor system may be configured to determine at least one property of the fluid from at least one of Doppler shift, differential time of flight and/or variations in a profile of measurements of the acoustic beams or signals from the plurality of measurement locations. The differential time of flight may comprise a difference in time of flight of the acoustic signal between at least one of the acoustic sources and one or more of the measurement locations located upstream of the acoustic source and one or more of the measurement locations located downstream of the acoustic source.

The sensor system may be configured to determine the one or more fluid properties by comparison of the received acoustic beam or signal(s) or profile to predetermined or pre-collected calibration or reference data. The sensor system may be configured to determine the one or more fluid properties by calculation, e.g. theoretically, from curve fitting, modelling and or the like.

The plurality of acoustic sources and/or plurality of measurement locations may be configured such that they are distributed over, and/or may determine the at least one property of the fluid in, one or more, e.g. a plurality of, zones or sections of the wellbore, pipeline or conduit, in use.

The one or more acoustic sources for a zone or section may be associated with one or more and preferably a plurality of measurement locations for that zone.

The sensor system may be configured to determine a flow rate or contribution to flow rate and/or a fluid density and/or speed of sound in the fluid for one or more or each zone. The sensor system may be configured to determine an overall flow rate or flow profile or density profile or material profile by combining or summing the flow rate or density or the characterisation of the fluid determined for the one or more or each zone.

The sensor system may be configured to determine temperature and/or strain, e.g. using the optical fibre(s), which may be used to compensate for the effects of temperature and/or strain variations on the acoustic measurements.

According to a second aspect of the present invention is a method of determining at least one property of a fluid in a welibore, pipeline or conduit. The property may comprise determining at least one of speed of sound in the fluid, density of the fluid or flow rate of the fluid.

The method may comprise providing at least one acoustic source. The acoustic source may be operable to transmit an acoustic beam or signal through the fluid, in use.

The method may comprise providing at least one sensor, such as an acoustic sensor, e.g. a distributed acoustic sensor. The sensor may be configured to detect and/or measure the acoustic beams or signals passing through at least a portion of the fluid.

The measurements and/or detection of the acoustic beams or signal may be at a plurality of measurement locations.

The method may comprise determining the at least one property of the fluid from the acoustic beams or signals detected or measured at the plurality of measurement locations.

The method may comprise using the sensor system according to the first aspect.

The method may comprise using the at least one sensor to measure the acoustic environment at the plurality of measurement locations. The method may comprise measuring the acoustic environment at one or more and preferably a plurality of the measurement locations upstream of the acoustic source. The method may comprise measuring the acoustic environment at one or more and preferably a plurality of measurement locations downstream of the acoustic source. At least one measurement location may be in line with or opposite the acoustic source in a width wise or lateral direction of the wellbore, pipeline or conduit. At least one measurement location may be spaced from the acoustic source in a direction that is perpendicular to the flow direction.

The method may comprise moving the sensor system within the wellbore, pipeline or conduit. The method may comprise retrofitting the sensor system into the wellbore, pipeline or conduit, e.g. without requiring a workover. The method may comprise running the at least one acoustic source and/or the at least one acoustic sensor into and/or out of the welibore, pipeline or conduit, e.g. using slickline or wireline.

The at least one sensor may comprise an optical fibre or a plurality of optical fibres.

The at least one sensor may be configured to measure properties of the one or more acoustic signals at the plurality of measurement locations distributed along the optical fibre or fibres. At least part of the at least one sensor, e.g. the optical fibre or fibres, may be provided within the wellbore, pipeline or conduit.

The method may comprise determining acoustic perturbations or environment experienced by the optical fibre, e.g. at the plurality of measurement locations, for example using a signal processing unit. The method may comprise determining properties of the acoustic perturbations or environments, e.g. from measured differences in phase of the scattered light and/or optical path length.

The method may comprise receiving or detecting the acoustic beam or signal and/or a scattered, backscattered or reflected acoustic beam or signal, such as scatter, backscatter or reflection of the acoustic beam or signal by the fluid using the at least one sensor. At least the optical fibre(s) of the at least one sensor may extend substantially perpendicularly to a beam direction or axis of the acoustic beam or signal acoustic source.

The method may comprise controlling and or operating the at least one acoustic source (e.g. the acoustic generator) wirelessly, e.g. without a physical or wired connection to a control unit. Examples of suitable acoustic generators include piezoelectric or magneto-restrictive acoustic generators, hammer or other actuating and/or striking apparatus, or the like.

In embodiments, the method may comprise forming the acoustic beams or signals in acoustic pulses. In embodiments, the method may comprise forming the acoustic beams or signals as continuous beams or signals.

The method may comprise propagating the acoustic signals such that they traverse, partially traverse or are transmitted across the pipeline or conduit, e.g. perpendicularly to the longitudinal direction of the pipeline or conduit.

The method may comprise determining a magnitude and/or amplitude and/or frequency spectrum and/or phase of at least one acoustic perturbations or the received acoustic beam or signal or the scattered or backscattered beam or signal, e.g. at one or more of the plurality of measurement locations. The method may comprise determining an intensity or amplitude profile or distribution of the acoustic beam or signal or scattered or backscattered acoustic beam or signal. The profile may comprise a plurality of acoustic measurements taken at the plurality of measurement locations of the distributed acoustic sensor. The method may comprise determining a change in the profile of acoustic measurements. The method may comprise determining the at least one property of the fluid, e.g. flow rate of the fluid, from the shift in the profile. The acoustic profile may be generated by the at least one acoustic source. The method may comprise determining the acoustic intensity profile along the array. The method may comprise relating the intensity profile to at least one property of the fluid. The method may comprise measuring the acoustic intensity profile for a specific period synchronous with the at least one acoustic source.

The method may comprise determining speed of sound through the fluid, e.g. using time of flight measurements. The speed of sound in the fluid may be determined from a time of flight of the acoustic signal from the acoustic sources to one or more of the measurement locations. The method may comprise determining time of flight of a signal propagating perpendicularly to a flow direction of the fluid and/or to a longitudinal direction of the wellbore, conduit or pipeline.

The method may comprise determining the density of the fluid from the determination of the speed of sound through the fluid. The method may comprise characterising or identifying the fluid based on the density of, or the speed of sound through, the fluid e.g. by comparison with reference or calibration data or by calculation. The fluid may comprise at least one liquid and/or at least one gas. The characterisation may comprise determining a degree of aeration or gas content in a liquid, distinguishing between a liquid and a gas or between two different liquids, such as oil and water.

The at least one property of the fluid may comprise at least one property of a liquid and/or at least one property of a gas.

The method may comprise determining a shift or degree of shift, such as a Doppler shift or degree of Doppler shift or a time of flight difference, in the acoustic beam or signal or profile or scattered or backscattered acoustic beam or signal or profile received by the distributed acoustic sensor, e.g. at the plurality of measurement locations. The method may comprise determining the at least one property of the fluid, e.g. flow rate of the fluid, by comparison of the received acoustic beam or signal(s) or profile to predetermined or pre-collected calibration or reference data. The method may comprise determining the at least one property of the fluid, e.g. flow rate of the fluid, from the shift or degree of shift.

The method may comprise providing an array comprising a plurality of acoustic sources. The acoustic sources may be distributed over a plurality of zones or sections of the conduit, pipeline or wellbore. The method may comprise providing a plurality of distributed acoustic sensors. The plurality of distributed acoustic sensors and/or the plurality of measurement locations may be distributed over the plurality of zones or sections of the conduit, pipeline or well system.

The method may comprise determining a flow rate or contribution to an overall flow rate and/or a fluid density and/or speed of sound in the fluid for one or more or each zone.

The method may comprise determining the overall flow rate or flow profile or density profile or material profile by combining or summing the flow rate or density or the characterisation of the fluid determined for the one or more or each zone.

The method may comprise determining a flow rate or contribution to an overall flow rate and/or a fluid density and/or speed of sound in the fluid for one or more or each zone at one or more flow setting for the well. Taking measurements at multiple flow settings and combining these measurements in nodal analysis model may allow the overall measurement results to be improved.

The method may comprise varying or selecting a frequency of the acoustic signals produced by one or more or each of the acoustic sources dependent on the determined density of the fluid and or the characterization of the fluid. For example, the frequency of the acoustic signal may be increased or decreased dependent on a determined relative proportion of liquid and gas or degree of aeration.

According to a third aspect of the present invention is an acoustic transmitter system comprising an array of acoustic sources, the transmitter system being configured to implement the method of the first aspect or is operable in the system of the second aspect.

The transmitter system may be operable for use in a conduit, pipeline or wellbore. The array of acoustic sources may comprise piezoelectric or magneto-resistive elements.

The array of acoustic sources may be wirelessly operable and/or controllable. The array of acoustic sources may be configured to receive and/or transmit data and/or commands encoded in acoustic signals.

According to a fourth aspect of the present invention is a computer program product configured to at least partially implement the method of the first aspect of the system of the second aspect.

According to a fifth aspect of the present invention is a carrier medium comprising or carrying the computer program product of the third aspect.

According to a sixth aspect of the present invention is a processing or computing apparatus when programmed with the computer program product of the third aspect.

It will be appreciated that features analogous to those described above in relation to any of the above aspects may be individually and separably or in combination applicable to any of the other aspects.

Apparatus features analogous to those described above in relation to a method and method features analogous to the use and construction of those described above in relation to an apparatus are also intended to fall within the scope of the present invention.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments are now described, by way of non-limiting example, and are illustrated in the following figures, in which: Figure 1 is a schematic of a distributed acoustic sensor system; Figure 2 is a schematic of a flow sensor system; Figure 3 is a schematic detail view of part of the flow sensor system of Figure 2; Figure 4 is a schematic showing an acoustic pulse received at upstream and downstream measurement points or locations of the flow sensor system of Figures 2 and 3; and Figure 5 is a schematic showing an acoustic profile determined from a plurality of measurement points or locations using the system of Figures 2 and 3.

DETAILED DESCRIPTION OF THE DRAWINGS

According to embodiments of the present invention, as illustrated with reference to Figures ito 3, is a sensor system 5 for sensing properties downhole, e.g. in a conduit, pipeline or wellbore 10. The sensor system 5 comprises a distributed acoustic sensor and an array of acoustic generators 40a-40c. In use, both the distributed acoustic sensor 15 and the array of acoustic generators 40a-40c extend along the length of the wellbore 10, pipeline or conduit. It will be appreciated that the present invention is applicable to a variety of applications, including producer wells comprising zones having inflow / outflow, amongst others.

The distributed acoustic sensor comprises optical fibre cabling 20. The optical fibre 20 extends within and along the wellbore, pipeline or conduit 10 and can be used to detect acoustic perturbations at a number of measurement points or locations 25a-25e along the optical fibre 20. In this way, determination of acoustic signals at a number of locations along the length of the wellbore 10, including in multiple zones 30a-30c or sections of the wellbore 10, can be made. Optionally, the zones 30a-30c are isolated from each other, for example, using packers or other suitable isolation mechanisms known in the art.

By providing the array of acoustic generators 40a-40c, preferably wirelessly controlled, the timing and amplitude of acoustic signals or events produced by the acoustic generators 40a-40c can be regulated. Beneficially, acoustic generators 40a-40c can be provided in the different zones 30a-30c or sections of the wellbore 10, pipeline or conduit in order to determine the contribution to overall flow from each zone 30a-30c and to more accurate perform flow, density and/or material profiling along the length of the wellbore 10, pipeline or conduit.

The sensor system 5 is operable to determine properties of fluids 35 within the wellbore 10, pipeline or conduit, such as fluid density and flow rate. These properties can be determined, for example, by measuring the speed of sound within the fluid 35 and determining shifts in the received acoustic signals, e.g. Doppler shifts or variations of upstream and downstream time of flight measurements.

The determination of the fluid properties could be used, for example, for information and/or for control of operations and/or planning remedial operations. For example, the sensor system 5 can be used to determine properties such as fluid density or speed of sound in the fluid for a variety of zones 30a-30c. After a time, a steady state may be reached where the determined property for a zone 30a-30c is the same as that of at least one other zone 30a-30c, such as one or both neighbouring zones, or related in a relatively constant manner to the at least one other zone 30a-30c. Variations in the determined property, such as fluid density or speed of sound in the fluid, for a zone 30a-30c relative to one or more of the other zones 30a-30c, could then be indicative of an event, such as a switch from oil production to water production. Control of the wellbore could be made dependent on the property determination, for example, by isolating water producing zones, as would be apparent to a skilled person.

An example of a suitable distributed acoustic sensor 15 that can be used with the present invention is shown in Figure 1. The distributed acoustic sensor 15 comprises an optical transmitter 45, such as a laser, and a receiver system 50, such as a photodiode array. Both the transmitter 45 and the receiver 50 are coupled to the one or more optical fibres 20. The transmitter 45 is modulated under the control of a controller 55 to transmit a suitably pulsed optical signal along the fibre 20. The optical signal is scattered as it propagates along the optical fibre 20 and the receiver system is configured to collect the scattered light.

There are various mechanisms by which the light can be scattered, such as Rayleigh, Brilliouin and Raman scattering. Changes in the acoustic environment experienced by the optical fibre 20 cause localised variations in the pressure and strain experienced by the optical fibre 20, which in turn result in measurable effects on the scaftered light from the optical signal.

The signals produced by the receiver system 50 from the detected backscattered light can be processed by the controller 55 in order to determine properties of the acoustic signal, such as amplitude and phase. A variety of methods are available for producing and consequently processing the scaftered light in order to determine the properties of the detected acoustic signals. For example, discrete optical elements such as Fabry-Perot etalons or fibre Bragg gratings can be provided in the optical fibre 20 wherein the optical elements are configured to produce a quantifiable and calculable effect on the transmitted light signal in response to variations in acoustic signal experienced by the optical element. However, a preferred system is one which does not require discrete optical elements, such as the iDASRTM system by Silixa ltd., e.g. as described in W02010!136809 and W02010/136810, each of which are hereby incorporated by reference. This system uses phase shifting and interference of the optical signals in order to determine the phase and amplitude of the acoustic signal at the series of measurement points 25a-25e. The location of a measurement points 25a-25e can be selected I determined from the timings of the transmitted and received optical signals and from knowledge of the speed of transmission of the optical signals in the optical fibre 20.

A sensor system 5 according to an embodiment of the present invention in use is shown in Figure 2. The sensor system 5 comprises the distributed sensor 15 (although only a portion of the optical fibre cabling 20 is shown) and the array of acoustic generators 40a-40c. The optical fibre cabling 20 used to measure acoustic signals is provided along a length of a well bore 10. Similarly, the array of acoustic generators 40a-40c is also distributed along the length of the well bore 10. The distributed sensor is operable to measure acoustic signals originating from each of the acoustic generators 40a-40c at respective associated groups of spatially distributed measurement points or locations 25a-25e spaced lengthwise along the optical fibre cabling 20. Each of the groups of measurement locations 25a-25e include measurement locations 25b-25e both upstream and downstream of the associated acoustic generator 40a-40c and a measurement location 25a located perpendicular to the flow direction or the longitudinal direction of the pipeline, conduit or wellbore 10 from the associated acoustic generator 40a-40c. The measurement locations 25a-25e are distributed along a direction generally parallel to the distribution of acoustic generators 40a-40c.

In embodiments, the acoustic generators 40a-40c advantageously comprise wireless transducers, such as piezoelectric or magneto-restrictive acoustic generators. Other examples of suitable acoustic generators 40a-40c include impact generators such as actuator and hammer systems for impacting a wall of a tubular or the like in order to produce an acoustic event. In embodiments, each of the acoustic generators 40a-40c are configured to produce a directional or anisotropic acoustic beam or signal, such as a conical beam or signal, which can be oriented toward the associated measurement locations 25a-25e associated with the respective acoustic generator 40a-40c.

Beneficially, the acoustic generators 40a-40c are configured to communicate with a remotely located control and/or data processing systems (not shown) using acoustic signals, e.g. by transmitting and/or receiving acoustic signals transmitted along a pipeline, tubular or other transmission medium, in addition to generating acoustic signals for performing the measurements described herein. In other words, the acoustic generators 40a-40c are operable for both acoustic telemetry and generation of acoustic measurement signals.

The acoustic generators 40a-40c are operable responsive to the control system 55, which is advantageously located remotely from the acoustic generators 40a-40c. In this way, the timing and amplitude of the acoustic events / signals can be controlled by suitable programming of the control system.

The acoustic generators 40a-40c may be distributed over the zones or sections 30a- 30c of the well bore 10. For example, the zones or sections 30a-30c could be associated with different surrounding geologies, well depths, functions or other properties of the wellbore 10 that would be apparent to those skilled in the art. In this way, the sensor system 5 is operable to selectively determine properties such as fluid density and flow rate of fluid 10 in individual zones 30a-30c and determine the contribution of each zone 30a-30c to the overall flow rate. This arrangement also allows selective fluid profiling to be performed along the wellbore 10, conduit or pipeline.

It will be appreciated that the sensor system 5 may be operated using a variety of methodologies. For example, the distances between the respective acoustic generators 40a-40c and the associated measurement locations 25a-25e can be known or determined. Thus, time of flight measurements can be performed in order to determine the speed of the acoustic signals in the fluid 35 within the well bore 10.

Particularly, the time of flight of signals from respective acoustic sources 40a-40c to the measurement location 25a associated with each acoustic source 40a-40c that is perpendicular to the fluid flow direction from the respective acoustic source 40a-40c can be used to determine the speed of the acoustic signal in the fluid 35. However, it will be appreciated that a skilled person would understand that other methods of determining speed of sound in the fluid could be used.

The speed of sound in the fluid 35 is indicative of the density of the fluid 35. The density of the fluid 35 can also in turn be used to determine the composition of the fluid 35, such as determining a degree of aeration or gas content of the fluid 35, or distinguishing between dissimilar liquids such as oil and water, or distinguishing between gas or liquid flowing in the wellbore 10. It will be appreciated that the local temperature may be measured in order to improve the accuracy of the fluid composition determination. A variety of techniques for determining local temperature, e.g. using the fibre optic cabling 20, are known in the art and can be conveniently used.

The determination of the fluid composition can be determined by comparison with reference or calibration data or be calculated, e.g. from changes in the speed of sound in the fluid, wherein decreasing or increasing speed of sound (normalised for temperature change) can be indicative of increasing or decreasing aeration or gas content, for example.

In embodiments, the determination of fluid composition can be advantageously used to adjust operating parameters of the sensor system 5. For example, the frequency of acoustic signal transmitted by the acoustic generators 40a-40c may be variable and selectable, e.g. by the control system. An example of a suitable frequency range is between 20Hz and 20kHz. In example embodiments, the frequency of the acoustic signal emitted by one or more of the acoustic generators 40a-40c can be varied in order to optimise the frequency of the transmitted acoustic signal for the composition of the fluid, e.g. to optimise transmission. For example, the frequency of the acoustic signals can be increased with increasing gas concentration I decreasing density The determination of the speed of the acoustic signal through the fluid and the relative time taken for the acoustic signal to be detected at the associated measurement locations (e.g. the upstream and downstream measurement locations 25b-25e) allows the fluid flow velocity to be determined, for example by determining Doppler shift or by differential time of flight calculations between upstream and downstream measurement locations 25b-25e that are at equal and opposite angles from the associated acoustic generator 40a-40c.

For example, Figure 3 shows an exemplary arrangement where the distributed acoustic sensor 15 is configured to measure an acoustic signal from one of the acoustic generators 4Db at five measurement locations 25a-25e. A first measurement location 25a is positioned laterally to the acoustic generator 4Db, i.e. perpendicularly to the direction of fluid flow or the longitudinal direction of the relevant portion of the wellbore 10. Second and third measurement locations 25b, 25c are provided at positions rotated around the acoustic generator 4Db by angles and $2 respectively in an upstream direction from the axis between the first measurement location 25a and the acoustic generator 4Db. Fourth and fifth measurement locations 25d, 25e are provided at positions rotated around the acoustic generator 4Db by angles 4 and $4 respectively in a downstream direction from the axis between the first measurement location 25a and the acoustic generator 4Db. In the example shown in Figure 3, = - and $2 = - $. Also, both the second and fifth measurement locations 25b, 25e are the same distance l from the acoustic generator 4Db and the third and fourth measurement locations 25c, 25d are the same distance 12 from the acoustic generator 4Db. It will be appreciated that the acoustic signals from the acoustic generator 40b will arrive at the 3D downstream measurement location 25d, 25e sooner than they arrive at the corresponding upstream measurement location 25b, 25c. For example, as illustrated in Figure 4, a signal emitted from the acoustic generator 4Db at a time t=D will be received at the fifth (downstream) measurement location 25e at a time t=t1 and received at the corresponding upstream measurement location (i.e. the second measurement location 25b) at a later time t=t2. In this case, if c is the speed of sound in the (stationary) fluid 35, and At1 is the time difference between the signal from the acoustic generator 40b being received at the second measurement location 25b and being received at the fifth measurement location 25e and At2 is the time difference between the signal from the acoustic generator being received at the second measurement location 25c and being received at the third measurement location 25d, then the flow rate of the fluid (vflUd) can be determined using: _________ c2Lxt2 12J'lULd = 211sinQ1 = 2l2siiup2 Of course, it will be appreciated that this is only one possible method for determining the flow rate of the fluid. For example, the acoustic generators 40a-40c may be configured to emit pulses of acoustic signals at given frequency, and the flow rate may be determined from a Doppler shift measured by the distributed acoustic sensor 15 at the plurality of measurement locations 25a-25e associated with the respective acoustic generator 40a-40c.

In another example, a continuous signal or tone may be emitted and the resulting acoustic signals detected at the associated plurality of measurement locations 25a-25e of the distributed acoustic sensor 15 will give rise to an indicative acoustic profile.

Variation of the flow rate will lead to variations in the received acoustic profile 60 determined by summing the contributions from all of the measurement locations 25a- 25e associated with a given acoustic generator 40a-40c, e.g. as shown in Figures 5 and 6. For example, an increase in flow rate may result in the downstream signals being received sooner and the upstream signals being received later, such that the profile is broadened 65 (as shown in Figure 5) and/or skewed (as shown in Figure 6).

Conversely, a decrease in flow rate may result in the downstream signals being received later and the upstream signals being received sooner, which may lead to a narrowing 70 of the profile. These effects may be enhanced by measuring the acoustic response not continuously, but for a small period shortly after sending an acoustic pulse from the acoustic generator 40a-40c. The time after and period during which the measurement locations 25a-25e are active may depend on the fluid type, flow regime and previous calibration of the measurement system. Signal levels may be enhanced by stacking measurements taken from multiple acoustic pulses. In this way, variations in the detected acoustic profile 60 can be used to determine variations in the flow rate, e.g. by calculation or by comparison with calibration or reference data. For example, the intensities of signals received from downstream sources may be stronger than for upstream sources, leading to a skewing of the pulse. As can be seen from Figure 6, the degree of skewing may vary depending on the flow rate.

While certain specific embodiments have been described, these embodiments have been presented by way of example only, and are not intended to limit the scope of the invention. Indeed the novel methods and systems described herein may be embodied in a variety of other forms. Furthermore, various omissions, substitutions and changes in the form of the methods and systems described herein may be made without departing from the spirit of the invention. The accompanying claims and their equivalents are intended to cover such forms and modifications as would fall within the scope of the invention.

For example, although examples of sensor systems 5 are shown and described, wherein the systems 5 have specific numbers of acoustic generators 40a-40c, distributed acoustic sensors 15 and measurement locations 25a-25e, it will be appreciated that other numbers or combinations of acoustic generators 40a-40c, distributed acoustic sensors 15 and/or measurement locations 25a-25e may be used.

For example, the sensor system might comprise a single acoustic generator, or a plurality of acoustic generators and/or the sensor system 5 may comprise a single distributed acoustic sensor system or a plurality of distributed acoustic sensor systems.

In addition, although a preferred distributed sensor 15 that uses conventional optical fibre cabling 20 and is potentially capable of determining the acoustic field at any point along the length of the optical fibre cabling 20 is described, it will be appreciated that the present invention is not limited to this particular distributed temperature sensor and that other suitable distributed acoustic sensors may be used, such as those having optical fibies comprising optical elements, such as Fabry-Perot etalons or fibre Bragg gratings, or other suitable types of distributed acoustic sensing systems known in the art.

Furthermore, whilst specific examples of wireless acoustic generator arrangements are advantageously described, it will be appieciated that other types of acoustic generators and/or acoustic generators that communicate with the control system via a physical or wired connection could alternatively be used.

Additionally, although time of flight and Doppler shift techniques for determining flow rate are described, it will be appreciated that other techniques for determining fluid flow from the acoustic measurements made by the systems of the present invention are possible.

Claims

CLAIMS: 1. A sensor system for determining at least one property of a fluid in a wellbore, pipeline or conduit, the sensor system comprising: at least one acoustic generator, the acoustic generator being operable to transmit an acoustic beam or signal through the fluid, in use; and at least one distributed acoustic sensor, the distributed acoustic sensor being configured to detect and/or measure the acoustic beams or signals passing through at least a portion of the fluid at a plurality of measurement locations; wherein the sensor system is configured to determine the at least one property of the fluid from the acoustic beams or signals detected or measured at the plurality of measurement locations.
2. The sensor system of claim 1, comprising a plurality of acoustic generators distributable lengthwise along at least pad of the wellbore, pipeline or conduit.
3. The sensor system of claim 1 or claim 2, where the sensor system is configured such that one or more of the acoustic generators are movable along the length of at least part of the wellbore, pipeline or conduit.
4. The sensor system of any preceding claim, wherein the acoustic generators are selectively operable, controllable and/or programmable in order to control the timing, phase, frequency and/or amplitude of the acoustic beams or signals emitted by the acoustic generators.
5. The sensor system according to claim 4, wherein the acoustic generators are wirelessly operable, controllable and/or programmable.
6. The sensor system according to claim 5, wherein the acoustic generators are remotely operable, controllable and/or programmable using acoustic signals sent to and/or from a remote control system.
7. The sensor system according to any preceding claim, wherein the distributed acoustic sensor comprises at least one optical fibre, at least one property of which is variable responsive to acoustic beams or signals and the distributed acoustic sensor is configured to determine variations in light scattered, reflected or propagating in the at least one optical fibre due to variations in the at least one property of the at least one optical fibre at the plurality of measurement locations in order to detect and/or measure the acoustic beams or signals passing through at least a portion of the fluid.
8. The sensor system according to any preceding claim, wherein the sensor system is configured to determine at least one of Doppler shift, differential time of flight and/or variations in a profile of measurements of the acoustic beams or signals from the plurality of measurement locations and thereby determine at least one property of the fluid.
9. The sensor system according to any preceding claim, wherein the system is configured to determine an acoustic intensity profile along the array created by an acoustic generator and relate this intensity profile to at least one property of the fluid.
10. The sensor system according to any preceding claim, wherein the or an acoustic intensity profile is measured for a specific period synchronous with an acoustic generator and this acoustic intensity profile is used to determine at least one property of the fluid.
11. The sensor system according to claim 2 or any claim dependent thereon, wherein the acoustic generators and plurality of measurement locations are arranged such that they are distributed over, and determine the at least one property of the fluid in, two or more zones or sections of the wellbore, pipeline or conduit, in use.
12. The sensor system according to any preceding claim, wherein the at least one property comprises at least one of speed of sound in the fluid, density of the fluid and flow rate of the fluid.
13. A method of determining at least one property of a fluid in a wellbore, pipeline or conduit, the method comprising: providing at least one acoustic generator, the acoustic generator being operable to transmit an acoustic beam or signal through the fluid, in use; providing at least one distributed acoustic sensor, the distributed acoustic sensor being configured to detect and/or measure the acoustic beams or signals passing through at least a portion of the fluid at a plurality of measurement locations; determining the at least one property of the fluid from the acoustic beams or signals detected or measured at the plurality of measurement locations.
14. The method of claim 13, comprising using the sensor system of any of claims 1 to 12.
15. An array of acoustic generators configured for use in the sensor system according to any of claims ito 12.
16. The array of acoustic generators according to claim 15, wherein acoustic generators are wirelessly operable, controllable and/or programmable in order to control the timing, phase, frequency and/or amplitude of the acoustic beams or signals emitted by the acoustic generators using acoustic signals sent to and/or from a remote control system.
17. A computer program product configured to implement the sensor system according to any of claimsl to 12, the method of claim 13 or claim 14 and/or the acoustic generator array according to claim 15.
18. A computer readable medium comprising the computer program product of claim 17.
19. A sensor system substantially as shown in the Figures and/or described in relation thereto.